Download:
pdf |
pdf20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION
)
)
Docket No. RM13-_____
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
BAL-003-1 – FREQUENCY RESPONSE AND FREQUENCY BIAS SETTING
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
Stacey Tyrewala
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
Counsel for North American Electric Reliability
Corporation
March 29, 2013
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
TABLE OF CONTENTS
I. Executive Summary………………………………………………………………………….. 3
II. Notices and Communications………………………………………………………………... 6
III. Background …………………………………………………………………………………. 6
a.
b.
c.
d.
Regulatory Framework
NERC Reliability Standards Development Procedure
Procedural Background
Frequency Response and the Frequency Response Initiative
IV. Justification for Approval of the Proposed Definitions and Reliability Standard……….. 13
a. Proposed Definitions
b. Proposed Reliability Standard, BAL-003-1
c. Enforceability of the Proposed Reliability Standard
V. Conclusion……………………………………………………………………………………. 23
EXHIBITS
Exhibit A — Order No. 672 Criteria
Exhibit B — Proposed Reliability Standard Submitted for Approval
Exhibit C — Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard
Exhibit D — Frequency Response Standard Background Document
Exhibit E — Implementation Plan for Reliability Standard Submitted for Approval
Exhibit F — Frequency Response Initiative Report
Exhibit G — Status of Recommendations of the Frequency Response Initiative Report
Exhibit H — Frequency Response Initiative Supplemental Report -IFRO Simulations (DRAFT)
Exhibit I — Consideration of Comments
Exhibit J — Analysis of how VRFs and VSLs Were Determined Using Commission Guidelines
Exhibit K — Summary of the Reliability Standard Development Proceeding and Complete Record
of Development of Proposed Reliability Standard
Exhibit L — Standard Drafting Team Roster for NERC Standards Development Project 2007-12
i
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION
)
)
Docket No. RM13-____
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
BAL-003-1 – FREQUENCY RESPONSE AND FREQUENCY BIAS SETTING
The North American Electric Reliability Corporation (“NERC”)1 hereby requests the
Federal Energy Regulatory Commission (“FERC” or the “Commission”) approve, in accordance
with Section 215(d)(1) of the Federal Power Act (“FPA”)2 and Section 39.5 of the Commission’s
regulations, 18 C.F.R. § 39.5 (2012), the proposed Reliability Standard —BAL-003-1—
Frequency Response and Frequency Bias Setting,3 which was approved by the NERC Board of
Trustees on February 7, 2013.
NERC is hereby requesting approval of the proposed Reliability Standard, the associated
definitions, implementation plan, Violation Risk Factors (“VRFs”) and Violation Severity Levels
(“VSLs”), and retirement of the currently effective Reliability Standard and definition as detailed
below. Specifically, NERC requests approval of the following:
Approval of proposed Reliability Standard BAL-003-1 Requirements R2, R3 and R4
included in Exhibit B, effective the first day of the first calendar quarter that is
twelve months following the effective date of a Final Rule in this docket;
1
NERC has been certified by the Commission as the electric reliability organization (“ERO”) in accordance
with Section 215 of the Federal Power Act. The Commission certified NERC as the ERO in its order issued July 20,
2006 in Docket No. RR06-1-000. North American Electric Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO
Certification Order”).
2
16 U.S.C. § 824o (2012).
3
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available here: http://www.nerc.com/files/Glossary_of_Terms.pdf.
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Approval of proposed Reliability Standard BAL-003-1 Requirement R1 included in
Exhibit B, effective the first day of the first calendar quarter that is twenty-four
months following the effective date of a Final Rule in this docket;
o Retirement of BAL-003-0.1b at midnight of the day immediately prior to the
effective date of Requirements R2, R3 and R4 of BAL-003-1.
Approval of three new definitions (Frequency Response Measure, Frequency
Response Obligation and Frequency Response Sharing Group) and one revised
definition (Frequency Bias Setting) effective the first day of the first calendar quarter
that is twelve months following the effective date of a Final Rule in this docket;
o Retirement of the existing definition of Frequency Bias Setting at midnight of
the day immediately prior to the effective date of Requirements R2, R3, and
R4 of BAL-003-1.
Approval of the implementation plan for the proposed BAL-003-1 Reliability
Standard which is included in Exhibit E.
As required by Section 39.5(a)5 of the Commission’s regulations, this petition presents the
technical basis and purpose of the proposed Reliability Standard, a summary of the development
proceedings conducted by NERC for proposed BAL-003-1 Reliability Standard, and a
demonstration that the proposed Reliability Standard meets the criteria identified by the
Commission in Order No. 672.6
The proposed standard achieves the specific reliability goal of ensuring that each of the
Interconnections have sufficient Frequency Response7 to guard against underfrequency load
shedding (“UFLS”) due to an event in that Interconnection. The proposed Reliability Standard
ensures that Balancing Authorities (“BAs”) provide Frequency Response necessary to ensure
5
18 C.F.R. § 39.5(a) (2012).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321–37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006). Exhibit A explains how the proposed Reliability Standard satisfies these
criteria.
7
Frequency Response is defined in the Glossary of Terms Used in NERC Reliability Standards,as:
“(Equipment) The ability of a system or elements of the system to react or respond to a change in system frequency.
(System) The sum of the change in demand, plus the change in generation, divided by the change in frequency,
expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).”
6
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
that frequency does not reach the point where coordinated UFLS relays are set to curtail loads.
This is accomplished through a measurement methodology that ensures consistency across the
industry for both Frequency Response and Frequency Bias Setting calculations.
I.
EXECUTIVE SUMMARY
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency
immediately following the sudden loss of generation or load, is a critical component to the
reliable operation of the Bulk-Power System, particularly during disturbances and restoration.8
Power system operators manage or control frequency primarily through adjustments to the output
of generators with the goal of restoring balance between generation and load. Failure to maintain
frequency can disrupt the operation of equipment and initiate disconnection of power plant
equipment to prevent them from being damaged, which could lead to wide-spread blackouts.
There is evidence of decline in Frequency Response in the three Interconnections over
the past 10 years leading up to this standards project, but no confirmed reason for the apparent
decline.9 System planning and operations experts are anticipating new and different technical
challenges, particularly in the reduction of system inertia through the displacement of
conventional generation resources during light load periods. It is clear that maintaining adequate
Frequency Response for Bulk-Power System reliability is becoming more important and
complex. While the decline in Frequency Response has lessened, it is important that the industry
understands the growing complexities of frequency control and is ready with comprehensive
strategies to stay ahead of any potential problems, and the proposed BAL-003-1 Reliability
Standard is an important part of that strategy.
8
System frequency reflects the instantaneous balance between generation and load. Reliable operation of a
power system depends on maintaining frequency within predetermined boundaries above and below a scheduled
value, which is 60 Hertz (“Hz”) in North America.
9
See Exhibit F, Frequency Response Initiative Report at p. 22.
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
The proposed Reliability Standard, BAL-003-1, sets a minimum Frequency Response
Obligation for each BA, provides a uniform calculation of Frequency Response and Frequency
Bias Settings that transition to values closer to natural Frequency Response, and encourages
coordinated Automatic Generation Control (“AGC”) operation. Frequency Response must be
evaluated on an interconnection-wide basis in order to establish the Frequency Response
responsibilities for an individual BA.10
Proposed Reliability Standard BAL-003-1 is applicable to Balancing Authorities and to
the newly proposed term -- Frequency Response Sharing Groups, and consists of four
Requirements and Attachment A: BAL-003-1 Frequency Response and Frequency Bias Setting
Standard Supporting Document. Attachment A (appended to the proposed standard) is a
supporting document for proposed Reliability Standard BAL-003-1 that discusses the process the
ERO will follow to validate the Balancing Authority’s FRS Form 1 data and publish the official
Frequency Bias Settings. FRS Form 1 provides the guidance as to how to account for and
measure Frequency Response. FRS Form 1, and the underlying data retained by the Balancing
Authority, will be used for measuring whether sufficient Frequency Response was provided.
A Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard and the Frequency Response Standard Background Document are submitted for
informational purposes.11 The Procedure for ERO Support of Frequency Response and
Frequency Bias Setting Standard outlines how the ERO will conduct a transparent process to
annually identify a list of frequency events to be used by BAs to calculate their Frequency
10
The amount of Frequency Response required on an interconnection-wide basis is known as the
Interconnection Frequency Response Obligation (“IFRO”).
11
NERC is not requesting Commission approval of these documents.
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Response to determine whether the BA met its Frequency Response Obligation and an
appropriate fixed Frequency Bias Setting.12
A detailed explanation of the development, testing and implementation of proposed
Reliability Standard BAL-003-1 is provided in the Frequency Response Standard Background
Document. This document will be maintained and updated by the ERO and the NERC
Resources Subcommittee (a division of the NERC Operating Committee) on a going-forward
basis and will be used as a reference and training resource.
In conjunction with the proposed Reliability Standard, the following definitions are
proposed for inclusion in the NERC Glossary of Terms Used in Reliability Standards:
Frequency Response Measure;
Frequency Response Obligation;
Frequency Bias Setting; and
Frequency Response Sharing Group.
Collectively, the proposed BAL-003-1 Reliability Standard and the proposed definitions
perform a vital reliability function by ensuring that there is sufficient Frequency Response from
BAs to maintain Interconnection frequency within predefined bounds and by providing
consistent methods for measuring Frequency Response and determining the Frequency Bias
Setting. The proposed Reliability Standard was developed by a standard drafting team that
consists of some of the foremost experts in the field of Frequency Response, as explained in
Exhibit L.
12
The Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard is submitted
for informational purposes. Any future approved revisions to the Procedure will also be filed with the Commission
for informational purposes.
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the following:13
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
III.
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
Stacey Tyrewala*
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
BACKGROUND
A. Regulatory Framework
By enacting the Energy Policy Act of 2005,14 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the nation’s Bulk-Power
System, and with the duty of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215 of the
FPA states that all users, owners, and operators of the Bulk-Power System in the United States
will be subject to Commission-approved Reliability Standards.15
Section 215(d)(5) of the FPA authorizes the Commission to order the ERO to submit a
new or modified Reliability Standard. Pursuant to Section 215(d)(2) of the FPA and Section
39.5(c)(1) of the Commission’s regulations, the Commission will give due weight to the
13
Persons to be included on the Commission’s service list are indicated with an asterisk. NERC requests
waiver of 18 C.F.R. § 385.203(b) to permit the inclusion of more than two people on the service list.
14
16 U.S.C. § 824o (2012).
15
See Section 215(b)(1)(“All users, owners and operators of the bulk-power system shall comply with
reliability standards that take effect under this section.”).
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
technical expertise of the ERO with respect to the content of a Reliability Standard. In Order
No. 693, the Commission noted that it would defer to the “technical expertise” of the ERO with
respect to the content of a Reliability Standard and explained that, through the use of directives,
it provides guidance but does not dictate an outcome. Rather, the Commission will consider an
equivalent alternative approach provided that the ERO demonstrates that the alternative will
address the Commission’s underlying concern or goal as efficiently and effectively as the
Commission’s proposal, example, or directive.16
Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes to become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes to be made effective. The Commission has the regulatory responsibility
to approve standards that protect the reliability of the Bulk-Power System and to ensure that such
standards are just, reasonable, not unduly discriminatory or preferential, and in the public
interest.
B. NERC Reliability Standards Development Procedure
The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.17 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
16
See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶
31,242 at PP 31, 186-187, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
17
Order No. 672 at P 334 (“Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.”).
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Development) of its Rules of Procedure and the NERC Standard Processes Manual.18 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable
notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfies certain of the criteria for approving Reliability
Standards. The development process is open to any person or entity with a legitimate interest in
the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders, and
a vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard before the Reliability Standard is submitted to the Commission for approval.
C. Procedural Background
In Order No. 693, issued on March 16, 2007, the Commission approved the NERC
Resource and Demand Balancing Reliability Standards, including BAL-003-0, which addresses
Frequency Response and Frequency Bias. Order No. 693 (at P 375) directed NERC to:
develop a modification to BAL-003-0 through the Reliability Standards
development process that: (1) includes Levels of Non-Compliance; (2) determines
the appropriate periodicity of frequency response surveys necessary to ensure that
Requirement R2 and other requirements of the Reliability Standard are being met,
and to modify Measure M1 based on that determination and (3) defines the
necessary amount of Frequency Response needed for Reliable Operation for each
balancing authority with methods of obtaining and measuring that the frequency
response is achieved.
On March 18, 2010, the Commission issued an Order Setting Deadline for Compliance19
(“March 18 Order”) with directives from Order No. 693 concerning Reliability Standard BAL003-0–Frequency Response and Bias. The March 18 Order directed NERC to submit a
18
The NERC Rules of Procedure are available here: http://www.nerc.com/page.php?cid=1%7C8%7C169.
The current NERC Standard Processes Manual is available here:
http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf.
19
Mandatory Reliability Standards for the Bulk Power System, Order Setting Deadline for Compliance, 130
FERC ¶ 61,218 (2010)(“March 18 Order”).
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
modification to BAL-003-0 responsive to the directive in Order No. 693 within six months from
the date of the issuance of the order.
NERC filed a request for clarification and rehearing of the March 18 Order on April 19,
2010, and explained that compliance with a six-month deadline was impossible given the highly
technical issues related to Frequency Response and the necessity of conducting studies and
analyses.20
On May 13, 2010, FERC issued an Order Granting Rehearing for Further Consideration
and Scheduling Technical Conference (“Rehearing Order”).21 Specifically, the Rehearing Order
granted rehearing for the limited purpose of further consideration, and scheduled a technical
conference to discuss technical issues identified in the development of a Frequency Response
requirement in BAL-003-0. In the Rehearing Order, the Commission directed NERC to file,
within 30 days after the technical conference, a proposed schedule that included the analyses
needed to develop a Frequency Response requirement, and firm deadlines for completing those
analyses. In the Rehearing Order, the Commission deferred the six-month compliance deadline
included in the March 18 Order.22
On October 14, 2010, as directed in the Rehearing Order, NERC filed comments
following the September 23 Frequency Response technical conference.23 In this filing, NERC
committed to filing a proposed timeline for development of a Reliability Standard addressing
FERC’s directives by October 25, 2010. NERC submitted an action plan and estimated timeline
on October 25, 2010 that provided milestones for the completion of the project by May 2012.
20
Request of the North American Electric Reliability Corporation for Clarification and Rehearing of the
Order Setting Deadline for Compliance, Docket No. RM06-16-010 (April 19, 2010) at pp. 4-7.
21
Mandatory Reliability Standards for the Bulk Power System, Order Granting Rehearing for Further
Consideration and Scheduling Technical Conference, 131 FERC ¶ 61,136 (2010).
22
Id. at P 2.
23
Comments Of The North American Electric Reliability Corporation Following September 23 Frequency
Response Technical Conference, Docket Nos. RM06-16-010 and RM06-16-011 (October 14, 2010).
9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
NERC continuously noted that significant rigorous technical analysis is necessary to determine
the Frequency Response requirement needed for each Interconnection without also placing
significant and unnecessary cost burdens for over-installing frequency responsive control
systems.24 On December 16, 2010, the Commission accepted NERC’s anticipated May 2012
target date.25
On March 30, 2012, NERC filed a motion for an extension of time to submit a revised
BAL-003 Reliability Standard. In an Order on Motion for an Extension of Time and Setting
Compliance Schedule, the Commission established a deadline for completion of research and
analysis and a deadline of May 31, 2013 for submission of a revised BAL-003 Reliability
Standard.26 In compliance, NERC submitted quarterly reports on October 31, 2012 and January
23, 2013. The instant filing is submitted prior to the May 31, 2013 deadline in compliance with
the Commission’s directive.
D. Frequency Response and the Frequency Response Initiative
Provided below is a brief explanation of Frequency Response and NERC’s Frequency
Response Initiative.
1. Frequency Response: An Overview
Primary frequency control involves the autonomous, automatic, and rapid action of a
generator, or other resource, to change its output (within seconds) to oppose large changes in
frequency. The primary frequency control provided by an individual generator is commonly
known as Frequency Response. Measurement of primary Frequency Response on an individual
resource or load basis requires analysis of energy amounts that are often small and difficult to
24
See Request of the North American Electric Reliability Corporation for Clarification and Rehearing of the
Order Setting Deadline for Compliance, Docket No. RM06-16-000 (April 19, 2010) at pp. 3-4.
25
Mandatory Reliability Standards for the Bulk-Power System, 133 FERC ¶ 61,212 (2010).
26
Mandatory Reliability Standards for the Bulk-Power System, 139 FERC ¶ 61,097 (2012).
10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
measure using installed metering. The ability of a power system to withstand a sudden loss of
generation depends on the presence and adequacy of operating reserves that are on-line and
capable of providing primary frequency control.
Secondary frequency control (also known as Automatic Generating Control (“AGC”))
comes from either manual or automated dispatch from a centralized control system and manages
the allocation of loading among the available power plants. Secondary frequency control follows
primary frequency control and takes place in the time scale of minutes. A task of secondary
frequency control is to ensure that the system is always positioned so that the required amount of
primary frequency control action will be available if needed. Tertiary generation control adjusts
the loading of turbines through operator dispatch and is dominant in the range of minutes to
hours after a frequency excursion.
Frequency Bias is a term used in AGC to prevent withdrawal of generator primary
control action following a disturbance as long as the frequency is off its nominal value.
Frequency Bias is not the same as Frequency Response. Frequency Bias is a secondary control
setting of the AGC system, not a primary control parameter. Changes in Frequency Bias of a
Balancing Authority do not change Frequency Response. A detailed explanation of Frequency
Response is provided in the Frequency Response Background Document, included as Exhibit D.
2. Frequency Response Initiative
To comprehensively address the issues related to Frequency Response, NERC launched the
Frequency Response Initiative in 2010. In addition to coordinating the myriad of efforts
underway in standards development and performance analysis, the Initiative includes performing
in-depth analysis of interconnection-wide Frequency Response to achieve a better understanding
11
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
of the factors influencing frequency performance across North America.27 Basic objectives of
the Frequency Response Initiative include:
development of a clearer and more specific statement of frequency-related
reliability factors, including better definitions for “ownership” of responsibility
for Frequency Response;
collection and provision of more granular Frequency Response data on and
technical analyses of frequency-driven bulk power system events, including root
cause analyses;
metrics and benchmarks to improve Frequency Response performance tracking;
increasing coordinated communication and outreach on the issue to include
webinars and NERC alerts and to share lessons learned; and
focused discussion on communication of emerging technology issues, including
frequency-related effects caused by renewable energy integration, smart grid
technology deployment, and new end-use technology.
The Frequency Response Initiative Report, included as Exhibit F, was issued in support of
Project 2007-12 with seventeen recommendations. A discussion of the status of these
recommendations is provided as Exhibit G. A draft supplemental report regarding the IFRO
Simulations is provided as Exhibit H.
27
The Electric Reliability Council of Texas (“ERCOT”) region is often held up as a model with respect to the
issue of Frequency Response because significant improvements in Frequency Response have been achieved in
ERCOT. NERC has reviewed the actions taken by ERCOT to address control settings within ERCOT and the
responsiveness of generation to a recent frequency event due to the tripping of a generator and has evaluated these
lessons learned in developing the proposed Reliability Standard. However, there are several significant differences
with respect to the ERCOT system that limit the application of these lessons on a North American-wide basis. The
ERCOT grid is separated electrically from the rest of North America. Two DC (direct current) ties link the ERCOT
with Southwest Power Pool to the north and east. ERCOT schedules and centrally dispatches its grid within a single
control area, ensures transmission reliability and wholesale open access, and manages financial settlement in the
wholesale power market. It also administers the Texas competitive retail market, including customer switching.
The ERCOT grid covers 75% of Texas land and serves 85% of the Texas load. See
http://www1.eere.energy.gov/analysis/pdfs/demand_response_in_the_ercot_markets_mark_patterson.pdf. In
contrast, the Eastern Interconnection covers approximately 3.5 million square miles and includes the provinces of
Saskatchewan, Manitoba, Ontario, Quebec and the Maritimes provinces in Canada, and all or portions of the
contiguous 39 U.S. states (and the District of Columbia) east of the Western Interconnection. Due to these physical
and regional variations that directly impact Frequency Response, the lessons learned in ERCOT cannot be
universally applied.
12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
IV.
JUSTIFICATION FOR APPROVAL OF PROPOSED DEFINITIONS AND
RELIABILITY STANDARD
Provided below is the following: (A) a description of the proposed definitions, (B)
justification for the proposed BAL-003-1 Reliability Standard on a Requirement by Requirement
basis, and (C) an explanation of the enforceability of the proposed Standard.
A. Proposed Definitions
Three new definitions are proposed for inclusion in the NERC Glossary of Terms Used in
Reliability Standards:
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually by Balancing Authorities or Frequency Response Sharing
Groups for frequency events specified by the ERO. This will be calculated as
MW/0.1Hz.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
This will be calculated as MW/0.1Hz.
Frequency Response Sharing Group (FRSG): A group whose members consist of two
or more Balancing Authorities that collectively maintain, allocate, and supply operating
resources required to jointly meet the sum of the Frequency Response Obligations of its
members.
The proposed BAL-003-1 Reliability Standard allows Balancing Authorities to cooperatively
form Frequency Response Sharing Groups as a means to jointly meet the obligations of the
standard. There is no obligation to form or be part of a Frequency Response Sharing Group.
The members of the Frequency Response Sharing Group would determine how to allocate
penalties/violations among its members. The creation of Frequency Response Sharing Groups is
one of the ways the standard drafting team addressed the Commission’s directive to provide
methods for obtaining Frequency Response.28
28
Order No. 693 at P 375.
13
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
One revised definition is proposed for inclusion in the NERC Glossary of Terms Used in
Reliability Standards:
Frequency Bias Setting: A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s inverse Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved Standards:
BAL-001-0.1a Real Power Balancing Control Performance
BAL-004-0 Time Error Correction
BAL-004-1 Time Error Correction
BAL-005-0.1b Automatic Generation Control
These proposed new and revised definitions are used throughout the Requirements of proposed
Reliability Standard BAL-003-1.
B. Proposed Reliability Standard, BAL-003-1
Proposed Reliability Standard BAL-003-1 consists of four Requirements and is
applicable to Balancing Authorities and to the newly proposed term -- Frequency Response
Sharing Groups. BAL-003-1 offers significant improvements for reliability over the existing
BAL-003-0.b Reliability Standard.29 BAL-003-1 defines the minimum Frequency Response
needed for reliable operation and methods for obtaining the Frequency Response.30
BAL-003 is part of the Resource and Demand Balancing (“BAL”) body of Reliability
Standards. Collectively, the six BAL Reliability Standards address balancing resources and
demand to maintain interconnection frequency within prescribed limits. As the Commission
29
A mapping document illustrating how the Requirements of the existing BAL-003 standard have been either
incorporated into or superseded by the proposed BAL-003-1 Reliability Standard is provided in Exhibit K.
30
The standard drafting team identified several methods of obtaining frequency response, including:
Regulation Services; contractual services; through a tariff; from generators through an interconnection agreement;
and contract with an internal resource or loads. See Exhibit D.
14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
noted in Order No. 693, the purpose of BAL-003-0 is to “ensure that a balancing authority’s
frequency bias setting is accurately calculated to match its actual frequency response.”31
The purpose of proposed Reliability Standard BAL-003-1 is to not only ensure that a
Balancing Authority’s Frequency Bias Setting is accurately calculated to match its actual
Frequency Response, but also to provide consistent methods for measuring Frequency Response
and determining the Frequency Bias Setting. The Commission stated in Order No. 693 that the
minimum Frequency Response needed for reliable operation should be defined and methods for
obtaining the Frequency Response identified (at P 372). BAL-003-1 satisfies these directives
and is a significant improvement over the currently effective BAL-003-0.1b Reliability Standard.
1. BAL-003-1, Requirement R1
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as
calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a FRSG to
maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time Horizon:
Real-time Operations]
The primary objectives of Requirement R1 are as follows:
(1) Determine whether a Balancing Authority has sufficient Frequency Response for
reliable operations.
(2) Provide the feeder information needed to calculate Control Performance Standard
limits and Frequency Bias Settings.
Requirement R1 achieves the first objective via FRS Form 1 and the process in Attachment A
that provides the method for determining the Interconnections’ necessary amount of Frequency
Response and allocating it to the Balancing Authorities.
31
Order No. 693 at P 357 (internal citations omitted).
15
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Each Frequency Response Sharing Group or Balancing Authority that is not a member of
a Frequency Response Sharing Group shall have evidence such as dated data plus documented
formula in either hardcopy or electronic format that it achieved an annual FRM (in accordance
with the methods specified by the ERO in Attachment A with data from FRS Form 1 reported to
the ERO as specified in Attachment A) that is equal to or more negative than its FRO to
demonstrate compliance with Requirement R1.
Consistent with the findings of the Frequency Response Initiative Report, BAL-003-1
does not judge compliance of Frequency Response performance on an event-by-event basis.
Analysis of data submitted by BAs during the field trial indicated that a single-event based
compliance measure is unsuitable for compliance evaluation when based on data that has the
large degree of variability demonstrated by the field trial. Analysis of data submitted by the BAs
during the field trial confirms that the sample size selected (a minimum of 20–25 frequency
events) is sufficient for stable results and alleviates the problem associated with outliers in the
measurement of BA Frequency Response performance.32
Requirement R1 and Attachment A satisfy the Commission’s directive in Order No. 693
(at P 375) to “determine the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other requirements of the Reliability Standard are met…” The
standard drafting team determined that an annual assessment would provide a sufficient sample
size of events of proper magnitudes to calculate Frequency Response with reasonable accuracy.33
The standard drafting team’s proposed methodology for determining each
Interconnection’s and BA’s obligation for obtaining the necessary amount of Frequency
Response is set forth in Attachment A. The contingency protection criterion is the largest
32
See Exhibit F, Frequency Response Initiative Report at p. 72.
Note, the Frequency Bias Setting process is an annual cycle and covers all seasons (there is variability
among the seasons).
33
16
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
reasonably expected contingency in the Interconnection and can be based on the largest observed
credible contingency in the previous ten years or the largest Category C event for the
Interconnection. Attachment A presents the base obligation by the Interconnection and adds a
reliability margin. The reliability margin addresses the difference between Points B and C and
accounts for other relevant variables as well. For multiple BA interconnections, the Frequency
Response Obligation is allocated to BAs based on size. This allocation is based on the formula
set forth in Attachment A to the proposed Reliability Standard.
FRS Form 1 and the underlying data retained by the BA will be used for measuring
whether Frequency Response was provided. FRS Form 1 provides the guidance as to how to
account for and measure Frequency Response. Therefore, the proposed Reliability Standard
defines the necessary amount of Frequency Response needed for reliable operation for each BA
with methods of obtaining and measuring that Frequency Response is achieved, in compliance
with Order No. 693.
2. Median as the Measure of Balancing Authority Performance
The standard drafting team evaluated different approaches for “averaging” individual
event observations to compute a technically sound estimate of Frequency Response Measure,
including the median and linear regression.
The MW contribution for a single BA in a multi-BA Interconnection is small compared
to the minute to minute changes in load, interchange and generation. For example, a 3000 MW
BA in the Eastern Interconnection may only be called on to contribute 10MW for the loss of a
1000 MW. The 10 MW of governor and load response may easily be masked by a coincident
change in load. In general, statisticians use the median as the best measure of central tendency
when a population has outliers. Based on the analyses performed thus far, the standard drafting
17
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
team believes that the median’s superior resiliency to this type of data quality problem makes it
the best aggregation technique at this time. However, the standard drafting team sees merit and
promise in future research with sample filtering combined with a technique such as linear
regression. When compared with the mean, linear regression shows superior performance with
respect to the elimination of noise because the measured data is weighted by the size of the
frequency change associated with the event.34 Since the noise is independent from frequency
change, the greater weighting on larger events provides a superior technique for reducing the
effect of noise on the results. The standard drafting team acknowledges that linear regression
should be re-evaluated for use in the BAL-003 Reliability Standard once more experience is
gained with data collected.35
3. BAL-003-1, Requirement R2
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency Bias Setting determined in
accordance with Attachment A, as validated by the ERO, into its Area Control Error
(ACE) calculation during the implementation period specified by the ERO and shall use
this Frequency Bias Setting until directed to change by the ERO. [Risk Factor: Medium
][Time Horizon: Operations Planning]
Attachment A is incorporated by reference into Requirement R2.36 Attachment A details the
process that the ERO will undertake to validate the BA’s FRS Form 1 data. Frequency Bias
Settings generally change very little from year-to-year.
34
The term “noise” refers to factors that can influence data and produce outliers such as concurrent operating
phenomena (discussed in the Background Document, Exhibit D), transient tie line flows for nearby contingencies,
data acquisition time skew in tie line data measurements and time skew and data compression issues.
35
As noted in Exhibit G, NERC and the Frequency Response Working Group will include an update of the
linear regression analysis from the Frequency Response Initiative Report during the annual review process
(described in Recommendation 14).
36
Any future modifications to Attachment A will be developed through the standard development process in
accordance with the NERC Standard Processes Manual.
18
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
The current BAL-003 Reliability Standard requires a minimum Frequency Bias Setting
equal in absolute value to one percent of the BA’s estimated yearly demand (or maximum
generation level if native load is not served) per tenth of a Hz change in frequency. For most
BA’s this calculated amount of Frequency Bias is significantly greater in absolute value than
their actual Frequency Response characteristic (which represents an over-bias condition)
resulting in over-control.
The ideal system control state exists when the Frequency Bias Setting of the BA exactly
matches the Frequency Response characteristics of the BA. Setting the Frequency Bias to better
approximate the BA natural response characteristic will improve the quality of ACE control and
general AGC System control response. The Procedure for ERO Support of Frequency Response
and Frequency Bias Setting Standard is intended to bring the BA’s Frequency Bias Setting
closer to their natural Frequency Response characteristic.
The proposed annual process is as follows:
1. The ERO posts the official list of frequency events to be used for BAL-003-1 in early
December. The FRS Form 1 for each Interconnection will be posted shortly thereafter.
2.
The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3.
The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, the ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which to
implement revised Frequency Bias Setting values. Implementation typically would be on
or about March 1st of each year.
The ERO, in coordination with the regions of each Interconnection, will annually review
Frequency Bias Setting data submitted by BAs.
19
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
4. BAL-003-1, Requirement R3
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/- 0.036 Hz.
In multiple BA interconnections, the Frequency Bias Setting should be coordinated
among all BAs in the interconnection. When there is a minimum Frequency Bias Setting
requirement, it should apply for all BAs. However, BAs using a variable Frequency Bias Setting
may have non-linearity in their actual response for a number of reasons including the dead-bands
implemented on their generator governors. The measurement to ensure that these BAs are
conforming to the interconnection minimum is adjusted to remove the dead-band range from the
calculated average Frequency Bias Setting actually used. For BAs using variable bias, FRS
Form 1 has a data entry location for the previous year’s average monthly Bias. The BA and the
ERO can compare this value to the previous year’s Frequency Bias Setting minimum to ensure
Requirement R3 has been met.
On single BA Interconnections, there is no need to coordinate the Frequency Bias Setting
with other BAs. This eliminates the need to maintain a minimum Frequency Bias Setting for any
reason other than meeting the reliability requirement as specified by the Frequency Response
Obligation.
20
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
5. BAL-003-1, Requirement R4
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias
Setting for the combined Balancing Authority Area, to be equivalent to either: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS Form
2 for the participating Balancing Authorities as validated by the ERO, or
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
Requirement R4 reflects the principles first established by NERC Policy 137 and is
similar to Requirement R6 in the existing BAL-003.1b Reliability Standard.38 Overlap
Regulation Service is a method of providing regulation service in which the BA providing the
regulation service incorporates another BA’s actual interchange, frequency response, and
schedules into the providing BA’s AGC/ACE equation. A BA that is providing Overlap
Regulation will report the sum of the Bias Settings in its FRS Form 1. A BA that is receiving
Overlap Regulation Service has an ACE and Frequency Bias Setting equal to zero.
C. Enforceability of the Proposed Reliability Standard
The Proposed BAL-003-1 Reliability Standard includes VRFs and VSLs which is an
equally effective and efficient method of satisfying the Commission’s directive in Order No. 693
(at P 375) to “include[] Levels of Non-Compliance…” The proposed BAL-003-1 Reliability
Standard contains Measures that support each Requirement by clearly identifying what is
required and how the Requirement will be enforced. The VSLs provide further guidance on the
way that NERC will enforce the Requirements of the proposed Reliability Standard. The VRFs
37
Prior to the establishment of mandatory and enforceable Reliability Standards, NERC Operating Policies
existed, including Policy 1 - Generation Control and Performance.
38
Reliability Standard BAL-003.1b, R6. A Balancing Authority that is performing Overlap Regulation
Service shall increase its Frequency Bias Setting to match the frequency response of the entire area being controlled.
A Balancing Authority shall not change its Frequency Bias Setting when performing Supplemental Regulation
Service.
21
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
and VSLs for the proposed BAL-003-1 Reliability Standard comport with NERC and the
Commission guidelines related to their assignment. For a detailed review of the VRFs, the
VSLs, and the analysis of how the VRFs and VSLs were determined using these guidelines, see
Exhibit J.
22
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
V.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:
approve the proposed Reliability Standard, definitions and associated elements
included in Exhibit B, effective as proposed herein;
approve the implementation plan included in Exhibit D; and
approve the retirement of Reliability Standards, effective as proposed herein.
Respectfully submitted,
/s/ Stacey Tyrewala
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595– facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
Stacey Tyrewala
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
March 29, 2013
23
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all parties
listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 29th day of March, 2013.
/s/ Stacey Tyrewala
Stacey Tyrewala
Attorney for North American Electric
Reliability Corporation
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000001
Exhibit A
Order No. 672 Criteria
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000002
EXHIBIT A – Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672,1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
The proposed standard achieves the specific reliability goal of ensuring that the
Interconnections have sufficient Frequency Response to guard against underfrequency load
shedding (“UFLS”) due to an event in that Interconnection. The proposed Reliability Standard
ensures that Balancing Authorities provide Frequency Response necessary to ensure that the
frequency does not reach the point where coordinated UFLS relays are set to curtail loads. This
is accomplished through a measurement methodology that ensures consistency across the
industry for both frequency response and Frequency Bias Setting calculations.
11
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment,
Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order
on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls within the
requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power System
facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such facilities
include all those necessary for operating an interconnected electric energy transmission network, or any portion of
that network, including control systems. The proposed Reliability Standard may apply to any design of planned
additions or modifications of such facilities that is necessary to provide for reliable operation. It may also apply to
Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve this goal. Although any person may propose a topic for a
Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should be
developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000003
EXHIBIT A – Order No. 672 Criteria
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what is
required and who is required to comply.3
The proposed revisions to this Reliability Standard apply to Balancing Authorities and
Frequency Response Sharing Groups and are clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. The requirements clearly state
who is required to comply with the standard. In addition, the standard includes an Attachment A
and a Background Document. Attachment A provides the methodology used to determine the
metrics for compliance. The Background Document, included as Exhibit D, provides
information describing how the requirements and metrics were determined and details what the
requirements are designed to accomplish.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a violation.4
The VRFs and VSLs for the proposed standard comport with NERC and Commission
guidelines related to their assignment. The assignment of the severity level for each VSL is
consistent with the corresponding Requirement and the VSLs should ensure uniformity and
consistency in the determination of penalties. The VSLs do not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar penalties for
similar violations. For these reasons, the proposed Reliability Standard includes clear and
understandable consequences in accordance with Order No. 672.
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner, or
operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding what is
required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know what
they are required to do to maintain reliability.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000004
EXHIBIT A – Order No. 672 Criteria
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non-preferential
manner. 5
The proposed Reliability Standard contains measures that support each requirement by
clearly identifying what is required and how the requirement will be enforced. These measures
help provide clarity regarding how the requirements will be enforced, and ensure that the
requirements will be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard to
implementation cost or historical regional infrastructure design.6
The proposed Reliability Standard achieves its reliability goals effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard was developed by the
Standard Drafting Team after NERC staff and the Standard Drafting team completed significant
studies related to Frequency Response. These studies helped determine the level of response
needed in each of the four Interconnections that are subject to compliance with NERC standards.
Based on the results of these studies, the proposed Reliability Standard addresses the amount of
Frequency Response needed in each Interconnection that is required to obtain an adequate level
or reliability. It then goes on to address the process to determine an appropriate Frequency Bias
Setting for each Balancing Authority within those Interconnections, balancing the desire to have
sustained response to frequency events and the desire to avoid excess regulation due to small
frequency changes.
5
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance with a
proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so that it
can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000005
EXHIBIT A – Order No. 672 Criteria
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for smaller
entities, but not at consequences of less than excellence in operating system reliability.7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed standard represents a significant improvement over the
previous version as described herein.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while not
favoring one geographic area or regional model. It should take into account regional
variations in the organization and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional
variations in market design if these affect the proposed Reliability Standard.8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model. The proposed Reliability Standard clearly addresses
differences across the Interconnections by setting an Interconnection Frequency Response
Obligation for each based on the size of the Interconnection as well as the resources located
within that Interconnection. Since the corporate structure of the Balancing Authorities does not
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the ERO’s
Reliability Standard development process based on the least effective North American practice — the so-called
“lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that must
comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000006
EXHIBIT A – Order No. 672 Criteria
cause the reliability needs to change, the proposed Reliability Standard does not differentiate
between the regional market designs found in an Interconnection. It simply and clearly states the
performance required from each Balancing Authority within an Interconnection and allows each
applicable entity the flexibility to address their needs as appropriate. This model provides a
performance requirement without mandating how each individual entity must comply.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for reliability.9
The proposed Reliability Standard does not restrict the available transmission capability or
limit use of the bulk-power system in a preferential manner.
9. The implementation time for the proposed Reliability Standard is reasonable.10
The proposed effective dates for the standard are just and reasonable and appropriately
balance the urgency in the need to implement the standards against the reasonableness of the
time allowed for those who must comply to develop necessary procedures, software, facilities,
staffing or other relevant capability.
This will allow applicable entities adequate time to ensure compliance with the requirements.
The proposed effective dates are explained in the proposed Implementation Plan, attached as
Exhibit E.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.11
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to the effect
of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed Reliability
Standard that has no undue negative effect on competition. Among other possible considerations, a proposed
Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power System
beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly
preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable, FERC
will consider also the timetable for implementation of the new requirements, including how the proposal balances
any urgency in the need to implement it against the reasonableness of the time allowed for those who must comply
to develop the necessary procedures, software, facilities, staffing or other relevant capability.
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal standard
of review, we will entertain comments about whether the ERO implemented its Commission-approved Reliability
Standard development process for the development of the particular proposed Reliability Standard in a proper
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000007
EXHIBIT A – Order No. 672 Criteria
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit K includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the drafting team were
properly noticed and open to the public. The initial and recirculation ballots both achieved a
quorum and exceeded the required ballot pool approval levels.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of
this proposed Reliability Standard. No comments were received that indicated the proposed
standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors.13
No other negative factors relevant to whether the proposed Reliability Standard is just
and reasonable were identified.
manner, especially whether the process was open and fair. However, we caution that we will not be sympathetic to
arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s Reliability Standard
development process if it is conducted in good faith in accordance with the procedures approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability Standard
may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we will
consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000008
Exhibit B
Proposed Reliability Standard Submitted for Approval
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000009
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority (BA) to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to its scheduled
value. To provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.1.1
The Balancing Authority is the responsible entity unless the Balancing
Authority is a member of a Frequency Response Sharing Group, in which
case, the Frequency Response Sharing Group becomes the responsible
entity.
1.2. Frequency Response Sharing Group
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, R3 and
R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as
calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a FRSG
to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time
Horizon: Real-time Operations]
Page 1 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000010
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency Bias Setting determined in
accordance with Attachment A, as validated by the ERO, into its Area Control Error
(ACE) calculation during the implementation period specified by the ERO and shall
use this Frequency Bias Setting until directed to change by the ERO. [Risk Factor:
Medium ][Time Horizon: Operations Planning]
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
1.1 Less than zero at all times, and
1.2 Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/- 0.036 Hz.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation, in order to represent the Frequency
Bias Setting for the combined Balancing Authority Area, to be equivalent to either:
[Risk Factor: Medium ][Time Horizon: Operations Planning]
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS
Form 2 for the participating Balancing Authorities as validated by the ERO, or
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
C. Measures
M1. Each Frequency Response Sharing Group or Balancing Authority that is not a member
of a Frequency Response Sharing Group shall have evidence such as dated data plus
documented formula in either hardcopy or electronic format that it achieved an annual
FRM (in accordance with the methods specified by the ERO in Attachment A with data
from FRS Form 1 reported to the ERO as specified in Attachment A) that is equal to or
more negative than its FRO to demonstrate compliance with Requirement R1.
M2. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service shall have evidence
such as a dated document in hard copy or electronic format showing the ERO validated
Frequency Bias Setting was implemented into its ACE calculation within the
implementation period specified or other evidence to demonstrate compliance with
Requirement R2.
M3. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and is utilizing variable
Frequency Bias shall have evidence such as a dated report in hard copy or electronic
format showing the average clock-minute average Frequency Bias Setting was less
than zero and during periods when the clock-minute average frequency was outside of
Page 2 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000011
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
the range 59.964 Hz to 60.036 Hz was equal to or more negative than its Frequency
Response Obligation to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation as
specified in Requirement R4 to demonstrate compliance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3 and R4, Measures M1, M2, M3 and M4 for the current
year plus the previous three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Frequency Response Sharing Group shall retain data or evidence to show
compliance with Requirement R1 and Measure M1 for the current year plus the
previous three calendar years unless directed by its Compliance Enforcement
Page 3 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000012
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority or Frequency Response Sharing Group is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and flat frequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Page 4 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000013
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
R3
R4
Service and uses a
fixed Frequency
Bias Setting failed to
implement the
validated Frequency
Bias Setting value
into its ACE
calculation within
the implementation
period specified but
did so within 5
calendar days from
the implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting did not
implement the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 25 calendar
days from the
implementation
period specified by
the ERO.
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
is not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 1% but by at
most 10%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 10% but by at
most 20%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 20% but by at
most 30%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
obligation by more
than 30%..
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Page 5 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000014
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Overlap Regulation
Services with
combined footprint
setting-error less
than or equal to 10%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 10% but less
than or equal to 20%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 20% but less
than or equal to 30%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 30% of the
validated or
calculated value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
E. Regional Variance
None
F. Associated Documents
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Errata
0
March 16, 2007
Removed "Proposed" from
Effective Date
FERC Approval — Order 693
0a
December 19,
2007
Added Appendix 1
Interpretation of R3 approved
by BOT on October 23, 2007
Addition
0a
July 21, 2008
FERC Approval of
Interpretation of R3
Addition
New
Page 6 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000015
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
February 12,
2008
Addition
Added Appendix 2
Interpretation of R2, R2.2, R5,
and R5.1 approved by BOT on
February 12, 2008
0.1b
January 16, 2008
Section F: added “1.”;
changed hyphen to “en dash.”
Changed font style for
“Appendix 1” to Arial;
updated version number to
“0.1b”
Errata
0.1b
October 29,
2008
BOT approved errata changes
Errata
0.1a
May 13, 2009
FERC Approved errata
changes – version changed to
0.1a (Interpretation of R2,
R2.2, R5, and R5.1 not yet
approved)
Errata
0.1b
May 21, 2009
FERC Approved
Interpretation of R2, R2.2, R5,
and R5.1
Addition
0b
1
February 7, 2013 Adopted by NERC Board of
Trustees
Complete Revision under
Project 2007-12
Page 7 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000016
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Attachment A
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Supporting Document
Interconnection Frequency Response Obligation (IFRO)
The ERO, in consultation with regional representatives, has established a target contingency protection
criterion for each Interconnection called the Interconnection Frequency Response Obligation (IFRO).
The default IFRO listed in Table 1 is based on the resource contingency criteria (RCC), which is the largest
category C (N‐2) event identified except for the Eastern Interconnection, which uses the largest event in
the last 10 years. A maximum delta frequency (MDF) is calculated by adjusting a starting frequency for
each Interconnection by the following:
Prevailing UFLS first step
CCAdj which is the adjustment for the differences between 1‐second and sub‐second Point C
observations for frequency events. A positive value indicates that the sub‐second C data is
lower than the 1‐second data
CBR which is the statistically determined ratio of the Point C to Value B
BC’Adj which is the statistically determined adjustment for the event nadir being below the Value
B (Eastern Interconnection only) during primary frequency response withdrawal.
The IFRO for each Interconnection in Table 1 is then calculated by dividing the RCC MWs by 10 times the
MDF. In the Eastern Interconnection there is an additional adjustment (BC’Adj) for the event nadir being
below the Value B due to primary frequency response withdrawal. This IFRO includes uncertainty
adjustments at a 95 % confidence level. Detailed descriptions of the calculations used in Table 1 below
are defined in the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard.
Interconnection
Starting Frequency (FStart)
Prevailing UFLS First Step
Base Delta Frequency (DFBase)
CCADJ
Delta Frequency (DFCC)
CBR
Delta Frequency (DFCBR)
BC’ADJ
Max. Delta Frequency (MDF)
Resource Contingency Criteria
(RCC)
Credit for Load Resources
(CLR)
IFRO
Eastern
59.974
59.5*
0.474
0.007
0.467
1.000
0.467
0.018
0.449
Western
59.976
59.5
0.476
0.004
0.472
1.625
0.291
N/A
0.291
ERCOT
59.963
59.3
0.663
0.012
0.651
1.377
0.473
N/A
0.473
HQ
59.972
58.5
1.472
N/A
1.472
1.550
0.949
N/A
0.949
4,500
2,740
2,750
1,700
300
‐840
1,400**
‐286
‐1,002
‐179
Units
Hz
Hz
Hz
Hz
Hz
Hz
Hz
MW
MW
MW/0.1 Hz
Table 1: Interconnection Frequency Response Obligations
Page 8 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000017
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
*The Eastern Interconnection UFLS set point listed is a compromise value set midway between
the stable frequency minimum established in PRC‐006‐1 (59.3 Hz) and the local protection UFLS
setting of 59.7 Hz used in Florida and Manitoba.
**In the Base Obligation measure for ERCOT, 1400 MW (Load Resources triggered by Under
Frequency Relays at 59.70 Hz) was reduced from its Resource Contingency Criteria level of 2750
MW to get 239 MW/0.1 Hz. This was reduced to accurately account for designed response from
Load Resources within 30 cycles.
An Interconnection may propose alternate IFRO protection criteria to the ERO by submitting a SAR with
supporting technical documentation.
Balancing Authority Frequency Response Obligation (FRO) and Frequency Bias
Setting
The ERO will manage the administrative procedure for annually assigning an FRO and implementation of
the Frequency Bias Setting for each Balancing Authority. The annual timeline for all activities described
in this section are shown below.
For a multiple Balancing Authority interconnection, the Interconnection Frequency Response Obligation
shown in Table 1 is allocated based on the Balancing Authority annual load and annual generation. The
FRO allocation will be based on the following method:
FROBA
IFRO
Annual GenBA
Annual GenI
Annual LoadBA
Annual LoadI
Where:
Annual GenBA is the total annual “Output of Generating Plants” within the Balancing Authority
Area (BAA), on FERC Form 714, column c of Part II ‐ Schedule 3.
Annual LoadBA is total annual Load within the BAA, on FERC Form 714, column e of Part II ‐
Schedule 3.
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
The data used for this calculation is from the most recently filed Form 714. As an example, a report to
NERC in January 2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to assemble
and submit equivalent data to the ERO for use in the FRO Allocation process.
Balancing Authorities that elect to form a FRSG will calculate a FRSG FRO by adding together the
individual BA FRO’s.
Balancing Authorities that elect to form a FRSG as a means to jointly meet the FRO will calculate their
FRM performance one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a
single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that contains the sum
of each participant’s individual event performance.
Page 9 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000018
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Balancing Authorities that merge or that transfer load or generation are encouraged to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation to the
Interconnection remains the same and so that CPS limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM), Frequency
Bias Setting and Frequency Bias type (fixed or variable) to the ERO each year to allow the ERO to validate
the revised Frequency Bias Settings on FRS Form 1. If the ERO posts the official list of events after the
date specified in the timeline below, Balancing Authorities will be given 30 days from the date the ERO
posts the official list of events to submit their FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing Authorities,
the ERO will use FRS Form 1 data to post the following information for each Balancing Authority for the
upcoming year:
Frequency Bias Setting
Frequency Response Obligation (FRO)
Once the data listed above is fully posted, the ERO will announce the three‐day implementation period
for changing the Frequency Bias Setting if it differs from that shown in the timeline below.
A BA using a fixed Frequency Bias Setting sets its Frequency Bias Setting to the greater of (in absolute
value):
Any number the BA chooses between 100% and 125% of its Frequency Response Measure as
calculated on FRS Form 1
Interconnection Minimum as determined by the ERO
For purposes of calculating the minimum Frequency Bias Setting, a Balancing Authority participating in a
Frequency Response Sharing Group will need to calculate its stand‐alone Frequency Response Measure
using FRS Form 1 and FRS Form 2 to determine its minimum Frequency Bias Setting.
A Balancing Authority providing Overlap Regulation will report the historic peak demand and generation
of its combined BAs’ areas on FRS Form 1 as described in Requirement R4.
There are occasions when changes are needed to Bias Settings outside of the normal schedule.
Examples are footprint changes between Balancing Authorities and major changes in load or generation
or the formation of new Balancing Authorities. In such cases the changing Balancing Authorities will
work with their Regions, NERC and the Resources Subcommittee to confirm appropriate changes to Bias
Settings, FRO, CPS limits and Inadvertent Interchange balances.
If there is no net change to the Interconnection total Bias, the Balancing Authorities involved will agree
on a date to implement their respective change in Bias Settings. The Balancing Authorities and ERO will
also agree to the allocation of FRO such that the sum remains the same.
If there is a net change to the Interconnection total Bias, this will cause a change in CPS2 limits and FRO
for other Balancing Authorities in the Interconnection. In this case, the ERO will notify the impacted
Balancing Authorities of their respective changes and provide an implementation window for making
the Bias Setting changes.
Frequency Response Measure (FRM)
The Balancing Authority will calculate its FRM from Single Event Frequency Response Data (SEFRD),
defined as: “the data from an individual event from a Balancing Authority that is used to calculate its
Page 10 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000019
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Frequency Response, expressed in MW/0.1Hz” as calculated on FRS Form 2 for each event shown on FRS
Form 1. The events in FRS Form 1 are selected by the ERO using the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change in its Net Actual
Interchange on its tie lines with its adjacent Balancing Authorities divided by the change in
Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to their Net
Actual Interchange (NAI) values to account for factors such as nonconforming loads. FRS Form 1 and 2
shows the types of adjustments that are allowed. Note that with the exception of the Contingent BA
column, any adjustments made must be made for all events in an evaluation year. As an example, if an
entity has non‐conforming loads and makes an adjustment for one event, all events must show the non‐
conforming load, even if the non‐conforming load does not impact the calculation. This ensures that the
reports are not utilizing the adjustments only when they are favorable to the BA.) The ERO will use a
standardized sampling interval of approximately 16 seconds before the event up to the time of the
event for the pre‐event NAI, and frequency (A values) and approximately 20 to 52 seconds after the
event for the post‐event NAI (B values) in the computation of SEFRD values, dependent on the data scan
rate of the Balancing Authority’s Energy Management System (EMS).
All events listed on FRS Form 1 need to be included in the annual submission of FRS Forms 1 and 2. The
only time a Balancing Authority should exclude an event is if its tie‐line data or its Frequency data is
corrupt or its EMS was unavailable. FRS Form 2 has instructions on how to correct the BA’s data if the
given event is internal to the BA or if other authorized adjustments are used.
Assuming data entry is correct FRS Form 1 will automatically calculate the Balancing Authority’s FRM for
the past 12 months as the median of the SEFRD values. A Balancing Authority electing to report as an
FRSG or a provider of Overlap Regulation Service will provide an FRS Form 1 for the aggregate of its
participants.
To allow Balancing authorities to plan its operations, events with a “Point C” that cause the
Interconnection Frequency to be lower than that shown in Table 1 above (for example, an event in the
Eastern Interconnection that causes the Interconnection Frequency to go to 59.4 Hz) or higher than an
equal change in frequency going above 60 Hz may be included in the list of events for that
interconnection. However, the calculation of the BA response to such an event will be adjusted to show
a frequency change only to the Target Minimum Frequency shown in Table 1 above (in the previous
example this adjustment would cause Frequency to be shown as 59.5 Hz rather than 59.4 HZ) or a high
frequency amount of an equal quantity. Should such an event happen, the ERO will provide additional
guidance.
Timeline for Balancing Authority Frequency Response and Frequency Bias Setting
Activities
Described below is the timeline for the exchange of information between the ERO and Balancing
Authorities (BA) to:
Facilitate the assignment of BA Frequency Response Obligations (FRO)
Calculate BA Frequency Response Measures (FRM)
Determine BA Frequency Bias Settings (FBS)
Page 11 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000020
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Target Date
Activity
April 30
The ERO reviews candidate frequency events and selects frequency events for the
first quarter (December to February).
May 10
Form1 is posted with selected events from the first quarter for BA usage by the
ERO.
May 15
The BAs receive a request to provide load and generation data as described in
Attachment A to support FRO assignments and determining minimum FBS for
BAs.
July 15
The BAs provide load and generation data as described in Attachment A to the
ERO.
July 30
The ERO reviews candidate frequency events and selects frequency events for the
second quarter (March to May).
August 10
Form1 is posted with selected events from the first and second quarters for BA
usage by the ERO.
October 30
The ERO reviews candidate frequency events and selects frequency events for the
third quarter (June to August)
November 10
Form1 is posted with selected events from the first, second, and third quarters for
BA usage by the ERO.
November 20
If necessary, the ERO provides any updates to the necessary Frequency Response.
November 20
The ERO provides the fractional responsibility of each BA for the Interconnection’s
FRO and Minimum FBS to the BAs.
January 30
The ERO reviews candidate frequency events and selects frequency events for the
fourth quarter (September to November).
2nd business day in
February
Form1 is posted with all selected events for the year for BA usage by the ERO.
February 10
The ERO assigns FRO values to the BAs for the upcoming year.
March 7
BAs complete their frequency response sampling for all four quarters and their
FBS calculation, returning the results to the ERO.
March 24
The ERO validates FBS values, computes the sum of all FBS values for each
Interconnection, and determines L10 values for the CPS 2 criterion for each BA as
applicable.
Any time during
first 3 business
days of April
(unless specified
otherwise by the
ERO)
The BA implements any changes to their FBS and L10 value.
Page 12 of 12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000021
Exhibit C
Procedure for ERO Support of Frequency Response and
Frequency Bias Setting Standard
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000022
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
This procedure outlines the Electric Reliability Organization (ERO) process for supporting the Frequency
Response Standard (FRS). A Procedure revision request may be submitted to the ERO for consideration.
The revision request must provide a technical justification for the suggested modification. The ERO shall
post the suggested modification for a 45-day formal comment period and discuss the revision request in
a public meeting. The ERO will make a recommendation to the NERC BOT, which may adopt the revision
request, reject it, or adopt it with modifications. Any approved revision to this Procedure shall be filed
with FERC for informational purposes.
Event Selection Process
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of
frequency events to be used by Balancing Authorities (BA) to calculate their Frequency Response to
determine:
•
•
Whether the BA met its Frequency Response Obligation, and
An appropriate fixed Bias Setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for analysis. The
events that best fit the criteria will be used to support the FRS. The evaluation period for
performing the annual Frequency Bias Setting and the Frequency Response Measure (FRM)
calculation is December 1 of the prior year through November 30 of the current year.
2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating
the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion
events in a 12 month evaluation period satisfying the criteria below, then similar acceptable
events from the subsequent year’s evaluation period will be included with the data set by the
ERO for determining FRS compliance. This is described later.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the
FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C and
the arrested frequency Point C exceeds the excursion threshold values specified for the
Interconnection in Table 1 below.
i. The A Value is computed as an average over the period from -16 seconds to 0
seconds before the frequency transient begins to decline.
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
November 30, 2012
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000023
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection
East
West
ERCOT
HQ
A Value
to Pt C
0.04Hz
0.07Hz
0.15Hz
0.30Hz
Point C (Low)
< 59.96
< 59.95
< 59.90
< 59.85
Point C (High)
> 60.04
> 60.05
> 60.10
> 60.15
Table 1: Interconnection Frequency Excursion Threshold Values
b. The time from the start of the rapid change in frequency until the point at which
Frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not be
included.
4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The
A Value is computed as an average over the period from -16 seconds to 0 seconds before the
frequency transient begins to decline. For example, given the choice of the two events below,
the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60
Hz.
5. Excursions that include 2 or more events that do not stabilize within 18 seconds will not be
considered.
6. Frequency excursion events occurring during periods:
(i) when large interchange schedule ramping or load change is happening, or
(ii) within 5 minutes of the top of the hour,
November 30, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000024
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
will be excluded from consideration if other acceptable frequency excursion events from the
same quarter are available.
7. The ERO will select the largest (A Value to Point C) 2 or 3 frequency excursion events occurring
each month. If there are not 2 frequency excursion events satisfying the selection criteria in a
month, then other frequency excursion events should be picked in the following sequence:
a. From the same event quarter of the year.
b. From an adjacent month.
c. From a similar load season in the year (shoulder vs. summer/winter)
d. The largest unused event.
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable
events from the next year’s evaluation period will be included with the data set by the ERO for
determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be
reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a
24 month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation. The
ERO will post the final list of frequency excursion events used for standard compliance as specified in
Attachment A of BAL-003-1. The following is a general description of the process that the ERO will use
to ensure that BAs can evaluate events during the year in order to monitor their performance
throughout the year.
Monthly
Candidate events will be initially screened by the "Frequency Event Detection Methodology" shown on
the following link located on the NERC Resources Subcommittee area of the NERC website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oct_2011.p
df. Each month's list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under "Candidate Frequency Events".
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
•
•
•
•
December through February
March through May
June through August
September through November
November 30, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000025
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Based on criteria established in the "Procedure for ERO Support of Frequency Response and Frequency
Bias Setting Standard", events will be selected to populate the FRS Form 1 for each Interconnection.
The Form 1's will be posted on the NERC website, in the Resources Subcommittee area under the title
"Frequency Response Standard Resources". Updated Form 1's will be posted at the end of each quarter
listed above after a review by the NERC RS' Frequency Working Group. While the events on this list are
expected to be final, as outlined in the selection criteria, additional events may be considered, if the
number of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the
year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters
listed above, will be posted as specified in Attachment A. Each Balancing Authority reports its previous
year’s Frequency Response Measure (FRM), Frequency Bias Setting and Frequency Bias type (fixed or
variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for
errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in
Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility in when
each BA implements its settings.
November 30, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000026
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Process for Adjusting Interconnection Minimum Frequency Bias Setting
This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to
better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance
with this procedure.
The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other
balancing standard limits.
Under BAL-003-1, the minimum Frequency Bias Settings will be moved toward the natural Frequency
Response in each interconnection. In the first year, the minimum Frequency Bias Setting for each
interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is
based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714
Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table
2 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum
Frequency Bias Setting is allocated among the BAs on an interconnection using the same allocation
method as is used for the allocation of the Frequency Response Obligation (FRO).
Interconnection
Eastern
Western
ERCOT*
HQ*
Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)
0.9% of non-coincident peak load
0.9% of non-coincident peak load
N/A
N/A
Table 2. Frequency Bias Setting Minimums
*The minimum Frequency Bias Setting requirement does not apply to a Balancing Authority that
is the only Balancing Authority in its Interconnection. These Balancing Authorities are solely
responsible for providing reliable frequency control of their Interconnection. These Balancing
Authorities are responsible for converting frequency error into a megawatt error to provide
reliable frequency control, and the imposition of a minimum bias setting greater than the
magnitude the Frequency Response Obligation may have the potential to cause control system
hunting, and instability in the extreme.
The ERO, in coordination with the regions of each interconnection, will annually review Frequency Bias
Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds
(in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value)
than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting
for BAs within that Interconnection may be reduced (in absolute value) in the subsequent years FRS
Form 1 based on the technical evaluation and consultation with the regions affected by 0.1 percentage
point of peak load (expressed in MW/0.1Hz) to better match that Frequency Bias Setting and natural
Frequency Response.
November 30, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000027
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
The ERO, in coordination with the regions of each Interconnection, will monitor the impact of the
reduction of minimum frequency bias settings, if any, on frequency performance, control performance,
and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish postcontingency restoration of frequency to schedule or control performance problems occur, then the prior
reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction
based on the criterion stated above may not be implemented.
November 30, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000028
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection Frequency Response Obligation Methodology
This procedure outlines the process the ERO is to use for determining the Interconnection Frequency
Response Obligation (IFRO).
The following are the formulae that comprise the calculation of the IFROs.
10
Where:
•
•
•
•
•
•
•
•
•
•
•
•
•
DFBase is the base delta frequency.
FStart is the starting frequency determined by the statistical analysis.
UFLS is the highest UFLS trip setpoint for the interconnection.
CCAdj is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data.
DFCC is the delta frequency adjusted for the differences between 1-second and sub-second Point
C observations for frequency events.
CBR is the statistically determined ratio of the Point C to Value B.
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
BC’ADJ is the statistically determined adjustment for the event nadir being below the Value B
(Eastern Interconnection only) during primary frequency response withdrawal.
MDF is the maximum allowable delta frequency.
RCC is the resource contingency criteria.
CLR is the credit for load resources.
ARCC is the adjusted resource contingency criteria adjusted for the credit for load resources.
IFRO is the interconnection frequency response obligation.
November 30, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000029
Exhibit D
Frequency Response Standard Background Document
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000030
Frequency Response
Standard Background
Document
November, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000031
Table of Contents
Table of Contents ............................................................................................................................ 1
Introduction .................................................................................................................................... 2
Background ..................................................................................................................................... 2
Rationale by Requirement ............................................................................................................ 22
Requirement 1 ...................................................................................................................... 22
Background and Rationale .................................................................................................... 22
Requirement 2 ...................................................................................................................... 32
Background and Rationale .................................................................................................... 32
Requirement 3 ...................................................................................................................... 34
Requirement 4 ...................................................................................................................... 34
Background and Rationale .................................................................................................... 35
How this Standard Meets the FERC Order No. 693 Directives ..................................................... 36
FERC Directive ........................................................................................................................... 36
1. Levels of Non‐Compliance ................................................................................................. 36
2. Determine the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other Requirements of the Reliability Standard are met ... 36
3. Define the necessary amount of Frequency Response needed for Reliable Operation for
each Balancing Authority with methods of obtaining and measuring that the frequency
response is achieved ................................................................................................................. 36
Necessary Amount of Frequency Response ......................................................................... 36
Methods of Obtaining Frequency Response ........................................................................ 37
Measuring that the Frequency Response is Achieved .......................................................... 37
Going Beyond the Directive ...................................................................................................... 38
Good Practices and Tools .............................................................................................................. 39
Background ............................................................................................................................... 39
Identifying and Estimating Frequency Responsive Reserves ................................................... 39
Using FRS Form 1 Data .............................................................................................................. 40
Tools .......................................................................................................................................... 40
1
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000032
Introduction
This document provides background on the development, testing and implementation of BAL‐
003‐1 ‐ Frequency Response Standard (“FRS”).1 The intent is to explain the rationale and
considerations for the Requirements of this standard and their associated compliance
information. The document also provides good practices and tips for Balancing Authorities
(“BAs”) with regard to Frequency Response.
In Order No. 693, the Federal Energy Regulatory Commission (“FERC” or the “Commission”)
directed additional changes to BAL‐003.2 This document explains how compliance with those
directives are met by BAL‐003‐1.
The original Standards Authorization Request (“SAR”), finalized on June 30, 2007, assumed
there was adequate Frequency Response in all the North American Interconnections. The goal
of the SAR was to update the Standard to make the measurement process of frequency
response more objective and to provide this objective data to Planners and Operators for
improved modeling. The updated models will improve understanding of the trends in
Frequency Response to determine if reliability limits are being approached. The Standard
would also lay the process groundwork for a transition to a performance‐based Standard if
reliability limits are approached.
This document will be periodically updated by the FRS Drafting Team (“FRSDT”) until the
Standard is approved. Once approved, this document will then be maintained and updated by
the ERO and the NERC Resources Subcommittee to be used as a reference and training
resource.
Background
This section discusses the different components of frequency control and the individual
components of Primary Frequency Control also known as Frequency Response.
Frequency Control
Most system operators generally have a good understanding of frequency control and Bias
Setting as outlined in the balancing standards and the references to them in the NERC
Operating Manual. Frequency control can be divided into four overlapping windows of time as
outlined below.
Primary Frequency Control (Frequency Response) – Actions provided by the
Interconnection to arrest and stabilize frequency in response to frequency deviations.
1
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of Terms Used in NERC Reliability
2
Mandatory Reliability Standards for the Bulk‐Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 368‐375, order on reh’g, Order
Standards, available here: http://www.nerc.com/files/Glossary_of_Terms.pdf.
No. 693‐A, 120 FERC ¶ 61,053 (2007).
2
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000033
Primary Control comes from automatic generator governor response (also known as speed
regulation), load response (typically from motors), and other devices that provide an
immediate response based on local (device‐level) control systems.
Secondary Frequency Control – Actions provided by an individual BA or its Reserve Sharing
Group to correct the resource – load unbalance that created the original frequency
deviation, which will restore both Scheduled Frequency and Primary Frequency Response.
Secondary Control comes from either manual or automated dispatch from a centralized
control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced basis
that are coordinated so there is a net zero effect on Area Control Error (ACE). Examples of
Tertiary Control include dispatching generation to serve native load; economic dispatch;
dispatching generation to affect Interchange; and re‐dispatching generation. Tertiary
Control actions are intended to replace Secondary Control Response by reconfiguring
reserves.
Time Control includes small offsets to scheduled frequency to keep long term average
frequency at 60 Hz.
Primary Frequency Control – Frequency Response
Primary Frequency Control, also known generally as Frequency Response, is the first stage of
overall frequency control and is the response of resources and load to a locally sensed change
in frequency in order to arrest that change in frequency. Frequency Response is automatic, not
driven by any centralized system, and begins within seconds rather than minutes. Different
resources, loads, and systems provide Frequency Response with different response times,
based on current system conditions such as total resource/load and their respective mix.
The proposed NERC Glossary of Terms defines Frequency Response as:
(Equipment) The immediate and automatic reaction or response of power from a
system or power from elements of the system to a change in locally sensed system
frequency.
(System) The sum of the change in demand, and the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).
As noted above, Frequency Response is the characteristic of load and generation within
Balancing Authorities and Interconnections. It reacts or responds with changes in power to
attempted changes in load‐resource balance that result in changes to system frequency.
Because the loss of a large generator is much more likely than a sudden loss of an equivalent
amount of load, Frequency Response is typically discussed in the context of a loss of a large
generator. Included within Frequency Response are many components of that response.
Understanding Frequency Response and the FRS requires an understanding of each of these
components and how they relate to each other.
3
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000034
Frequency Response Illustration
The following simple example is presented to illustrate the components of Frequency Response
in graphical form. It includes a series of seven graphs that illustrate the various components of
Frequency Response and a brief discussion of each describing how these components react to
attempted changes in the load‐resource balance and resulting changes in system frequency.
The illustration is based on an assumed Disturbance event of the sudden loss of 1000 MW of
generation. Although a large event is used to illustrate the response components, even small
frequently occurring events will result in similar reactions or responses. The magnitude of the
event only affects the shape of the curves on the graph; it does not obviate the need for
Primary Frequency Control ‐ Frequency Response ‐ Graph 1
3000
60.100
Power Deficit
2500
60.000
2000
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
‐500
Frequency (Hz)
Change in Power (MW)
Frequency
59.400
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Frequency Response.
The first graph, Primary Frequency Control – Frequency Response – Graph 1, presents a sudden
loss of generation of 1000 MW. The components are presented relative to time as shown on
the horizontal Time axis in seconds. This simplified example assumes a Disturbance event of
the sudden loss of generation resulting from a breaker trip that instantaneously removes 1000
MW of generation from the interconnection. This sudden loss is illustrated by the power deficit
line shown in black using the MW scale on the left. Interconnection frequency is illustrated by
the frequency line shown in red using the Hertz scale on the right. Since the Scheduled
Frequency is normally 60 Hz, it is assumed that this is the frequency when the Disturbance
event occurs.
4
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000035
Even though the generation has tripped and power injected by the generator has been
removed from the interconnection, the loads continue to use the same amount of power. The
“Law of Conservation of Energy”3 requires that the 1000 MW must be supplied to the
interconnection if energy balance is to be “conserved.” This additional 1000 MW of power is
produced by extracting kinetic energy that was stored in the rotating mass of all of the
synchronized generators and motors on the interconnection – essentially using this equipment
as a giant flywheel. The extracted energy supplies the “balancing inertia”4 power required to
maintain the power and energy balance on the interconnection. This balancing inertia power is
produced by the generators’ spinning inertial mass’ resistance to the slowdown in speed of the
rotating equipment on the interconnection that both provides the stored kinetic energy and
reduces the frequency of the interconnection. This is illustrated in the second graph, Primary
Frequency Control – Frequency Response – Graph 2, by the orange dots representing the
balancing inertia power that exactly overlay and offset the power deficit.
Primary Frequency Control ‐ Frequency Response ‐ Graph 2
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
‐500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
As the frequency decreases, synchronized motors slow, as does the work they are providing,
resulting in a decrease in load called “load damping.” This load damping is the reason that the
power deficit initially declines. Synchronously operated motors will contribute to load
3
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power which is the first
derivative of energy with respect to time, must also be conserved.
4
The term “balancing Inertia” is coined here from the terms “inertial frequency response” and “balancing energy”. Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
5
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000036
damping. Variable speed drives that are decoupled from the interconnection frequency do not
contribute to load damping. In general, any load that does not change with interconnection
frequency including resistive load will not contribute to load damping or Frequency Response.
It is important to note that the power deficit equals exactly the balancing inertia, indicating that
there is no power or energy imbalance at any time during this process. What is normally
considered as “balancing power or energy” is actually power or energy required to correct the
frequency error from scheduled frequency. Any apparent power or energy imbalance is
corrected instantaneously by the balancing inertia power and energy extracted from the
interconnection. Thus the balancing function is really a frequency control function described as
a balancing function because ACE is calculated in MWs instead of Hertz, frequency error.
During the initial seconds of the Disturbance event, the governors have yet to respond to the
frequency decline. This is illustrated with the Blue line on the third graph, Primary Frequency
Control – Frequency Response – Graph 3, showing Governor Response. This time delay results
from the time that it takes the controller to adjust the equipment and the time it takes the
mass to flow from the source of the energy (main steam control valve for steam turbines, the
combustor for gas turbines, or the gate valve for hydro turbines) to the turbine‐generator
blades where the power is converted to electrical energy.
Primary Frequency Control ‐ Frequency Response ‐ Graph 3
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
‐500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Note that the frequency continues to decline due to the ongoing extraction by balancing inertia
power of energy from the rotating turbine‐generators and synchronous motors on the
6
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000037
interconnection. The reduction in load also continues as the effect of load damping continues
to reduce the load while frequency declines. During this time delay (before the governor
response begins) the balancing inertia limits the rate of change of frequency.
After a short time delay, the governor response begins to increase rapidly in response to the
initial rapid decline in frequency, as illustrated on the fourth graph, Primary Frequency Control
– Frequency Response – Graph 4. Governor response exactly offsets the power deficit at the
point in time that the frequency decline is arrested. At this point in time, the balancing inertia
has provided its contribution to reliability and its power contribution is reduced to zero as it is
replaced by the governor response. If the time delay associated with the delivery of governor
response is reduced, the amount of balancing inertia required to limit the change in frequency
by the Disturbance event can also be reduced. This supports the conclusion that balancing
inertia is required to manage the time delays associated with the delivery of Frequency
Response. Not only is the rapid delivery of Frequency Response important, but the shortening
of the time delay associated with its delivery is also important. Therefore, two important
components of Frequency Response are 1) how long the time delay is before the initial delivery
of response begins; and 2) how much of the response is delivered before the frequency change
is arrested.
Primary Frequency Control ‐ Frequency Response ‐ Graph 4
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
‐500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
This point, at which the frequency is first arrested, is defined as “Point C” and Frequency
Response calculated at this point is called the “arrested frequency response.” The arrested
7
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000038
frequency is normally the minimum (maximum for load loss events) frequency that will be
experienced during a Disturbance event. From a reliability perspective, this minimum
frequency is the frequency that is of concern. Adequate reliability requires that frequency at
the time frequency is arrested remain above the under‐frequency relay settings so as not to trip
these relays and the firm load interrupted by them. Frequency Response delivered after
frequency is arrested at this minimum level provides less reliability value than Frequency
Response delivered before Point C, but greater value than Secondary Frequency Control power
and energy which is delivered minutes later.
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with their Governor Response. This results in the frequency partially
recovering from the minimum arrested value and results in an oscillating transient that follows
the minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period that ends roughly 20 seconds after the Disturbance event. This post‐
disturbance transient period is included on the fifth illustrative graph, Primary Frequency
Control – Frequency Response – Graph 5.
Primary Frequency Control ‐ Frequency Response ‐ Graph 5
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
‐500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The total Disturbance event illustration is presented on the sixth graph, Primary Frequency
Control – Frequency Response – Graph 6. Frequency and power contributions stabilize at the
end of the transient period. Frequency Response calculated from data measured during this
8
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000039
settled period is called the “Settled Frequency Response.” The Settled Frequency Response is
the best measure to use as an estimator for the “Frequency Bias Setting” discussed later.
Primary Frequency Control ‐ Frequency Response ‐ Graph 6
60.100
3000
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
‐500
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The final Disturbance event illustration is presented on the seventh graph, Primary Frequency
Control – Frequency Response – Graph 7. This graph shows the averaging periods used to
estimate the pre‐disturbance A‐Value averaging period and the post‐disturbance B‐Value
averaging period used to calculate the settled frequency response. A discussion of the
measurement of Frequency Response immediately follows these graphs. That discussion
includes consideration of the factors that affect the methods chosen to measure Frequency
Response for implementation in a reliability standard.
9
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000040
Primary Frequency Control ‐ Frequency Response ‐ Graph 7
60.100
3000
Power Deficit
Balancing Inertia
Load Damping
Governor Response
A‐value
B‐value
60.000
2500
Frequency
Power (MW)
59.800
1500
B‐Value Averaging Period
A‐Value Averaging Period
Point C
1000
59.700
500
59.600
0
59.500
Frequency (Hz)
59.900
2000
59.400
‐500
‐20
‐15
‐10
‐5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Frequency Response Measurement (FRM)
The classic Frequency Response points A, C, and B, shown below in Fig. 1 Frequency Response
Characteristic, are used for measurement as found in the Frequency Response Characteristic
Survey Training Document within the NERC operating manual, found at
http://www.nerc.com/files/opman_7‐1‐11.pdf. This traditional Frequency Response Measure
has recently been more specifically termed “settled frequency response.” This term has been
used because it provides the best Frequency Response Measure to estimate the Frequency Bias
Setting in Tie‐line Bias Control based Automatic Generation Control Systems. However, the
industry has recognized that there is considerable variability in measurement resulting from the
selection of Point A and Point B in the traditional measure making the traditional measurement
method unsuitable as the basis for an enforceable reliability standard in a real world setting of
multiple Balancing Authority interconnections.
10
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000041
Frequency Response
60.050
60.025
A = 60.000
60.000
Frequency (Hz)
59.975
59.950
59.925
59.900
B = 59.874
59.875
59.850
59.825
C = 59.812
59.800
59.775
59.750
-30
-20
-10
0
10
20
30
40
50
60
Time (Seconds)
Figure 1. Frequency Response Characteristic
By contrast, measuring an Interconnection’s settled frequency response is straightforward and
fairly accurate. All that’s needed to make the calculation is to know the size of a given
contingency (MW), divide this value by the change in frequency and multiply the results by 10
since frequency response is expressed in MW/0.1Hz.
Measuring a BA’s frequency response is more challenging. Prior to BAL‐003‐1, NERC’s
Frequency Response Characteristic Survey Training Document provided guidance to calculate
Frequency Response. In short, it told the reader to identify the BA’s interchange values
“immediately before” and “immediately after” the Disturbance event and use the difference to
calculate the MWs the BA deployed for the event. There are two challenges with this
approach:
Two people looking at the same data would come up with different values when
assessing which exact points were immediately before and after the event.
In practice, the actual response provided by the BA can change significantly in the
window of time between point B and when secondary and tertiary control can assist in
recovery.
Therefore, the measurement of settled frequency response has been standardized in a number
of ways to limit the variability in measurement resulting from the poorly specified selection of
Point A and Point B. It should be noted that t‐0 has been defined as the first scan value that
11
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000042
shows a deviation in frequency of some significance, usually approaching about 10 mHz. The
goal is such that the first scan prior to t‐0 was unaffected by the deviation and appropriate for
one of the averaging points.
The A‐value averaging period of approximately the previous 16 seconds prior to t‐0 was
selected to allow for an averaging of at least 2 scans for entities utilizing 6 second scan
rates. (All time average period references in this document are for 2 second scan rates
unless noted otherwise.)
The B‐value averaging period of approximately (t+20 to t+52 seconds) was selected to
attempt to obtain the average of the data after primary frequency response was
deployed and the transient completed(settled), but before significance influence of
secondary control. Multiple periods were considered for averaging the B‐value:
o 12 to 24 sec
o 18 to 30 sec
o 20 to 40 sec
o 18 to 52 sec
o 20 to 52 sec
It is necessary for all BAs from an interconnection to use the same averaging periods to
provide consistent results. In addition, the SDT decided that until more experience is
gained, it is also desirable for all interconnections to use the same averaging periods to
allow comparison between interconnections.
The methods presented in this document only address the values required to calculate the
frequency response associated with the frequency change between the initial frequency, A‐
Value, and the settling frequency, B‐Value. No reasonable or consistent calculations can be
made relating to the arresting frequency, C‐Value, using Energy Management System (EMS)
scan rate data as long as 6‐seconds or tie‐line flow values associated with the minimum value of
the frequency response characteristic (C‐value) as measured at the BA level.
Both the calculation of the frequency at Point A and the frequency at Point B began with the
assumption that a 6‐second scan rate was the source of the data. Once the averaging periods
for a 6‐second scan rate were selected, the averaging periods for the other scan rates were
selected to provide as much consistency as possible between BAs with different scan rates.
The Frequency at Point A was initially defined as the average of the two scans immediately
prior to the frequency event. All other averaging periods were selected to be as consistent as
possible with this 12 second average scan from the 6‐second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” is defined as the average of the
same scans as used for the Point A frequency average.
The Frequency at Point B was then selected to be an average as long as the average of 6‐second
scan data as possible that would not begin until most of the hydro governor response had been
delivered and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” is defined as the average of the same
scans as used for the Point B frequency average.
12
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000043
B Averaging Period Selection:
Experience from the Electric Reliability Council of Texas (“ERCOT”) and the field trail on
other interconnections indicated that the 12 to 24 second and 18 to 30 second
averaging periods were not suitable because they did not provide the consistency in
results that the other averaging periods provided, and that the remaining measuring
periods do not provide significantly different results from each other. The team
believed that this was observed because the transients were not complete in all of the
samples using these averaging periods.
The 18 to 52 second and 20 to 52 second averaging periods were compared to each
other, with the 20 to 52 second period providing more consistent values, believed to
result from the incomplete transient in some of the 18 to 52 second samples.
This left a choice between the 20 to 40 second and the 20 to 52 second averaging
periods. The team recognized that there would be more AGC response in the 20 to 52
second period, but the team also recognized that the 20 to 52 second period would
provide a better measure of squelched response from outer loop control action. The 20
to 52 second period was selected because it would indicate squelched response from
outer‐loop control and provide incentive to reduce response withdrawal. The final
selections for the data averaging periods used in FRS Form 1 are shown in the table
below.
Definitions of Frequency Values for Frequency Response Calculation
Scan Rate
T 0 Scan
6-Seconds
5-Seconds
4-Seconds
3-Seconds
2-Seconds
Identify first
significant
change in
frequency as
the T 0 scan
A Value (average)
B Value (average)
Average of T-1 through T-2 scans
Average of T+4 through T+8 scans
Average of T-1 through T-2 scans
Average of T+5 through T+10 scans
Average of T-1 through T-3 scans
Average of T+6 through T+12 scans
Average of T-1 through T-5 scans
Average of T+7 through T+17 scans
Average of T-1 through T-8 scans
Average of T+10 through T+26 scans
Consistent measurement of Primary Frequency Response is achievable for a selected number of
events and can produce representative frequency response values, provided an appropriate
sample size is used in the analysis. Available research investigating the minimum sample size to
provide consistent measurements of Frequency Response has shown that a minimum sample
size of 20 events should be adequate.
Measurement of Primary Frequency Response on an individual resource or load basis requires
analysis of energy amounts that are often small and difficult to measure using current methods.
In addition, the number of an interconnection's resources and loads providing their response
could be problematic when compiling results for multiple events.
Measurement of Primary Frequency Response on an interconnection (System) basis is straight
forward provided that an accurate frequency metering source is available and the magnitude of
the resource/load imbalance is known in MWs.
13
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000044
Measurement on a Balancing Authority basis can be a challenge, since the determination of
change in MWs is determined by the change in the individual BA's metered tie lines.
Summation of tie lines is accomplished by summing the results of values obtained by the digital
scanning of meters at intervals up to six seconds, resulting in a non‐coincidental summing of
values. Until the technology to GPS time stamp tie line values at the meter and the summing of
those values for coincidental times is in use throughout the industry, it is necessary to use
averaging of values described above to obtain consistent results.
Figure 2. Frequency Response Measurement
The standardized measure is shown graphically in Fig. 2 Frequency Response Measurement
with the averaging periods shown by the solid green and red lines on the graph. Since FERC
directed a performance obligation for BAL‐003‐1, it is important to be more objective in the
measurement process. The standardized calculation is available on FRS Form 2 for EMS scan
rates of 2, 3, 4, 5, and 6 seconds at
http://www.nerc.com/filez/standards/Frequency_Response.html.
Arrested Frequency Response
There is another measure of Frequency Response that is of interest when developing a
Frequency Response estimate that not only will be used for estimating the Frequency Bias
Setting, but will also be used to assure reliability by operating in a manner that will bound
interconnection frequency and prevent the operation of Under‐frequency Relays. This
Frequency Response Measure has recently been named “arrested frequency response.” This
Frequency Response is significantly affected by the inertial Frequency Response, the governor
Frequency Response and the time delays associated with the delivery of governor Frequency
14
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000045
Response. It is calculated by using the change in frequency between the initial frequency, A,
and the maximum frequency change during the event, C, instead of using the change between
A and B. Arrested Frequency Response is the correct response for determining the minimum
Frequency Response related to under‐frequency relay operation and the support of
interconnection reliability. This is because it can be used to provide a direct estimate of the
maximum frequency deviation an interconnection will experience for an initial frequency and a
given size event in MW. Unfortunately, arrested frequency response cannot currently be
measured using the existing EMS‐based measurement infrastructure. This limitation exists
because the scan rates currently used in industry EMSs are incapable of measuring the net
actual interchange at the same instant that the maximum frequency deviation is reached.
Fortunately, the ratio of arrested frequency response and settled frequency response tends to
be stable on an interconnection. This allows the settled frequency response value to be used as
a surrogate for the arrested frequency response and implement a reasonable measure upon
which to base a standard. One consequence of using the settled frequency response as a
surrogate for the arrested frequency response is the inclusion of a large reliability margin in
Interconnection Frequency Response Obligation to allow for the difference between the settled
frequency response as measured and the arrested frequency response that indicates reliability.
As measurement infrastructure improves one might expect the Frequency Response Obligation
to transition to a measurement based directly on the arrested frequency response while the
Frequency Bias Setting will continue to be based on the settled frequency response. However,
at this time, the measurement devices and methods in use do not support the necessary level
of accuracy to estimate arrested frequency response contribution for an individual Balancing
Authority.
Frequency Response Definition and Examples
Limitations of the measurement infrastructure determine the measurement methods
recommended in this standard. The measurement limitations provide opportunities to improve
the Frequency Response as measured in the standard without contributing to an improvement
in Frequency Response that contributes to reliability. These definitions and examples provide a
basis for determining which contributions to Frequency Response contribute the most to
improved reliability. They also provide the basis for determining on a case by case basis
whether the individual contributors to the Frequency Response Measure are also contributing
to reliability.
General Frequency Response Characteristics
In the simplest case Frequency Response includes any automatic response to changes in local
frequency. If that response works to decrease that change in frequency, it is beneficial to
reliability. If that response works to increase that change in frequency, it is detrimental to
reliability. However, this definition does not address the relative value of one response as
compared to other responses that may be provided in a specific case.
There are numerous characteristics associated with the Frequency Response that affect the
reliability value and economic value of the response. These characteristics include:
1. Inertial – the response is inertial or approximates inertial response
15
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000046
Inertial response provides power without delay that is proportional to the frequency
and the change in frequency. Therefore, power provided by electronic control as
synthetic Inertial response must be proportional to the frequency and change in
frequency and be provided without a time delay.
2. Immediate – no unnecessary intentional time delays or reduction in the rate of
response delivery
a. time delay before the beginning of the response
Turbines that convert heat or kinetic energy have time delays related to the time
delay from the time that the control valves are moved to initiate the change in
power and the time that the power is delivered to the generator. These times
are usually associated with the time it takes a change in mass flow to travel from
the control valve to the first blades of the turbine in the turbine generator.
b. reduction in the rate of response delivery
There are natural delays associated with the rate of response delivery that are
related to the mass flow travel from the first turbine blades to the last turbine
blades. In addition, some turbines have intentional delays designed into the
control system to slow the rate of change in the delivery of the kinetic energy or
fuel to the turbine to prevent the turbine or other equipment from being
damaged, hydro turbines, or to prevent the turbine from tripping due to
excessive rate of change, gas turbines.
3. Proportional – the amount of the total response is proportional to the frequency error
a. No Deadband – the response is proportional across the entire frequency range
b. Deadband – the response is only proportional outside of a defined deadband
4. Bi‐directional – the response occurs to both increases and decreases in frequency
5. Continuous – there are no discontinuities in the delivery of the response (no step
changes)
6. Sustained – the response is sustained until frequency is returned to schedule
Frequency Response Reliability Value
This section contains a more detailed discussion of the various characteristics of Frequency
Response listed in the previous section. It also provides an indication of the relative value of
these characteristics with respect to their contribution to reliability. Finally, it includes some
examples of the described responses.
Inertial Response is provided from the stored energy in the rotating mass of the turbine‐
generators and synchronous motors on the interconnection. It limits the rate of change of
frequency until sufficient Frequency Response can be supplied to arrest the change in
frequency. Its reliability value increases as the time delay associated with the delivery of other
Frequency Response on the interconnection increases. If those time delays are minimal, then
the value of inertial response is low. If all time delays associated with the Frequency Response
could be eliminated, then inertial response would have little value.
16
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000047
The reliability value of Inertial Response is the greatest on small interconnections because the
size of the Disturbance events is larger relative to the inertia of the interconnection. Electronic
controls have been developed to provide synthetic inertial response from the stored energy in
asynchronous generators to supplement the natural inertial response. Some Type III & IV Wind
Turbines have this capability. In addition, electronically controlled SCRs have been developed
that can store energy in the electrical system and release this stored energy to supply synthetic
inertial response when required.
Immediate Response is provided by load damping and because the time delays associated with
its delivery are very short (related to the speed of electrical signal in the electrical system); load
damping requires very little inertial response to limit arrested frequency effectively. Synthetic
immediate response can also be supplied from loads because in many cases, there is no mass
flow time delay associated with the load process providing the power and energy reduction.
Therefore, loads can provide an immediate response with a higher reliability value than
generators with time delays required by the physics of the turbine‐generator.
Governor response has time delays associated with its delivery. Governor response provided
with shorter time delays has a higher reliability value because those shorter time delays require
less inertial response to arrest frequency. Governor response is provided by the turbine‐
generators on the interconnection. Time delays associated with governor response vary
depending on the type of turbine‐generator providing the response.
The longest time delays are usually associated with high head hydro turbine‐generators that
require long times from the governor action until the additional mass flow through the turbine.
These units may also have the longest delivery time associated with the full delivery of
response because of the timing designed into the governor response.5
Intermediate time delays are usually associated with steam turbine‐generators. The response
begins when the steam control valves are adjusted and the steam mass flows from the valves to
the first high pressure turbine blades. The delivery times associated with the full delivery of
response may require the steam to flow through high, intermediate and low pressure turbines
including reheat flows before full power is delivered. These times are shorter than those of the
hydro turbine‐generators in general, but not as fast as the times associated with gas turbines.6
Gas turbines typically have the shortest time delays, because control is provided by injecting
more or less fuel into the turbine combustor and adjusting the air control dampers. These
control changes can be initiated rapidly and the mass flow has the shortest path to the turbine
5
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1‐6 – 1‐9.
6
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1‐4 – 1‐6.
17
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000048
blades. There may be timing limitations related to the rate of change in output of the gas
turbine‐generator to maintain flame stability in some cases slowing the rate of change.7
Synthetic Governor Response can be supplied by certain loads and storage systems. The
immediacy of the response is normally limited only by the electronic controls used to activate
the desired response. Synthetic response, when it can be supplied immediately without
significant time delay, has a higher reliability value because it requires less inertial response to
achieve smaller arrested frequency deviations.
Proportional Response indicates that the response provided is proportional in magnitude to
the frequency error. Response deadbands cause a non‐proportional response and reduce the
value of the response with respect to reliability. Contrary to general consensus, deadbands do
not reduce the amount of Frequency Response that must be provided, they only transfer the
responsibility for providing that Frequency Response from one source on the interconnection to
another. For a given response, the response with the smaller deadband has the greater
reliability value. Therefore, deadbands should be set to the smallest value that supports overall
reliable operation including the reliable operation of the generator.
Electronic controls have also been developed to provide synthetic governor response. When
these controls are applied to certain loads or stored energy systems, they can be programmed
to provide synthetic governor response similar to the proportional response of a turbine‐
generator governor. Governor response in generators is limited to a small percentage of the
output of the generating unit, while synthetic governor response could be applied to much
larger percentages of loads or storage devices providing such response.
Load damping provides a proportional response.
Continuous Response is response that has no discontinuous (step) changes in the frequency
versus response curve. Step changes (Non‐continuous Response) in the Governor Response
curve can lead to frequency instabilities at frequencies near the changes. The ERCOT
Interconnection observed this and has since prohibited the use of governor response
characteristics incorporating step responses.
Step responses also occur with the implementation of load interruption using under‐frequency
or over‐frequency relays.
Bi‐directional Response is response that occurs in both directions, when the frequency is
increasing and when the frequency is decreasing. A uni‐directional response is a response that
only occurs once when frequency is decreasing or when frequency is increasing.
Inertial response, governor response and load damping are all bi‐directional responses. Certain
loads are capable of providing proportional bi‐directional response while others are only
capable of providing non‐proportional bi‐directional response.
7
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1‐16 – 1‐19.
18
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000049
The ERCOT Load Resource program is a uni‐directional response program. Loads are only
tripped when frequency declines below a given set‐point. When frequency is restored above
that set‐point, the loads must be manually reconnected. As a consequence, the Frequency
Response only occurs once with declining frequency and does not oppose the increase in
frequency after the initial decline. If there should be a frequency oscillation, the uni‐directional
response will not contribute to the opposition of a second frequency decline across the set‐
point during an oscillation event. Once a uni‐directional response has occurred, it is unavailable
for a second decline before reset.
Step or proportional responses implemented bi‐directionally can lead to frequency instability
when there is less continuous frequency response than the magnitude of the change in
continuous response between the trip and reset frequencies in step, or the proportional
response rate of change is greater than the underlying continuous response. A step bi‐
directional response will have the load reconnected as frequency recovers from the event thus
opposing the increase in frequency during recovery, and also resetting the load response for
the next frequency decline automatically. Bi‐directional response obviously has a greater
reliability value than uni‐directional response.
Sustained Response is provided at its full value until frequency is restored to its scheduled
value. On today’s interconnections, few frequency responses are fully sustained until
frequency has been restored to its scheduled value. On steam based turbine‐generators, the
steam pressure may drop after a time as the result of the additional steam flow from governor
action. However, in general this has not been a problem because most responses are
incomplete at the time that frequency has been initially arrested and the additional response
has generally been sufficient to make up for more than the these unpreventable reductions in
response. However, the intentional withdrawal of response before frequency has been
restored to schedule can cause a decline in frequency beyond that which would be otherwise
expected. This intentional withdrawal of response is highly detrimental to reliability.
Therefore, it can be concluded in general that sustained response has a higher reliability value
than un‐sustained response.
On an interconnection, the withdrawal of response due to the loss of steam pressure on the
steam units may be offset by the slower response of hydro turbine‐generators. In these cases,
the reliability of the combined response provides a greater reliability value than the individual
response of each type. The steam turbine‐generators provide a fast response that may be
reduced, while the hydro turbine‐generators provide a slower response, contributing less to the
arresting response, offsetting any reduction by the steam turbine‐generators to assure a
sustained response.
Sustained Response must also be considered for any resource that has a limited duration
associated with its response. The amount of stored energy available from a resource may limit
its ability to sustain response for a duration of time necessary to support reliability.
Frequency Response Cost Factors
In every system of exchange there are two sides; the supply side and the demand side. The
supply side provides the services used by the demand side. In the case of Frequency Response,
19
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000050
the supply side includes all providers of Frequency Response and the demand side includes all
participants that create the need for Frequency Response.
Frequency Response Costs – Supply Side
There are a number of factors that affect the cost of providing Frequency Response from
resources. Since there is a cost associated with those factors, some method of appropriate
compensation could be made available to those resources providing Frequency Response.
Without compensation, providers of Frequency Response will be put in the position of incurring
additional cost that can be avoided only by reducing or eliminating the response they provide.
These costs are incurred independently of whether provided for in a formal Regional
Transmission Organization/Independent System Operator (RTO/ISO) market or in a traditional
BA subject to the FERC pro‐forma tariffs.
It is the responsibility of the BA or the RTO/ISO to acquire the necessary amount of Frequency
Response to support reliability in the most cost effective manner. This function is performed
best when the suppliers are evaluated based on the value of the Frequency Response they
provide and compensated appropriately for that Frequency Response. Suppliers provide
Frequency Response when they are assured that they will receive fair compensation. Before
considering how to perform this evaluation and compensation, the costs associated with
providing Frequency Response should be understood and evaluated with respect to the level of
reliability they offer.
Some cost factors that have been identified for providing Frequency Response include:
1. Capacity Opportunity Cost – the costs, including opportunity costs, associated with
reserving capacity to provide Frequency Response. These costs are usually associated
with the alternative use of the same capacity to provide energy or other ancillary
services. There may also be capacity opportunity costs associated with the loss in
average capacity by a load providing Frequency Response.
2. Fuel Cost – The cost of fuel used to provide the Frequency Response. The costs for fuel
to provide Frequency Response can result in energy costs significantly different from the
system marginal energy cost, both higher and lower. This is the case when Frequency
Response is provided by resources that are not at the system marginal cost.
3. Energy Efficiency Penalty Costs – the costs associated with the loss in efficiency when
the resource is operated in a mode that supports the delivery of Frequency Response.
This cost is usually in the form of additional fuel use to provide the same amount of
energy. An example is the difference between operating a steam turbine in valve
control mode with an active governor and sliding pressure mode with valves wide open
and no active governor control except for over‐speed. This cost is incurred for all of the
energy provided by the resource, not just the energy provided for Frequency Response.
There may be additional energy costs associated with a load providing Frequency
Response from loss in efficiency of their process when load is reduced.
4. Capacity Efficiency Penalty Costs – the costs associated with any reduction in capacity
resulting from the loss of capacity associated with the loss in energy efficiency. When
efficiency is lost, capacity may be lost at the same time because of limitations in the
amount of input energy that can be provided to the resource.
20
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000051
5. Maintenance Costs – the operation of the resource in a manner necessary to provide
Frequency Response may result in increases in the maintenance costs associated with
the resource.
6. Emissions Costs – the additional costs incurred to manage any additional emissions that
result when the resource is providing Frequency Response or stands ready to provide
Frequency Response.
A good contract for the acquisition of Frequency Response from a resource will provide
appropriate compensation to the resource for all of the costs the resource incurs to provide
Frequency Response. It will also provide a method to evaluate the least cost mix of resources
necessary to provide the minimum required Frequency Response for maintaining reliability.
Finally, it will provide the least complex method of evaluation considering the complexity and
efficiency of the acquisition process.
Frequency Response Costs – Demand Side
Not only are there costs associated with acquiring Frequency Response from the supplying
resources, there are costs associated with the amount of Frequency Response that must be
acquired and influenced by those participants that create the need for Frequency Response. If
the costs of acquiring Frequency Response from the supply resources can be assigned to those
parties that create the need for Frequency Response, there is the promise that the amount of
Frequency Response required to maintain reliability can be minimized. The considerations are
the same as those that are driving the development of “real time pricing” and “dynamic
pricing”. If the costs are passed on to those contributing to the need for Frequency Response,
incentives are created to reduce the need for Frequency Response making interconnection
operations less expensive and more reliable. The problem is to balance both cost and
complexity against reliability on both the supply side and the demand side.
21
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000052
Rationale by Requirement
Requirement 1
R1. Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more negative than its
Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each FRSG or Balancing Authority that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more negative than the Interconnection
Frequency Response Obligation.
Background and Rationale
R1 is intended to meet the following primary objectives:
• Determine whether a Balancing Authority (BA) has sufficient Frequency Response for
reliable operations.
• Provide the feeder information needed to calculate CPS limits and Frequency Bias
Settings.
Primary Objective
With regard to the first objective, FRS Form 1 and the process in Attachment A provide the
method for determining the Interconnections’ necessary amount of Frequency Response and
allocating it to the Balancing Authorities. The field trial for BAL‐003‐1 is testing an allocation
methodology based on the amount of load and generation in the BA. This is to accommodate
the wide spectrum of BAs from generation‐only all the way to load‐only.
Frequency Response Sharing Groups (FRSGs)
This standard proposes an entity called FRSG, which is defined as:
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to
jointly meet the sum of the Frequency Response Obligations of its members.
This standard allows Balancing Authorities to cooperatively form FRSGs as a means to jointly
meet the FRS. There is no obligation to form or be a part of FRSGs. The members of the FRSG
would determine how to allocate sanctions among its members. This standard does not
mandate the formation of FRSGs, but allows them as a means to meet one of FERC’s Order No.
693 directives.
FRSG performance may be calculated one of two ways:
22
Calculate a group NIA and measure the group response to all events in the reporting
year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each
participant’s individual event performance.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000053
Frequency Response Obligation and Calculation
The basic Frequency Response Obligation is based on annual load and generation data reported
in FERC Form 714 (where applicable, see below for non‐jurisdictional entities) for the previous
full calendar year. The basic allocation formula used by NERC is:
FROBA
FROI
Annual GenBA
Annual GenI
Annual LoadBA
Annual LoadI
Where:
Annual GenBA is the annual “Net Generation (MWh)”, FERC Form 714, line 13, column c
of Part II ‐ Schedule 3.
Annual LoadBA is the annual “Net Energy for Load (MWh)”, FERC Form 714, line 13,
column e of Part II ‐ Schedule 3.
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to
assemble and submit equivalent data. Until the BAL‐003‐1 process outlined in Attachment 1 is
implemented, Balancing Authorities can approximate their FRO by multiplying their
Interconnection’s FRO by their share of Interconnection Bias. The data used for this calculation
should be for the most recently filed Form 714. As an example, a report to NERC in January
2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that merge or that transfer load or generation need to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation for
the Interconnection remains the same and so that CPS limits can be adjusted.
Attachment A proposes the following Interconnection event criteria as a basis to determine an
Interconnection’s Frequency Response Obligation:
Largest category C loss‐of‐resource (N‐2) event.
Largest total generating plant with common voltage switchyard.
Largest loss of generation in the interconnection in the last 10 years.
With regard to the second objective above (determining Frequency Bias Settings and CPS
limits), Balancing Authorities have been asked to perform annual reviews of their Frequency
Bias Settings by measuring their Frequency Response, dating back to Policy 1. This obligation
was carried forward into BAL‐003‐01.b. While the associated training document provided
useful information, it left many of the details to the judgment of the person doing the analysis.
The FRS Form 1 and FRS Form 2 provide a consistent, objective process for calculating
Frequency Response to develop an annual measure, the FRM.
23
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000054
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as:
“the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz”. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change of its net
actual interchange on its tie lines with its adjacent Balancing Authorities divided by the change
in interconnection frequency. (Some Balancing Authorities may choose to apply corrections to
their net actual interchange values to account for factors such as nonconforming loads. FRS
Form 1 shows the types of adjustments that are allowed.)
A standardized sampling interval of approximately 20 to 52 seconds will be used in the
computation of SEFRD values. Microsoft Excel® spreadsheet interfaces for EMS scan rates of 2
through 6 seconds are provided to support the computation.
Single Event Frequency Response Data8
The use of a “single event measure” was considered early in the development of the FRS for
compliance because a single event measure could be enforced for each event on the
interconnection making compliance enforcement a simpler process. The variability of the
measurement of Frequency Response for an individual BA for an individual Disturbance event
was evaluated to determine its suitability for use as a compliance measure. The individual
Disturbance events were normalized and plotted for each BA on the Eastern and Western
Interconnections. This data was plotted with a dot representing each event. Events with a
measured Frequency Response above the FRO were shown as blue dots and events with a
measured Frequency Response below the FRO were shown as red dots. In order to show the
full variability of the results the plots have been provided with two scales, a large scale to show
all of the events and small scale to show the events closer to the FRO or a value of 1.0. This
data is presented on four charts titled Frequency Response Events as Normalized by FRO.
Analysis of this data indicates a single event based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in these charts.
Based on the field trial data provided, only 3 out of 19 BAs on the Western Interconnection
would be compliant for all events with a standard based on a single event measure. Only 1 out
of 31 BAs on the Eastern Interconnection would be compliant for all events with a standard
based on a single event measure. The general consensus of the industry is that there is not a
reliability issue with insufficient Frequency Response on any of the North American
Interconnections at this time. Therefore, it is unreasonable to even consider a standard that
would indicate over 90% of the BAs in North American to be non‐compliant with respect to
maintaining sufficient Frequency Response to maintain adequate reliability.
In an attempt to balance the workload of Balancing Authorities with the need for accuracy in
the FRM, the standard will require at least 20 samples selected during the course of the year to
compute the FRM. Research conducted by the FRSDT indicated that a Balancing Authority’s
FRM will converge to a reasonably stable value with at least 20 samples.
8
Single Event Analysis based on results of Frequency Response Standard Field Trial Analysis, September 17, 2012.
24
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000055
Frequency Response Events as Normalized by FRO
Eastern Interconnection ‐ 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
‐25.0
32
31
30
29
28
27
26
25
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐50.0
Balancing Authority
25
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000056
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
‐5.0
‐10.0
‐15.0
‐20.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
‐25.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
‐5.0
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
‐10.0
Balancing Authority
26
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000057
Sample Size
In order to support field trial evaluations of sample size, sampling intervals, and aggregation
techniques, the FRSDT will be retrieving scan rate data from the Balancing Authorities for each
SEFRD. Additional frequency events may also be requested for research purposes, though they
will not be included in the FRM computation.
FERC Order No. 693 directed the ERO (at P 375) to define the number of Frequency Response
surveys that were conducted each year and to define a necessary amount of Frequency
Response. R1 addresses both of these directives:
There is a single annual survey of at least 20 events each year.
The FRM calculated on FRS Form 1 is compared by the ERO against the FRO determined
12 months earlier (when the last FRS Form 1 was submitted) to verify the Balancing
Authority provided its share of Interconnection Frequency Response.
Median as the Standard’s Measure of Balancing Authority Performance
The FRSDT evaluated different approaches for “averaging” individual event observations to
compute a technically sound estimate of Frequency Response Measure. The MW contribution
for a single BA in a multi‐BA Interconnection is small compared to the minute to minute
changes in load, interchange and generation. For example, a 3000 MW BA in the Eastern
Interconnection may only be called on to contribute 10MW for the loss of a 1000MW. The 10
MW of governor and load response may easily be masked as a coincident change in load.
In general, statisticians use the median as the best measure of central tendency when a
population has outliers. Two independent reviews by the FRSDT has shown the Median to be
less influenced by noise in the measurement process and the team has chosen the median as
the initial metric for calculating the BAs’ Frequency Response Measure.
The FRSDT performed extensive empirical studies and engaged in lively discussions in an
attempt to determine the best aggregation technique for a sample set size of at least 20 events.
Mean, median, and linear regression techniques were used on a trial basis with the data that
was available during the early phases of the effort.
A key characteristic of the “aggregation challenge” is related to the use of actual net
interchange data for measuring frequency response. The tie line flow measurements are
varying continuously due to other operational phenomena occurring concurrently with the
provision of frequency response. (See Appendix 1 for details.) All samples have “noise” in
them, as most operational personnel who have computed the frequency response of their BA
can attest. What has also become apparent to the FRSDT is that while the majority of the
frequency response samples have similar levels of noise in them, a few of the samples may
have much larger errors in them than the others that result in unrepresentative results. And
with the sample set size of interest, it is common to have unrepresentative errors in these few
samples to be very large and asymmetric. For example, one BA’s subject matter expert
observed recently that 4 out of 31 samples had a much larger error contribution than the other
27 samples, and that 3 out of 4 of the very high error samples grossly underestimated the
frequency response. The median value demonstrated greater resiliency to this data quality
problem than the mean with this data set. (The median has also demonstrated superiority to
27
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000058
linear regression in the presence of these described data quality problems in other analyses
conducted by the FRSDT, but the linear regression showed better performance than the mean.)
The above can be demonstrated with a relatively simple example. Let’s assume that a
Balancing Authority’s true frequency response has an average value of ‐200 MW/ .1 Hz. Let’s
also assume that this Balancing Authority installed “special” perfect metering on key loads and
generators, so that we could know the true frequency response of each sample. And then we
will compare them with that measured by typical tie line flow metering, with the kind of noise
and error that occurs commonly and “not so commonly”. Let’s start with the following 4
samples having a common level of noise, with MW/ .1 Hz as the unit of measurement.
Perfect measurement
‐190
‐210
‐220
‐180
‐200
‐200
Noise
‐30
‐20
10
20
Mean
Median
Samples from tie lines
‐220
‐230
‐210
‐160
‐205
‐215
Now let’s add a fifth sample, which is highly contaminated with noise and error that grossly
underestimates frequency response.
Perfect measurement
‐190
‐210
‐220
‐180
‐200
‐200
‐200
Noise
‐30
‐20
10
20
250
Mean
Median
Samples from tie lines
‐220
‐230
‐210
‐160
+50
‐154
‐210
It is clear from the above simplistic example that the mean drops by about 25% while the
median is affected minimally by the single highly contaminated value.
Based on the analyses performed thus far, the FRSDT believes that the median’s superior
resiliency to this type of data quality problem makes it the best aggregation technique at this
time. However, the FRSDT sees merit and promise in future research with sample filtering
combined with a technique such as linear regression.
When compared with the mean, linear regression shows superior performance with respect to
the elimination of noise because the measured data is weighted by the size of the frequency
change associated with the event. Since the noise is independent from frequency change, the
greater weighting on larger events provides a superior technique for reducing the effect of
noise on the results.
However, linear regression does not provide a better method when dealing with a few samples
with large magnitudes of noise and unrepresentative error. There are only two alternatives to
improve over the use of median when dealing with these larger unrepresentative errors:
1. Increase the sample size, or
2. Actively eliminate outliers due to unrepresentative error.
28
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000059
Unfortunately, the first alternative, increasing the sample size is not available because
significantly more sample events are not available within the measurement time period of one
year. Linear regression techniques are being investigated that have an active outlier
elimination algorithm that would eliminate data that lie outside ranges of the 96th percentile
and 99th percentile, for example.
Still, the use of linear regression has value in the context of this standard. The NERC Resources
Subcommittee will use linear regression to evaluate Interconnection frequency response,
particularly to evaluate trends, seasonal impacts, time of day influences, etc. The Good
Practices and Tools section of this document outlines how a BA can use linear regression to
develop a predictive tool for its operators.
Additional discussion on this topic is contained in “Appendix 1 – Data Quality Concerns Related
to the Use of Actual Net Interchange Value” of this document.
The NERC Frequency Response Initiative Report addressed the relative merits of using the
median versus linear regression for aggregating single event frequency response samples into a
frequency response measurement score for compliance evaluation. This report provided 11
evaluation criteria as a basis for recommending the use of linear regression instead of the
median for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but concluded
that the median would be the best aggregation technique to use initially when the relative
importance of each criterion was considered. A brief summary of the FRSDT majority
consensus on the basis of each evaluation criterion is provided below.
Provides two dimensional measurement – The FRSDT agrees that the two dimensional
concept is a useful way to perceive frequency response characteristics, and that it may
be useful for potential future modeling activities. Better data quality would increase
support for such future efforts, and the use of the median for initial compliance
evaluations within BAL‐003‐1 should not hinder any such effort. The FRSDT perceived
this as a mild advantage for linear regression.
Represents nonlinear characteristics – With considerations similar to those applied to
the previous criterion, the FRSDT perceived this as a mild advantage for linear
regression.
Provides a single best estimator – The FRSDT gave minimal importance to the
characteristic of the median averaging the middle values when used with an even
number of samples.
Is part of a linear system ‐ With considerations similar to those applied to the first two
criteria, the FRSDT perceived this as a mild advantage for linear regression (particularly
in the modeling area.)
Represents bimodal distributions – The FRSDT gave minimal weight of this criterion, as
a change in Balancing Authority footprint does not seem to be addressed adequately by
any aggregation technique.
Quality statistics available – The FRSDT perceived this as a mild advantage for linear
regression in that the statistics would be coupled directly to the compliance evaluation.
The FRSDT also included this criterion as part of the modeling advantages cited above.
29
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000060
The FRSDT supports collecting data and performing quality statistical analysis. If it is
determined that the use of the median, as opposed to a mean or linear regression
aggregation, is yielding undesirable consequences, the FRSDT recommends that other
aggregation techniques be re‐evaluated at that time.
Reducing influence of noise ‐ This is the dominant concern of the FRSDT, and it
perceives the median to have a major advantage over linear regression in addressing
noise in the change in actual net interchange calculation. The FRSDT bases this
judgment on: prior FRSDT studies that have shown that the median produces more
stable results; the data used in the NERC Frequency Response Initiative document
exhibits large quantities of noise; prior efforts of FRSDT members in performing
frequency response sampling for their own Balancing Authorities over many years; and
similar observations of noise in the CERTS frequency Monitoring Application. The
FRSDT has serious concerns that the influence of noise has a greater tendency to yield a
“false positive” compliance violation with linear regression than with the median. Also,
limited studies performed by the FRSDT indicates the possibility that the resultant
frequency response measure would yield more measurement variation across years
with linear regression versus the median while the actual Balancing Authority
performance remains unchanged.
Reducing the influence of outliers – This is related to the previous criterion. The FRSDT
recognizes four main sources of noise: concurrent operating phenomena (described
elsewhere in this document), transient tie line flows for nearby contingencies, data
acquisition time skew in tie line data measurements, and time skew and data
compression issues in archiving techniques and tools such as PI. Some outliers may be
caused in part by true variation in the actual frequency response, and it is desirable to
include those in the frequency response measure. The FRSDT supports efforts in the
near future to distinguish between outliers caused by noise versus true frequency
response, and progress in this area may make it feasible and desirable to replace the
median with linear regression, or some other validated technique. The FRSDT does
note that this is a substantial undertaking, and it would require substantial input from a
sufficient number of experts to help distinguish noise from true frequency response.
Easy to calculate – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made in noise elimination.
Familiar indicator – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made as a result of noise elimination.
Currently used as a measure in BAL‐003 – The present standard refers to an average
and does not provide specific guidance on the computation of that average, but the
FRSDT puts minimal weight on this evaluation criterion.
In summary, the FRSDT perceives an approximate balance between the modeling advantage for
linear regression and the simplicity advantage of the median. However, the clear determinant
in endorsing the use of the median is the data quality issue related to concurrent operational
phenomena, transient tie line flows, and data acquisition and archiving limitations.
30
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000061
FERC Order No. 693 also directed the Standard (at P 375) to identify methods for Balancing
Authorities to obtain Frequency Response. Requirement R1 allows Balancing Authorities to
participate in Frequency Response Sharing Groups (FRSGs) to provide or obtain Frequency
Response. These may be the same FRSGs that cooperate for BAL‐002‐0 or may be FRSGs that
form for the purposes of BAL‐003‐1.
If BAs participate as an FRSG for BAL‐003‐1, compliance is based on the sum of the participants’
performance.
Two other ways that BAs could obtain Frequency Response are through Supplemental Service
or Overlap Regulation Service:
No special action is needed if a BA provides or receives supplemental regulation. If the
regulation occurs via Pseudo Tie, the transfer occurs automatically as part of Net Actual
Interchange (NIA) and in response to information transferred from recipient to
provider.
If a BA provides overlap regulation, its FRS Form 1 will include the Frequency Bias
setting as well as peak load and generation of the combined Balancing Authority Areas.
The FRM event data will be calculated on the sum of the provider’s and recipient’s
performance.
In the Violation Severity Levels for Requirement R1, the impact of a BA not having enough
frequency response depends on two factors:
Does the Interconnection have sufficient response?
How short is the BA in providing its FRO?
The VSL takes these factors into account. While the VSLs look different than some other
standards, an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is
intended to measure a violation’s impact on reliability and thus levy an appropriate sanction.
Frequency Response is an interconnection‐wide resource. The proposed VSLs are intended to
put multi‐BA Interconnections on the same plane as single‐BA Interconnections.
Consider a small BA whose performance is 70% of its FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability,
yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection
that had insufficient Frequency Response, because this would treat multi‐BA Interconnections
more harshly than single BA Interconnections on a significant scale.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and
Severe VSLs say the Interconnection does not meet the FRO and assesses sanctions based on
whether the BA is deficient by a small or larger amount respectively.
31
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000062
Requirement 2
R2. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined in accordance with Attachment
A, as validated by the ERO, into its Area Control Error (ACE) calculation during the
implementation period specified by the ERO.
Background and Rationale
Attachment A of the Standard discusses the process the ERO will follow to validate the BA’s FRS
Form 1 data and publish the official Frequency Bias Settings. Historically, it has taken multiple
rounds of validation and outreach to confirm each BA’s data due to transcription errors,
misunderstanding of instructions, and other issues. While BAs historically submit Bias Setting
data by January 1, it often takes one or more months to complete the process.
The target is to have BAs submit their data by January 10. The BAs are given 30 days to
assemble their data since the BAs are dependent on the ERO to provide them with FRS Form 1,
and there may be process delays in distributing the forms since they rely on identification of
frequency events through November 30 of the preceding year.
Frequency Bias Settings generally change little from year to year. Given the fact that BAs can
encounter staffing or EMS change issues coincident with the date the ERO sets for new
Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date.
To recap the annual process:
1. The ERO posts the official list of frequency events to be used for this Standard in early
December. The FRS Form 1 for each Interconnection will be posted shortly thereafter.
2. The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3. The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, The ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which
to implement revised Frequency Bias Setting values. Implementation typically would be
on or about March 1st of each year.
BAL‐003‐0.1b standard requires a minimum Frequency Bias Setting equal in absolute value to
one percent of the Balancing Authority’s estimated yearly peak demand (or maximum
generation level if native load is not served). For most Balancing Authorities this calculated
amount of Frequency Bias is significantly greater in absolute value than their actual Frequency
Response characteristic (which represents an over‐bias condition) resulting in over‐control
32
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000063
since a larger magnitude response is realized. This is especially true in the Eastern
Interconnection where this condition requires excessive secondary frequency control response
which degrades overall system performance and increases operating cost as compared to
requiring an appropriate balance of primary and secondary frequency control response.
Balancing Authorities were given a minimum Frequency Bias Setting obligation because there
had never been a mandatory Frequency Response Obligation. This historic “one percent of
peak per 0.1Hz” obligation, dating back to NERC’s predecessor, NAPSIC, was intended to ensure
all BAs provide some support to Interconnection frequency.
The ideal system control state exists when the Frequency Bias Setting of the Balancing
Authority exactly matches the actual Frequency Response characteristic of the Balancing
Authority. If this is not achievable, over‐bias is significantly better from a control perspective
than under‐bias with the caveat that Frequency Bias is set relatively close in magnitude to the
Balancing Authority actual Frequency Response characteristic. Setting the Frequency Bias to
better approximate the Balancing Authority natural Frequency Response characteristic will
improve the quality and accuracy of ACE control, CPS & DCS and general AGC System control
response. This is the technical basis for recommending an adjustment to the long standing “1%
of peak/0.1Hz” Frequency Bias Setting. The Procedure for ERO Support of Frequency
Response and Frequency Bias Setting Standard is intended to bring the Balancing
Authorities’ Frequency Bias Setting closer to their natural Frequency Response. Procedure for
ERO Support of Frequency Response and Frequency Bias Setting Standard balances the
following objectives:
•
Bring the Frequency Bias Setting and Frequency Response closer together.
•
Allow time to analyze impact on other Standards (CPS, BAAL and to a lesser extent DCS)
by adjustments in the minimum Frequency Bias Setting, by accommodating only minor
adjustments.
•
Do not allow the Frequency Bias Setting minimum to drop below natural Frequency
Response, because under‐biasing could affect an Interconnection adversely.
Additional flexibility has been added to the Frequency Bias Setting based on the actual
Frequency Response (FRM) by allowing the Frequency Bias Setting to have a value in the range
from 100% of FRM to 125% of FRM. This change has been included for the following reasons:
•
33
When the new standardized measurement method is applied to BAs with a Frequency
Response close to the interconnection minimum response, the requirement to use FRM
is as likely to result in a Frequency Bias Setting below the actual response as it is to
result in a response above the actual response. From a reliability perspective, it is
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000064
always better to have a Frequency Bias Setting slightly above the actual Frequency
Response.
•
As with single BA interconnections, the tuning of the control system may require that
the BA implement a Frequency Response Setting slightly greater in absolute terms than
its actual Frequency Response to get the best performance.
•
The new standardized measurement method for determining FRM in some cases results
in a measured Frequency Response significantly lower than the previous methods used
by some BAs. It is desirable to not require significant change in the Frequency Bias
Setting for these BAs that experience a reduction in their measured Frequency
Response.
Requirement 3
R3. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
Less than zero at all times, and
Equal to or more negative than its Frequency Response Obligation when the Frequency
varies from 60 Hz by more that +/‐ 0.036 Hz.
Background and Rationale
In multi‐Balancing Authority interconnections, the Frequency Bias Setting should be
coordinated among all BAs on the interconnection. When there is a minimum Frequency Bias
Setting requirement, it should apply for all BAs. However, BAs using a variable Frequency Bias
Setting may have non‐linearity in their actual response for a number of reasons including the
dead‐bands implemented on their generator governors. The measurement to ensure that
these BAs are conforming to the interconnection minimum is adjusted to remove the dead‐
band range from the calculated average Frequency Bias Setting actually used. For BAs using
variable bias, FRS Form 1 has a data entry location for the previous year’s average monthly Bias.
The Balancing Authority and the ERO can compare this value to the previous year’s Frequency
Bias Setting minimum to ensure R3 has been met.
On single BA interconnections, there is no need to coordinate the Frequency Bias Setting with
other BAs. This eliminates the need to maintain a minimum Frequency Bias Setting for any
reason other than meeting the reliability requirement as specified by the Frequency Response
Obligation.
Requirement 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias Setting for
the combined Balancing Authority Area, to be equivalent to either:
34
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000065
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting as shown on FRS Form 1 and FRS Form 2 for the entirety of
the participating Balancing Authorities’ Areas.
Background and Rationale
This requirement reflects the operating principles first established by NERC Policy 1 and is
similar to Requirement R6 of the approved BAL‐003‐0.1b standard. Overlap Regulation Service
is a method of providing regulation service in which the Balancing Authority providing the
regulation service incorporates another Balancing Authority’s actual interchange, frequency
response, and schedules into the providing Balancing Authority’s AGC/ACE equation.
As noted earlier, a BA that is providing Overlap Regulation will report the sum of the Bias
Settings in its FRS Form 1. Balancing Authorities receiving Overlap Regulation Service have an
ACE and Frequency Bias Setting equal to zero (0).
35
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000066
How this Standard Meets the FERC Order No. 693
Directives
FERC Directive
The following is the relevant paragraph of Order No. 693.
Accordingly, the Commission approves Reliability Standard BAL‐003‐0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a modification to
BAL‐003‐0 through the Reliability Standards development process that: (1) includes
Levels of Non‐Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other requirements of
the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) defines the necessary amount of Frequency Response needed for
Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.
1. Levels of Non-Compliance
VRFs and VSLs are an equally effective way of assigning compliance elements to the standard.
2. Determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other Requirements of
the Reliability Standard are met
BAL‐003 V0 R2 (the basis of Order No. 693) deals with the calculation of Frequency Bias Setting
such that it reflects natural Frequency Response.
The drafting team has determined that a sample size on the order of at least 20 events is
necessary to have a high confidence in the estimate of a BA’s Frequency Response. Selection of
the frequency excursion events used for analysis will be done via a method outlined in
Attachment A to the Standard.
On average, these events will represent the largest 2‐3 “clean” frequency excursions occurring
each month.
Since Frequency Bias Setting is an annual obligation, the survey of the at least 20 frequency
excursion events will occur once each year.
3. Define the necessary amount of Frequency Response needed for
Reliable Operation for each Balancing Authority with methods of
obtaining and measuring that the frequency response is achieved
Necessary Amount of Frequency Response
The drafting team has proposed the following approach to defining the necessary amount of
frequency response. In general, the goal is to avoid triggering the first step of under‐frequency
load shedding (UFLS) in the given Interconnection for reasonable contingencies expected. The
36
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000067
methodology for determining each Interconnection’s and Balancing Authority’s obligation is
outlined in Attachment A to the Standard.
It should be noted the standard cannot guarantee there will never be a triggering of UFLS as the
magnitude of “point C” differs throughout an interconnection during a disturbance and there
are local areas that see much wider swings in frequency.
The contingency protection criterion is the largest reasonably expected contingency in the
Interconnection. This can be based on the largest observed credible contingency in the
previous 10 years or the largest Category C event for the Interconnection.
Attachment A to the standard presents the base obligation by Interconnection and adds a
Reliability Margin. The Reliability Margin included addresses the difference between Points B
and C and accounts for variables.
For multiple BA interconnections, the Frequency Response Obligation is allocated to BAs based
on size. This allocation will be based on the following calculation:
FROBA
FROI
Annual GenBA
Annual GenI
Annual LoadBA
Annual LoadI
Methods of Obtaining Frequency Response
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a
contractual share of Frequency Response from Adjacent Balancing Authorities. See FRS
Form 1. While the final rules with regard to contractual services are being defined, the
current expectation is that the ERO and the associated Region(s) should be notified
beforehand and that the service be at least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the
development of a NAESB business practice for Frequency Response service for linear
(droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service,
BAs and FRSGs may use whatever is most appropriate for their situation.
Measuring that the Frequency Response is Achieved
FRS Form 1 and the underlying data retained by the BA will be used for measuring whether
Frequency Response was provided. FRS Form 1 will provide the guidance on how to account for
and measure Frequency Response.
37
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000068
Going Beyond the Directive
Based on the combined operating experience of the SDT, the drafting team consensus is that
each Interconnection has sufficient Frequency Response. If margins decline, there may be a
need for additional standards or tools. The drafting team and the Resources Subcommittee are
working with the ERO on its Frequency Response Initiative to develop processes and good
practices so the Interconnections are prepared. These good practices and tools are described in
the following section.
The drafting team is also evaluating a risk‐based approach for basing the Interconnection
Frequency Response Obligation on an historic probability density of frequency error, and for
allocating the obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error. This allocation method uses the inverse of the rationale for allocating the CPS1
epsilon requirement by Bias share.
38
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000069
Good Practices and Tools
Background
This section outlines tips and tools to help Balancing authorities meet the Frequency Response
Standard or to operate more reliably. If you have suggested additions, please send them to
[email protected].
Identifying and Estimating Frequency Responsive Reserves
Knowing the quantity and depth of frequency responsive reserves in real time is a possible next
step to being better prepared for the next event. The challenge in achieving this is having the
knowledge of the capabilities of all sources of frequency response. Presently the primary
source of Frequency Response remains with the generation resources in our fleets.
Understanding how each of these sources performs to changes in system frequency and
knowing their limitations would improve the BA’s ability to measure frequency responsive
reserves. Presently there are only guidelines, criteria and protocols in some regions of the
industry that identify specific settings and performance expectations of Primary Frequency
Response of resources.
One method of gaining a better understanding of performance is to measure performance
during actual events that occur on the system. Measuring performance during actual events
would only provide feedback for performance during that specific event and would not provide
insight into depth of response or other limitations.
Repeated measurements will increase confidence in expected performance. NERC modeling
standards are in process to be revised that will improve the BA’s insight into predicting
available frequency responsive reserves. However, knowing how resources are operated, what
modes of operation provide sustained Primary Frequency Response and knowing the operating
range of this response would give the BA the knowledge to accurately predict frequency
response and the amount of frequency responsive reserves available in real time.
Some benefits have been realized by communicating to generation resources (GO) the
importance of operating in modes that allow Primary Frequency Response to be sustained by
the control systems of the resource. Other improvements in implementation of Primary
Frequency Response have been achieved through improved settings on turbine governors
through the elimination of “step” frequency response with the simultaneous reduction in
governor dead‐band settings.
Improvements in the full AGC control loop of the generating resource, which accounts for the
expected Primary Frequency Response, have improved the delivery of quality Primary
Frequency Response while minimizing secondary control actions of generators. Some of these
actions can provide quick improvement in delivery of Primary Frequency Response.
39
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000070
Once Primary Frequency Response sources are known, the BA could calculate available reserves
that are frequency responsive. Planning for these reserves during normal and emergency
operations could be developed and added to the normal planning process.
Using FRS Form 1 Data
The information collected for this standard can be supplemented by a few data points to
provide the Balancing Authority useful tools and information. The BA could do a regression
analysis of its frequency response against the following values:
Load (value A).
Interchange (Value A).
Total generation.
Spinning reserve.
While the last two values above are not part of Form 1, they should be readily available. Small
BAs might even include headroom on its larger generators as part of the regression.
The regression would provide a formula the BA could program in its EMS to present the
operator a real time estimate of the BA’s Frequency Response.
Statistical outliers in the regression would point to cases meriting further inspection to find
causes of low Frequency Response or opportunities for improvement.
Tools
Single generating resource performance evaluation tools for steam turbine, combustion turbine
(simple cycle or combined cycle) and for intermittent resources are available at the following
link. http://texasre.org/standards_rules/standardsdev/rsc/sar003/Pages/Default.aspx.
These tools and the regional standard associated with them are in their final stages of
development in the Texas region.
These tools will be posted on the NERC website.
40
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000071
References
NERC Frequency Response Characteristic Survey Training Document (Found in the NERC
Operating Manual)
NERC Resources Subcommittee Position Paper on Frequency Response
NERC TIS Report Interconnection Criteria for Frequency Response Requirements (for the
Determination Interconnection Frequency Response Obligations (IFRO)
Frequency Response Standard Field Trial Analysis, September 17, 2012
41
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000072
Appendix 1 - Data Quality Concerns Related To The Use Of The
Actual Net Interchange Value
Actual net interchange for a typical Balancing Authority (BA) is the summation of its tie lines to
other BAs. In some cases, there are pseudo‐ties in it which reflect the effective removal or
addition of load and/or generation from another BA, or it could include supplemental
regulation as well. But in the typical scenario, actual net interchange values that are extracted
from EMS data archiving can be influenced by data latency times in the data acquisition
process, and also any timestamp skewing in the archival process.
Of greater concern, however, are the inevitable variations of other operating phenomena
occurring concurrently with a frequency event. The impacts of these phenomena are
superimposed on actual net interchange values along with the frequency response that we wish
to measure through the use of the actual net interchange value.
To explore this issue further, let’s begin with the idealized condition:
frequency is fairly stable at some value near or a little below 60 Hz
ACE of the non‐contingent BA of interest is 0 and has been 0 for an extended period,
and AGC control signals have not been issued recently
Actual net interchange is “on schedule”, and there are no schedule changes in the
immediate future
BA load is flat
All generators not providing AGC are at their targets
Variable generation such as wind and solar are not varying
Operators have not directed any manual movements of generation recently
And when the contingency occurs in this idealized state, the change in actual net interchange
will be measuring only the decline in load due to lesser frequency and generator governor
response, and, none of the contaminating influences. While the ACE may become negative due
to the actual frequency response being less than that called for by the frequency bias setting
within the BA’s AGC system, this contaminating influence on measuring frequency response will
not appear in the actual net interchange value if the measurement interval ends before the
generation on AGC responds.
Now let’s explore the sensitivity of the resultant frequency response sampling to the relaxation
of these idealized circumstances.
1. The “60 Hz load” increases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator‐directed
manual load adjustments occur, then the actual net interchange will be reduced by the
moderate increase in load and the frequency response will be underestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be increased by the AGC response (and/or manual
adjustments) and the frequency response will be overestimated.
42
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000073
2. The “60 Hz load” decreases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator‐directed
manual load adjustments occur, then the actual net interchange will be increased by the
moderate reduction in load and the frequency response will be overestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be decreased by the AGC response (and/or manual
adjustments) and the frequency response will be underestimated.
3. In anticipation of increasing load during the next hour, the operator increases manual
generation before the load actually appears. If the frequency event happens while the
generation “leading” the load is increasing, then the actual net interchange will be
increased by the increase in manual generation and the frequency response will be
overestimated. But if the frequency event occurs when the result of AGC signals sent to
offset the operator’s leading actions take effect, then the actual net interchange will be
decreased and the frequency response is underestimated.
4. In anticipation of decreasing load during the next hour, the operator decreases manual
generation before the load actually declines. If the frequency event happens while the
generation “leading” the load downward is decreasing, then the actual net interchange
will be decreased by the reduction in manual generation and the frequency response
will be underestimated. But if the frequency event occurs when the result of AGC
signals sent to offset the operator’s leading actions take effect, then the actual net
interchange will be increased and the frequency response is overestimated.
5. A schedule change to export more energy is made at 5 minutes before the top of the
hour. The BA’s “60 Hz load” is not changing. The schedule change is small enough that
the operator is relying on upward movement of generators on AGC to provide the
additional energy to be exported. The time at which the AGC generators actually begin
to provide the additional energy is dependent on how much time passes before the AGC
algorithm gets out of its deadbands, the individual generator control errors get large
enough for sending out the control signal, and maybe 20 seconds to 3 minutes for the
response to be effected. The key point here is that it is not clear when the effects of a
schedule change, as manifested in a change in generation and then ultimately a change
in actual net interchange, will occur.
6. With the expected penetration of wind in the near future, unanticipated changes in
their output will tend to affect actual net interchange and add noise to the frequency
response observation process.
To a greater or lesser extent, 1 through 4 above are happening continuously for the most part
with most BAs in the Eastern and Western Interconnections. The frequency response is buried
within the typical hour to hour operational cacophony superimposed on actual net interchange
values. The choice of metrics will be important to artfully extract frequency response from the
noise and other unrepresentative error.
43
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000074
Exhibit E
Implementation Plan for Reliability Standard Submitted for Approval
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000075
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b should be retired midnight of the day immediately prior to the Effective Date of
Requirements R2, R3 and R4 of BAL-003-1 in the Jurisdiction in which the new standard is becoming
effective.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4
and R5 become effective:
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually by Balancing Authorities for frequency events specified
by the ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
This will be calculated as MW/0.1Hz.
Frequency Bias Setting: A number, either fixed or variable, , usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s inverse Frequency Response contribution to the
Interconnection, and discourage withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG) 1: A group, whose members consist
of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of
its members.
1
This term and definition is identical to the definition in BAL-012-1 proposed standard.
November 2012
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000076
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
The existing definition of Frequency Bias Setting should be retired midnight of the day immediately prior
to the Effective Date of Requirements R2, R3 and R4 of BAL-003-1 in the Jurisdiction in which the new
standard is becoming effective.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved standards:
•
BAL-001-0.1a Real Power Balancing Control Performance
•
BAL-004-0 Time Error Correction
•
BAL-004-1 Time Error Correction
•
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
•
Frequency Response Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R2, R3 and R4 of this
standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R2, R3 and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter 24 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, Requirements R1 of this standard shall become effective the first calendar day of
the first calendar quarter 24 months after Board of Trustees adoption.
•
Requirement R1 cannot be implemented prior to the addition of Frequency Response Sharing
Group to the Compliance Registry.
November 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000077
Exhibit F
Frequency Response Initiative Report
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000078
Frequency Response
Initiative Report
The Reliability Role of Frequency Response
October 30, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000079
NERC’s Mission
NERC’s Mission
The North American Electric Reliability Corporation’s (NERC) mission is to ensure the reliability
of the North American bulk power system. NERC is the electric reliability organization (ERO)
certified by the Federal Energy Regulatory Commission (FERC) to establish and enforce
reliability standards for the bulk power system. NERC develops and enforces reliability
standards; assesses adequacy annually via a 10-year forecast and summer and winter forecasts;
monitors the bulk power system; and educates, trains, and certifies industry personnel. ERO
activities in Canada related to the reliability of the bulk power system are recognized and
overseen by the appropriate governmental authorities in that country. 1
NERC assesses and reports on the reliability and adequacy of the North American bulk power
system, which is divided into eight Regional areas, as shown on the map and table below. The
users, owners, and operators of the bulk power system within these areas account for virtually
all the electricity supplied in the United States, Canada, and a portion of Baja California Norte,
Mexico.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load-serving
entities participate in one Region and their
associated transmission owner/operators in
another.
1
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability
Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst
Corporation
WECC
Western Electricity
Coordinating Council
As of June 18, 2007, FERC granted NERC the legal authority to enforce reliability standards with all U.S. users, owners, and operators of the
bulk power system, and made compliance with those standards mandatory and enforceable. In Canada, NERC has memorandums of
understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the
Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial
law. NERC has an agreement with Manitoba Hydro that makes reliability standards mandatory for that entity, and Manitoba has recently
adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the province. In
addition, NERC has been designated the “electric reliability organization” under Alberta’s Transportation Regulation, and certain reliability
standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been recognized as standards-setting bodies by
the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and
British Columbia also have frameworks in place for reliability standards to become mandatory and enforceable. NERC is working with the
other governmental authorities in Canada to achieve equivalent recognition.
i
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
000080
Table of Contents
NERC’s Mission................................................................................................................................. i
Table of Contents .............................................................................................................................ii
Introduction .................................................................................................................................... 1
Executive Summary......................................................................................................................... 3
Recommendations ...................................................................................................................... 3
Findings ....................................................................................................................................... 7
Frequency Response Overview ....................................................................................................... 9
Frequency Control ...................................................................................................................... 9
Primary Frequency Control – Primary Frequency Response ...................................................... 9
Frequency Response Illustration .............................................................................................. 10
Balancing Authority Frequency Response ................................................................................ 17
Historical Frequency Response Analysis ....................................................................................... 22
History of Frequency Response and its Decline ....................................................................... 22
Projections of Frequency Response Decline ......................................................................... 23
Statistical Analysis of Frequency Response (Eastern Interconnection).................................... 27
Key Statistical Findings .......................................................................................................... 27
Frequency Response Withdrawal ............................................................................................. 31
Modeling of Frequency Response in the Eastern Interconnection .......................................... 35
Concerns for Future of Frequency Response ........................................................................... 38
Role of Inertia in Frequency Response ................................................................................. 39
Need for Higher Speed Primary Frequency Response .......................................................... 40
Preservation or Improvement of Existing Generation Primary Frequency Response.......... 40
Frequency Response Initiative Report – October 2012
ii
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
000081
Withdrawal of Primary Frequency Response ....................................................................... 41
Interconnection Frequency Response Obligation (IFRO) ............................................................. 43
Tenets of IFRO ........................................................................................................................... 43
Statistical Analyses.................................................................................................................... 44
Frequency Variation Statistical Analysis ............................................................................... 44
Point C Analysis – One-second versus Sub-second Data ...................................................... 48
Adjustment for Differences between Value B and Point C................................................... 48
Adjustment for Primary Frequency Response Withdrawal .................................................. 50
Variables in Determination of Interconnection Frequency Response Obligation from Criteria
.................................................................................................................................................. 51
Low Frequency Limit ............................................................................................................. 51
Credit for Load Resources (CLR)............................................................................................ 52
Interconnection Resource Contingency Protection Criteria..................................................... 53
Largest N-2 Event .................................................................................................................. 53
Largest Total Plant with Common Voltage Switchyard ........................................................ 54
Largest Resource Event in Last 10 Years ............................................................................... 54
Recommended Resource Contingency Protection Criteria .................................................. 55
Comparison of Alternative IFRO Calculations ............................................................................... 56
IFRO Formulae .......................................................................................................................... 56
Determination of Maximum Delta Frequencies ....................................................................... 57
Largest N-2 Event ...................................................................................................................... 58
Largest Total Plant with Common Voltage Switchyard ............................................................ 59
Largest Resource Event in Last 10 Years................................................................................... 60
Recommended IFROs................................................................................................................ 61
Special IFRO Considerations ..................................................................................................... 61
iii
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
000082
Comparison of IFRO Calculations.............................................................................................. 63
Allocation of IFRO to Balancing Authorities.................................................................................. 66
Frequency Response Performance Measurement ....................................................................... 68
Interconnection Process ........................................................................................................... 68
Frequency Event Detection, Analysis, and Trending (for Metrics and Analysis) .................. 68
Ongoing Evaluation ............................................................................................................... 69
Balancing Authority Level Measurements ................................................................................ 69
Single-Event Compliance....................................................................................................... 70
Balancing Authority Frequency Response Performance Measurement Analysis .................... 71
Event Sample Size ................................................................................................................. 72
Measurement Methods – Median, Mean, or Regression Results ........................................ 72
Role of Governors ......................................................................................................................... 79
Deadband and Droop................................................................................................................ 79
ERCOT Experience ..................................................................................................................... 80
Frequency Regulation ........................................................................................................... 80
Turbine-Generator Performance with Reduced Deadbands ................................................ 84
Generator Governor Survey...................................................................................................... 87
Administrative Findings ........................................................................................................ 87
Summary of the Survey Responses....................................................................................... 88
Reported Deadband Settings ................................................................................................ 90
Reported Droop Settings ...................................................................................................... 92
Governor Status and Operational Parameters ..................................................................... 93
Response to Selected Frequency Events .............................................................................. 94
Future Analysis Work Recommendations..................................................................................... 99
Testing of Eastern Interconnection Maximum Allowable Frequency Deviations .................... 99
Frequency Response Initiative Report – October 2012
iv
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000083
Table of Contents
Eastern Interconnection Inter-area Oscillations – Potential for Large Resource Losses ......... 99
This report was approved by the Planning Committee October 4, 2012, via e-mail vote.
This report was accepted by the Operating Committee October 12, 2012, via e-mail vote.
v
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000084
Introduction
Introduction
System planning and operations experts are anticipating significantly higher penetrations of
renewable energy resources, most of which are electronically coupled to the grid. This presents
some new and different technical challenges, particularly in the reduction of system inertia
through the displacement of conventional generation resources during light load periods. Load
management and other demand-side initiatives also continue to grow. Most importantly, a
continued downward trend for frequency response over a number of years has raised concern
that credible contingencies may result in frequency excursions that encroach on the first step of
under-frequency load shedding (UFLS). Such large frequency excursions could also trigger
undesirable reactions from frequency-sensitive smart grid loads and electronically coupled
renewable resources. Taken together, it is clear that maintaining adequate frequency response
for bulk power system reliability is becoming more important and complex. While the decline in
frequency response has lessened in the last couple of years, it is important that the industry
understands the growing complexities of frequency control and is ready with comprehensive
strategies to stay ahead of any potential problems.
NERC has undertaken various activities over the past few years in an effort to understand the
steady decline in frequency response, particularly in the Eastern Interconnection. While some
significant insight has been gained and system-wide and technical improvements have been
achieved in the Western Interconnection and ERCOT, a deeper and more dedicated effort is
needed.
To comprehensively address the issues related to frequency response, NERC launched the
Frequency Response Initiative in 2010. In addition to coordinating the myriad of efforts
underway in standards development and performance analysis, the initiative includes
performing in-depth analysis of interconnection-wide frequency response to achieve a better
understanding of the factors influencing frequency performance across North America.
Basic objectives of the Frequency Response Initiative include:
1
•
development of a clearer and more specific statement of frequency-related reliability
factors, including better definitions for “ownership” of responsibility for frequency
response;
•
collection and provision of more granular frequency response data on and technical
analyses of frequency-driven bulk power system events, including root cause analyses;
•
metrics and benchmarks to improve frequency response performance tracking;
•
increasing coordinated communication and outreach on the issue to include webinars
and NERC alerts and to share lessons learned; and
•
focused discussion on communication of emerging technology issues, including
frequency-related effects caused by renewable energy integration, smart grid
technology deployment, and new end-use technology.
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Introduction
000085
In March 2011, the NERC Planning Committee tasked the Transmission Issues Subcommittee
(TIS, now the System Analysis and Modeling Subcommittee (SAMS)) with determining what
criteria should be used to decide the appropriate level of interconnection-wide frequency
response needed for reliability. The TIS started with a body of work already underway by the
Resources Subcommittee (RS) and the Frequency Working Group (FWG) of the Operating
Committee, and the Frequency Responsive Reserve Standard Drafting Team (FRRSDT). The RS
produced a position paper on frequency response outlining the method to translate a resource
contingency criterion into an Interconnection Frequency Response Obligation (IFRO).
The report on IFRO was approved by the Planning Committee September 2011. 2 Since that
time, numerous modifications and improvements have been made to the IFRO determination
analysis and calculations. Those changes are reflected in the IFRO section of this report.
This report provides an overview of the work that has been done to date toward gaining
understanding of frequency response. It is in support of NERC Standards Project 2007-12
Frequency Response, which is preparing a revised draft standard (BAL-003-1). That standard is
intended to codify a Frequency Response Obligation and means for measuring the performance
of the Balancing Authorities.
2
http://www.nerc.com/docs/pc/tis/Agenda_Item_5.d_Draft_TIS_IFRO_Criteria%20Rev_Final.pdf
Frequency Response Initiative Report – October 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000086
Executive Summary
Executive Summary
Recommendations
1.
NERC should embark immediately on the development of a NERC Frequency Response
Resource Guideline to define the performance characteristics expected of those
resources for supporting reliability. That guideline should address appropriate
parameters for the following:
•
Existing conventional generator fleet – In order to retain or regain frequency
response capabilities of the existing generator fleet, adopt:
o
o
o
o
o
•
deadbands of ±16.67 mHz,
droop settings of 3%–5% depending on turbine type,
continuous, proportional (non-step) implementation of the response,
appropriate operating modes to provide frequency response, and
appropriate outer-loop controls modifications to avoid primary frequency
response withdrawal at a plant level.
Other frequency-responsive resources – Augment existing generation response with
fast-acting, electronically coupled frequency responsive resources, particularly for
the arresting and rebound periods of a frequency event:
o
o
o
o
contractual high-speed demand-side response,
wind and photo-voltaic – particularly for over-frequency response,
storage – automatic high-speed energy retrieval and injection, and
variable-speed drives – non-critical, short-time load reduction.
2.
Instead of using a fixed margin, the calculation of the Interconnection Frequency
Response Obligations should use statistical analysis to determine the necessary margin.
3.
The starting frequency for the calculation of IFROs should be the frequency 5% of the
lower tail of samples from the statistical analysis, representing a 95% confidence that
frequencies will be at or above that value at the start of any frequency event, as shown
in table A.
Table A: Interconnection Frequency Variation Analysis (Hz)
3
Value
Eastern
Western
ERCOT
Québec
Starting Frequency (FStart)
59.974
59.976
59.963
59.972
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000087
Executive Summary
4.
The recommended UFLS first-step limitations for IFRO calculations are listed in table B.
Table B: Low-frequency Limits (Hz)
Interconnection
5.
Highest UFLS Trip Frequency
Eastern
59.5 3
Western
59.5
ERCOT
59.3
Québec
58.5
The allowable frequency deviation (starting frequency minus the highest UFLS step)
should be reduced to account for differences between the 1-second and sub-second
data for Point C (frequency nadir) by a statistically determined adjustment as listed in
table C. Sub-second measurements will more accurately detect Point C.
Table C: Analysis of 1-Second and Sub-Second Data for Point C (CCADJ)
Number
of
Samples
Mean
Standard
Deviation
CCADJ
(95% Quantile)
Eastern
30
0.0006
0.0038
0.0068
Western
17
0.0012
0.0019
0.0044
ERCOT
58
0.0021
0.0061
0.0121
Québec
0
N/A
N/A
N/A
Interconnection
6.
The allowable change in frequency from the IFRO Starting Frequency should be adjusted
by a statistically determined value to account for the differences between the Value B
and the Point C for historical frequency events as listed in table D.
Table D: Analysis of B Value and Point C (CBR)
3
4
Interconnection Number of Samples
Mean
Eastern
Western
ERCOT
Québec5
0.964
1.570
1.322
1
41
30
88
N/A
Standard
Deviation
CBR
(95% Quantile)
0.0149
0.0326
0.0333
1.0 (0.989)4
1.625
1.377
1.550
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
CBR value limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not need to be adjusted. The
calculated value is 0.989.
Frequency Response Initiative Report – October 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000088
Executive Summary
7.
An adjustment should be made to the maximum allowable delta frequency to
compensate for the predominant withdrawal of primary frequency response exhibited
in an interconnection until such withdrawal is no longer exhibited in that
interconnection.
8.
The determination of the maximum delta frequencies should be calculated in
accordance with the methods embodied in Table E – Determination of Maximum Delta
Frequencies.
Table E: Determination of Maximum Delta Frequencies
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Minimum Frequency
Limit
59.500
59.500
59.300
58.500
Hz
Base Delta Frequency
0.474
0.476
0.663
1.472
Hz
CCADJ6
0.007
0.004
0.012
N/A
Hz
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
Hz
CBR7
1.0008
1.625
1.377
1.5509
Hz
Delta Frequency
(DFCBR)10
0.467
0.291
0.473
0.949
Hz
BC’ADJ11
.018
N/A
N/A
N/A
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
5
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 millisecond operating time (responsive to Point C) and 59.0 Hz UFLS step
with a 20‐second delay (responsive to Value B or beyond) with a 0.05 Hz confidence interval. See the Adjustment for Differences between
Value B and Point C section of this report for further details.
6
Adjustment for the differences between 1‐second and sub‐second Point C observations for frequency events.
7
Adjustment for the differences between Point C and Value B.
8
CBR value for the Eastern Interconnection limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not
need to be adjusted. The calculated value is 0.989.
9
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 ms operating time (responsive to Point C) and 59.0 Hz UFLS step with a 20‐
second delay (responsive to Value B or beyond).
10
DFCC/CBR
11
Adjustment for the event nadir being below the Value B (Eastern Interconnection only) due to primary frequency response withdrawal.
5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000089
Executive Summary
9.
The Interconnection Frequency Response Obligations should be calculated as shown in
Table F: Recommended IFROs.
Table F: Recommended IFROs
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
2,740
2,750
1,700
MW
–
300
1,400
–
MW
-1,002
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 13
40.6%
71.2%
48.7%
23.9%
% of Interconnection
Load 14
0.17%
0.56%
0.45%
0.50%
Credit for LR
IFRO
12
10.
NERC and the Western Interconnection should analyze the FRO allocation implications
of the Pacific Northwest RAS generation tripping of 3,200 MW.
11.
Trends in frequency response sustainability should be measured and tracked by
observing frequency between T+45 seconds and T+180 seconds. A pair of indices for
gauging sustainability should be calculated comparing that value to both the Point C and
Value B.
12.
Frequency response performance by Balancing Authorities should not be judged for
compliance on a per-event basis.
13.
Linear regression is the method that should be used for calculating Balancing Authority
Frequency Response Measure (FRM) for compliance with Standard BAL-003-1 –
Frequency Response.
12
IFRO =
13
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
14
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000090
Executive Summary
14.
NERC and the Frequency Working Group should annually review the process for
detection of frequency events and the method for calculating the A and B Values and
Point C. The associated interconnection frequency event database, methods for
calculating interconnection metrics on risks to reliability, the associated probabilities,
and the calculation of the IFROs using updated data should also undergo review in an
effort to improve the process. Throughout this process, NERC should strive to improve
the quality and consistency of the data measurements.
15.
NERC should address improving the level of understanding of the role of turbine
governors through seminars and webinars, with educational materials available to the
Generator Owners and Generator Operators on an ongoing basis.
16.
When the Eastern Interconnection Reliability Assessment Group Multiregional Modeling
Working Group (ERAG MMWG) completes its review of turbine governor modeling, a
new light-load case should be developed, and the resource loss criterion for the Eastern
Interconnection’s IFRO should be re-simulated.
17.
Eastern Interconnection inter-area oscillatory behavior should be further investigated by
NERC, including the testing of large resource loss analysis for IFRO validation.
Findings
1.
Analysis of data submitted by the Balancing Authorities during the field trial indicates
that a single-event-based compliance measure is unsuitable for compliance evaluation
when based on data that has the large degree of variability demonstrated by the field
trial.
2.
Analysis of data submitted by the Balancing Authorities during the field trial confirms
that the sample size selected (a minimum of 20–25 frequency events) is sufficient to
stabilize the result and alleviate the perceived problem associated with outliers in the
measurement of Balancing Authority frequency response performance.
3.
There is a strong positive correlation between Eastern Interconnection load and
frequency response for the 2009–2011 events. On average, when interconnection load
changes by 1,000 MW, frequency response changes by 3.5 MW/0.1Hz.
4.
Pre-disturbance frequency (Value A) is a statistically significant contributor to the
variability of frequency response for the Eastern Interconnection. The expected (mean
of the sample) frequency response for events where Value A is greater than 60 Hz is
2,188 MW/0.1 Hz versus 2,513 MW/0.1 Hz for events where Value A is less than or
equal to 60 Hz based on data from 2009 through April 2012.
5.
There is a statistically significant seasonal (summer/not summer) correlation to the
variability of frequency response for the Eastern Interconnection. The expected
frequency response for summer (June–August) frequency events is 2,598 MW/0.1 Hz
versus 2,271 MW/0.1 Hz for non-summer events based on data from 2009 through April
2012.
7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Executive Summary
6.
000091
The difference in average frequency response between on-peak events and off-peak
events is not statistically significant for the Eastern Interconnection and could occur by
chance.
Frequency Response Initiative Report – October 2012
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000092
Frequency Response Overview
Frequency Response Overview
To understand the role frequency response plays in system reliability, it is important to
understand the different components of frequency control and the individual components of
Primary Frequency Control (also known as frequency response). It is also important to
understand how those individual components relate to each other.
Frequency Control
Frequency control can be divided into four overlapping windows of time:
Primary Frequency Control (frequency response) – Actions provided by the
interconnection to arrest and stabilize frequency in response to frequency deviations.
Primary Control comes from automatic generator governor response, load response
(typically from motors), and other devices that provide an immediate response based on
local (device-level) control systems.
Secondary Frequency Control – Actions provided by an individual Balancing Authority or
its Reserve Sharing Group to correct the resource-load unbalance that created the
original frequency deviation, which will restore both Scheduled Frequency and Primary
frequency response. Secondary Control comes from either manual or automated
dispatch from a centralized control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced
basis that are coordinated so there is a net-zero effect on area control error (ACE).
Examples of Tertiary Control include dispatching generation to serve native load,
economic dispatch, dispatching generation to affect interchange, and re-dispatching
generation. Tertiary Control actions are intended to replace Secondary Control
Response by reconfiguring reserves.
Time Control – This includes small offsets to scheduled frequency to keep long-term
average frequency at 60 Hz.
Primary Frequency Control – Primary Frequency Response
Primary Frequency Control, also known generally as primary frequency response, is the first
stage of frequency control and is the response of resources and load to arrest local changes in
frequency. Primary frequency response is automatic, is not driven by any centralized system,
and begins within seconds after the frequency changes, rather than minutes. Different
resources, loads, and systems provide primary frequency response with different response
times, based on current system conditions such as total resource/load mix and characteristics.
9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
000093
The NERC Glossary of Terms defines Frequency Response 15 in two parts:
•
Equipment – The ability of a system or elements of the system to react or respond to a
change in system frequency.
•
System – The sum of the change in demand, plus the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 hertz (MW/0.1 Hz).
Because the loss of a large generator is much more likely than a sudden loss of an equivalent
amount of load, frequency response is typically discussed in the context of a loss of generation.
NOTE: For purposes of this report, the term “frequency response” is considered to be the
overall response measured between T+20 and T+52 seconds, as used in the BAL-003-1 draft
standard.
Frequency Response Illustration
Many components are included within the defined frequency response. The following
simplified example graphically illustrates those components of frequency response and how
they react to changes in system frequency. The example is presented as an energy balance
problem for the interconnection. It is not intended to be a treatise on governors or other
turbine-generator controls or the internal machine dynamics associated with those control
actions. For additional information on those topics, see the References on Rotating Machines
section in Appendix L.
The example is based on an assumed disturbance event due to the sudden loss of 1,000 MW of
generation. Although a large event is used to illustrate the response components, even small
events can result in similar reactions or responses. The magnitude of the event only affects the
shape of the curves on the graph; it does not obviate the need for frequency response.
The loss of generation is illustrated by the black power deficit line using the MW scale on the
left. The interconnection frequency is illustrated in red, using the hertz (Hz) scale on the right.
The interconnection frequency is assumed to be 60 Hz when the disturbance occurs.
Figure 1 shows the tripping of a 1,000 MW generator. Even though the generation has tripped
and power injected by the generator has been removed from the interconnection, the loads
across the system continue to use the same amount of power. The Law of Conservation of
Energy 16 requires that the 1,000 MW must be supplied to the interconnection if the energy
balance is to be conserved. That 1,000 MW of balancing power is provided by extracting it from
the kinetic energy stored as inertial energy in the rotating mass of all of the synchronized
turbine-generators and motors on the interconnection. It is produced by the slowing of the
spinning inertial mass of rotating equipment on the interconnection that both releases the
stored kinetic energy and reduces the frequency of the interconnection. The extracted energy
15
16
Capitalized as referenced in the NERC Glossary of Terms; lowercased otherwise.
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power—which is the first
derivative of energy with respect to time—must also be conserved.
Frequency Response Initiative Report – October 2012
10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000094
Frequency Response Overview
supplies the “balancing inertia” 17 power required to maintain the power and energy balance on
the interconnection.
Figure 1: Loss of a 1,000 MW Generator
As this balancing power from inertia is used, the speed of the rotating equipment on the
interconnection declines, resulting in a reduction of the interconnection frequency.
Synchronously operated motors contribute to load damping; adjustable or variable speed drive
motors are effectively decoupled from the interconnection frequency through their electronic
controls, and they do not contribute to load damping. In general, any load that does not
change with interconnection frequency (such as resistive loads) will not contribute to load
damping or frequency response. The balancing inertia is illustrated in figure 2 by the orange
dots, which represent the balancing inertia power that exactly overlays and offsets the power
deficit. At this point in the example, no other energy injection has occurred through any
governor control action.
17
The term “balancing inertia” is coined here from the terms “inertial frequency response” and “balancing energy.” Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response, and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
000095
Figure 2: Inertial Energy Extracted from Rotating Mass of Generation and
Synchronous Motor Load
As the rotating machines slow down (reflected as a decline of frequency), the generator
governors, which are the controls that “govern” the speed of the generator turbines, sense this
as a change in turbine speed. In this example, the change in frequency will be used to reflect
this control parameter. Governor action then takes physical action, such as injecting more gas
into a gas turbine, opening steam valves wider on a steam unit (also injecting more fuel into the
boiler), or opening the control gates wider on a hydraulic turbine. This control action results in
more combusted gases, steam, or water to impart more mechanical energy to the shaft of the
turbine to increase its speed. The turbine shaft is coupled to the generator, where it is
converted into additional electric energy. The process of the turbine slowing, the detection of
change in speed, and the injection of additional mechanical energy is not instantaneous.
Until the additional mechanical energy can be injected, the frequency continues to decline, due
to the ongoing extraction of balancing power from the inertial energy of the rotating turbinegenerators and synchronous motors on the interconnection. As frequency continues to decline,
the reduction in load also continues as the effect of load damping continues to reduce the load.
Frequency Response Initiative Report – October 2012
12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000096
Frequency Response Overview
Figure 3: Time Delay of Governor Response
During the initial seconds of the disturbance event, the primary frequency response from the
turbine governors has not yet influenced the frequency decline. For this example, primary
frequency response from governors that injects additional energy into the system is reflected
by the blue line (in MW) on figure 3.
After a short time delay, the governor response begins to increase rapidly in response to the
initial decline in frequency, as illustrated in figure 4. In order to arrest the frequency decline,
the governor response must offset the power deficit and replace the balancing power that had
extracted inertial energy from the rotating machines of the interconnection. At this point in
time, the balancing power from inertia is reduced to zero as it is replaced by the governor
response. That replacement is shown as the crossing of the orange and blue lines in figure 4.
The point at which the frequency decline is arrested is called the nadir, or Point C, and
frequency response calculated to that point is “arrested frequency response.”
If the time delay associated with the delivery of governor response is reduced, the amount of
balancing power from inertia required to limit the change in frequency for the disturbance
event can also be reduced. This supports the conclusion that balancing power from inertia is
required to manage the time delays associated with the delivery of primary frequency
response. Not only is the rapid delivery of primary frequency response important, but so is the
shortening of the time delay associated with its delivery.
13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
000097
Figure 4: Governor Response Replaces Balancing Power from Inertia and
Arrests Frequency Decline
The above components are related to the length of time before the initial delivery of primary
frequency response from governors begins and how much of the response is delivered before
the frequency change is arrested.
From a system standpoint during this time delay, the amount of inertia on the interconnection,
which determines the amount of energy available to be extracted from rotating machines,
determines the slope of the frequency decline: the less inertia there is, the steeper the slope.
This is important in the relationship between the balancing power from inertia and the time
delay associated with the governor response. For a given time delay in primary frequency
response from governors, the steeper the slope, the lower frequency will dip before it is
arrested. Conversely, for a given balancing power from inertia and slope of frequency decline,
the faster governor response can be provided, the sooner the frequency decline is arrested,
making the nadir less severe.
Therefore, as traditional rotating generators are replaced by electronically coupled resources,
such as wind turbines and solar voltaic resources (which provide less overall system inertia), the
speed of delivery of governor response should increase, or other methods should be provided
that support fast-acting energy injection to minimize the depth of frequency excursions.
The arrested frequency is normally the minimum (maximum for load loss events) frequency
that will be experienced during a disturbance event. This minimum frequency is the frequency
that is of concern from a reliability perspective. The goal is to arrest the frequency decline so
frequency remains above the under-frequency load shedding (UFLS) relays with the highest
settings so that load is not tripped. Frequency response delivered after frequency is arrested at
Frequency Response Initiative Report – October 2012
14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000098
Frequency Response Overview
this minimum provides less reliability value than frequency response delivered before Point C,
but greater value than secondary frequency control power and energy that is delivered minutes
later.
Figure 5: Post-Disturbance Transient Period (0 to 20 seconds)
Point C
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with the governor action. This results in the frequency partially recovering
from the minimum arrested value and results in some oscillating transient that follows the
minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period, which typically ends around 20 seconds after start of the disturbance event.
This post-disturbance transient period is shown in figure 5.
The total disturbance event is illustrated in figure 6. Frequency and power contributions
stabilize at the end of the transient period. Frequency response calculated from data measured
during this settled period is called the “settled frequency response.” The settled frequency
response is the measure used as an estimator for determining the Frequency Bias 18 setting
used in the automated generator control (AGC) systems of the energy management systems
(EMS) in energy control centers.
18
As defined in the NERC Glossary: “A value, usually expressed in megawatts per 0.1 hertz (MW/0.1 Hz), associated with a Balancing Authority
Area that approximates the Balancing Authority Area’s response to Interconnection frequency error.”
15
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000099
Frequency Response Overview
Figure 6: Disturbance Event Frequency Excursion
Point C
Figure 7: Averaging Periods used for Measuring Frequency Response
Frequency Response Initiative Report – October 2012
16
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000100
Frequency Response Overview
Figure 7 shows the averaging periods used to calculate 19 the pre-disturbance Value A frequency
averaging period (T-16 through T+0 seconds) and the post-disturbance Value B frequency
averaging period (T+20 through T+52 seconds) used to calculate the settled frequency
response. The length of those periods is based on the length of the system control and data
acquisition (SCADA) scan rates of the energy management systems (EMS) of the Balancing
Authorities.
The calculation of the Value A and Value B frequencies began with the assumption that a 6second scan rate was the source of the data. Once the averaging periods for a 6-second SCADA
scan rate were selected, the averaging periods for the other scan rates were selected to provide
as much consistency as possible between Balancing Authorities with different scan rates.
The Value A frequency was initially defined as the average of the two scans immediately prior
to the frequency event. All other averaging periods were then selected to be as consistent as
possible with this 12-second average scan from the 6-second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” was then defined as the average of
the same period and same scans as used for Value A averaging.
The Value B frequency was then selected to be an average as long as the average of 6-second
scan data as possible, that would not begin until most of the hydro governor response had been
delivered, and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” was then similarly defined as the
average of the same period and same scans as used for the Value B.
Balancing Authority Frequency Response
Disturbances can cause the frequency to either increase from loss of load or decrease from loss
of generation; frequency response characteristics of Balancing Authorities should be evaluated
for both types of events.
Accurate measurement of frequency response for an interconnection or for individual
Balancing Authorities is difficult unless the frequency deviation resulting from a system
disturbance is significant. Therefore, it is better to analyze response only when significant
frequency deviations occur.
Frequency response considers the following elements of an interconnected transmission
system:
1.
Frequency Response Characteristic (FRC) – For any change in generation/load balance
in the interconnection, a frequency change occurs. Each Balancing Authority in the
interconnection will respond to this frequency change through:
•
19
a load change that is proportional to the frequency change due to the load’s FRC,
and
As proposed in Standard BAL-003-1 – Frequency Response.
17
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
•
000101
a generation change that is inverse to the frequency change due to turbine governor
action. The net effect of these two actions is the Balancing Authority’s response to
the frequency change; that is, its FRC. The combined response of all Balancing
Authorities in the interconnection will cause the interconnection frequency to settle
at some value different from the pre-disturbance value. It will not return frequency
to the pre-disturbance value because of the turbine governor droop characteristic.
Frequency will remain different until the Balancing Authority with the
generation/load imbalance (referred to as the “Contingent Balancing Authority”)
corrects that imbalance, thus returning the interconnection frequency to its predisturbance value.
2.
Response to Internal and External Generation/Load Imbalances – Most of a Balancing
Authority’s frequency response will be reflected in a change in its actual net
interchange. By monitoring the frequency error (the difference between actual and
scheduled frequency) and the difference between actual and scheduled interchange,
using its response to frequency deviation, a Balancing Authority’s automatic generation
control (AGC) can determine whether the imbalance in load and generation is internal
or external to its system. If internal, the Balancing Authority’s AGC should correct the
imbalance. If external, the Balancing Authority’s AGC should allow its generator
governors to continue responding (preserved by its frequency bias contribution in its
ACE equation) until the contingent Balancing Authority corrects its imbalance, which
should return frequency to its pre-disturbance value.
3.
Frequency Bias versus Frequency Response Characteristic (FRC) – The Balancing
Authority should set its bias setting in its AGC ACE equation to match its FRC. In doing
so, the Balancing Authority’s bias contribution term would exactly offset the tie line flow
error (NiA – NiS) of the ACE that results from governor action following a frequency
deviation on the interconnection. The following sections discuss the effects of bias
settings on control action and explain the importance of setting the bias equal to the
Balancing Authority’s FRC. The discussion explains the control action on all Balancing
Authorities external to the contingent Balancing Authority (the Balancing Authority that
experienced the sudden generation/load imbalance) and on the contingent Balancing
Authority itself.
While this discussion deals with loss of generation, it applies equally to loss of load, or
any sudden contingency resulting in a generation/load mismatch. Each Balancing
Authority’s frequency response will vary with each disturbance because generation and
load characteristics change continuously. This discussion also assumes that the
frequency error from 60 Hz was zero (all ACE values were zero) just prior to the sudden
generation/load imbalance.
4.
Effects of a Disturbance on all Balancing Authorities External to the Contingent
Balancing Authority – When a loss of generation occurs, an interconnection frequency
error will occur as rotating kinetic energy from the generators of the interconnection is
expended, slowing the generators throughout the interconnection. All Balancing
Authorities’ generator governors will respond to the frequency error and increase the
Frequency Response Initiative Report – October 2012
18
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000102
Frequency Response Overview
output of their generators (increase speed) accordingly. This will cause a change in the
Balancing Authorities’ actual net interchange. In other words, the Actual Net
Interchange (NiA) will be greater than the Scheduled Net Interchange (NiS) for all but the
contingent Balancing Authority, and the result is a positive flow out of the noncontingent Balancing Authorities. The resulting tie flow error (NiA – NiS) will be counted
as Inadvertent Interchange.
If the Balancing Authorities were using only tie line flow error (i.e., flat tie control
ignoring the frequency error), this non-zero ACE would cause their AGC to reduce
generation until NiA was equal to NiS, returning their ACE to zero. However, doing this
would not help arrest interconnection frequency decline, because the Balancing
Authorities would not be helping to temporarily replace some of the generation
deficiency in the interconnection. With the tie line bias method, the Balancing
Authorities’ AGC should allow their governors to continue responding to the frequency
deviation until the contingent Balancing Authority replaces the generation it has lost.
In order for the AGC to allow governor action to continue to support frequency, a
frequency bias contribution term is added to the ACE equation to counteract the tie
flow error. This bias contribution term is equal in magnitude and opposite in direction
to the governor action and should ideally be equal to each Balancing Authority’s
frequency response characteristic measured in MW/0.1 Hz. Then, when multiplied by
the frequency error, the bias should exactly counteract the tie flow error portion of the
ACE calculation, allowing the continued support of the generator governor action to
support system frequency.
In other words, BiasContributionTerm
= 10 B ( f A − f S ) . ACE will be zero, and AGC will
not read just generation.
The ACE equation is then:
ACE = ( NiA − NiS ) − 10 B( f A − f S ) − I ME
Where:
• The factor 10 converts the bias setting (B) from MW/0.1 Hz to MW/Hz.
•
IME is meter error correction estimate; this term should normally be very small or
zero.
NOTE: Although frequency response and bias are often discussed as positive values
(such as “our bias is 50 MW/0.1 Hz”), frequency response and bias are actually negative
values.
If the bias setting is greater than the Balancing Authority’s actual frequency response
characteristic, then its AGC will increase generation beyond the primary frequency
response from governors, which further helps arrest the frequency decline, but
increases Inadvertent Interchange. Likewise, if the bias contribution term is less than
19
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
000103
the actual FRC, its AGC will reduce generation, reducing the Balancing Authority’s
contribution to arresting the frequency change. In both cases, the resultant control
action is unwanted.
5.
Effects of a Disturbance on the Contingent Balancing Authority – In the contingent
Balancing Authority where the generation deficiency occurred, most of the replacement
power comes from the interconnection over its tie lines from the frequency response
contributions of the other Balancing Authorities in the interconnection. A small portion
will be made up internally from the contingent Balancing Authority’s own governor
response. In this case, the difference between NiA and NiS for the contingent Balancing
Authority is much greater than its frequency bias component. Its ACE will be negative (if
the loss is generation), and its AGC will begin to increase generation.
•
NiA – drops by the total generation lost less the contingent Balancing Authority’s
own primary frequency response from governors
•
NiS – does not change
The contingent Balancing Authority must take appropriate steps to reduce its ACE to
zero or pre-disturbance ACE if ACE is negative within 15 minutes of the contingency.
(Reference: formerly Operating Criterion II.A.) The energy supplied from the
interconnection is posted to the contingent Balancing Authority’s inadvertent balance.
6.
Effects of a Disturbance on the Contingent Balancing Authority with a Jointly Owned
Unit – In the contingent Balancing Authority where the generation deficiency occurred
on a jointly owned unit (with dynamically scheduled shares being exported), the effect
on the tie line component (NiA – NiS) of their ACE equation is more complicated. The NiA
drops by the total amount of the generator lost, while the NiS is reduced only by the
dynamic reduction in the shares being exported.
•
NiA – drops by the total generation lost less the contingent Balancing Authority’s
own primary frequency response from governors
•
NiS – decreases by the reduction in dynamic shares being exported
The net effect is that the tie line bias component only reflects the contingent Balancing
Authority’s share of the lost generation. Most of the replacement power comes from
the interconnection over its tie lines from the frequency bias contributions of the other
Balancing Authorities in the interconnection.
7.
Effects of a Disturbance on the Non-contingent Balancing Authority with a Jointly
Owned Unit – In the non-contingent Balancing Authority where the generation
deficiency occurred on a jointly-owned unit in another Balancing Authority (with
dynamically scheduled shares being exported), the effect on the tie line component (NiA
– NiS) of their ACE equation is also complicated. The NiA increases by the Balancing
Authority’s own primary frequency response from governors, while the NiS is reduced
only by the dynamic reduction in the shares being imported.
Frequency Response Initiative Report – October 2012
20
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000104
Frequency Response Overview
•
•
NiA – increases by the Balancing Authority’s own primary frequency response
from governors
NiS – decreases by withdrawn dynamic shares of the jointly-owned unit
The net effect is that the tie line bias component only reflects the contingent Balancing
Authority’s share of the lost generation. Most of the replacement power comes from
the interconnection over its tie lines from the frequency bias contributions of the other
Balancing Authorities in the interconnection.
21
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
000105
Historical Frequency Response Analysis
History of Frequency Response and its Decline
Interconnection frequency response has been a subject of industry interest and attention since
the first two electric systems became interconnected and the concept of frequency bias was
adopted. In 1942, the first test to determine the system’s load/frequency characteristic was
conducted for use in setting bias control. As interconnected systems grew larger and the
characteristics of load and generation changed, it became apparent that guidelines were
needed regarding frequency response to avoid one system imposing undue frequency
regulation burdens on its interconnected neighbors. During the 1970s and 1980s, NERC’s
Performance Subcommittee (now the Resources Subcommittee of the Operating Committee),
which is charged with monitoring the control performance of the interconnections, observed
that generators’ governor responses to frequency deviations had been decreasing, especially in
the Eastern Interconnection. The result was quite noticeable during large generation losses
where the frequency deviation was not arrested as quickly as it once was. The industry did not
initially recognize that power systems operations could significantly influence primary
frequency response. 20
In 1991, NERC’s Performance Subcommittee approached the Electric Power Research Institute
(EPRI) with a request to fund and manage a study of the apparent decline in governor response
in the interconnections. EPRI agreed and in turn contracted with EPIC Engineering to perform
this study. The conclusions were captured in a joint EPRI/NERC report, “Impacts of Governor
Response Changes on the Security of North American Interconnections.” 21 These studies
indicated that the frequency response of the interconnections was declining at rates greater
than would be expected with the growth of demand and generating capacity. 22 Although
frequency response was declining, the opinion of experts at the time was that the decline had
not reached a point at which reliability was being compromised.
The NERC Resources Subcommittee proposed a frequency response standard for comment in
2001. In response to these comments, the Frequency Task Force of the NERC Resources
Subcommittee published a Frequency Response Standard white paper 23 intended to create an
understanding of the need for a frequency response standard and the technical and economic
drivers motivating its development. The paper documented and discussed the decline
observed in frequency response in the Eastern and Western Interconnections.
20
See Illian, H.F. Frequency Control Performance Measurement and Requirements, LBNL-4145E (December 2010).
EPRI Report TR-101080, Impacts of Governor Response Changes on the Security of North American Interconnections, October 1992.
22
See EPRI Report TR-101080, Impacts of Governor Response Changes on the Security of North American Interconnections, October 1992 (“An
analysis of the 14 Frequency Response Characteristics Surveys conducted by NERC over the 1971 to 1993 period showed that the Frequency
Response in percent MW/O. 1Hz has deteriorated. This value in 1971 was between 2.25 and 3.25% (depending on the area) and by 1993 had
dropped to 0.75 and 1.25 %.”).
23
Available here: http://www.nerc.com/docs/oc/rs/Frequency_Response_White_Paper.pdf (“Frequency Response Standard Whitepaper”).
21
Frequency Response Initiative Report – October 2012
22
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000106
Historical Frequency Response Analysis
P rojections of Frequency R esponse Decline
In August 2011, the Transmission Issues Subcommittee 24 of the NERC Planning Committee
completed an analysis titled “Interconnection Criteria for Frequency Response Requirements –
Determination of Interconnection Frequency Response Obligations.” 25 The analysis included
comparisons of various Resource Contingency Protection Criteria for loss of resources, including
largest potential loss-of-resource event (N-2), the largest total generating plant with common
voltage switchyard, and the largest loss of generation in the interconnection in the last 10
years. Also examined in that analysis were the various other factors that must be considered in
an IFRO determination: the highest under-frequency load shedding (UFLS) program setpoint
within each interconnection, special consideration of demand-side frequency responsive
programs in ERCOT, and a reliability margin to account for the variability of frequency due to
items such as time error correction (TEC), variability of load, variability of interchange,
variability of frequency over the course of a normal day, and other uncertainties. The proposed
margin was analyzed using a probabilistic approach based on 1-minute frequency performance
data for each interconnection. The Transmission Issues Subcommittee recommended the
following IFROs for the four interconnections: Eastern: -1,875 MW/0.1 Hz; Western: -637
MW/0.1 Hz; Texas: -327 MW/0.1 Hz; and Québec: -113 MW/0.1 Hz. The Transmission Issues
Subcommittee IFRO report was approved by the NERC Planning Committee in September 2011
and forwarded to the Standard Drafting Team for their consideration.
A similar report had been prepared by the Resources Subcommittee of the NERC Operating
Committee in January 2011 titled “NERC Resources Subcommittee Position Paper on Frequency
Response.” 26 That report used similar Resource Contingency Protection Criteria but used the
prevalent 59.5 Hz highest UFLS setpoint for the Eastern Interconnection and a lower 59.3 Hz
UFLS setpoint for ERCOT. The Resources Subcommittee analysis also used a 25% reliability
margin for all four interconnections. The Resources Subcommittee recommended the following
IFROs for the four interconnections: Eastern: -1,406MW/0.1 Hz; Western: -685 MW/0.1 Hz;
Texas: -286 MW/0.1 Hz; and Québec: -141 MW/0.1 Hz. The Resources Subcommittee position
paper was approved by the Operating Committee in March 2011 and was considered by the
Frequency Response Standard Drafting Team. NERC has been tracking the decline of frequency
response in the Eastern Interconnection for several years.
24
The Transmission Issues Subcommittee is now the System Analysis and Modeling Subcommittee (SAMS).
Available here: http://www.nerc.com/docs/pc/tis/Agenda_Item_5.d_Draft_TIS_IFRO_Criteria%20Rev_Final.pdf.
26
Available here:
http://www.nerc.com/docs/oc/rs/NERC%20RS%20Position%20Paper%20on%20Frequency%20Response%20Final%20(May%2027%202011).p
df.
25
23
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000107
Historical Frequency Response Analysis
Figure 8: Eastern Interconnection Mean Primary Frequency Response 27
(March 30, 2012)
4,000
Source 1994-2009: J. Ingleson & E. Allen, "Tracking the
Eastern Interconnection Frequency Governing
Characteristic" presented at 2010 IEEE PES.
Source 2010-2011: Daily Automated Reliability Reports
3,500
*
* 1999 Data Interpolated
MW / 0.1 Hz
3,000
2,500
2,000
1,500
1,000
Year
Figure 8 shows how frequency response has declined since 1994, as filed in NERC’s “Motion for
an Extension of Time of the North American Electric Reliability Corporation” (for the
development of Standard BAL-003-1 – Frequency Response). 28 That request for extension of
time was granted by FERC in its Order on Motion for an Extension of Time and Setting
Compliance Schedule (Issued May 4, 2012). 29
Comparing the proposed IFROs from those two studies, the Eastern Interconnection IFROs
range from about 1,400 MW/0.1 Hz to about 1,900 MW/0.1 Hz, and the linear projection of the
frequency response decline intercepts those target IFROs between 2019 and 2024. Even the
more pessimistic polynomial projection of the decline intercepts the proposed IFROs between
2014 and 2016. This shows that there was still some time as of that filing for revising BAL-003-1
and responding to the decline in frequency response.
Figure 8 was revised shortly after the March 2012 filing in conjunction with revised frequency
response calculation methods used in NERC’s 2012 State of Reliability report (May 2012).
Figure 9 reflects the revised frequency response calculations for 2009 through 2011.
27
The Frequency Response data from 1994 through 2009 displayed in figure 2 is from a report by J. Ingleson & E. Allen, Tracking the Eastern
Interconnection Frequency Governing Characteristic that was presented at the 2010 IEEE.
28
Filing available at: http://www.nerc.com/files/MotionExtTime_RM06-16_03302012.pdf
29
Order available at: http://www.nerc.com/files/Order_Motion_Extension_Time_Compliance_Sched_2012.5.4.pdf
Frequency Response Initiative Report – October 2012
24
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000108
Historical Frequency Response Analysis
Figure 9: Updated Eastern Interconnection Mean Primary Frequency Response
(May 2012)
4,000
Source 1994-2009: J. Ingleson & E. Allen, "Tracking the
Eastern Interconnection Frequency Governing
Characteristic" presented at 2010 IEEE PES.
Source 2009-2011: Reliability Metrics Working Group
3,500
* 1999 Data Interpolated
*
MW / 0.1 Hz
3,000
Change in Value A & B
Calculation Method
2,500
2,000
1,500
1,000
Year
Figure 9 shows an improvement in frequency response in 2009 through 2011 due to alignment
of the methods for calculation Values A and B. That method is consistent with the method
being proposed in NERC Standard BAL‐003‐1. The method has since been further refined, as
reflected in the Statistical Analysis of Frequency Response section of this report.
Figures 10–13 show the statistical analysis of the frequency response for 2009–2011 for the
Eastern, Western, and ERCOT Interconnections from the 2012 State of Reliability report in box
plot format (only 2011 data was available for the Québec Interconnection).
Figure 10: Eastern Interconnection Frequency Response Analysis for 2009–2011
4500
4000
Frequency Response (MW/0.1 Hz)
3500
3000
2,206
2,200
2,312
2500
First Quartile
Minimum
Median
2000
Maximum
Third Quartile
1500
1000
500
0
2009
25
2010
Period
2011
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000109
Historical Frequency Response Analysis
Figure 11: Western Interconnection Frequency Response Analysis for 2009–2011
5000
4500
4000
Frequency Response
3500
3000
First Quartile
2500
Minimum
1,635
1,623
1,521
2000
Median
Maximum
Third Quartile
1500
1000
500
0
2010
Period
2009
2011
Figure 12: ERCOT Interconnection Frequency Response Analysis for 2009–2011
1800
1600
1400
Frequency Response
1200
1000
First Quartile
Minimum
576
567
800
511
Median
Maximum
Third Quartile
600
400
200
0
2009
2010
Period
2011
It is important to note the range of variability of the frequency response for each year.
Additional events and modifications to the calculation methods for the A, B, and C values have
been made since these values were calculated for the May 2012 report. The new values are
reflected in the Statistical Analysis section of this report.
Frequency Response Initiative Report – October 2012
26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000110
Historical Frequency Response Analysis
Figure 13: Québec Interconnection Frequency Response Analysis for 2011
900
800
700
506
Frequency Response
600
500
First Quartile
Minimum
400
Median
Maximum
Third Quartile
300
200
100
0
2011
Period
Statistical Analysis of Frequency Response (Eastern
Interconnection)
In July 2012, a statistical analysis of the frequency response of the Eastern Interconnection was
performed for the calendar years 2009–2011 and the first three months of 2012. The size of
the dataset was 163 (with 44 observations for 2009, 49 for 2010, 65 for 2011, and 5 for 2012).
Table 1: Statistical Analysis Dataset
Sample Parameter
Sample Size
Sample Mean
Sample Standard
Deviation
2009
2010
2011
44
49
65
2,258.4
2,335.7
2,467.8
522.5
697.6
593.7
The report on that analysis was updated in August and September 2012 and is contained in
Appendix G. Its results are paraphrased here for brevity. For the analysis, frequency response
pertains to the absolute value of frequency response.
K ey Statistical Findings
1. A linear regression equation with the parameters defined in Appendix G is an adequate
statistical model to describe the relationship between time (predictor) and frequency
response (responsive variable). The graph of the linear regression line and frequency
response scatter plot is given in figure 14.
27
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
000111
Figure 14: Linear Regression Fit Plot for Eastern Interconnection Frequency Response
2. The probability distribution of the whole frequency response dataset is approximately
normal, with an expected frequency response of 2,363 MW/0.1 Hz and a standard deviation
of 605.7 MW/0.1 Hz as shown in figure 15.
Figure 15: Probability Distribution Eastern Interconnection Frequency Response
January 2009–April 2012
Frequency Response Initiative Report – October 2012
28
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000112
Historical Frequency Response Analysis
3. There is a statistically significant seasonal (summer/not summer) correlation to the
variability of frequency response for the Eastern Interconnection. The expected frequency
response (mean of the samples) for summer (June–August) frequency events is 2,598
MW/0.1 Hz versus 2,271 MW/0.1 Hz for non-summer events. This is attributable to at least
two factors: higher load contribution to frequency response and increased generation
dispatch of units with higher frequency response characteristics.
4. Pre-disturbance (average) frequency (Value A) is another statistically significant contributor
to the variability of frequency response. The expected frequency response (mean of the
samples) for events where Value A is greater than 60 Hz is 2,188 MW/0.1 Hz versus 2,513
MW/0.1 Hz for events where Value A is less than or equal to 60 Hz.
Figure 16: Linear Regression for Frequency Response and Interconnection Load
5. The difference in average frequency response between on-peak events and off-peak events
is not statistically significant and could occur by chance. According to the NERC definition,
Eastern Interconnection on-peak hours are designated as follows: Monday to Saturday from
07:00 to 22:00 hours (Central Time) excluding six holidays: New Year’s Day, Memorial Day,
Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Analysis showed that
the on-peak/off-peak variable is not a statistically significant contributor to the variability of
frequency response. There is a positive correlation of 0.06 between the indicator function
of on-peak hours and frequency response; however, difference in average frequency
response between on-peak events and off-peak events is not statistically significant and
could occur by chance (P-value—the probability of obtaining a result at least as extreme—is
0.49).
29
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000113
Historical Frequency Response Analysis
6. There is a strong positive correlation of 0.364 between interconnection load and frequency
response for the 2009–2011 events. On average, when interconnection load changes by
1,000 MW, frequency response changes by 3.5 MW/0.1 Hz.
This correlation indicates a statistically significant linear relationship between
interconnection load (predictor) and frequency response (response variable). Figure 16
shows the linear regression line and frequency response scatter plot. For the dataset, the
regression line has a positive slope estimate of 0.00349; thus, the frequency response
variable increases when interconnection load grows.
7. For the 2009–2011 dataset, five variables (time, summer, high pre-disturbance frequency,
on-peak/off peak hour, and interconnection load) were involved in the statistical analysis of
frequency response. Four of these—time, summer, on-peak hours, and interconnection
load—have a positive correlation with frequency response (0.16, 0.24, 0.06, and 0.36,
respectively), and the high pre-disturbance frequency has a negative correlation with
frequency response (-0.26). The corresponding coefficients of determination R2 (the square
of correlation) indicate that about 2.6% in variability of frequency response can be
explained by the changes in time, about 5.8% is seasonal, 0.4% is due to on-peak/off-peak
changes, 13.3% is the effect of interconnection load variability, and about 6.9% can be
accounted for by a high pre-disturbance frequency. However, the correlation between
frequency response and on-peak hours is not statistically significant, with the probability of
about 0.44 having occurred by mere chance (the same holds true for the corresponding R2).
Table 2: Explanatory Variables for Eastern Interconnection
Frequency Response
P-Value
Linear
Regression
Statistically
Significant
Coefficient of
Determination
R2 (Single
Regression)
0.36
<0.0001
Yes
13.3%
Value A > 60 Hz
-0.26
0.0008
Yes
6.9%
Summer/Not
Summer
0.24
0.0023
Yes
5.8%
Date
0.16
0.044
Yes
2.6%
On-Peak Hours
0.06
0.438
No
N/A
Sample
Correlation
(X, FR)
Interconnection
Load
Variable X
Therefore, out of the five parameters, interconnection load has the biggest impact on
frequency response followed by the indicator of high pre-disturbance frequency. A
multivariate regression with interconnection load and starting frequency (Value A) greater
Frequency Response Initiative Report – October 2012
30
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000114
Historical Frequency Response Analysis
than 60 Hz as the explanatory variables for frequency response yields a linear model with
the best fit (it has the smallest mean square error among the linear models with any other
set of explanatory variables selected from the five studied). Together these two factors can
account for about 20% of the variability in frequency response.
Frequency response is, therefore, affected by other parameters that have low correlation with
those studied and account for the remaining share of frequency response variability, minimizing
the random error variance.
Note that interconnection load is positively correlated with summer (0.55), on-peak hours
(0.45), and time (0.20), but is uncorrelated with starting frequency greater than 60 Hz (P-value
of the test on zero correlation is 0.90).
Frequency Response Withdrawal
Withdrawal of primary frequency response is an undesirable characteristic associated most
often with digital turbine-generator control systems using setpoint output targets for generator
output. These are typically outer-loop control systems that defeat the primary frequency
response of the governors after a short time to return the unit to operating at a requested MW
output.
Figure 17: Primary Response Sustainability
0.0
100.0
Time (sec)
Blue = frequency response is sustained
Red = generator has a “slow” load controller returning to MW set-point
Figure 17 shows how the outer-loop control on a single machine would influence its ability to
provide primary frequency response.
Some of the typical causes of the withdrawal are:
•
•
31
Plant outer-loop control systems – driving the units to MW setpoints
Unit characteristics
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
•
000115
o Plant incapable of sustaining primary frequency response
o Governor controls overridden by other turbine/steam cycle controls
Operating philosophies – operating characteristic choices made by plant operators
o Desire to maintain highest efficiencies for the plant
The phenomenon is most prevalent in the Eastern Interconnection and can easily be seen in the
comparison of the typical frequency response performance of the three interconnections
(figure 18).
Figure 18: Typical Interconnection Responses for 2011 30
Sustainability of primary frequency response becomes more important during light load
conditions (nighttime) when there are generally fewer frequency-responsive generators online.
A number of the governor survey questions addressed the operational status and parameters
of the governor fleet. The results of the survey show:
•
About 90% of the generators were reported to have governors.
30
NERC interconnections 2011 typical event frequency patterns using the median of the same second of each RS−FWG selected event –
Revised: 09/26/12 provided by Advanced Systems Researchers.
Frequency Response Initiative Report – October 2012
32
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000116
Historical Frequency Response Analysis
•
•
•
Virtually all (95–99% by interconnection) of the GOs and GOPs reported that their
governors are operational.
80–85% (by interconnection) of the governors were reported to be capable of sustaining
primary frequency response for longer than 1 minute if the frequency remained outside
of their deadband.
Roughly 50% of the governors reported that they had unit-level or plant-level control
systems that override or limit governor performance.
Despite the fact that the majority of generators reported they have operational turbine
governors, half of them have unit- or plant-level control systems that override governor
responses. These control systems allow the units to return to scheduled output (MW setpoint)
or an optimized operating point for economic reasons. These factors heavily influence the
sustainability of primary frequency response, contributing to the withdrawal symptom often
observed. This is often evident during light load periods in the middle of the night when highefficiency, low-cost units that operate on MW setpoints are the majority of the generators
dispatched to serve load.
This was exhibited by two events involving generator trips in the spring of 2012 in one
weekend. During the first event (figure 19), 1,711 MW of generation was tripped with a typical
-2,369 MW/0.1 Hz frequency response.
Figure 19: 3:30 pm Saturday Afternoon 1,711 MW Resource Loss
Value A
60.021 HZ
ΔF = 0.0722 Hz
FR = -2,369 MW/0.1 Hz
Value B
59.948 Hz
33
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000117
Historical Frequency Response Analysis
The second event (figure 20) occurred late Sunday night when load in the Eastern
Interconnection was much lighter, and the generators dispatched—probably the most efficient
units—were of a different character. Despite the resource loss being almost 700 MW less, the
frequency response of the interconnection was significantly reduced and exhibited the “lazy L”
of primary frequency response withdrawal. Point C defined to occur during the first 8 seconds
(at that time) was 59.962 Hz, while a lower point of about 59.939 Hz occurred about 1 minute
after the event.
Figure 20: 11:21 pm Sunday Night 1,049 MW Resource Loss
Value A
60.026 HZ
ΔF = 0.0799 Hz
FR = -1,312 MW/0.1 Hz
Value B
59.946 Hz
Point C’
These two events point to the composition of the dispatch and the characteristics of the units
on-line as primary elements in the frequency response strength, as well as the key elements in
creating withdrawal. Therefore, when calculating an Interconnection Frequency Response
Obligation (IFRO), it is important for operational planners and operators to recognize the
potential for that withdrawal and the frequency consequentially being lower one to two
minutes after the beginning of the event.
A similar withdrawal was experienced during the major frequency excursion of August 4, 2007
(figure 21). During that event some 4,500 MW of generation was lost.
The lowest frequency in the event was 59.868 Hz at about one minute after the start. Recovery
to pre-event frequency was about 8 minutes, but the measurement of Value B (20 to 52
seconds) would not capture the lowest frequency. That frequency point is the true frequency
Frequency Response Initiative Report – October 2012
34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000118
Historical Frequency Response Analysis
event nadir, hereafter referred to as Point C’ (“Point C Prime”), and is normally equal to Point C
for events that don’t exhibit the so-called “lazy L” effect.
It is important that the phenomenon be recorded and trended to determine if it is improving or
deteriorating.
Figure 21: Interconnection Frequency – August 4, 2007 EI Frequency Excursion
Recommendation – Measure and track frequency response sustainability trends by observing
frequency between T+45 seconds and T+180 seconds. A pair of indices for gauging
sustainability should be calculated comparing that value to both Point C and Value B.
Modeling of Frequency Response in the Eastern Interconnection
Modeling of frequency response characteristics has been a known problem since at least 2008,
when forensic modeling of the Eastern Interconnection required a “de-tuning” of the existing
MMWG dynamics governor to 20% of modeled (80% error) to approach the measured
frequency response values from the event.
Figure 22 shows the response comparison for that event analysis. Although the event was an
over-frequency problem at that point, it is indicative of the larger problem of governor
modeling in the Eastern Interconnection. The problem was further highlighted in the 2010 “Use
of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable
Integration of Variable Renewable Generation,” by Ernest Orlando Lawrence Berkeley National
Laboratory (LBNL). In that analysis, an attempt was made to simulate a 4,500 MW loss event
that occurred on August 4, 2007. Figure 23 shows a comparison of the simulation to the
measured frequency from the event.
35
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000119
Historical Frequency Response Analysis
Figure 22: 2007 Event Frequency Response Forensic Analysis
Actual (DFR)
Simulation with 20%
governor response
Simulation with
original modeled
governor response
Figure 23: Eastern Interconnection Frequency Response – August 4, 2007 Initial 20 Seconds
As part of the NERC Frequency Response Initiative and the Modeling Improvements Initiative,
NERC collaborated with the Eastern Interconnection Reliability Assessment Group (ERAG)
Multiregional Modeling Working Group (MMWG) to perform an analysis of the modeling of
overall frequency response in the Eastern Interconnection. That review was a prelude to a plan
Frequency Response Initiative Report – October 2012
36
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000120
Historical Frequency Response Analysis
for thorough examination of the governor models in the Eastern Interconnection dynamics
study cases that are assembled by the MMWG. That report stated, “The turbine-governor
modeling currently reflected in the MMWG dynamics simulation database is not a valid
representation of the frequency control behavior of the Eastern Interconnection.”
That project created a “generic case” dynamics model, replacing the turbine governor models
in the case with a generic governor model in order to ascertain the basic characteristics of the
frequency response of the Eastern Interconnection. Figure 24 shows a comparison of the actual
event data and the simulations using the original governor data and the generic case.
The characteristics found in that study were:
•
•
•
Only 30% of the units on-line provide primary frequency response.
Two-thirds of the units that did respond exhibit withdrawal of primary frequency
response.
Only 10% of units on-line sustain primary frequency response.
Figure 24: Comparison of Legacy and Generic Simulations to August 4 Event
Following that study, a follow-on analysis was performed by NERC staff to determine the
general order of magnitude of a frequency event that could be sustained by the Eastern
Interconnection without violating the 59.7 Hz first step UFLS in FRCC. A simulation was run that
tripped about 8,500 MW of generation in the southeast United States (north of Florida). Figure
25 shows the result of that testing.
37
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000121
Historical Frequency Response Analysis
The simulation showed that the lowest frequency would be about 59.76 Hz in southern Florida.
The initial nadir of 59.78 Hz in southern Florida is lower than the nadir in northern Florida due
to the wave properties of the disturbance.
Figure 25: 8,500 MW Resource Loss Simulation
60.10
60.05
Blue = Duval (Northern FL)
Green= Turkey Point (Southern FL)
60.00
59.95
Frequency (Hz)
59.90
59.85
59.80
59.75
59.78 Hz
59.76 Hz
59.70
59.65
59.60
Time (seconds)
Although the simulations using the generic governor models are not exact, that analysis is
indicative of the Eastern Interconnection’s ability to sustain a resource loss event significantly
higher than the Resource Contingency Protection Criteria proposed in this report.
Concerns for Future of Frequency Response
There is a growing concern about the future of frequency response in light of a number of
factors:
•
Electronically coupled resources – The incorporation of renewable resources such as
wind and solar and the increasing penetration of variable speed motor drives presents a
continuing erosion of system inertia; all are electronically coupled to the system. As
such, those resources, unless specifically designed to mimic inertial response, do not
have inertial response.
•
Electronically coupled loads – As synchronous motors are replaced by variable speed
drives, the load response of the motors is eliminated by the power electronics of the
motor controller. This reduces the load damping factor for the interconnection.
•
Displacement of traditional turbine-generators in the dispatch – Traditional turbinegenerators are being displaced in the dispatch, particularly during off-peak hours when
wind generation is at its highest and the loads and generation levels are at their lowest.
Frequency Response Initiative Report – October 2012
38
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000122
Historical Frequency Response Analysis
Such displacement of frequency responsive resources increasingly depletes the inertia
of the interconnection at those times.
Role of Inertia in Frequency Response
Inertia plays a crucial role in determining the slope of a frequency decline during a resource loss
event.
The slope of frequency excursion is determined by the inertia of the system and a factor to
account for the load damping characteristics of the interconnection.
2
Where:
D = Load Damping Factor
The load damping factor ranges from 0 to 2, where 2 would represent a load of
all motors.
H = Inertia Constant of the interconnection
The inertia constant ranges from 2.5 to 6.5
Figure 26 shows the sensitivity of frequency response to changes to system inertia. The lower
green curve represents an inertia constant of 2.5, and the lower red curve represents an inertia
constant of 5.0.
Figure 26: Frequency Response Sensitivity to System Inertia
39
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000123
Historical Frequency Response Analysis
Figure 27 shows an actual example from ERCOT of how frequency response is changed for
similarly sized resource loses with differences in inertia. It is clear that when the inertia on the
system is lower, a similar resource MW loss creates a much steeper and deeper frequency
excursion. This is a good example of the displacement of traditional resources with
electronically coupled resources during light load periods.
Figure 27: Inertial Response Sensitivity
High Inertia
Light Inertia
Need for Higher Speed P rim ary Frequency R esponse
The reduction of inertia drives a need for higher speed response to frequency excursions. If the
slope of the frequency decline is steeper, it is necessary for high-speed injection of energy to
arrest the decline in order to prevent the excursion from being too deep. Such energy injection
can come from a number of sources, such as energy storage devices and wind turbines with
modified inverters.
P reservation or I m provem ent of Existing Generation P rim ary Frequency
R esponse
Additionally, to further ensure strong overall frequency response, it is important to preserve or
improve the primary frequency response of the existing generation fleet. The Role of
Governors section of this report discusses the results of the 2010 survey on generator
governors. The survey results show that there is a significant portion of the existing generator
fleet that has operational governors. However, the reported deadband ranges make those
governors ineffective for all but catastrophic losses of resources. Figure 28 shows the reported
deadband ranges.
Frequency Response Initiative Report – October 2012
40
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000124
Historical Frequency Response Analysis
If the existing generator fleet primary frequency response performance can be improved
through adjustments in deadbands and implementation of no‐step droop responses, a
significant improvement in interconnection frequency response could be realized. Further, if all
of the existing generators were made capable of response, any generators that are on‐line
during light load periods would be more able to provide response.
Figure 28: Reported Governor Deadband Settings
400
700
700
<500 MW
500-1000
MW
2000
540
Deadband Setting (mHz)
350
300
250
200
150
100
50
0
East
>1000 MW
<500 MW
500-1000
MW
West
>1000 MW
<500 MW
500-1000
MW
>1000 MW
Texas
Unit Size
The Role of Governors section of this report recommends immediate development of a NERC
turbine‐generator governor guideline calling for deadbands of ±16.67 mHz with droop settings
of 4%–5% depending on turbine type in order to retain or regain frequency response
capabilities of the existing generator fleet.
Withdrawal of Primary Frequency Response
Withdrawal of primary frequency response caused by outer‐loop control systems must be
addressed. As shown in the Frequency Response Withdrawal section of this report, frequency
response during light load periods can be highly influenced by the mix of dispatched resources.
Economics of the dispatch dictates that the most efficient, cost‐effective generation will remain
on‐line during those periods. Such generation employs setpoint controls that return generation
to AGC‐prescribed or efficiency‐prescribed generation levels regardless of system frequency.
This results in “squelching” of any primary frequency response that the governors may have
provided during a frequency event. This withdrawal of primary response before secondary
frequency response from AGC becomes effective starting at about T+45 to T+60 seconds,
creating the “lazy L” event response prevalent in the Eastern Interconnection.
To illustrate this effect, a dynamic simulation of a 3,700 MW resource loss frequency event was
performed for the Eastern Interconnection using the generic dynamics case described in the
Modeling of Frequency Response in the Eastern Interconnection section of this report. Two
simulation runs were performed to mimic about 1,400 MW/0.1 Hz frequency response
41
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000125
Historical Frequency Response Analysis
(between 20 and 52 seconds), with different combinations of generator dispatch and differing
amounts of response “squelch.” Figure 29 shows that the effects on frequency response
sustainability can be highly influenced by the composition of the resource dispatch, even with
the same measured frequency response.
There are potential ways of alleviating this withdrawal symptom, including introduction of a
frequency bias into the outer-loop controls systems that would prevent withdrawal of primary
frequency response, similar to the frequency bias settings in an automatic generation control
(AGC) system.
Recommendation – NERC should include guidance on methods to reduce or eliminate the
effects of primary frequency response withdrawal by outer-loop unit or plant control systems.
Figure 29: Simulations of Varying Levels of Primary Frequency Response Withdrawal
Eastern Interconnection
3,700 MW Resource Loss
1,400 MW/0.1 Hz Response
Lower
Squelch
59.7 Hz
Higher
Squelch
59.5 Hz
Note that these simulation runs were done for illustrative purposes only; the simulations are
not yet accurate enough to confidently predict system performance, and AGC secondary
frequency response was NOT simulated. Secondary frequency response from AGC becomes
effective starting at about T+45 to T+60 seconds.
Frequency Response Initiative Report – October 2012
42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000126
Interconnection Frequency Response Obligation (IFRO)
Interconnection Frequency Response Obligation
(IFRO)
Tenets of IFRO
The IFRO is intended to be the minimum amount of frequency response that must be
maintained by an interconnection. Each Balancing Authority in the interconnection should be
allocated a portion of the IFRO that represents its minimum responsibility. In order to be
sustainable, Balancing Authorities that may be susceptible to islanding may need to carry
additional frequency responsive reserves to coordinate with their under-frequency load
shedding (UFLS) plans for islanded operation.
A number of methods to assign the frequency response targets for each interconnection can be
considered. Initially, the following tenets should be applied:
1. A frequency event should not trip the first stage of regionally approved UFLS systems within
the interconnection.
2. Local tripping of first-stage UFLS systems for severe frequency excursions, particularly those
associated with protracted faults or on systems on the edge of an interconnection, may be
unavoidable.
3. Other frequency-sensitive loads or electronically coupled resources may trip during such
frequency events (as is the case for photovoltaic inverters in the Western Interconnection).
4. Other susceptible frequency sensitivities may have to be considered in the future (e.g.,
electronically coupled load common-mode sensitivities).
UFLS is intended to be a safety net to prevent against system collapse from severe
contingencies. Conceptually, that safety net should not be violated for frequency events that
happen on a relatively regular basis. As such, the resource criteria are selected to avoid
violating UFLS settings approved by the Regional Entities.
The Frequency Responsive Reserve Standard Drafting Team (FRRSDT) is proposing an
administered value approach for the BAL-003-1 field trial. Eventually, an agreed-upon method
of determining the interconnection FRO will be included in a reliability standard, or in the NERC
Rules of Procedure. 31
31
http://www.nerc.com/files/NERC_Rules_of_Procedure_EFFECTIVE_20110412.pdf
43
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000127
Interconnection Frequency Response Obligation (IFRO)
Statistical Analyses
Frequency Variation Statistical Analysis
A statistical analysis of the variability of frequency for each of the four interconnections was
performed using 1-second measured frequency for the Eastern, Western, and ERCOT
Interconnections for 2007–2011 (five years). Data for the Québec Interconnection was only
available for 2010 and 2011. Analysis of data showed the Western Interconnection frequency
deviations (Epsilon) to be more volatile since the Balancing Authority ACE Limit (BAAL) field trial
began there in March of 2010. Therefore, it was decided to limit the analysis to the years
2009–2011 to more accurately portray the current frequency characteristics.
This variability accounts for items such as time error correction; variability of load, interchange,
and frequency over the course of a normal day; and other uncertainties, including time error
corrections and all frequency events—no large events were excluded. The results of the
analysis are shown in table 3.
Table 3: Interconnection Frequency Variation Analysis (Hz)
Value
Eastern
Western
ERCOT
Québec
2009–2011
2009–2011
2009–2011
2010–2011
91,283,555
90,446,802
85,924,929
34,494,049
Expected Value
60.0000367
59.9999522
59.9999847
60.00002303
Maximum Value
60.3090
60.3575
62.1669
60.8776
Minimum Value
59.0015
59.7364
58.0000
59.1879
Variance of Frequency
(σ²)
0.00024092
Hz2
0.00022266
Hz2
0.00060749
Hz2
0.00035315
Hz2
σ
0.01552147
0.01492184
0.02464722
0.01879236
2σ
0.03104295
0.02984369
0.04929445
0.03758472
3σ
0.04656442
0.04476553
0.07394167
0.05637708
59.974
59.976
59.963
59.972
Timeframe
Number
32
of Samples
Starting Frequency (FStart)
5% of lower tail samples
32
Numbers of samples vary due to exclusion of data drop-outs and other obvious observation anomalies.
Frequency Response Initiative Report – October 2012
44
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000128
Interconnection Frequency Response Obligation (IFRO)
For each interconnection, the distribution of the interconnection frequency fails the normality
test (both the chi-square goodness-of-fit and the Kolmogorov-Smirnov goodness-of-fit) at any
standard significance level. The combined datasets for the interconnection frequency consist of
very large numbers of observations. For such large samples, the empirical distribution can be
considered as a very good approximation of the actual distribution of the frequency, and was
judged a better predictor than use of standards deviation for predicting the interconnection
starting frequencies for an event. The rate of convergence in the Glivenko-Cantelli theorem is
n(-1/2), where n is the sample size. Therefore, quantiles of the empirical distribution function
can be used directly to calculate intervals where values of frequency belong with any predetermined probability.
Only resource losses (frequency drops) are examined for IFRO calculations, so the focus is on
the one-sided lower tail of the distribution for frequencies that fall outside the upper 95%
interval of the overall distribution. Therefore, the starting frequency that should be used for
the calculation of the IFROs is the 10% quantile frequency value, which represents a 95%
confidence in the prediction for that single tail.
Those starting frequencies encompass all variations in frequency, including changes to the
target frequency during time error correction. That eliminates the need to expressly evaluate
TEC as a variable in the IFRO calculation.
Recommendation – The starting frequency for the calculation of IFROs should be frequency of
the 5% of lower tail of samples from the statistical analysis, representing a 95% confidence that
frequencies will be at or above that value at the start of any frequency event.
45
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000129
Interconnection Frequency Response Obligation (IFRO)
Figures 30–33 show the interconnection histograms broken into 1-mHz “bins.” A complete set
of graphs for the four interconnections is located in Appendix D of this report.
Figure 30: Eastern Interconnection 2009–2011 Frequency Histogram
4.5
4
Percentage of Observations (%)
3.5
3
2.5
2
1.5
1
0.5
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure 31: Western Interconnection 2009–2011 Frequency Histogram
0.035
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Frequency Response Initiative Report – October 2012
46
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000130
Interconnection Frequency Response Obligation (IFRO)
Figure 32: ERCOT Interconnection 2009–2011 Frequency Histogram
0.016
0.014
Percentage of Observations (%)
0.012
0.01
0.008
0.006
0.004
0.002
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Note that the ERCOT frequency histogram displays the influence of the “flat-top” f profile that
was common to that interconnection prior to 2008. That phenomenon was caused by a
standardized ±36 mHz deadband with a step-function implementation. Additional discussion
on that topic is in the ERCOT Experience section of this report.
Figure 33: Québec Interconnection 2010–2011 Frequency Histogram
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
47
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000131
Interconnection Frequency Response Obligation (IFRO)
P oint C Analysis – One-second versus Sub-second Data
Additional statistical analysis was performed for the differences between Point C and Value B
calculated as a ratio of Point C to Value B using 1-second data for events from December 2010
through May 2012. Although the 1-second data sample is robust, it does not necessarily ensure
the nadir of the event was accurately captured. To do so requires sub-second measurements
that can only be provided by PMUs or FDRs. Therefore, a “CC” adjustment component (CCADJ)
for the IFRO calculation was designed to account for the differences observed between the 1second Point C and high-speed Point C measurements.
Table 4: Analysis of One-second and Sub-second Data for Point C (CCADJ)
Number
of
Samples
Mean
Standard
Deviation
CCADJ
(95% Quantile)
Eastern
30
0.0006
0.0038
0.0068
Western
17
0.0012
0.0019
0.0044
ERCOT
58
0.0021
0.0061
0.0121
0
N/A
N/A
N/A
Interconnection
Québec
33
This adjustment should be made to the allowable frequency deviation value before it is
adjusted for the ratio of Point C to Value B. Note: No sub-second data was available for the
Québec Interconnection.
Recommendation – The allowable frequency deviation (starting frequency minus the highest
UFLS step) should be reduced by the CCADJ to account for differences between the 1-second and
sub-second data for Point C as listed in table B-C9.
Adjustm ent for Differences betw een Value B and P oint C
All of the calculations of the IFRO are based on protecting from instantaneous or time-delayed
tripping of the highest step of UFLS, either for the initial nadir (Point C), or for any lower
frequency that might occur during the frequency event. The frequency variance analysis in the
previous section of this report is based on 1-second data from 2007 through 2011 (except
Québec 2010 and 2011 only).
As a practical matter, the ability to measure the tie line and loads for the Balancing Authorities
is limited to system control and data acquisition (SCADA) scan-rate data of 1–6 seconds.
Therefore, the ability to measure frequency response of the Balancing Authorities is still limited
by the SCADA scan rates available to calculate Point B.
33
Sub-second data from Québec was not available.
Frequency Response Initiative Report – October 2012
48
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000132
Interconnection Frequency Response Obligation (IFRO)
Candidate events from the ALR1‐12 Interconnection Frequency Response selection process
(Appendix E) for frequency response analysis were used to analyze the relationship between
Value B and Point C for the significant frequency disturbances from December 2010 through
May 2012. This sample set was selected because data was available for the analysis on a
consistent basis. This resulted in the number of events shown in table 5.
Analysis Method
When evaluating some physical systems, the nature of the system and the data resulting from
measurements derived from that system do not fit the standard linear regression methods that
allow for both a slope and an intercept for the regression line. In those cases, it is better to use
a linear regression technique that represents the system correctly.
The Interconnection Frequency Response Obligation is a minimum performance level that must
be met by the Balancing Authorities in an interconnection. Such response is expected to come
from the frequency response in MWs of the Balancing Authorities to a change in frequency. As
such, if there is no change in frequency there should be no change in MWs resulting from
frequency response.
This response is also related to the function of the frequency bias setting in the ACE equation of
the Balancing Authorities for longer term. The ACE equation looks at the difference between
scheduled frequency and actual frequency times the frequency bias setting to estimate the
amount of MWs that are being provided by load and generation within the Balancing Authority.
If the actual frequency is equal to the scheduled frequency, the frequency bias component of
ACE must be zero.
Since the IFRO is ultimately a projection of how the interconnection is expected to respond to
changes in frequency related to a change in MW (resource loss or load loss), there should be no
expectation of frequency response without an attendant change in MW. It is this relationship
that indicates the appropriateness of the use of regression with a forced fit through zero.
Evaluation of data to determine C‐to‐B ratio:
The evaluation of data to determine C‐to‐B ratio to account for the differences between
arrested frequency response (to the nadir, Point C) and settled frequency response (Value B) is
also based on a physical representation of the electrical system. Evaluation of this system
requires investigation of the meaning of an intercept. The C‐to‐B ratio is defined as the
difference between the pre‐disturbance frequency and the frequency at the maximum
deviation in post‐disturbance frequency, divided by the difference between the pre‐disturbance
frequency and the settled post‐disturbance frequency.
A stable physical system requires the ratio to be positive; a negative ratio indicates frequency
instability or recovery of frequency greater than the initial deviation.
49
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Interconnection Frequency Response Obligation (IFRO)
000133
Table 5: Analysis of Value B and Point C (CBR)
Number
Standard
CBR
Interconnection
of
Mean
Deviation
(95% Quantile)
Samples
Eastern
41
0.964
0.0149
1.0 (0.989)34
Western
30
1.570
0.0326
1.625
ERCOT
88
1.322
0.0333
1.377
35
Québec
1.550
This statistical analysis was completed using 1-second averaged data that does not accurately
capture Point C and is better measured by high-speed metering (PMUs or FDRs). Therefore, a
separate correction must be used to account for the differences between the Point C in the 1second data and the Point C values measured with sub-second measurements from the FNet
FDRs.
The CBR value for the Eastern Interconnection indicates that the Value B is generally below the
Point C value. Therefore, there is no adjustment necessary for that interconnection.
The Québec Interconnection’s resources are predominantly hydraulic and are operated to
optimize efficiency, typically at about 85% of rated output. Consequently, most generators
have about 15% headroom to supply primary frequency response. This results in a robust
response to most frequency events, exhibited by high rebound rates between Point C and the
calculated B Value. For the 26 frequency events in their event sample, Québec’s CBR value
would be 3.613, or two to three times as high as the CBR value of other interconnections. Using
the same calculation method for CBR would effectively penalize Québec for their outstanding
rebound performance and make their IFRO artificially high. Therefore, the method for
calculating the Québec CBR was modified.
Québec operates with an operating mandate for frequency responsive reserves to protect from
tripping their 58.5 Hz (300 ms trip time) first step UFLS for their largest hazard at all times,
effectively protecting against tripping for Point C frequency excursions. They also protect
against tripping a UFLS step set at 59.0 Hz that has a 20-second time delay, which protects them
for Value B low frequency and any withdrawals. This results in a Point C to Value B ratio of 1.5.
To account for the confidence interval, 0.05 is then added, making the CBR = 1.550.
Adjustm ent for P rim ary Frequency R esponse W ithdraw al
At times, the nadir for a frequency event occurs after Point C—defined in BAL-003-1 as
occurring in the T+0 to T+12 second period, during the Value B averaging period (T+20 through
T+52 seconds), or later. For purposes of this report, that later occurring nadir is termed Point
34
CBR value limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not need to be adjusted. The
calculated value is 0.989.
35
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 millisecond operating time (responsive to Point C)and 59.0 Hz UFLS step
with a 20 second delay (responsive to Value B or beyond).
Frequency Response Initiative Report – October 2012
50
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000134
Interconnection Frequency Response Obligation (IFRO)
C’. This lower nadir is symptomatic of primary frequency response withdrawal, or squelching,
by unit or plant-level outer-loop control systems. Withdrawal is most prevalent in the Eastern
Interconnection, as described earlier.
As described in the Withdrawal of Primary Frequency Response section of this report,
frequency response withdrawal can become important depending on the type and
characteristics of the generators in the resource dispatch, especially during light load periods.
Therefore, an additional adjustment to the maximum allowable delta frequency for calculating
the IFROs was statistically developed. This adjustment should be used whenever withdrawal is
a prevalent feature of frequency events. Initially, it is only being applied to the Eastern
Interconnection.
Table 6 shows the statistical results of the analysis based on the 34 frequency response events
in the Eastern Interconnection. Note that the expected timeframe for the C’ nadir to occur is
about 82 seconds after the start of the event.
Table 6: Statistical Analysis of the Adjustment for C’ Nadir (BC’ADJ)
Value
Delta Frequency from Value
B to Point C’ Nadir
Seconds from T+0 to C’ Nadir
Number of
Samples
Mean
Standard
Deviation
BC’ADJ
(95% Quantile)
34
4.0 mHz
8.2 mHz
17.5 mHz
34
38.9 s
26.3 s
82.1 s
This BC’ADJ should be applied to the allowable delta frequency after the differences from Value
B to Point C are adjusted. The values driving this adjustment should also be carefully monitored
and the adjustment recalculated during the annual review of IFRO calculations.
Variables in Determination of Interconnection Frequency
Response Obligation from Criteria
To make a determination of the appropriate Resource Contingency Protection Criteria to
protect for a certain kind of event, the MW target value needs to be translated into an
Interconnection Frequency Response Obligation (IFRO) for an appropriate comparison. A
number of other variables must be taken into consideration.
Low Frequency Lim it
The low frequency limit to be used for the IFRO calculations should be the highest setpoint in
the interconnection for regionally approved UFLS systems.
Recommendation – Based on the tenet that UFLS should not trip for a frequency event
throughout the interconnection, the recommended UFLS first-step limitations for IFRO
calculations listed in table 7 should be used.
51
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000135
Interconnection Frequency Response Obligation (IFRO)
Table 7: Low-Frequency Limits (Hz)
Interconnection
Highest UFLS Trip Frequency
Eastern
59.5 36
Western
59.5
ERCOT
59.3
Québec
58.5
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, while the prevalent
highest setpoint in the rest of that interconnection is 59.5 Hz. The FRCC 59.7 Hz first UFLS step
is based on internal stability concerns and preventing the Florida peninsula from separation
from the rest of the interconnection. The FRCC concluded that the IFRO starting point of 59.5
Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation for an interconnection resource loss event than for an internal FRCC event.
Protection against tripping the highest step of UFLS does not ensure that generation that has
frequency-sensitive protection or turbine control systems will not trip. Severe system
conditions might drive the frequency to levels that may present protection and control systems
with a combination of conditions that may cause the generation to trip, such as severe rate of
change in voltage or frequency, which might actuate volts per hertz relays. Similarly, some
combustion turbines may not be able to sustain operation at frequencies below 59.5 Hz.
Recent laboratory testing by Southern California Edison of inverters used on residential and
commercial scale photovoltaic (PV) systems revealed a propensity to trip at about 59.4 Hz,
which is 200 mHz above the expected 59.2 Hz prescribed in IEEE Standard 1547 for distributionconnected PV rating ≤ 30 kW (57.0 Hz for larger installations). This could become problematic
in areas of high penetration of photovoltaic resources.
Credit for Load R esources (CLR )
The ERCOT Interconnection depends on contractually interruptible demand that automatically
trips at 59.7 Hz to help arrest frequency declines. A 1,400 MW Load Resource (formerly Load
acting as a Resource – LaaR) credit is included against the Resource Contingency for the ERCOT
Interconnection. Similarly, there is a remedial action scheme (RAS) in WECC that trips 300 MW
of load for the loss of two Palo Verde generating units.
For the Western Interconnection, if the larger 3,200 MW resource loss activates the RAS and
trips the Pacific DC Intertie (PDCI), the 300 MW credit for Load Resources associated with the
loss of the two Palo Verde units does not apply.
36
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
Frequency Response Initiative Report – October 2012
52
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000136
Interconnection Frequency Response Obligation (IFRO)
For both interconnections, credit for load resources is handled in the calculation of the IFRO as
a reduction to the loss of resources, when appropriate.
Interconnection Resource Contingency Protection Criteria
Selection of discrete event protection criteria for each interconnection must be done before
the IFRO can be calculated. The protection criteria selected should ensure that Point C would
not encroach on the first step UFLS. However, the criteria may need to be different from one
interconnection to the other due to the differences in size and design characteristics.
The following potential interconnection event criteria were considered:
•
largest N-2 loss-of-resource event,
•
largest total generating plant with common voltage switchyard, and
•
largest loss-of-resource event in the interconnection in the last 10 years.
Largest N-2 Event
For this approach, each interconnection will have a target Resource Contingency Protection
Criteria based on the largest N-2 loss-of-resource event. This should not be confused with a
Category C, N-2 event prescribed in the NERC TPL standards; it is intended to reflect a
simultaneous loss of the resources without time for system adjustments. As such, these events
would be considered Category D events in the current standards.
Table 8: Largest N-2 Event
Interconnection
Basis
MW
Eastern
Nelson DC Bi-poles 1 & 2
3,854 37
Western
Two Palo Verde Units
2,740 38
Two South Texas Project Units
2,750 39
ERCOT
For both the ERCOT and Western Interconnections, that would be the loss of the two largest
generating units in the interconnection. However, for the Eastern Interconnection, the largest
N-2 loss-of-resource event would be the loss of the two Nelson dc bi-pole converters.
37
Nelson Bi-poles 1 and 2 are rated 1,854 MW and 2,000 MW, respectively.
38
Net winter ratings per Form EIA-860 reporting.
39
Net rating from ERCOT Resource Asset Registration Form (RARF).
53
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000137
Interconnection Frequency Response Obligation (IFRO)
Largest Total P lant w ith Com m on Voltage Sw itchyard
Another approach is to examine the largest complete generating plant outage in each of the
interconnections, limiting this classification to those generators with a common voltage
switchyard. The reasoning for considering such a protection criteria is that despite popular
belief, complete plant outages can and do happen on a regular basis; 15 complete plant
outages occurred in North America in the 12 months from July 1, 2010 through June 30, 2011.
Table 9: Largest Total Plant with Common Voltage Switchyard
Interconnection
Basis
MW
Eastern
Darlington Units 1-4
3,524 40
Western
3 Palo Verde Units
3,575 41
2 South Texas Project Units
2,750 42
ERCOT
Note that in the Western Interconnection, multi-plant generation tripping by the operation of
the Pacific Northwest remedial action scheme (RAS) results in resource loss of 3,200 MW. That
issue is further discussed in the Special IFRO Considerations section of this report.
Largest R esource Event in Last 10 Years
A third approach is to examine the largest complete resource loss event in the interconnection
over the last 10 years. Although this method yields a reasonable value for the Eastern
Interconnection, the values for the other two interconnections would likely not be sustainable
without activating some UFLS. It also results in a larger resource contingency for the Western
Interconnection than for the Eastern Interconnection. These single events were not
approached in magnitude by any other events in the 10-year period.
Table 10: Largest Resource Contingency Event in Last 10 Years
Interconnection
Basis
MW
Eastern
August 4, 2007
Disturbance 43
4,500
Western
June 14, 2004 Disturbance 44
5,000
ERCOT
May 15, 2003 Disturbance 45
3,400
40
Net winter ratings from the NERC Electricity Supply and Demand.
Net winter ratings per Form EIA-860 reporting.
42
Net rating from ERCOT Resource Asset Registration Form (RARF).
43
The August 4, 2007 frequency excursion was a complex, multi‐faceted event involving nine generators across three states. Of those nine
generators, seven tripped because of turbine control actions, and the others tripped on instability. This was not an N‐1 event.
44
The June 14, 2004 disturbance was a complex series of events thattripped ten generators across the western Interconnection as the result of
a protracted fault. This was not an N‐1 event.
41
Frequency Response Initiative Report – October 2012
54
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000138
Interconnection Frequency Response Obligation (IFRO)
R ecom m ended R esource Contingency P rotection Criteria
Because the philosophy is for the criteria to protect against the largest frequency excursion the
interconnection can withstand, the contingency criteria may vary significantly between the
interconnections. For example, because of its sheer size and generating capacity, the Eastern
Interconnection can withstand a greater loss of resources.
Therefore, a blending of Resource Contingency Protection Criteria is recommended (table 4) for
the determination of IFROs.
Table 11: Recommended Resource Contingency Protection Criteria
Interconnection
Resource Contingency
Basis
MW
Eastern
Largest Resource Event in
Last 10 Years
August 4, 2007
Disturbance
4,500
Western
Largest N-2 Event
2 Palo Verde Units
2,740 46
ERCOT
Largest N-2 Event
2 South Texas Project
Units
2,750 47
Although the size of a resource contingency that can be sustained by an interconnection should
be tested through dynamic simulations, that test can currently be done only for the Western
and ERCOT Interconnections.
Recommendation – Dynamic simulation testing of the Western and ERCOT Resource
Contingency Protection Criteria should be conducted as soon as possible.
Recommendation – Dynamic simulation testing of the Eastern Interconnection Resource
Contingency Protection Criteria should be conducted when the dynamic simulation models of
the interconnection are capable of performing the analysis.
45
The May 15, 2003 disturbance was a complex series of events that tripped six generators due to a protracted fault. This was not an N‐1
event.
46
Net winter ratings per Form EIA-860 reporting.
47
Net rating from ERCOT Resource Asset Registration Form (RARF).
55
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000139
Comparison of Alternative IFRO Calculations
Comparison of Alternative IFRO Calculations
Each of the proposed resource loss criteria alternatives were compared through development
of the corresponding IFROs. The following tables show the calculation of an IFRO for each
alternative for the Eastern, Western, and ERCOT Interconnections. The criterion for the Québec
Interconnection was kept constant throughout.
IFRO Formulae
The following are the formulae that comprise the calculation of the IFROs.
Where:
DFBase is the base delta frequency.
FStart is the starting frequency determined by the statistical analysis.
UFLS is the highest UFLS trip setpoint for the interconnection.
CCADJ is the adjustment for the differences between 1‐second and sub‐second Point C
observations for frequency events. A positive value indicates that the sub‐second C
data is lower than the 1‐second data.
DFCC is the delta frequency adjusted for the differences between 1‐second and sub‐
second Point C observations for frequency events.
CBR is the statistically determined ratio of the Point C to Value B.
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
BC’ADJ is the statistically determined adjustment for the event nadir occurring below the
Value B (Eastern Interconnection only) during primary frequency response withdrawal.
MDF is the maximum allowable delta frequency.
RLPC is the resource loss protection criteria.
CLR is the credit for load resources.
Frequency Response Initiative Report – October 2012
56
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000140
Comparison of Alternative IFRO Calculations
•
ARLPC is the adjusted resource loss protection criteria adjusted for the credit for load
resources.
•
IFRO is the interconnection frequency response obligation.
Determination of Maximum Delta Frequencies
Because of the limitation of measurement of the Balancing Authority-level frequency response
performance using Value B, the Interconnection Frequency Obligations must be calculated in
“Value B space.” Protection from tripping UFLS for the interconnections based on Point C (the
nadir defined as occurring between T=0 and T+12 seconds in BAL-003-1), Value B (defined as
occurring from T+20 seconds to T+52 seconds), or any nadir occurring after point C, within
Value B, or after T+52 seconds must be reflected in the maximum allowable delta frequency for
IFRO calculations expressed as a Value B.
Table 12: Determination of Maximum Delta Frequencies
Eastern
Western
ERCOT
Québec
Units
59.974
59.976
59.963
59.972
Hz
Minimum Frequency Limit 59.500 48
59.500
59.300
58.500
Hz
Base Delta Frequency
0.474
0.476
0.663
1.472
Hz
CCADJ
0.007
0.004
0.012
N/A
Hz
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
Hz
1.000 49
1.625
1.377
1.550 50
Hz
Delta Frequency (DFCBR) 51
0.467
0.291
0.473
0.949
Hz
BC’ADJ
.018
N/A
N/A
N/A
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Starting Frequency
CBR
Table 12 shows the calculation of the maximum allowable delta frequencies for each of the
interconnections. All adjustments to the maximum allowable change in frequency are made to
include:
•
•
adjustments for the differences between 1-second and sub-second Point C observations
for frequency events,
adjustments for the differences between Point C and Value B, and
48
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
49
CBR value for the Eastern Interconnection limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does
not need to be adjusted. The calculated value is 0.989.
50
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 ms operating time (responsive to Point C) and 59.0 Hz UFLS step with a
20-second delay (responsive to Value B or beyond).
51
DFCC/CBR
57
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000141
Comparison of Alternative IFRO Calculations
•
adjustments for the event nadir being below the Value B (Eastern Interconnection only)
due to primary frequency response withdrawal.
Recommendation – The determination for the Maximum Delta Frequencies should be
calculated in accordance with the methods embodied in Table 12 – Determination of Maximum
Delta Frequencies.
Largest N-2 Event
Table 13 shows the determination of IFROs based on a resource loss equivalent to the largest
N-2 event in each interconnection. This calculation has been adjusted to include the
recommended adjustment for the differences between Value B and Point C, and for the
differences in measurement of Point C using 1-second and sub-second data.
Table 13: Largest N-2 Event
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
3,854
2,740
2,750
1,700
MW
300
1,400
Credit for LR
52
MW
IFRO 52
-858
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
858
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 53
34.8%
71.2%
48.7%
23.9%
% of Interconnection
Load 54
0.14%
0.56%
0.45%
0.50%
IFRO =
53
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
54
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
58
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000142
Comparison of Alternative IFRO Calculations
Largest Total Plant with Common Voltage Switchyard
Table 14 shows the determination of IFROs based on a resource loss equivalent to the largest
total plant with common voltage switchyard in each interconnection. This calculation has been
adjusted to include the recommended adjustment for the differences between Value B and
Point C, and for the differences in measurement of Point C using 1-second and sub-second data.
Table 14: Largest Total Plant with Common Voltage Switchyard
Starting Frequency
Max. Delta Frequency
Resource Contingency
Protection Criteria
Credit for LR
IFRO 55
Absolute Value of
IFRO
% of Current
Interconnection
Performance 56
% of Interconnection
Load 57
55
Eastern
59.974
0.449
Western
59.976
0.291
ERCOT
59.963
0.473
Québec
59.972
0.949
Units
Hz
Hz
3,524
3,575
2,750
1,700
MW
-785
300
-1,127
1,400
-286
-179
MW
MW/0.1Hz
785
1,127
286
23.9%
MW/0.1Hz
31.8%
95.6%
48.7%
23.9%
0.13%
0.76%
0.45%
0.50%
IFRO =
56
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
57
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
59
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000143
Comparison of Alternative IFRO Calculations
Largest Resource Event in Last 10 Years
Table 15 shows the determination of IFROs based on a resource loss equivalent to the largest
resource event in the last 10 years in each interconnection. This calculation has been adjusted
to include the recommended adjustment for the differences between Value B and Point C, and
for the differences in measurement of Point C using 1-second and sub-second data.
Table 15: Largest Resource Event in Last 10 Years
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
5,000
3,400
1,700
MW
300
1,400
Credit for LR
58
MW
IFRO 58
-1,002
-1,721
-423
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
1,721
423
179
MW/0.1Hz
% of Current
Interconnection
Performance 59
40.6%
146.0%
72.2%
23.9%
% of Interconnection
Load 60
0.17 %
1.16%
0.66%
0.50%
IFRO =
59
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
60
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
60
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000144
Comparison of Alternative IFRO Calculations
Recommended IFROs
Table 16 shows the determination of IFROs based on a resource loss equivalent to the
recommended criteria in each interconnection. This calculation has been adjusted to include
the recommended adjustment for the differences between Value B and Point C, and for the
differences in measurement of Point C using 1-second and sub-second data.
Recommendation – The Interconnection Frequency Response Obligations should be calculated
as shown in Table 16 – Recommended IFROs.
Table 16: Recommended IFROs
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
2,740
2,750
1,700
MW
300
1,400
Credit for LR
MW
IFRO 61
-1,002
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 62
40.6%
71.2%
48.7%
23.9%
% of Interconnection
Load 63
0.17%
0.56%
0.45%
0.50%
Special IFRO Considerations
The IFRO calculation scenarios for the Western Interconnection do not take into account
intentional tripping of generation during the operation of remedial action schemes (RAS). A key
example is the Pacific Northwest RAS for loss of the Pacific DC Intertie (PDCI), which trips up to
3,200 MW of generation in the Pacific Northwest when the PDCI trips, depending on the
loading of the PDCI. The RAS is intended to avoid system instability, tripping generation,
inserting the Chief Joseph braking resistor (for up to 30 cycles), and other reactive configuration
61
IFRO =
62
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
63
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
61
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000145
Comparison of Alternative IFRO Calculations
changes. However, because the generation in the Pacific Norwest is some of the most
responsive to frequency deviations in the Western Interconnection, the RAS also blocks
frequency response by a number of generators and Balancing Authorities to avoid overloading
the Pacific AC ties (such as the California–Oregon Interface (COI)).
Frequency events caused by the 3,200 MW generation trips from that RAS have not been
considered historically as candidate events for the Western Interconnection calculation of
frequency bias settings by the Balancing Authorities because of the response blocking.
However, from an interconnection perspective, the frequency of the interconnection still must
be maintained as a whole, regardless of which Balancing Authorities are responding to the
event. This creates a dilemma when calculating an IFRO for the interconnection—the resultant
resource loss is larger than the design loss criteria of two Palo Verde units (2,440 MW). Table
17 shows a comparison of the two resource losses in calculating the IFRO for the Western
Interconnection.
Table 17: Western Interconnection IFRO Comparison
2-PV
PNW RAS
Units
Starting Frequency
59.976
59.976
Hz
Max. Delta Frequency
0.291
0.291
Hz
Resource Contingency Protection Criteria
2,740
3,200
MW
Credit for LR
300
IFRO 64
-840
-1,101
MW/0.1Hz
840
1,101
MW/0.1Hz
71.2 %
93.4 %
0.56 %
0.74 %
Absolute Value of IFRO
% of Current Interconnection Performance
% of Interconnection Load
66
65
MW
Using a 3,200 MW resource loss criterion in the IFRO calculation increases the obligation by 260
MW but is further complicated when that obligation is allocated to the Balancing Authorities in
the interconnection; allocation of FRO to Balancing Authorities whose response is blocked by
the RAS is inappropriate. Therefore, a different FRO allocation would be necessary for that
IFRO.
Recommendation – NERC and the Western Interconnection should analyze the FRO allocation
implications of the Pacific Northwest RAS generation tripping of 3,200 MW.
64
IFRO =
65
Current Interconnection Frequency Response Performance: WI = -1,179 MW / 0.1Hz.
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: WI = 148,895 MW.
66
Frequency Response Initiative Report – October 2012
62
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000146
Comparison of Alternative IFRO Calculations
Comparison of IFRO Calculations
Table 18 shows a comparison of the four criteria analyzed by the TIS, as well as the criteria
recommended by the NERC Resources Subcommittee (RS) in their white paper on frequency
response. The table also compares the IFROs to current levels of frequency response
performance 67 for each of the interconnections. A comparison is also made to IFROs adjusted
to include the recommended adjustment for the differences between Value B and Point C.
Table 18: IFRO Calculation Comparison
Current Interconnection
Frequency Response Performance
Eastern
Western
ERCOT
Québec
Units
-2,467
-1,179
-586
N/A
MW/0.1Hz
Largest N-2 Event
Resource Loss Criteria
3,854
2,740
2,750
1,700
MW
IFRO
-858
-840
-286
-179
MW/0.1Hz
34.8%
71.2%
48.7%
23.9%
0.14%
0.56%
0.45%
0.50%
IFRO as % of Current Performance
IFRO as % of Load
68
Largest Total Plant with Common Voltage Switchyard
Resource Loss Criteria
3,524
3,575
2,750
1,700
MW
IFRO
-785
-1,127
-286
-179
MW/0.1Hz
IFRO as % of Current Performance
31.8%
95.6%
48.7%
23.9%
IFRO as % of Load
0.13%
0.76%
0.45%
0.50%
Largest Resource Event in Last 10 Years
Resource Loss Criteria
4,500
5,000
3,400
1,700
MW
IFRO
-1,002
-1,716
-423
-179
MW/0.1Hz
IFRO as % of Current Performance
40.6%
146.0%
72.2%
23.9%
IFRO as % of Load
0.17%
1.16%
0.66%
0.50%
67
Based on the frequency response performance calculated in the daily CERTS-EPG Automated Reliability Reports for 2011 through August 16,
2011.
68
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI = 20,599 MW.
63
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000147
Comparison of Alternative IFRO Calculations
Table 19 compares the recommended IFROs with those recommended by the Resources
Subcommittee.
Table 19: IFRO Calculation Comparison
Current Interconnection
Frequency Response
Performance
Eastern
Western
ERCOT
Québec
Units
-2,467
-1,179
-586
N/A
MW/0.1Hz
Recommended IFROs
Resource Loss Criteria
4,500
2,740
2,750
1,700
MW
IFRO
-1,692
-838
-286
-417
MW/0.1Hz
IFRO as % of Load
0.28 %
0.56 %
0.45 %
2.03 %
RS Recommendation
Resource Loss Criteria
4,500
2,740
2,750
1,700
MW
Base IFRO
-1,125
-548
-229
-113
MW/0.1Hz
-281
-137
-57
-28
MW/0.1Hz
IFRO
-1,406
-685
-286
-141
MW/0.1Hz
IFRO as % of Load
0.23 %
0.46 %
0.45 %
0.68 %
25 % Margin
Frequency Response Initiative Report – October 2012
64
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000148
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000149
Allocation of IFRO to Balancing Authorities
Allocation of IFRO to Balancing Authorities
The allocation of the IFRO to individual Balancing Authorities in a multi-Balancing Authority
interconnection will be done in accordance with the “Attachment A – BAL-003-1 Frequency
Response and Frequency Bias Setting Supporting Document,” which can be found at:
http://www.nerc.com/docs/standards/sar/Att_A_Freq_Response_Standard_Support_Documen
t_100611.pdf)
The process is paraphrased here for brevity.
Once the IFROs have been calculated by the ERO, the FRO for each Balancing Authority in a
multi-Balancing Authority interconnection is allocated based on the Balancing Authority’s
annual load and annual generation to each Balancing Authority by the following formula:
FROBA = FROInt X
AnnualGenBA + AnnualLoad BA
AnnualGenInt + AnnualLoad Int
Where:
•
Annual GenBA is the total annual “Output of Generating Plants” within the Balancing
Authority Area (BAA), on FERC Form 714, column C of Part II – Schedule 3.
•
Annual LoadBA is total annual load within the BAA, on FERC Form 714, column E of Part II
– Schedule 3.
•
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
•
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
The data used for this calculation is from the most recently filed Form 714. As an example, a
report to NERC in January 2013 would use the Form 714 data filed in 2012, which used data
from 2011. Balancing Authorities that are not FERC-jurisdictional will use the Form 714
instructions to assemble and submit equivalent data to the ERO for use in the FRO allocation
process.
Balancing Authorities that elect to form a Frequency Response Sharing Group (FRSG) will
calculate an FRSG FRO by summing the individual Balancing Authority FROs. Balancing
Authorities that elect to form an FRSG as a means to jointly meet the FRO will calculate their
FRM performance for the FRS Form 1 as follows:
•
calculate a group NIA and measure the group response to all events in the reporting year
on a single FRS Form 1, or
•
jointly submit each Balancing Authority’s Form 1 with a summary spreadsheet that sums
each participant’s individual event performance.
Frequency Response Initiative Report – October 2012
66
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000150
Allocation of IFRO to Balancing Authorities
Balancing Authorities that merge or transfer load or generation are encouraged to notify the
ERO of the change in footprint and corresponding changes in allocation such that the net
obligation to the interconnection remains the same and so that Control Performance Standard
(CPS) limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM),
frequency bias setting and frequency bias type (fixed or variable) to the ERO each year to allow
the ERO to validate the revised frequency bias settings on FRS Form 1. If the ERO posts the
official list of events after the date specified in the timeline below, Balancing Authorities will be
given 30 days from the date the ERO posts the official list of events to submit FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing
Authorities, the ERO will use FRS Form 1 data to post the following information for each
Balancing Authority for the upcoming year:
•
frequency bias setting
•
Frequency Response Obligation (FRO)
A Balancing Authority providing Overlap Regulation will report the historic peak demand and
generation of its combined Balancing Authorities’ areas on FRS Form 1 as described in
Requirement R4 of the BAL-003-1 standard.
67
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
000151
Frequency Response Performance Measurement
Interconnection Process
The process for detection of candidate interconnection frequency events for use in frequency
response metrics is described in the ALR1-12 Metric Event Selection Process contained in
Appendix W. It is paraphrased here for brevity.
Frequency Event Detection, Analysis, and Trending (for M etrics and Analysis)
Interconnection frequency events are detected through a number of systems, including:
•
FNet (Frequency monitoring Network) – FNet is a wide-area power system frequency
measurement system that uses a type of phasor measurement unit (PMU) known as a
Frequency Disturbance Recorder (FDR). FNet is able to measure the power system
frequency, voltage, and angle very accurately at a rate of 10 samplers per second. The
FNet system is currently operated by the Power Information Technology Laboratory at
Virginia Tech and the University of Tennessee, Knoxville. FNet alarms are received by
the NERC Situational Awareness staff and contain an estimate of the size of the resource
or load loss and general location description based on triangulation between FDRs.
•
CERTS–EPG Resource Adequacy Tool Intelligent Alarms – The Electric Power Group
(EPG) operates the Resource Adequacy (RA) tool developed under the auspices of the
Consortium for Electric Reliability Technology Solutions (CERTS). The RA tool uses 1minute frequency and area control error (ACE) SCADA data transmitted to a NERC
central database. The RA tool constantly monitors frequency and produces many Smart
Alarms for a number of frequency change conditions, but most useful for frequency
event detection is the short-term frequency deviation alarm, which indicates when
there has been a significant change in frequency over the last few minutes, typically
indicating a resource loss.
•
CERTS–EPG Frequency Monitoring and Analysis (FMA) Tool – EPG also developed and
operates the FMA tool that allows rapid analysis of frequency events, calculating the A,
B, and C values for a frequency event in accordance with parameters set by the
Frequency Working Group (FWG). Event selection criteria are further discussed in
Appendix E of this report.
Those three systems are used in combination by NERC staff to detect and collect data about
frequency excursions in the four North American interconnections. The size of resource losses
is verified with the Regional Entities for events where FNet estimates of resource loss meet the
following criteria:
•
Eastern: >1,000 MW (60 mHz excursion)
•
Western: >700 MW (80 mHz excursion)
•
ERCOT: >450 MW (100 mHz excursion)
Frequency Response Initiative Report – October 2012
68
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000152
Frequency Response Performance Measurement
Events that are detected and meet the ALR1-12 metric criteria are then considered to be
“candidate events” and are used by NERC to calculate interconnection frequency response
metrics and trends. Those candidate events are also presented to the Frequency Working
Group for consideration to be used as events for calculation of Balancing Authority frequency
response and bias setting calculations in accordance with NERC Standard BAL-003-1.
Ongoing Evaluation
The process for detection of frequency events and the calculation of Values A, B, and C and the
associated interconnection level metrics will undergo constant review in an effort to improve
the process. NERC staff and the Frequency Working Group will perform that review at least
annually.
Recommendation –NERC staff and the Frequency Working Group should annually review the
process for detection of frequency events and the method for calculating A and B Values and
Point C. The associated interconnection frequency event database, methods for calculating
interconnection metrics on risks to reliability, the associated probabilities, and the calculation
of the IFROs using updated data should also undergo review in an effort to improve the
process. Throughout this process, NERC should strive to improve the quality and consistency of
the data measurements.
Balancing Authority Level Measurements
A statistical analysis and evaluation was performed on field trial data with similar sample sizes
to those specified in the draft Standard BAL-003-1 Frequency Response and Frequency Bias
Setting. Field trial data was provided on FRS Form 1 for 2011 for 60 Balancing Authorities on
the Eastern and Western Interconnections; the analysis was not performed for either of the
single Balancing Authority interconnections, (i.e., ERCOT or Québec). Of the 60 Balancing
Authorities that provided data, only 50 provided data of sufficient quality to be used in the
analysis. Balancing Authorities that were excluded provided frequency data that was either
obviously incorrect (i.e., frequency data in hertz instead of change in hertz) or frequency data
that was uncorrelated to the frequency measured in an interconnection.
To protect the confidential nature of the data, the Form 1 data was normalized by dividing the
change in actual net interchange by the Frequency Response Obligation (FRO) for each
Balancing Authority, based on Interconnection Frequency Response Obligations (IFROs) of
-1,215 MW/0.1 Hz and -836 MW/0.1 Hz for the Eastern and Western Interconnections,
respectively.69 This normalization method converts all of the data from the actual frequency
response of the Balancing Authority to a per-unit frequency response value where 1.0 indicates
that the frequency response is exactly equal to the Balancing Authority’s FRO. The process also
required the development of the some of the data that would appear on the equivalent of the
CPS2 Bounds Report under this revised standard. The required data was extracted from FERC
Form 714 reports for the year 2009 and was estimated for those Balancing Authorities that did
69
As recommended by the Project 2007-12 Frequency Response Standards Drafting Team during the May 2012 Frequency Response Technical
Conferences.
69
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000153
Frequency Response Performance Measurement
not submit 714 reports from equivalent data based on other sources. The validity of this
analysis is not dependent upon the accuracy of the FRO estimates. It is only necessary for these
estimates to be close to the actual values for firm conclusions to be drawn from the results and
put the results in the proper context. Once the FROs were estimated for all of the Balancing
Authorities on the Eastern and Western Interconnections, they were transcribed onto the FRS
Form 1 for each Balancing Authority included in the analysis.
Single-Event Com pliance
The question was posed whether or not a Balancing Authority’s compliance with the proposed
BAL-003-1 standard should be measured on each event, through use of the mean, median, or a
regression analysis for a 12-month period. The variability of the measurement of frequency
response for an individual Balancing Authority for an individual disturbance event was
evaluated to determine its suitability for use as a compliance measure. The individual Balancing
Authorities’ performance disturbance events were normalized and plotted for each Balancing
Authority on the Eastern and Western Interconnections.
Figure 34: 2011 Normalized Frequency Response Events by BA Eastern Interconnection
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
32
31
30
29
28
27
26
25
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
3
4
2
1
0
-10.0
Balancing Authority
On Figures 34 and 35, events that had a measured Balancing Authority’s frequency response
above its FRO were shown as blue dots, and events that had a measured frequency response
below its FRO were shown as red dots.
Analysis of this data indicates that a single-event-based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in the charts in
Appendix 1. Based on the field trial data provided, only three out of 19 Balancing Authorities in
the sample (16%) would be compliant for all events with a standard based on a single event
Frequency Response Initiative Report – October 2012
70
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000154
Frequency Response Performance Measurement
measure on the Western Interconnection. Only one out of 31 Balancing Authorities in the
sample (3%) would be compliant for all events with a standard based on a single-event measure
on the Eastern Interconnection.
Figure 35: 2011 Normalized Frequency Response Events by BA Western Interconnection
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
20
19
18
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-10.0
Balancing Authority
Finding – Analysis of the field trial data indicates that a single-event-based compliance measure
is unsuitable for compliance evaluation when the data has a large degree of variability.
Recommendation – Balancing Authority compliance with BAL-003-1 should not be judged on a
per-event basis. Doing so would cause almost 90% of the Balancing Authorities to be out of
compliance.
Balancing Authority Frequency Response Performance
Measurement Analysis
Data provided by the Balancing Authorities from the field trial were also analyzed to determine:
1) if the sample size minimum of 20–25 frequency events, as specified for FRM calculation of
the draft BAL-003-1 standard, is sufficient to provide stable measurements results; and 2) which
of the three candidate FRM measurement methods is most appropriate. These analyses were
carried out using the normalized data provided by a number of Balancing Authorities during the
field trial.
71
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
000155
Event Sam ple Size
Previous studies have recommended a sample size sufficient to provide a stable measure of
frequency response of 20–25 events. These previous studies were performed on limited data
and a limited number of Balancing Authorities. The field trial data set is sufficiently large to
allow conclusions to be drawn with respect to that sample size recommendation specified for
FRM calculation in the draft standard.
Review of the full set of graphs (Appendix H) indicates that the outlier problem, as previously
described, did not present itself. There were no Balancing Authorities that had a small degree
of variability in the measured single-event frequency response for most of the events that
contained a few outliers.
The variability appeared similar for all events for each Balancing Authority, which indicates that
the sample size of 20–25 events was sufficient to stabilize the result and eliminate any undue
influence from potential outliers. In those Balancing Authorities with large variations in
measured single-event response, the sample size was large enough that no single outliers
unduly influenced the result. Balancing Authorities with large measurement variation still had
enough samples to mitigate the risk associated with outliers. This demonstrates that the
sample size chosen was sufficient to stabilize all three methods of measuring FRM. Therefore,
it can be concluded that none of the methods are unduly influenced by outliers and the
selection of the measurement method should be based on other factors.
Finding – Analysis of data submitted by the Balancing Authorities during the field trial confirms
that the sample size selected (a minimum of 20–25 frequency events) is sufficient to stabilize
the result and alleviate the perceived problem associated with outliers in the measurement of
Balancing Authority frequency response performance.
M easurem ent M ethods – M edian, M ean, or R egression R esults
All of the normalized data were analyzed using all three candidate methods for measuring FRM.
median – Median is the numerical value separating the higher half of a one-dimensional
sample, a one-dimensional population, or a one-dimensional probability distribution
from the lower half. The median of a finite list of numbers is found by arranging all the
observations from lowest value to highest value and picking the middle one. When the
number of observations is even, there is no single middle value; the median is arbitrarily
defined as the mean of the two middle values.
In a sample of data, or a finite population, there may be no member of the sample
whose value is identical to the median (in the case of an even sample size), and, if there
is such a member, there may be more than one so that the median may not uniquely
identify a sample member. Nonetheless, the value of the median is uniquely
determined with the usual definition. A median is also a central point that minimizes
the arithmetic mean of the absolute deviations. However, a median need not be
Frequency Response Initiative Report – October 2012
72
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000156
Frequency Response Performance Measurement
uniquely defined. Where exactly one median exists, statisticians speak of “the median”
correctly; even when no unique median exists, some statisticians speak of “the median”
informally.
The median can be used as a measure of location when a distribution is skewed, when
end values are not known, or when one requires reduced importance to be attached to
outliers; e.g., because they may be measurement errors. A median-unbiased estimator
minimizes the risk with respect to the absolute-deviation loss function, as observed by
Laplace. 70 For continuous probability distributions, the difference between the median
and the mean is never more than one standard deviation. Calculation of medians is a
popular technique in summary statistics and summarizing statistical data, since it is
simple to understand and easy to calculate. It also gives a measure that is more robust
in the presence of outlier values than the mean.
mean – Mean is the numerical average of a one-dimensional sample, a one-dimensional
population, or a one-dimensional probability distribution. A mean-unbiased estimator
minimizes the risk (expected loss or estimate error) with respect to the squared-error
loss function, as observed by Gauss.71 The mean is more sensitive to outliers for the
very reason that it is a better estimator; it minimizes the squared-error loss function.
linear regression – Linear regression is the linear average of a multi-dimensional
sample, or a multi-dimensional population. A linear regression unbiased estimator
minimizes the risk (expected loss or estimate error) with respect to the squared-error
loss function in multiple dimensions, as observed by Gauss. 72 The linear regression is
also sensitive to outliers for the very reason that it is a better estimator; it minimizes the
squared-error loss function.
Important Considerations
The following issues are important to consider with respect to the selection of the best method
for measuring frequency response.
two-dimensional measurement – Two-dimensional measurement of frequency
response provides the best representation of the change in MWs divided by the change
in frequency and is used to estimate the frequency bias setting, which indicates the
frequency response in MWs provided at actual frequency as compared to scheduled
frequency.
non-linear attribute of frequency response – The non-linear attribute of frequency
response has been demonstrated on all of the North American interconnections and is
an important consideration in the representation of frequency response.
70
An absolute-deviation loss function is used to minimize the risk of estimate error when dealing with uniform distributions. Appendix 3
provides a description of Uniform Distributions and a derivation of the median.
71
A squared-error loss function is used to minimize the risk when dealing with normal (Gaussian) distributions. Appendix 4 provides a
description of normal (Gaussian) distributions and a derivation of the mean.
72
Appendix H provides a derivation of the linear regression.
73
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
000157
single best estimator – A single best estimator of frequency response is a necessary
result for use in compliance evaluation.
linear system – A linear system 73 is assumed in the development of the individual
Frequency Response Obligation for each Balancing Authority on a multiple Balancing
Authority interconnection and is used to distribute the Interconnection Frequency
Response Obligation among the Balancing Authorities on that interconnection. If the
system is non-linear, 74 then it cannot be assumed that the total required
Interconnection Frequency Response Obligation will be achieved when all Balancing
Authorities provide their individual Frequency Response Obligations.
bi-modal distributions – Bi-modal distributions occur whenever a reconfiguration of
Balancing Authorities occurs within a compliance year. Unless the method chosen can
correctly represent bi-modal distributions, reconfigured Balancing Authorities cannot be
effectively measured for compliance.
quality statistics – Quality statistics should be available for use in compliance
evaluation. Frequency response is used to determine compliance with minimum
provision of the Balancing Authority’s obligation for providing its share of frequency
response for the interconnection. When using a measure for compliance, one must
ensure that the measure fairly represents the Balancing Authority’s performance. There
is still a presumption that an indication of non-compliance should not occur due to pure
chance.
reducing influence of noise – Reducing influence of noise in the data is considered an
important attribute in the measurement method. All measurements of frequency
response will be affected by noise in the measurement process.
reducing influence of outliers – Reducing influence of outliers in the data is considered
the most important attribute in the measurement method. All measurements of
frequency response will be affected by true outliers. The risk associated with the
reduction in the influence of outliers is that valid information about the measure is also
lost when an outlier reduction method is used.
ease of calculation and familiar indicators – Ease of calculation and familiar indicators
are important considerations for communication and to promote ease of understanding
by the industry.
Appendix H presents the series of graphs indicating results for each Balancing Authority. Each
graph shows all of the individual data points use to determine the median, mean, and
regression lines.
73
74
A linear system is a system in which the sum of the parts is equal to the whole.
A non-linear system is a system in which the sum of the parts is not equal to the whole.
Frequency Response Initiative Report – October 2012
74
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000158
Frequency Response Performance Measurement
The median line is green, the mean line is blue, and the regression line is red. The value of the
normalized frequency response (vertical axis) where the line intercepts the value of frequency
(horizontal axis) at a value of 0.1 Hz indicates compliance. Values above 1.0 indicate an FRM
above the FRO, and values below 1.0 indicate an FRM below the FRO.
Figure 36 shows an example of a Balancing Authority with a small degree of variability in the
measured frequency response for each individual event.
Figure 36: BA with Small Degree of Variability in Measured Frequency Response
Figure 37 shows an example of a Balancing Authority with a large degree of variability in the
measured frequency response for each individual event.
During the analysis, the graphs appeared to show that the regression provided a higher
estimate of FRM than the median. Consequently, a comparison was made between the FRM as
measured by the median and the FRM as measured by the regression. The results of the
regression analysis demonstrate a performance for all samples that is 0.087% of their FRO
higher than the median’s performance on the Eastern Interconnection and 0.117% of their FRO
higher than the median’s performance on the Western Interconnection. In an unbiased
analysis, one would expect the median and regression to yield the same result. This indicates
there is an unknown statistical bias affecting the results of the analysis.
75
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
000159
Figure 37: BA with Large Degree of Variability in Measured Frequency Response
The bias causing the difference between the median and regression results can be explained by
an attribute of frequency response. As the frequency deviation increases for larger disturbance
events, the frequency response increases, but it does so disproportionately, shown in figure 38.
This attribute of frequency response has been demonstrated in technical papers.75 It has also
been implemented in the variable frequency bias settings used by ERCOT, BPA and BC Hydro.
In simple terms, the regression includes the effect of this non-linear attribute and the median
does not.
The regression accommodates the disproportion on the slope of the regression line. In this
case the effect tends to be upward—ever bigger MWs per increment in size of larger frequency
error. The median is biased against any disproportionate increase in response per increase in
size of frequency error as part of the median’s blindness to outliers. The median will give no
credit for the ever-growing amount of MWs deployed per added increment in size of frequency
error. All the median does is count the number of MW responses regardless of size and, to
represent all the MW responses, choose the one that occurred half-way in the sequence of
decreasingly negative and increasingly positive frequency errors. Therefore, the median
underestimates the FRM because it cannot evaluate the non-linear attribute correctly. It does
not see or notice that attribute at all through its blinders regardless of numerical order or
placement in a sequence. Regression is the only measurement method that captures the nonlinear frequency response correctly.
75
Hoffman, Stephen P., Frequency Response Characteristic Study for ComEd and the Eastern Interconnection, Proceedings of the American
Power Conference, 1997. Kennedy, T., Hoyt, S. M., Abell, C. F., Variable, Non-linear Tie Line Frequency Bias for Interconnected Systems
Control, IEEE Transactions on Power Systems, Vol. 3, No. 3, August 1988.
Frequency Response Initiative Report – October 2012
76
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000160
Frequency Response Performance Measurement
Figure 38: Typical Non-Linear Frequency Response
The advantages of each method of measurement are presented in Table 20 – Median, Mean
and Regression Comparison. The alphabetic key is below.
Table 20: Median, Mean, and Regression Comparison
Attribute
Provides two-dimensional
measurement
Represents non-linear attributes
Provides a single best estimator
(single value)
Is part of a linear system
Represents bi-modal distributions
Quality statistics available
Reducing influence of noise
Reducing influence of outliers
Easy to calculate
Familiar indicator
Currently used as the measure in
BAL-003-1
77
Median
Mean
Regression
A
A
Yes
B
B
Yes
C
Yes
Yes
Yes
Yes
Yes
D
E
Yes (F)
Yes
Yes
Yes
Yes
Yes (J)
Yes
Yes
Yes
Partial (G)
Partial (H)
I
No
No
Yes
No
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
000161
A. Neither median nor mean can evaluate the two-dimensional nature of frequency
response.
B. Neither median nor mean can capture the non-linear attribute of frequency response.
Both underestimate the typical non-linear frequency response.
C. Median is arbitrarily defined as the average of the two central values when there is an
even number of values in the data set. The decision to further constrain this central
range of values to a single value that is the average of the ends of that range is
unsupported by any mathematical construct. It is only the desire of those looking for
simplicity in the result that supports this singular definition of median.
D. The median fails to provide a valid estimate of frequency response when the
distribution of frequency event responses is bi-modal due to Balancing Authority
reconfiguration or changes in responsibility for control such as partial-period overlap of
supplemental control.
E. The median fails to provide any methods to determine the quality, significance, or
confidence associated with the measure.
F. The median reduces the influence of noise in the data, but that noise reduction comes
with the cost of eliminating the availability of any quality statistics.
G. Linear regression provides a result that weights the data according to the change in
frequency. Since the noise in the data is independent of change in frequency, linear
regression provides a method superior to the mean for reducing the influence of noise
in the resulting estimate of frequency response.
H. Linear regression is less sensitive to outliers and large data errors than the mean.
I. Linear regression is more complex and requires more effort to calculate, but that
additional effort is small when the evaluation process has been automated.
J. Mean is currently used as the measure in the proposed draft BAL-003-1 standard.
After consideration of the mitigating effects of the sample size with respect to outliers, the
linear regression method is the preferred method for calculating the frequency response
Measure (FRM) for Balancing Authorities for compliance with proposed NERC Standard BAL003-1 – Frequency Response.
Recommendation – Linear regression is the method that should be used for calculating
Balancing Authority Frequency Response Measure (FRM) for compliance with Standard BAL003-1 – Frequency Response.
Frequency Response Initiative Report – October 2012
78
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000162
Role of Governors
Role of Governors
Deadband and Droop
Turbine-generator units use turbine speed control systems, called governors, to control shaft
speed by sensing turbine shaft speed deviations and initiating adjustments to the mechanical
input power to the turbine. This control action results in a shaft speed change (increase or
decrease). Since turbine-generators rotate at a variety of speeds, outside the power plant it is
more appropriate to generally relate shaft speed to system frequency and throttle valve
position to generator output power (MW).
The expected response of a turbine-generator’s governor to frequency deviations is often
plotted on what is known as a governor droop characteristic curve or a droop curve. The curve
shows the relationship between the generator output and system frequency. The curve droops
from left to right. Simply stated, as the frequency decreases, the generator’s output will
increase in accordance with its size.
Figure 39: Sample Droop Characteristic Curve
5% Governor Droop
63
Frequency - Hz
62
61
60
59
58
57
0
20
40
60
80
100
Percent Output
Droop settings on governors are necessary to enable multiple generators to operate in parallel
while on governor control while not competing with each other for load changes. Droop is
expressed as a percentage of the frequency change required for a governor to move a unit from
no-load to full-load or from full-load to no-load. Prior to 2004, NERC Operating Policy 1,
Generation Control and Performance, recommended generators with governor control
(typically 10 MW and larger) to have a droop setting of 5% for steam turbine (and 4% for
combustion turbines, although not explicitly stated in the policy). This means that a 3 Hz (5% of
60.00 Hz) change in system frequency is required to move a generator across its full range.
Normally governors respond only to substantial frequency deviations.
Guidelines of the 2004 NERC Operating Policy 1, Generation Control and Performance, section
C, stated:
79
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Role of Governors
000163
1. Governor installation – Generating units with nameplate ratings of 10 MW or greater
should be equipped with governors operational for frequency response unless restricted
by regulatory mandates.
2. Governors free to respond – Governors should be allowed to respond to system
frequency deviation unless there is a temporary operating problem.
3. Governor droop – All turbine-generators equipped with governors should be capable of
providing immediate and sustained response to abnormal frequency excursions.
Governors should provide a 5% droop characteristic. Governors should, at a minimum,
be fully responsive to frequency deviations exceeding ±0.036 Hz (±36 mHz).
4. Governor limits – Turbine control systems that provide adjustable limits to governor
valve movement (valve position limit or equivalent) should not restrict travel more than
necessary to coordinate boiler and turbine response characteristics.
Within the Frequency Response Initiative, NERC is considering modifications to those
parameters based on the recent advances in frequency response performance in ERCOT and
revised governor control parameters.
In 2010, NERC conducted a survey of governor status and settings through Generator Owners
and Generators Operators. The results of that survey are summarized in the Generator
Governor Survey section of this report. A complete set of the summary graphics of the survey
is contained in Appendix K.
ERCOT Experience
The general decline in primary frequency response in all interconnections has prompted
regulatory entities to address the issue. Electric grids such as the one in Texas are especially
sensitive to frequency regulation and response due to their relatively small overall
interconnected capacity compared to the other interconnections. The Texas Regional Entity
(TRE) is actively working on a regional standard for frequency regulation.
Frequency R egulation
Electric grid frequency regulation is attained by the response of the turbine governors to
deviations from nominal synchronous speed, the operation of the boilers-turbine controls in
response to the frequency change, and the actions of the dispatching system.
Frequency regulation success for any given boiler-turbine plant depends on many factors,
primarily:
•
steady state and dynamic stability of the unit
•
load following capability
•
linearization of turbine governor valves’ steam flow characteristics
•
proper calibration and coordination of the boiler and turbine frequency regulation
parameters
Frequency Response Initiative Report – October 2012
80
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000164
Role of Governors
•
proper high and low limiting of the boiler and turbine frequency regulation based on
unit conditions
•
proper dispatching actions to restore the frequency to its normal operating value
Another factor that influences a unit’s capability for frequency regulation is the available boiler
energy storage. The larger the storage, the less the initial pressure drop caused by the quick
opening of the governor valves, and the better the initial unit frequency regulation.
The standard speed regulation setting for the turbine governors of the boiler-turbine
generating units is 5%. This is a ±5% change from rated speed (0.05*3,600 = 180 RPM), which
causes the turbine governor to change its valves’ position demand ±100 percent. It is also
generalized industry practice to add a small deadband (DB) to the calibration of the governor
speed error bias in order to minimize the movement for very small speed deviations. The
selection of the DB affects the fidelity of the regulation, as shown in figure 40.
Figure 40: Regulation versus RPM Deadbands
The regulation curves of figure 40 are for the noted speed regulation at constant pressure.
They are calculated by developing the equation ΔGVD= f (ΔRPM) for each DB, where ΔGVD is
the change in the turbine Governor Valve Demand as a function of the change in RPM.
Knowing the ΔGVD for any given ΔRPM enables the regulation calculation via the equation:
REG (%) = (100 * ∆RPM/ΔGVD)*(100/3,600)
ERCOT Nodal Operating Guides Section 2 has specific requirements for governor deadband
settings. The maximum allowable deadband is ±0.036 Hz, which has been the industry standard
for mechanical “fly-ball” governors on steam turbines for many years. With the development
81
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000165
Role of Governors
of energy markets in the early 2000s, generators with electronic or digital governors began
implementing this same deadband in their primary frequency response implementation.
Unfortunately, the Guides were not clear on how to implement the droop curve at the
deadband. Since the Guides required 5% droop performance, many generators introduced a
“step function” or modified “step” once the deadband was reached in order to achieve near 5%
droop performance outside the deadband.
As can be seen in figure 40, a 2 rpm deadband on a 3,600 rpm turbine is equivalent to +/‐0.033
Hz. Based on the corresponding droop (regulation percent) for this deadband, a generator’s
performance to typical frequency deviations during disturbances would be much greater than
5% without some “step” function. These governor settings resulted in an abnormal frequency
profile for the interconnection.
Figure 41: Frequency Profile for March and September 2008
(in 5 mHz bins)
Sep-08
60
.1
00
60
.0
90
60
.0
80
60
.0
70
60
.0
60
60
.0
50
60
.0
40
60
.0
30
60
.0
20
60
.0
10
60
.0
00
59
.9
90
59
.9
80
59
.9
70
59
.9
60
59
.9
50
59
.9
40
59
.9
30
59
.9
20
59
.9
10
59
.9
00
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0
Mar-08
Figure 41 is the ERCOT frequency profile for March and September of 2008. It is clear that the
“flat top” of the profile is centered on the ±0.036 Hz deadband. This flat frequency profile
created significant problems because frequency spent as much time at the governor deadband
points as it did at any point in between. This made it difficult to employ Frequency Regulation
to correct frequency to 60 Hz, and for ERCOT to meet the NERC BAL‐001‐0 — Real Power
Balancing Control Performance Requirement 1 (aka, CPS1), since ERCOT had an epsilon‐1 limit
of 0.030 Hz. The frequency profile also contributed to generator instability at the deadbands
with the implementation of the various “step” functions in the governors.
If generators that had implemented governor step functions were to be electrically separated
from the grid during an islanding event, they would experience extreme instability. This would
be caused by the governor providing excessive frequency response to the island to small
generation load imbalances, resulting in large frequency swings and unit instability.
Frequency Response Initiative Report – October 2012
82
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000166
Role of Governors
The ERCOT Performance Disturbance and Compliance Working Group (PDCWG) became
increasingly concerned about the frequency instability and the realization of the risk of the step
function in the governors (see figure 42). Because of their analysis, a member of the PDCWG
discussed the issues with one large generating facility that was willing to try different deadband
settings along with a specific droop curve implementation. This implementation required a
straight linear curve from the deadband to full range of the governor, eliminating any step
function shown in figure 43.
Figure 42: Frequency Response of 600 MW Unit ±36.0 mHz Deadband and Step Response
150.00
100.00
MW Change
50.00
0.00
-50.00
Step response at
dead-band.
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
After brief testing of a number of different deadbands, a 1‐rpm deadband (± 0.01666 Hz) was
chosen. Four turbine governors were set in this manner on November 3, 2008 (about 2,500
MW capacity or 7.5% of the average grid capacity in November).
Figure 43: Frequency Response of 600 MW Unit ±16.67 mHz Deadband and No‐Step
Response
150.00
100.00
MW Change
50.00
0.00
No Step response at
dead-band
-50.00
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
83
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000167
Role of Governors
The possibility of leaving the deadband at ±0.036 Hz and just eliminating the stepped droop
response was considered. Analysis showed that the droop performance at 59.900 Hz would be
around 7.72% with a ±0.036 Hz deadband but only 5.97% droop with the ±0.0166 Hz deadband.
That difference increases at 59.950 Hz, with a 17.64% droop performance for the ±0.036 Hz
deadband and a 7.46% droop performance for the ±0.0166 Hz deadband. However, without
the primary frequency response of the lower deadband, the frequency profile would return to
the “flat top” frequency profile spanning the ±0.036 Hz deadbands, which is a less reliable state
(less stable) for the interconnection. Also, with the larger deadband the interconnection or
Balancing Authority may not have been able to meet the minimum frequency response
requirements.
Turbine-Generator P erform ance w ith R educed Deadbands
The general purpose for using governor deadbands is to minimize generator movement due to
frequency regulation. In an interconnection where generators have various deadband settings,
the diversity of settings creates diversity in responses to frequency changes. However, when a
majority of the generators in an interconnection set the deadband the same and with a step
function, the diversity of responses disappears, and frequency will move to the deadband
frequently as demonstrated in the profile in figure 41. When the frequency exceeds the
deadband, all units react with a stepped response simultaneously.
The amount of generator movement expected for a specific set of deadband settings can be
compared by calculating the MW-minute average movement of a hypothetical generator
exposed to actual measured frequency using the different governor settings.
Table 21 compares the movement of two generators with different governor settings: one with
a ±0.036 Hz deadband and droop step function, and one with a ±0.01666 Hz deadband and no
droop step function.
Table 21: Comparison of MW Movement for Response of Different Governor Settings
±0.036 Hz Deadband with
Droop Step Function
±0.01666 Hz Deadband
with
No Droop Step
Function
Percent
Increase
for Smaller
Deadband
2008 Frequency Profile
662,574.0 MW-min.
893,164.2 MW-min.
34.80%
2009 Frequency Profile
446,244.0 MW-min.
692,039.8 MW-min.
55.08%
Using the 2008 1-minute average frequency data, the generator with the lower deadband
would have had 893,164.2 MW-minutes of primary frequency response while the generator
with the larger deadband unit would have had 662,574.0 MW-minutes of primary frequency
response. This is a 34.80% increase in movement for the lower deadband generator.
Frequency Response Initiative Report – October 2012
84
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000168
Role of Governors
However, if the exact same comparison is made for ERCOT frequency data from 2009, where
the new deadbands had an actual impact on frequency, the following observation scan be
made. The lower deadband generator would have had 692,039.8 MW‐minutes of primary
frequency response compared to the larger deadband generator with 446,244.0 MW‐minutes,
a 55.08% increase in movement for the lower deadband. One observation is that the MW‐
minute movement of the lower deadband generator is only 4.45% higher than the movement
of the larger deadband generator of the previous year (692,039.8 MW‐minutes versus
662,574.0 MW‐minutes).
Having the lower deadband in service for the entire year greatly reduced the frequency
movement of the interconnection and reduced the primary frequency response movement as
well. The lower deadband generator MW‐minute movement decreased 201,124.4 MW‐
minutes, or 22.518%, between 2008 and 2009. This indicates the reduced impact on the
generator movement with the smaller deadband and the non‐step governor droop
implementation when the governor becomes active, as compared to the “step”
implementation.
Figure 44: MW‐Minute Movement of a 600 MW Unit with 5% Droop
140000
404989.0
2010 MW Response of 0.0166 db
545670.0
2008 MW Response of 0.036 db
120000
25.78% Decrease in MW
movement with
lower deadband.
100000
MW
80000
60000
40000
20000
6
60 0
.0
1
60
.0
60 2
.0
3
60
.0
60 4
.0
5
60
.0
60 6
.0
7
60
.0
8
60
.0
9
60
.1
59
.
59 9
.9
1
59
.9
2
59
.9
59 3
.9
4
59
.9
59 5
.9
6
59
.9
59 7
.9
8
59
.9
9
0
2008 MW Response of 0.036 db
2010 MW Response of 0.0166 db
This benefit is further emphasized by the comparison in Figure 44, which shows the response of
a theoretical 600 MW unit for the 2008 ERCOT frequency profile with a ±0.036 Hz deadband
versus the same unit with a ±0.01666 Hz deadband for the 2010 frequency profile. Using the
lower deadband, there is a savings of 140,641 MW‐minutes of regulation movement because
there were a larger number of generators using the ±0.01666 Hz deadband in 2010, which
greatly influenced the frequency profile. Figure 45 shows a comparison of the actual January–
September ERCOT frequency profiles for 2010 and 2008. The profile changed from a flat
response between the ±0.036 Hz deadband to a more normal distribution.
85
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000169
Role of Governors
Figure 45: ERCOT 2010 versus 2008 Frequency Profile (Jan.–Sept.)
40000
One Minute Occurances
35000
30000
25000
20000
15000
10000
5000
60
60
.0
1
60
.0
2
60
.0
3
60
.0
4
60
.0
5
60
.0
6
60
.0
7
60
.0
8
60
.0
9
60
.1
59
.9
59
.9
1
59
.9
2
59
.9
3
59
.9
4
59
.9
5
59
.9
6
59
.9
7
59
.9
8
59
.9
9
0
2010
2008
Conclusion – The benefits of using the smaller ±0.01666 Hz deadband coupled with a non‐step
governor droop implementation results in the following:
•
improved frequency response for small disturbances
•
generators responding more often in smaller increments, saving fuel and wear and tear
on turbines
•
more stable operation when near boundary conditions of deadbands
Recommendation – NERC should embark immediately on the development of a Frequency
Response Resource Guideline to define the performance characteristics expected of those
resources for supporting reliability. That guideline should address appropriate parameters for:
Existing generator fleet – In order to retain or regain frequency response capabilities of the
existing generator fleet, adopt:
deadbands of ±16.67 mHz,
droop settings of 3%‐5% depending on turbine type,
continuous, proportional (non‐step) implementation of the response,
appropriate operating modes to provide frequency response, and
appropriate outer‐loop controls modifications to avoid primary frequency response
withdrawal at a plant level.
Frequency Response Initiative Report – October 2012
86
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000170
Role of Governors
Other frequency-responsive resources – Augment existing generation response with fastacting electronically coupled frequency responsive resources, particularly for the arresting and
rebound periods of a frequency event:
contractual high-speed demand-side response,
wind and photo-voltaic – particularly for over-frequency response,
storage – automatic high-speed energy retrieval and injection, and
variable speed drives – non-critical, short time load reduction.
Generator Governor Survey
On September 9, 2010, NERC issued a Generator Governor Information and Setting Alert (the
alert) recommending that Generator Owners (GOs) and Generator Operators (GOPs) provide
information and settings for turbine governors for all generators rated at 20 MVA or greater, or
plants that aggregate to a total of 75 MVA or greater net rating at the point of interconnection
(i.e., wind farms, PV farms, etc.). The alert was issued as a recommendation to industry, which
requires reporting obligations (as specified in Section 810 of the Rules of Procedures) from
industry to NERC and, subsequently, from NERC to FERC. Balancing Authorities in North
America were the only functional group required to respond to this alert. A copy of the survey
instructions is located in Appendix J of this report.
The survey requested three types of information:
1. policies on installation and maintenance, and testing procedures and testing frequency
for governors;
2. unit-specific characteristics and governor settings; and
3. unit-specific performance information for a recent, single event.
NERC sent the survey instrument and instructions to 799 GOs and 748 GOPs in North America.
Of the 794 GOs that acknowledged receipt of the survey, 749 developed and provided a
response. Of the 743 GOPs that acknowledged receipt of the survey, 721 developed and
provided a response.
Adm inistrative Findings
NERC staff first reviewed the information submitted by the GOs and GOPs. This initial review
led to the following findings from the administration of the survey:
1. There is a wide variety of levels of understanding among GOs and GOPs of the role of
turbine governors in maintaining frequency response, including confusion in
terminology and a lack of understanding of governor control settings. This indicates a
need for education on settings and performance of turbine governors and the
governor’s role in interconnection frequency response.
87
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000171
Role of Governors
Recommendation – NERC should address improving the level of understanding of the
role of turbine governors through seminars and webinars, with educational materials
available to GOs and GOPs on an ongoing basis.
2. There was a significant amount of duplication of reporting. This was mostly due to dual
submittals by entities that are registered both as GOs and as GOPs. NERC staff sought to
eliminate as much duplication as possible. However, eliminating duplication was
difficult when the entities that own and operate a generator differ, yet both submitted
information on the same generator. Hence, there remains some duplication in this
analysis.
Sum m ary of the Survey R esponses
Table 22 summarizes, by interconnection, the aggregate characteristics of the generators
analyzed.
Table 22: Number of Generators as Reported
Interconnection
Total
With Governors
Without Governors
Eastern
4,372 (648.7 GW)
4,217 (630.2 GW)
152 (18.5 GW)
Western
1,560 (171.6 GW)
1,445 (162.9 GW)
114 (8.7 GW)
ERCOT
503 (95.6 GW)
446 (85.6 GW)
53 (9.0 GW)
Totals
6,435 (915.9 GW)
6,110 (878.7 GW)
319 (36.2 GW)
Figures 46–48 summarize the responses on turbine governors for three of the interconnections.
Data for the Québec Interconnection is not summarized in this report. The GOs and GOPs
reported that governors were operational for 95%, 97%, and 99% of the total number of
generating units that were reported as having governors in the Eastern, Western, and Texas
Interconnections, respectively.
Frequency Response Initiative Report – October 2012
88
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000172
Role of Governors
Figure 46: Eastern Interconnection Generator Responses
Figure 47: Western Interconnection Generator Responses
89
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000173
Role of Governors
Figure 48: ERCOT Interconnection Generator Responses
R eported Deadband Settings
The deadband setting of a governor establishes a minimum frequency deviation that must be
exceeded before the governor will act. Frequency deviations that are less than the setting will
not cause the governor to act. Of the information provided by the GOs and GOPs on governor
deadbands, 51%, 63%, and 79% of the number of units in the Eastern, Western, and Texas
Interconnections, respectively, was usable. Figure 49 summarizes the usability of the deadband
data submitted in the survey.
Frequency Response Initiative Report – October 2012
90
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000174
Role of Governors
Figure 49: Usability of Information Provided on Governor Deadbands
100%
90%
21%
23%
35%
37%
80%
Unusable
49%
70%
47%
Usable
60%
50%
40%
79%
77%
65%
63%
30%
53%
51%
20%
10%
0%
East
West
Texas
No. of Units
East
West
Texas
Capacity
Figure 50 summarizes the range of deadband settings reported by generating unit size for all
three interconnections. The simple average, or mean, of the frequency response values
calculated is indicated by the orange dot. A horizontal line inside the green box indicates the
median of these values. The upper and lower boundaries of the box are the inter‐quartile
range, which is the range that contains half the calculated frequency response values. Finally,
the end points of the upper and lower vertical lines indicate the lowest and highest calculated
frequency response values, respectively.
The use of these descriptive statistics provides additional information on the distribution of
values. For example, if the average is lower than the median, it means that the distribution has
a small number of low values compared to the main body of values. Similarly, the height of the
inter‐quartile range (the top and bottom of the box) provides a measure of how widely the
values are distributed. The location of the median within the box indicates whether values are
evenly distributed on either side of the median (when the median is close to the center of the
box) or whether values are disproportionately on one or the other side of the median (when
the median is closer to the top or the bottom of the box).
91
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000175
Role of Governors
Figure 50: Reported Governor Deadband Settings
700
700
<500 MW
500-1000
MW
400
2000
540
Deadband Setting (mHz)
350
300
250
200
150
100
50
0
>1000 MW
East
<500 MW
500-1000
MW
West
>1000 MW
<500 MW
500-1000
MW
>1000 MW
Texas
Unit Size
Figure 50 indicates:
•
Eastern Interconnection – Half of the deadband settings are between 0 and 100 mHz,
with the smallest generating units having the lowest settings, followed by the mid‐size,
and then the largest units. The figure also indicates that there are a number of units in
all size ranges with very high deadband settings (> 200 mHz).
•
Western Interconnection – Half of the deadband settings are between 0 and 50 mHz for
the smallest and mid‐size generating units. However, the range is considerably broader
for the largest units, with half of the settings lying between 0 and more than 300 mHz.
The very large deadbands on units greater than 1,000 MW are attributable to the
nuclear units.
•
Texas Interconnection – The deadband settings are generally less than 50 mHz. There
appears to be at least one very high deadband setting for a small generating unit.
Reported Droop Settings
Governor droop expresses the effect of changes in generating unit speed in terms of changes in
power output as a function of the amount of frequency deviation from the reference
frequency. Of the information provided by the GOs and GOPs on governor droop settings, 89%,
94%, and 87% of the number of units in the Eastern, Western, and Texas Interconnections,
respectively, was usable.
Figure 51 summarizes the range of governor droop settings for the interconnections. Generally,
the droop settings were in the range of expected values.
Frequency Response Initiative Report – October 2012
92
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000176
Role of Governors
Figure 51: Range of Governor Droop Settings by Generating Unit Size
10
9
Droop Setting (%)
8
7
6
5
4
3
2
1
0
<500 MW
500-1000
MW
>1000 MW
<500 MW
500-1000
MW
East
>1000 MW
<500 MW
500-1000
MW
West
>1000 MW
Texas
Unit Size
Governor Status and Operational Parameters
A number of the survey questions addressed the operational status and parameters of the
governor fleet. As shown in Figure 52, the vast majority of the GOs and GOPs reported that
their governors are operational.
Figure 53 shows that the governors also were reported to be able to sustain primary frequency
response for longer than 1 minute if the frequency remains outside of its deadband. However,
as shown in Figure 54, roughly half of the governors are expected to be overridden or limited by
plant‐level control schemes. This factor heavily influences the sustainability of primary
frequency response, contributing to the withdrawal symptom often observed in the Eastern
Interconnection, especially during light load periods.
Figure 52: Operational Status of Governors
21, 1%
128, 3%
0, 0%
26, 1%
30, 2%
39, 1%
1, 0%
0, 0%
4, 1%
1378, 97%
4015, 95%
Western
Eastern
394, 99%
ERCOT
Yes
93
No
N/A
Unknown
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000177
Role of Governors
Figure 53: Response Sustainable for More Than 1 Minute if Outside Deadband
117, 8%
0, 0%
480, 11%
99, 7%
9, 0%
360, 9%
37, 9%
2, 1%
27, 7%
1213, 85%
3359, 80%
Western
Eastern
333, 83%
ERCOT
Yes
No
N/A
Unknown
Figure 54: Unit‐Level or Plant‐Level Control Schemes that Override
or Limit Governor Performance
65, 5%
337, 8%
0, 0%
27, 1%
700, 49%
2026, 48%
664, 46%
32, 8%
1818, 43%
2, 1%
Western
Eastern
197, 49%
168, 42%
ERCOT
Yes
No
N/A
Unknown
Response to Selected Frequency Events
The GOs and GOPs were asked to provide information on the performance of turbine governors
during a selected event in each interconnection. Table 23 lists the date and time of the events
selected for the Eastern, Western, and Texas Interconnections (data was not requested from
the Québec Interconnection).
Frequency Response Initiative Report – October 2012
94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000178
Role of Governors
Table 23: Selected Events for Provision of
Generator Governor Performance Information
Interconnection
Basis
Frequency
Eastern
8/16/2010
1:06:15 CST
1,200 MW
Western
8/12/2010
14:44:03 CST
1,260 MW
ERCOT
8/20/2010
14:25:29 CST
1,320 MW
Of the interconnections’ total generating capacity, 64%, 58%, and 75% of the units were on‐line
at the time of the event for the Eastern, Western, and Texas Interconnections, respectively.
Figure 55: Governor Response by Total Generating Capacity On‐Line
West
East
Online, No
Data on
Response,
53.2, 13%
Expected
Response,
124.7, 30%
No Response,
34.6, 35%
Texas
Online, No
Data on
Response,
3.4, 4%
Online, No
Data on
Response,
8.6, 14%
Expected
Response,
42.7, 44%
No Response,
7.8, 13%
Expected
Response,
31.6, 53%
No Response,
159.9, 38%
Opposite of
Expected
Response,
77.6, 19%
Opposite of
Expected
Response,
16.9, 17%
Opposite of
Expected
Response,
11.8, 20%
Figure 55 shows:
•
Of the total generating capacity on‐line, 30%, 44%, and 53% reported responding in the
expected direction of response (i.e., to correct the change in frequency) for the Eastern,
Western, and Texas Interconnections, respectively.
•
Some generation reported no response to the frequency deviations (38%, 35%, and 13%
for the Eastern, Western, and Texas Interconnections, respectively).
•
Notably, 19%, 17%, and 20% were reported as responding in the opposite direction of
the expected response (i.e., not in opposition to the change in frequency) for the
Eastern, Western, and Texas Interconnections, respectively.
The values reported for the Eastern Interconnection for capacity providing expected response
are in keeping with those calculated from the generic governor simulation of the frequency
response to the August 4, 2007 Eastern Interconnection Frequency Disturbance. Those
simulations showed that 30% of the capacity on‐line responded, and 20% of the capacity on‐
line withdrew primary support, leaving only 10% of the capacity on‐line providing sustained
primary frequency response.
95
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000179
Role of Governors
Figure 56 shows that for the Eastern Interconnection, total response in the expected direction
was 973 MW, while response in the direction opposite expectations was -361 MW, for a total
net response of 613 MW. Steam coal and combined-cycle gas turbine units, accounting for 327
MW and 244 MW of the net response, respectively, made the largest contributions. These
contributions were made by steam coal and combine-cycle with a total on-line generating
capacity of about 180 GW steam coal and about 60 GW combined-cycle gas turbine units, of
which about 80 GW and about 10 GW of capacity provided response in the expected direction,
respectively.
Figure 56: Eastern Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Expected
Response
Opposite of
Expected
Response
Net Response
Steam Coal
541
-214*
327
Steam Gas
55
-27
28
9
-21
-12
290
-47
244
Steam nuclear
Combined cycle gas
Hydro
36
-5
30
Remaining
42
-47
-5
973
-361
613
Sub-Total
* Excludes the impact of one outlier unit with -101 MW response
Frequency Response Initiative Report – October 2012
96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000180
Role of Governors
Figure 57 shows that for the Western Interconnection, total response in the expected direction
was 1040 MW, while response in the direction opposite expectations was -180 MW, for a total
net response of 860 MW. Hydro units, accounting for 727 MW of the net response, made the
largest contribution. Hydro units made this contribution with a total on-line generating
capacity of about 50 GW, of which about 19 GW of capacity provided response in the expected
direction.
Figure 57: Western Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Opposite of
Expected
Response
Net
Response
Steam Coal
85
-35
50
Steam Gas
32
0
32
1
-7
-6
Combined cycle gas
144
-74
70
Hydro
742
-15
727
37
-49
-12
1040
-180
860
Steam nuclear
Remaining
Sub-Totals
97
Expected
Response
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000181
Role of Governors
Figure 58 shows that for the ERCOT Interconnection, total response in the expected direction
was 896 MW, while response in the direction opposite expectations was -50 MW, for a total net
response of 845 MW. Steam gas units, accounting for 490 MW of the net response, made the
largest contribution. Steam gas units made this contribution with a total on-line generating
capacity of about 11 GW, of which ~10 GW of capacity provided response in the expected
direction.
Figure 58: ERCOT Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Expected
Response
Opposite of
Expected
Response
Net
Response
Steam Coal
137
-16
121
Steam Gas
490
0
490
Steam nuclear
Combined cycle gas
Hydro
Remaining
Sub-Total
Frequency Response Initiative Report – October 2012
0
0
0
197
-33
164
7
0
7
65
-1
63
896
-50
845
98
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000182
Future Analysis Work Recommendations
Future Analysis Work Recommendations
Testing of Eastern Interconnection Maximum Allowable
Frequency Deviations
The stability simulation testing of the Eastern Interconnection resource loss criteria used in the
determination of the IFRO was limited to analysis using the generic governor stability case
developed by the NERC Model Validation Working Group and the Eastern Interconnection
Reliability Assessment Group (ERAG) Multi-Regional Modeling Working Group (MMWG) in
December 2011 (based on the August 4, 2007 Eastern Interconnection Frequency Disturbance).
Simulations using that stability simulation indicated a maximum sustainable generation loss of
about 8,500 MW for the Eastern Interconnection. However, that simulation case was not for
the light load conditions where system inertia and load response would be expected to be
lower than in the generic case.
Recommendation – Dynamic simulation testing of the Western and ERCOT Resource
Contingency Protection Criteria should be conducted as soon as possible.
Recommendation – When ERAG MMWG completes its review of turbine governor modeling, a
new light-load case should be developed, and the resource loss criterion for the Eastern
Interconnection’s IFRO should be re-simulated.
Eastern Interconnection Inter-area Oscillations – Potential for
Large Resource Losses
During the spring of 2012, a number of inter-area oscillations were observed between the
upper Midwest and the New England/New Brunswick areas in the 0.25 Hz family. During one
such event, a large generation outage in Georgia instigated that oscillation mode and was
interpreted by the FNet frequency monitoring and event detection program as an 1,800 MW
resource loss in the upper Midwest. Immediately, the FNet Oscillation Monitoring system
detected the 0.025 Hz family oscillations between the upper Midwest and New England/New
Brunswick. Investigation into the event showed that it occurred while the Dorsey – Forbes 500
kV transmission line was out of service for maintenance. During that line outage, the transfers
on the Dorsey DC line from Northern Manitoba were significantly curtailed, and the oscillation
of the Dorsey DC terminal capabilities for damping the 0.025 Hz oscillations were greatly
reduced. This made the system more susceptible to such oscillations. In all instances, the
energy magnitude under the oscillations was small, well-damped, and of little danger to the
reliability of the Eastern Interconnection.
However, the instigation of those oscillations by a generator trip in Georgia seemed unlikely
until reviewed in light of the inter-area oscillations detected following the South Florida
disturbance of February 26, 2008. During that disturbance, a family of 0.22 Hz oscillations was
detected between the Southeast and the upper Midwest. In both cases, the same generation
99
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Future Analysis Work Recommendations
000183
in the upper Midwest has a strong participation in both mode shapes, and since both oscillation
modes are close in frequency, the 0.25 Hz family was easily perturbed by an instance of the
0.22 Hz mode oscillations caused by the Georgia generator tripping.
Recommendation – Eastern Interconnection inter-area oscillatory behavior should be further
investigated by NERC, including during the testing of large resource loss analysis for IFRO
validation.
Frequency Response Initiative Report – October 2012
100
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000184
Appendices – Table of Contents
Appendices Table of Contents
Appendix A – Contributors
Appendix B – Abbreviations
Appendix C – Definitions and Terminology
Appendix D – Interconnection Frequency Deviation Duration Plots
Appendix E – ALR1-12 Metric Event Selection Process
Appendix F – Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard (BAL-003-1)
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Statistical Analysis of Frequency Response
Appendix H – Frequency Response Field Trial Analysis Graphs
Appendix I – Derivation of the Median, Mean, and Linear Regression
Appendix J – Generator Governor Survey Instructions
Appendix K – Generator Governor Survey Summary
Appendix L – References
Frequency Response Initiative Report – October 2012
ii
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000185
Appendix A – Contributors
Appendix A – Contributors
Principal – Robert W. Cummings – Director of Reliability Initiatives and System Analysis, NERC
Gregory P. Henry – Performance and Analysis Engineer, NERC
Eric H. Allen – Senior Performance and Analysis Engineer, NERC
Neil Burbure – Engineer of Reliability Initiatives and System Analysis, NERC
Matthew Varghese – Senior Performance Analysis Engineer, NERC
Svetlana Ekisheva – Senior Statistician, NERC
Stacey Tyrewala – Attorney, NERC
Mark G. Lauby – Vice President and Director of Standards, NERC
Howard F. Illian1 – President, Energy Mark, Inc.
John Undrill1 – John Undrill, LLC
Carlos A. Martinez1 – Advanced Systems Researchers (ASR)
Sydney L. Niemeyer – Control System Specialist, NRG Texas LP
Joseph H. Eto1 – Staff Scientist, Ernest Orlando Lawrence Berkeley National Laboratory,
Environmental Energy Technologies Division
NERC Frequency Response Standard Drafting Team
NERC Frequency Working Group
NERC Resources Subcommittee
NERC System Analysis and Modeling Subcommittee (formerly the Transmission Issues
Subcommittee)
1
Participation made possible through funding provided by the U.S. Department of Energy Office of Electricity and Energy Reliability,
coordinated through the Lawrence Berkeley National Laboratory.
A‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000186
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000187
Appendix B – Abbreviations
Appendix B – Abbreviations
ACE
ADF
AGC
ALR
ARLPC
BA
BAA
CERTS
CPS
Area Control Error
Adjusted Delta Frequency
Automatic Generator Control
Acceptable Level of Reliability
Adjusted resource loss protection criteria adjusted for the credit for load resources
Balancing Authority
Balancing Authority Area
Consortium for Electric Reliability Technology Solutions
Control Performance Standard
Ratio of the Point C to Value B to adjust the allowable delta frequency to account for
CBR
that difference.
Adjustment to Point C for the differences between 1‐second and sub‐second
CCADJ
measurements
COI
California‐Oregon Interface (ac)
D
Load damping factor
dc
Direct current
DCS
Disturbance Control Standard
DFBase
Base delta frequency
DFCC
Delta frequency adjusted for the differences between 1‐second and sub‐second Point
C observations for frequency events
EMS
Energy Management System
EPG
Electric Power Group
ERAG
Eastern Interconnection Reliability Assessment Group
ERCOT Electric Reliability Council of Texas
ERO
Electric Reliability Organization
FStart
Starting Frequency
FERC
The U.S. Federal Energy Regulatory Commission
FDR
Frequency Disturbance Recorder
FMA
Frequency Monitoring and Analysis tool
FNet
Frequency Monitoring Network (University of Tennessee, Knoxville, and Virginia
Tech)
FRC
Frequency Response Characteristic
FRCC
Florida Reliability Coordinating Council
FRM
Frequency Response Measure
FRO
Frequency Response Obligation (FROBA)
FRRSDT Frequency Response Standard Drafting Team
B‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000188
Appendix B – Definitions and Terminology
FR
FRS
FRSG
FWG
GOs
GOPs
GVD
GW
H
Hz
IFRO
LaaR
LBNL
mHz
MMWG
MVA
MW
N‐1
N‐2
NIA
NIS
PAS
PDCI
PDCWG
PMU
PV
RA
RARF
RAS
RLPC
RPM
RC
SAMS
SCADA
SEFRD
SEFRD
TIS
TRE
Frequency Response
Frequency Response Standard
Frequency Response Sharing Group
Frequency Working Group
Generator Owners
Generator Operators
Governor Valve Demand
gigawatts (thousands of megawatts)
Inertial constant (of the interconnection)
hertz (cycles per second)
Interconnection Frequency Response Obligation (FROInt)
Load Acting as a Resource
Ernest Orlando Lawrence Berkeley National Laboratory
millihertz
Multi‐Regional Modeling Working Group
megavoltampere
megawatts
Loss of one system element
Loss of two system elements
Net Interchange Actual
Net Interchange Scheduled
Performance Analysis Subcommittee
Pacific Direct Current Intertie
Performance Disturbance and Compliance Working Group (ERCOT)
Phasor Measurement Unit
Photovoltaic
Resource Adequacy Tool
ERCOT Resource Asset Registration Form
Remedial Action Scheme (also known as a Special Protection Scheme – SPS)
Resource Loss Protection Criteria
Revolutions per Minute
Resources Subcommittee
System Analysis and Modeling Subcommittee (formerly TIS)
System Control and Data Acquisition
Single Event Frequency Response Data
Single Event Frequency Response Data
Transmission Issues Subcommittee (now SAMS)
Texas Regional Entity
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000189
Appendix B – Abbreviations
UFLS
B‐3
Under‐Frequency Load Shedding
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000190
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000191
Appendix C – Definitions and Terminology
Appendix C – Definitions and Terminology
Definitions used in Standard BAL-003-1
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s inverse Frequency Response contribution to the interconnection, and
discourage response withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG)
Groups, whose members consist of two or more Balancing Authorities, that collectively
maintain, allocate, and supply operating resources required to jointly meet the sum of
the Frequency Response Obligations of its members.
Area Control Error (ACE)*: The instantaneous difference between a Balancing Authority’s net
actual and scheduled interchange, taking into account the effects of Frequency Bias and
correction for meter error.
Arrested Frequency – Value C – Point C – Frequency Nadir: The point of maximum frequency
excursion in the first swing of the frequency excursion between time zero (Point A) and
time zero plus 20 seconds.
Arresting Period: The period of time from time zero (Point A) to the time of Point C.
Arresting Period Frequency Response: A combination of load damping and the initial Primary
Control Response acting together to limit the duration and magnitude of frequency
change during the Arresting Period.
Automatic Generation Control (AGC)*: Equipment that automatically adjusts generation in a
Balancing Authority Area from a central location to maintain the Balancing Authority’s
C‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000192
Appendix B – Definitions and Terminology
interchange schedule plus Frequency Bias. AGC may also accommodate automatic
inadvertent payback and time error correction.
Balancing Authority (BA)*: The responsible entity that integrates resource plans ahead of time,
maintains load‐interchange‐generation balance within a Balancing Authority Area, and
supports interconnection frequency in real time.
Beta: The factor by which the frequency deviation is multiplied by in the ACE equation to
adjust the ACE to protect a BA’s Frequency Response.
Contingency Protection Criteria of an interconnection: The selected capacity contingency that
an interconnection must withstand at all times without the activation of the first tier of
UFLS.
Contingency Reserve*: The provision of capacity deployed by the Balancing Authority to meet
the Disturbance Control Standard (DCS) and other NERC and Regional Reliability
Organization contingency requirements.
Frequency ¡: The rate at which a repeating waveform repeats itself. Frequency is measured in
cycles per second or in hertz (Hz). The symbol is “F.”
Frequency Bias Setting: The term of the ACE equation that is multiplied by frequency deviation
portion. This is a corrective term to offset the tie‐line flow error caused by
generation/load responding to a frequency deviation.
Frequency Deviation*: A change in interconnection frequency.
Frequency Response*: (Equipment) The ability of a system or elements of the system to react
or respond to a change in system frequency. (System) The sum of the change in
demand, plus the change in generation, divided by the change in frequency, expressed
in megawatts per 0.1 hertz (MW/0.1 Hz).
Frequency Responsive Reserve (a.k.a., dynamic headroom): The capacity of Governor
Response and/or Frequency‐Responsive Demand Response that will be deployed for any
frequency excursion.
Frequency‐Responsive Demand Response: Voluntary load shedding that complements
governor response. This load reduction is typically triggered by relays that are activated
by frequency.
Frequency Sensitive Load: Customer loads that vary directly with changes in frequency or
would trip as a result of frequency deviations.
Governor response§: The control response of turbine‐governors to sensing a change in speed
of the turbine as frequency increases or declines, causing an adjustment to the energy
input of the turbine’s prime mover.
Headroom: The difference between the current operating point of a generator and its
maximum operating capability.
Inertia¡: The property of an object that resists changes to the motion of an object. For example,
the inertia of a rotating object resists changes to the object’s speed of rotation. The
inertia of a rotating object is a function of its mass, diameter, and speed of rotation.
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000193
Appendix C – Definitions and Terminology
Load damping¥: The damping effect of the load to a change in frequency due to the physical
aspects of the load such as the inertia of motors and the physical load to which they are
connected.
Load following¡: Commitment of energy based resources (generation or energy schedule) to
match the forecast load level for a given period. This is a form of course control for
moment‐by‐moment resource/load matching.
Non‐spinning reserve*: 1. That generating reserve not connected to the system but capable of
serving demand within a specified time. 2. Interruptible load that can be removed from
the system in a specified time.
Off‐line Reserve§: The off‐line capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection.
On‐line Reserve§: The on‐line capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection. This can consist of spinning reserve and interruptible load that can act
as a resource.
Operating Reserve*: That capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection. It consists of spinning and non‐spinning reserves.
Other On‐line Reserves§: On‐line Resources that can increase their output or connected loads
that can decrease their consumption (curtailable loads) in time frames outside the
continuum of regulating or spinning reserve (i.e. on four hours’ notice).
Other Off‐line Reserves§: Resources that can be brought to bear outside the continuum of
non‐spinning reserve (i.e., on four hours’ notice).
Plant secondary control@: Secondary control refers to controls affected through commands to
a turbine controller issued by external entities not necessarily working in concert with
frequency management objectives. It is common for a modern power plant to have
several distinct modes of secondary control implemented within the plant and to be
able to accept secondary control inputs from sources external to the plant.
Primary Control Response Withdrawal: The withdrawal of previously delivered Primary
Control Response, through plant secondary controls.
Primary Frequency Control Response: The power delivered to the interconnection in response
to a frequency deviation through generator governor response, load response (typically
from motors), demand response (designed to arrest frequency excursions), and other
devices that provide an immediate response to frequency based on local (device‐level)
control systems, without human or remote intervention.
Primary Frequency Control Reserves: Frequency‐responsive reserves that respond nearly
instantaneously (starting in less than 1 second) to oppose any changes in power system
frequency.
C‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000194
Appendix B – Definitions and Terminology
Quick Start Reserve: A form of non‐spinning reserve that can be put on‐line and the capacity
that can be deployed in ten minutes.
Recovery Period: The period of time from when Secondary Control Response are deployed
(typically about zero plus 53 seconds) to the time of the return of frequency to within
pre‐established ranges of reliable continuous operation.
Regulation¥: Controllable resources necessary to provide for the continuous balancing of
resources (generation and interchange) with load and for maintaining scheduled
interchange and interconnection scheduled frequency. Regulation is accomplished by
committing on‐line generation whose output is raised or lowered (predominantly
through the use of automatic generating control equipment) as necessary to follow the
moment‐by‐moment changes actual net interchange.
Regulating reserve*: An amount of reserve responsive to Automatic Generation Control, which
is sufficient to provide a normal regulating margin.
Settling frequency¥, #: Refers to the third key event during a disturbance when the frequency
stabilizes following a frequency excursion. Point B represents the interconnected system
frequency at the point immediately after the frequency stabilizes due to governor action
but before the contingent control area takes corrective AGC action.
Secondary Control Response: The power delivered by a Balancing Authority or Reserve Sharing
Group in response to a frequency deviation through Secondary Control actions, such as
manual or automated dispatch from a centralized control system. Secondary control
actions are intended to restore Primary Control Response and restore frequency from
the Arrested Frequency back to Scheduled Frequency, or maintain Scheduled
Frequency.
Secondary Frequency Control: Actions provided by an individual BA or its Reserve Sharing
Group intended to restore Primary Control Response and restore frequency from the
Arrested Frequency back to Scheduled Frequency, or to maintain Scheduled Frequency
deployed in the “minutes” time frame. Secondary Control comes from either manual or
automated dispatch from a centralized control system. Secondary Control also includes
initial reserve deployment for disturbances and maintains the minute‐to‐minute balance
throughout the day and is used to restore frequency to normal following a disturbance
and is provided by both spinning and non‐spinning reserves.
Secondary Frequency Control Reserves: Frequency‐responsive reserves that respond over
slightly longer time frames (starting in 20‐30 seconds). Following the sudden loss of
generation, they assist in restoring frequency to the scheduled value after Primary
Frequency Control Reserves have been deployed. They also safeguard Primary
Frequency Control Reserves (so that primary reserves remain available to respond to
these sudden events) by controlling frequency in response to slower imbalances that
arise between electricity demand and generation such as the normal rise and fall of
system load over the course of a day.
Spinning reserve*: Unloaded generation that is synchronized and ready to serve additional
demand.
Frequency Response Initiative Report – October 2012
D‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000195
Appendix C – Definitions and Terminology
Tertiary frequency control§: Encompasses actions taken to get resources in place to handle
current and future changes in load or contingencies. Reserve deployment and Reserve
restoration following a disturbance is a common type of Tertiary frequency control.
Under‐frequency load shedding¡: The tripping of customer load based on magnitudes of
system frequency. For example, a utility may dump 5% of their connected load if
frequency falls below 59.3 Hz, dump an additional 10% if frequency falls below 58.9 Hz,
and dump a final 10% if frequency falls below 58.5 Hz. These three steps of load
shedding would form this utility’s UFLS plan. The purpose of UFLS is a final effort (safety
net) to arrest a frequency decline.
Sources:
* NERC Glossary of Terms Used in Reliability Standards,
http://www.nerc.com/files/Glossary_of_Terms.pdf
¥
NERC Reference Document Understand and Calculating Frequency Response (June 19, 2008)
§
NERC Balancing and Frequency Control (July 5, 2009)
#
NERC Frequency Response Characteristic Survey Training Document,
http://www.nerc.com/docs/standards/sar/opman_12‐
13Mar08_FrequencyResponseCharacteristicSurveyTrainingDocument.pdf (January 1, 1989)
@
Undrill, J.M. 2010. Power and Frequency Control as it Relates to Wind‐Powered Generation.
LBNL‐4143E. Berkeley: Lawrence Berkeley National Laboratory
¡
Definitions taken from the EPRI Power Systems Dynamics Tutorial. EPRI, Palo Alto, CA: 2009.
1016042
C‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000196
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000197
Appendix D – Interconnection Frequency Deviation Duration Plots
Appendix D – Interconnection Frequency Deviation
Duration Plots
Figure D1: Summary of Eastern Interconnection Frequency 2007–2011
2500000
2000000
1500000
1000000
500000
0
58.8
59
59.2
59.4
59.6
59.8
60
60.2
60.4
Figure D2: Eastern Interconnection 2007–2011 Frequency Histogram
4
3.5
Percentage of Observations (%)
3
2.5
2
1.5
1
0.5
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
D‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000198
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D3: Eastern Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Figure D4: Summary of Western Interconnection Frequency 2007–2011
600000
500000
400000
300000
200000
100000
0
59.5
59.6
59.7
59.8
59.9
60
60.1
60.2
60.3
60.4
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000199
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D5: Western Interconnection 2007–2011 Frequency Histogram
0.035
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure D6: Western Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
D‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000200
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D7: Summary of ERCOT Interconnection Frequency 2007–2011
350000
300000
250000
200000
150000
100000
50000
0
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
Figure D8: ERCOT Interconnection 2007–2011 Frequency Histogram
0.016
0.014
Percentage of Observations (%)
0.012
0.01
0.008
0.006
0.004
0.002
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Frequency Response Initiative Report – October 2012
D‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000201
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D9: ERCOT Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Figure D10: Summary of Québec Interconnection Frequency 2010–2011
Q
120000
100000
80000
60000
40000
20000
0
59
D‐5
59.2
59.4
59.6
59.8
60
60.2
60.4
60.6
60.8
61
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000202
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D11: Québec Interconnection 2010–2011 Frequency Histogram
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure D12: Québec Interconnection Frequency 2010–2011 Cumulative Distribution
Q
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Frequency Response Initiative Report – October 2012
D‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000203
Appendix E – ALR1‐12 Metric Event Selection Process
Appendix E – ALR1-12 Metric Event Selection
Process
1. CERTS‐EPG produces a monthly spreadsheet for four interconnections (Eastern
Interconnection or EI, Western or WI, ERCOT Interconnection or TI, and Québec). The
spreadsheet captures significant frequency events based on the Resources Subcommittee
(RS) specified threshold. The Frequency Monitoring and Analysis tool (FMA) gathers and
stores the raw data.
2. The spreadsheet is sent by CERTS‐EPG to the Frequency Working Group (FWG) on the 15th
of each month for the previous month’s raw data.
3. The FNET application uses automatic e‐mails to flag frequency deviations. Generation loss is
estimated.
4. The actual generation loss for the FNET flagged frequency events is determined by the NERC
Situation Awareness Coordinator from the Regional Entities and sent to the FWG.
5. The FWG members validate the data and add the actual generation loss values into the
spreadsheet.
6. FWG sends the validated monthly sheet to the Resource Subcommittee (RS) and the
Performance Analysis Subcommittee (PAS) on the 30th of each month for the previous
month’s raw data.
7. NERC staff will update the candidate event list on the NERC website that will be used to
support the standard. The final official event list for a year will be identified as a subset of
the posted candidate list.
8. PAS publishes the quarterly Frequency Response metric data on NERC’s Reliability
Indicators webpage. The initial trending will be based on annual median/mean and rolling
12 month values.
Background Information
The frequency delta thresholds recommended by RS for the Eastern, Western, ERCOT and
Québec Interconnections are shown in Table E1.
Table E1: Frequency delta thresholds recommended by RS
Interconnections
Frequency Delta for events
captured in (mHz)
Frequency Delta for
Significant events that
have a higher Delta
Time
Window
(Seconds)
Eastern
24
36
15
Western
40
70
15
ERCOT
45
90
15
Québec
140
200
15
E‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000204
Appendix E – ALR1‐12 Metric Event Selection Process
The raw statistics for events in 2008, 2009, 2010 and the first half of 2011 are listed in Table E2
below. This was sent by CERTS‐EPG to the FWG on August 31, 2011.
Table E2: Raw Statistics for frequency events from 2008 to July 2011
Interconnection
Eastern
Western
ERCOT
Québec
2008
195
102
26
No Data
2009
78
72
85
No Data
2010
132
85
122
No Data
2011 (until July)
70
37
61
159
The statistics for TI from 2008 to 2011 were validated and modified by the FWG. Table E3
shows the statistics for TI that were sent by the FWG to the RS on September 02, 2011.
Table E3: Validated Statistics for TI frequency events
from 2008 to July 2011
Interconnections
TI
2008
8
2009
51
2010
67
2011 (until July)
40
The FWG Lead members who will validate the data and add the actual generation loss values
into the spreadsheet for the four interconnections are listed in Table E4.
Table E4: Lead members for the four interconnections
Terry L. Bilke
Eastern Interconnection
Don E. Badley
Western Interconnection
Sydney L. Niemeyer
ERCOT Interconnection
Michael Potishnak
Québec Interconnection
In July 2011, CERTS‐EPG produced the first of the monthly reports for the FWG. July 2011 has
22 frequency events and a summary is shown in Table E5.
Frequency Response Initiative Report – October 2012
E‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000205
Appendix E – ALR1‐12 Metric Event Selection Process
Table E5: Summary of the 1st monthly report produced by CERTS‐EPG for the FWG in
July 2011
E‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000206
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000207
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
Appendix F – Procedure for ERO Support of
Frequency Response and Frequency Bias Setting
Standard (BAL-003-1)
Event Selection Process
This procedure outlines the ERO process for supporting the Frequency Response Standard
(FRS). A procedure revision request may be submitted to the ERO for consideration. The
revision request must provide a technical justification for the suggested modification. The ERO
will post the suggested modification for a 45‐day comment period and discuss the revision
request in a public meeting. The ERO will make a recommendation to the NERC BOT, which
may adopt the revision request, adopt it with modifications, or reject it. Any approved revision
to this procedure will be filed with FERC for informational purposes.
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify
a list of frequency events to be used by Balancing Authorities (BA) to calculate their Frequency
Response to determine:
whether the BA met its Frequency Response Obligation; and
an appropriate fixed bias setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for
analysis. The events that best fit the criteria will be used to support the FRS. The
evaluation period for performing the annual Frequency Bias Setting and the Frequency
Response Measure (FRM) calculation is December 1 of the prior year through November
30 of the current year.
2. The ERO will identify 20–35 frequency excursion events in each interconnection for
calculating the Frequency Bias Setting and the FRM. If the ERO cannot identify 20
frequency excursion events in a 12‐month evaluation period satisfying the criteria
below, then similar acceptable events from the subsequent year’s evaluation period will
be included with the data set by the ERO for determining FRS compliance.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event
for the FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C
and the arrested frequency Point C exceeds the excursion threshold values specified
for the interconnection in Table F1 below.
i. The A Value is computed as an average over the period from ‐16 seconds to 0
seconds before the frequency transient begins to decline.
F‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000208
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
Table F1: Interconnection Frequency Excursion
Threshold Values (Hz)
A Value
to Pt C
Point C
(Low)
Point C
(High)
Eastern
0.04
< 59.96
> 60.04
Western
0.07
< 59.95
> 60.05
ERCOT
0.15
< 59.90
> 60.10
Québec
0.30
< 59.85
> 60.15
Interconnection
b. The time from the start of the rapid change in frequency until the point at which
frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not
be included.
4. Pre‐disturbance frequency should be relatively steady and near 60.000 Hz for the A
Value. The A Value is computed as an average over the period from ‐16 seconds to 0
seconds before the frequency transient begins to decline. For example, given the choice
of the two events below, the one on the right is preferred as the pre‐disturbance
frequency is stable and also closer to 60 Hz.
5. Excursions that include two or more events that do not stabilize within 18 seconds will
not be considered.
6. Frequency excursion events occurring during periods when large interchange schedule
ramping or load change is happening, and frequency excursion events occurring within 5
Frequency Response Initiative Report – October 2012
F‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000209
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
minutes of the top of the hour, will be excluded from consideration if other acceptable
frequency excursion events from the same quarter are available.
7. The ERO will select the largest (A Value to Point C) two or three frequency excursion
events occurring each month. If there are not two frequency excursion events that
satisfy the selection criteria in a month, then other frequency excursion events should
be picked in the following order of priority:
1)
2)
3)
4)
from the same event quarter of the year
from an adjacent month
from a similar load season in the year (shoulder vs. summer/winter)
the largest unused event
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar
acceptable events from the next year’s evaluation period will be included with the data set by
the ERO for determining FRO compliance. The first year’s small set of data will be reported and
used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a 24
month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation.
The ERO will post the final list of frequency excursion events used for standard compliance as
specified in Attachment A of BAL‐003‐1. The following is a general description of the process
that the ERO will use to ensure that BAs can evaluate events during the year in order to monitor
their performance throughout the year.
Monthly
Candidate events will be initially screened by the “Frequency Event Detection Methodology”
shown on the following link located on the NERC Resources Subcommittee area of the NERC
website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oc
t_2011.pdf.
Each month’s list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under “Candidate Frequency Events.”
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
F‐3
December through February
March through May
June through August
September through November
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000210
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
Based on criteria established in the “Procedure for ERO Support of Frequency Response and
Frequency Bias Setting Standard,” events will be selected to populate the FRS Form 1 for each
interconnection. Each interconnection’s Form 1 will be posted on the NERC website, in the
Resources Subcommittee area under the title “Frequency Response Standard Resources.” The
updated Form 1 documents will be posted at the end of each quarter listed above after a
review by the NERC RS Frequency Working Group. While the events on this list are expected to
be final, as outlined in the selection criteria, additional events may be considered, if the number
of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events
throughout the year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each interconnection, which will contain the events from all four
quarters listed above, will be posted as specified in Attachment A. Each Balancing Authority
reports its previous year’s Frequency Response Measure (FRM), Frequency Bias Setting and
Frequency Bias type (fixed or variable) to the ERO as specified in Attachment A using the final
FRS Form 1. The ERO will error check and use the FRS Form 1 data to calculate CPS limits and
FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified
in Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility
in when each BA implements its settings.
Frequency Response Initiative Report – October 2012
F‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000211
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Appendix G – Statistical Analysis of Frequency
Response (Eastern Interconnection)
Statistical Analysis of Frequency Response
Eastern Interconnection August 7, 2012
Introduction
An interconnected electric power system is a complex system that must be operated within a
safe frequency range to reliably maintain the instantaneous balance between generation and
load, and is directly reflected in the frequency of the interconnection. Frequency Response is
one measurement of how a power system has performed in response to the sudden loss of
generation or load. This white paper analyzes the Frequency Response data for the Eastern
Interconnection using statistical methods to study the probability distribution of the Frequency
Response and its changes from year‐to‐year, as well as construct a set of variables that strongly
influence Frequency Response.
Objectives and Method
The main goals of the statistical analysis of the Frequency Response data for the Eastern
Interconnection are to study the:
1. time trend of Frequency Response by selecting an appropriate model describing the
relationship between a point in time when an event happens and the absolute value of
Frequency Response for this event, and to use this model for Frequency Response
forecasting with a given confidence level;
2. probability distribution of the Frequency Response and its changes over the years;
3. seasonal changes in Frequency Response distribution and correlation between Frequency
Response value and season when the event happened (summer/non‐summer);
4. impact of pre‐disturbance frequency on Frequency Response;
5. impact of on‐peak/off‐peak hours on Frequency Response;
6. impact of interconnection load on Frequency Response; and
7. hierarchy of these explanatory factors of Frequency Response.
The analysis uses the Frequency Response dataset for the Eastern Interconnection for the
calendar years 2009‐2011 and the first three months of 2012. The size of this dataset is 163
frequency events (with 44 observations for the year of 2009, 49 for 2010, 65 for 2011, and 5 for
2012). Since interconnection load data are not yet available for 2012, the part of the study
involving interconnection load deals with the 158 Frequency Response events occurred in 2009‐
2011. For purposes of this whitepaper, Frequency Response pertains to the absolute value of
Frequency Response.
G‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000212
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Key Findings
1. A linear regression equation with the parameters defined in the Appendix of this
whitepaper is an adequate statistical model to describe a relationship between time
(predictor) and Frequency Response (response variable). The graph of the linear regression
line and Frequency Response scatter plot is given in Figure G1. For the dataset, the
regression line has a small positive slope estimate, meaning that the Frequency Response
variable has a slowly increasing general trend in time. The value of the slope estimate is
0.00000303805 (the time unit is a second). This means that, on average, Frequency
Response increases daily by 0.26 MW/0.1Hz, monthly by 7.87 MW/0.1 Hz, and annually by
95.81 MW/ 0.1Hz (for a month with 30 days , and a year with 365 days). A 90% confidence
interval for slope, CI=[‐0.00000041605, 0.00000649214], has a negative left‐end point (the
same is true for a 95% CI and a 99% CI). With new data available the trend line can (a)
increase its positive slope, (b) change the positive slope to a slight negative one, or (c)
become essentially flat that will correspond to an absence of a correlation between time
and Frequency Response.
Figure G1: Frequency Response Scatter Plot
2. The probability distribution of the whole Frequency Response dataset is approximately
normal with the expected Frequency Response of 2363 MW/0.1 Hz and the standard
deviation of 605.7 MW/0.1 Hz as shown in Figure G2. The comparative statistical analysis
for every pair of years shows that the changes in the 2010 data versus the 2009 data (and
in the 2011 data versus the 2010 data) are not statistically significant enough to lead to the
conclusion that the mean value of Frequency Response for any two consecutive years
changes. However, the data for 2009 and 2011 differ at the level that results in accepting
Frequency Response Initiative Report – October 2012
G‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000213
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
the hypothesis that the expected value of Frequency Response for 2011 is greater than for
2009.
Figure G2: Probability Distribution of the Entire Frequency Response Data Set
3. A season (summer/non‐summer) is a significant contributor to the variability of Frequency
Response. There is a positive correlation of 0.24 between the indicator function for summer
(defined as 1 for events that occur in June–August and 0 otherwise) and Frequency
Response: summer events have a statistically significantly greater expected Frequency
Response (the sample mean equals to 2598MW/0.1 Hz) than non‐summer events (the mean
equals to 2271 MW/0.1 Hz).
4. Pre‐disturbance (average) frequency (A) is another significant contributor to the variability of
Frequency Response. There is a negative correlation of ‐0.27 between the indicator function
of A>60 Hz and Frequency Response: the events with A>60 Hz have a statistically significantly
smaller expected Frequency Response (the sample mean equals to 2188 MW/0.1 Hz) than
the events with A≤60 Hz (the mean equals to 2513 MW/0.1 Hz).
5. According the NERC definition, for Eastern Interconnection on‐peak hours are designated as
follows: Monday to Saturday hours from 0700 to 2200 (Central Time) excluding six holidays
(New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and
Christmas Day). It turns out that on‐peak/off‐peak variable is not a statistically significant
G‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000214
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
contributor to the variability of Frequency Response. There is a positive correlation of 0.06
between the indicator function of on‐peak hours and Frequency Response; however,
difference in average Frequency Response between on‐peak events and off‐peak events is
not statistically significant and could occur by chance (P‐value is 0.49).
6. There is a strong positive correlation of 0.364 between interconnection load and Frequency
Response for the 2009‐2011 events; this correlation indicates to a statistically significant
linear relationship between interconnection load (predictor) and Frequency Response
(response variable). The graph of the linear regression line and Frequency Response scatter
plot is given in Figure G3. For the dataset, the regression line has a positive slope estimate of
0.00349; thus, the Frequency Response variable increases when interconnection load grows.
On average, when interconnection load changes by 1000 MW, Frequency Response changes
by 3.5 MW/0.1Hz.
Figure G3: Linear Regression for Frequency Response and Interconnection Load
7. For the 2009–2011 dataset, five variables (time, summer, high pre‐disturbance frequency,
on‐peak/off‐peak hour, interconnection load) have been involved in the statistical analysis of
Frequency Response. Four of these (time, summer, on‐peak hours, and interconnection load)
have a positive correlation with Frequency Response (0.16, 0.24, 0.06, and 0.36,
Frequency Response Initiative Report – October 2012
G‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000215
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
respectively), and the high pre‐disturbance frequency has a negative correlation with
Frequency Response (‐0.26). The corresponding coefficients of determination R2 are 2.6%,
5.8%, 0.4%, 13.3% and 6.9%. These values indicate that about 2.6% in variability of
Frequency Response can be explained by the changes in time, about 5.8% of Frequency
Response variability is seasonal, 0.4% is due to on‐peak/off‐peak changes, 13.3% is the effect
of the interconnection load variability, and about 6.9% can be accounted for by a high pre‐
disturbance frequency. However, the correlation between Frequency Response and On‐Peak
hours is not statistically significant and with the probability about 0.44 occurred by mere
chance (the same holds true for the corresponding R2). Therefore, out of the five
parameters, interconnection load has the biggest impact on Frequency Response followed
by the indicator of high pre‐disturbance frequency. A multivariate regression with
interconnection load and A>60 as the explanatory variables for Frequency Response yields a
linear model with the best fit (it has the smallest mean square error among the linear models
with any other set of explanatory variables selected from the five studied). Still, together
these two factors can account for about 20% in variability of Frequency Response. Therefore,
there are other parameters that affect Frequency Response, have a low correlation with
those studied, together account for a remaining share in Frequency Response variability, and
minimize a random error variance. Note that interconnection load is positively correlated
with summer (0.55), on‐peak hours (0.45), and Date (0.20) but uncorrelated with A>60 (P‐
value of the test on zero correlation is 0.90).
Explanatory Variables for EI Frequency Response (2009-2011)
Sample
Correlation (X,FR)
P-value
Linear Regression
Statistically
Significant?
Coefficient of
Determination R^2
(Single Regression)
Interconnection Load
0.36
<0.0001
Yes
13.3%
A>60
-0.26
0.0008
Yes
6.9%
Summer
0.24
0.0023
Yes
5.8%
Date
0.16
0.044
Yes
2.6%
On-Peak Hours
0.06
0.438
No
N/A
Variable X
G‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000216
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Appendix – Background Materials
Frequency Response is a metric used to track and monitor Interconnection Frequency
Response. Frequency Response2 is a measure of an interconnection’s ability to stabilize
frequency immediately following the sudden loss of generation or load. It is a critical
component to the reliable operation of the bulk power system, particularly during disturbances
and restoration. The metric measures the average Frequency Response for all events where
frequency drops more than the interconnection’s defined threshold as shown in Table 1.
Frequency Response Definition
For a given interconnection, Frequency Response is defined as the sum of the change in
demand, plus the change in generation, divided by the change in frequency, expressed in
megawatts per 0.1 hertz (MW/0.1 Hz).
Table 1: Frequency Event Triggers for Data Collection
∆Frequency (mHz)
MW Loss Threshold
Rolling Windows
(seconds)
Eastern
40
800
15
Western
70
700
15
ERCOT
90
450
15
Québec
300
450
15
Interconnection
The change in frequency is the difference between pre‐disturbance frequencies A and setting
frequency B. Figure 3 shows the criteria for calculating average values A and B. The event starts
at time t ±0. Value A is the average from t ‐16 to t ‐2 and Value B is the average from t +20 to t
+52. These lengths of time used to calculate these values accounts for the variability in
Supervisory Control and Data Acquisition (SCADA) scan rates that vary from 2 to 6 seconds in
the multiple‐Balancing Authority interconnections. For Balancing Authority SCADA data, t ±0
represents the first scan of data that is part of the disturbance. Value A is the average of all
SCADA scans between 2 and 16 seconds before t ±0. Value B is the average of all SCADA scans
between 20 and 52 seconds after t ±0.
2
Frequency Response is in fact a negative value. However to reduce confusion for the reader, Frequency Response is expressed in this report
as positive values (the absolute value of the actual calculated value).
Frequency Response Initiative Report – October 2012
G‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000217
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Figure 3: Criteria for Calculating Value A and Value B
t ±0
The actual MW loss for the flagged frequency events is determined jointly by NERC and
Regional Entity situation awareness staff. Both the change in frequency and the MW loss
determine whether the event qualifies for further consideration in the monthly frequency
event candidate list.
Statistical Analysis
Linear Regression for Time Trend
Assumptions: Frequency Response and time are related by the following regression equation:
Where:
variable represents a time (year, month, day, hour, minute, second) when a
Frequency Response event happened. For each event the Frequency Response is
calculated and recorded. This record represents an observation from the dataset. Time
is an explanatory variable (predictor, regressor) of the linear regression;
is the Frequency Response value measured in MW/0.1 Hz (response variable of the
model);
is a slope of the regression line;
is an intercept of the regression line; and
ε is a random error which has a centered normal distribution with variance σ2.
G‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000218
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
A SAS program for the linear regression analysis yields the following results shown in figure G3.
(a) The equation of the regression line derived by the least squares method is
0.00000304
2493.41315 with
sec elapsed between midnight of
January 1, 1960 (the time origin for the date format in SAS) and the time of a FR event;
(b) Estimate for the variance σ2 of the random error ε is 362,383 and for the standard
deviation of ε is 601.98255;
(c) Statistical test for significance of the regression (based on the analysis of variance
approach) is an important part of assessing the adequacy of the linear regression model
for time and FR variables. The procedure tests a null‐hypothesis that the slope A = 0
versus an alternative hypothesis that it is not 0. Sample value of F‐statistic, 3.0170, has
P‐value of 0.0843 implying that the null hypothesis should be rejected (and the
alternative hypothesis accepted) at any significance level above 0.0843. Therefore, the
data are statistically significant to support a hypothesis about a linear relationship
between time and Frequency Response assuming that the 8.43% significance level (i.e.,
the probability to reject the null hypothesis when it is true) is appropriate for the model
selection. Alternatively, the hypothesis about the correlation coefficient ρ(time, FR) can
be tested (with the null hypothesis ρ=0). These tests are equivalent and result in the
same P‐values for their test statistics.
Another important part of the verification of the linear regression model is testing the
assumptions on the random error ε. Student’s t‐test on location and goodness‐of‐fit test for
normality both result in acceptance the corresponding null‐hypothesis (with P‐values of 1.0000
and 0.881, respectively).
The linear regression equation with the parameters defined above is an adequate statistical
model to describe the relationship between variables time of a FR event and Frequency
Response value for this event. For the dataset, the regression line has a small positive slope
estimate, meaning that Frequency Response variable has a slowly increasing general trend in
time. However, the value of this slope estimate is very small, and confidence intervals for slope
at 90%, 95% and 99% levels all have a negative left‐end point. By using T‐distribution for the
slope estimator, we estimate that the probability that the slope of the regression is negative is
below 5%.
The coefficient of determination R2 for the linear regression model equals to 0.0184. This small
value indicates very low degree of dependence of Frequency Response on time variable.
Essentially, the linear regression model connecting FR and time accounts for 1.8% of variability
in the Frequency Response data.
The random error ε has a large estimated variance that makes the “error” term of the linear
regression equation a major component of the Frequency Response value. Our next goal is to
consider the Frequency Response data as observations of a random variable independent of
time and to study properties of its distribution.
Frequency Response Initiative Report – October 2012
G‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000219
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Distribution of Frequency Response
Goodness‐of‐Fit test for normality of the distribution of the Frequency Response data results in
acceptance on the null hypothesis at a significance level below 0.177 (including the standard
levels of 1%, 5% and 10%). The sample estimate for the expected Frequency Response equals to
2363 MW/0.1 Hz and the sample standard deviation is 605.7 MW/0.1 Hz.
Since for each full year (2009, 2010, and 2011) the sample size of the Frequency Response data
exceeds 40, we ran a large‐sample test for the difference in the mean Frequency Response for
2009 versus 2010, 2010 versus 2011, and 2009 versus 2011. The null hypothesis that the
difference is zero is accepted when the 2009 data are compared to the 2010 data, and when
the 2010 data are compared to the 2011 data at any standard significance level (P‐values of the
two‐sided tests are 0.54 and 0.28, respectively). For the 2009 versus 2011 comparison, the test
result is not that conclusive (its P‐value equals to 0.03 and, therefore, the null hypothesis
should be rejected at the 5% and 10% significance levels but is accepted at the 1% level if tested
versus an alternative hypothesis that the 2011 mean value is greater than the 2009 mean
value).
Seasonal Variability of Frequency Response
Let a function summer be defined as follows: it equals to 1 for Frequency Response events that
occur in June‐August and 0 otherwise. The FR dataset is therefore divided in two subsets: the
Frequency Response data for summer events and non‐summer events, respectively. Summer
Frequency Response set has 46 observations and non‐summer set has 117 observations. The
sample mean and the sample variance for the first dataset are 2597.7 MW/0.1 Hz and 675.5
MW/0.1 Hz, respectively. The sample mean and the sample variance for the second dataset are
2270.9 MW/0.1 Hz and 552.2 MW/0.1 Hz. A large‐sample test for the difference in the mean
Frequency Response for these distributions results in rejection of the null hypothesis that the
difference is zero and acceptance of an alternative hypothesis that the expected Frequency
Response for summer events is greater than for other events (P‐value of the one‐sided z‐test is
0.0018).
Variables summer and Frequency Response are positively correlated (with the correlation equal
to 0.24351), and the coefficient of determination R2 of the linear regression model is 0.0593.
The null hypothesis about zero correlation (no linear relationship between FR and summer)
should be rejected (P‐value is 0.0017). This analysis indicates that seasonality is a significant
factor affecting Frequency Response: almost 6% of its variability is the seasonal variability.
Impact of Pre-Disturbance Frequency
Let a function high pre‐disturbance frequency be defined as follows: it equals to 1 for
Frequency Response events with A>60 Hz and 0 otherwise. The FR dataset is therefore divided
in two subsets: the Frequency Response data for events with A>60 Hz and events with A≤60 Hz,
respectively. High pre‐disturbance frequency set has 75 observations and its complement has
88 observations. The sample mean and the sample variance for the first dataset are 2187.6
MW/0.1 Hz and 531.5 MW/0.1 Hz, respectively. The sample mean and the sample variance for
the second dataset are 2512.8 MW/0.1 Hz and 627.4 MW/0.1 Hz. A large‐sample test for the
difference in the mean Frequency Response for these distributions results in rejection of the
null hypothesis that the difference is zero and acceptance of an alternative hypothesis that the
G‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000220
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
expected Frequency Response for events with A>60 Hz is smaller than for other events (P‐value
of the one‐sided z‐test is 0.0002).
Variables high pre‐disturbance frequency and Frequency Response are negatively correlated
(with the correlation equal to ‐0.26844), and the coefficient of determination R2 of the linear
regression model is 0.0721. The null hypothesis about zero correlation (no linear relationship
between FR and high pre‐disturbance frequency) should be rejected (P‐value is 0.0005). This
analysis indicates that the high pre‐disturbance frequency is a factor that accounts for 7.2% of
the Frequency Response variability. In fact, out of the four variables involved in this study (time,
summer, high pre‐disturbance frequency, on‐peak/off‐peak hours), it is the biggest contributor
to the variability of Frequency Response.
Impact of On-Peak/Off-Peak hours
Let a function on‐peak hour be defined as follows: it equals to 1 for Frequency Response events
occurred during an on‐peak hour and 0 otherwise. The FR dataset is therefore divided in two
subsets: the Frequency Response data for on‐peak hours and off‐peak hours, respectively. On‐
peak set contains 108 observations, and off‐peak set has 55 observations. The sample mean
and the sample variance for the first dataset are 2386.9 MW/0.1 Hz and 602.9 MW/0.1 Hz,
respectively. The sample mean and the sample variance for the second dataset are 2316.6
MW/0.1 Hz and 614.1 MW/0.1 Hz. A large‐sample test for the difference in the expected
Frequency Response for these distributions results in acceptance of the null hypothesis that the
difference is zero and rejection of an alternative hypothesis that the expected Frequency
Responses for on‐peak events and off‐peak events are different (P‐value of the two‐sided z‐test
is 0.49).
Variables on‐peak hour and Frequency Response are positively correlated (with the correlation
equal to 0.005505), and the coefficient of determination R2 of the linear regression model is
0.0030. However, the correlation is not statistically significant since the null hypothesis about
zero correlation (no linear relationship between FR and on‐peak hour) should be accepted (P‐
value is 0.4852). The same is true for the coefficient of determination: there is a high
probability that on‐peak hours have no explanatory power in the Frequency Response
variability. Out of the four variables involved in this study (time, summer, high pre‐disturbance
frequency, on‐peak/off‐peak hours), it is the only factor with no statistically significant impact
on Frequency Response.
Linear Model that relates Frequency Response to Interconnection Load
Assumptions: Frequency Response and interconnection load are related by the following
regression equation:
ε
Where:
is the value of interconnection load (in MW) for a Frequency Response event.
is the Frequency Response value measured in MW/0.1 Hz (response variable of
the model);
Frequency Response Initiative Report – October 2012
G‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000221
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
is a slope of the regression line;
is an intercept of the regression line; and
ε is a random error which has a zero mean and variance of
.
A SAS program for the linear regression analysis yields the following results shown in figure G3.:
(a) The equation of the regression line derived by the least squares method is
0.00349
1174.09949;
(b) Estimate for the variance σ2 of the random error ε is 327,416 and for the standard
deviation of ε is 572.2; and
(c) Statistical test for significance of the regression (based on the analysis of variance
approach) is an important part of assessing the adequacy of the linear regression
model for interconnection load and FR variables. The procedure tests a null‐
hypothesis that the slope
0 versus an alternative hypothesis that it is not 0.
Sample value of F‐statistic, 23.83, has P‐value of 0.0001 implying that the null
hypothesis should be rejected (and the alternative hypothesis accepted) at any
significance level above 0.0001. Therefore, the data are statistically significant to
support a hypothesis about linear relationship between interconnection load and
Frequency Response. Alternatively, the hypothesis about the correlation coefficient
between interconnection load and Frequency Response can tested (with the null
hypothesis ρ=0). These tests are equivalent and result in the same P‐values for their
test statistics.
The coefficient of determination R2 for the linear regression model equals to 0.1325. This value
indicates high degree of dependence of Frequency Response on interconnection load.
Essentially, the linear regression model connecting FR and interconnection load accounts for
about 13.3% of variability in the Frequency Response data.
Multiple Linear Regression
A statistically significant linear regression model connects interconnection load and high pre‐
disturbance frequency (regressors) and Frequency Response (response variable). The estimates
of the linear regression coefficients are listed in the Table 2 (P‐value of the model is below
0.0001). An error term, ε, has a zero mean and the standard deviation of 551 MW/0.1 Hz. This
multiple regression model accounts for 19.96% of the variability in Frequency Response data.
Table 2: Parameter Estimates of Multiple Regression
Variable
Parameter
DF
Intercept
1
Estimate
1325.96255
A>60
1
-317.95091
Interconnection Load
1
0.00347
G‐11
Standard
Error
243.49079
t Value
Pr > |t|
5.45
<.0001
88.191
-3.61
0.0004
0.00068929
5.03
<.0001
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000222
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Note that even though time and summer both have a statistically significant positive correlation
with Frequency Response, adding one or both of them to the set of explanatory variables does
not improve the linear model. This can be explained by a high correlation between
interconnection load and summer (0.55) and time (0.20), respectively: addition of these
variables does not increase the explanatory power of the model enough to offset an increase of
its cumulative error.
Frequency Response Initiative Report – October 2012
G‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000223
Appendix H – Frequency Response Field Trial Analysis Graphs
Appendix H – Frequency Response Field Trial
Analysis Graphs
NOTE: These are the background graphics of the Frequency Response Field Trial Analysis of BA
performance measurements.
Frequency Response Events as Normalized by FRO
Eastern Interconnection ‐ 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
‐25.0
25
26
27
28
29
30
31
32
26
27
28
29
30
31
32
24
25
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐50.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Eastern Interconnection ‐ 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
‐5.0
24
23
22
21
20
19
18
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
‐10.0
Balancing Authority
H‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000224
Appendix H – Frequency Response Field Trial Analysis Graphs
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
‐5.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐10.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
‐5.0
‐10.0
‐15.0
‐20.0
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐25.0
Balancing Authority
Frequency Response Initiative Report – October 2012
H‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000225
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 1
2.93266
2.44868
2.57361
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 2
2.78374
2.95180
3.01883
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000226
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 3
1.38620
1.86272
1.65009
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 3
1.38620
1.86272
1.65009
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000227
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 4
2.69908
3.92009
3.43317
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 4
2.69908
3.92009
3.43317
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000228
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 5
3.41783
3.59448
3.36306
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 6
2.77009
3.15820
3.09135
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000229
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 7
0.35407
1.74493
1.03098
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 7
0.35407
1.74493
1.03098
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000230
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 8
0.45946
1.01731
0.76053
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 9
0.82449
1.12570
0.95545
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000231
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 10
1.33795
1.12685
1.18659
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 11
1.36260
1.79121
1.50127
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000232
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 12
3.20919
3.28179
2.93860
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 13
1.33862
0.93276
1.22791
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000233
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 13
1.33862
0.93276
1.22791
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 14
1.88020
1.80109
1.83616
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000234
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 15
3.15755
2.99668
2.93316
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 16
1.82722
1.16967
1.45768
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000235
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 17
2.40390
3.03502
2.91760
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 18
5.74785
6.08231
6.12109
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
H‐13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000236
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 18
5.74785
6.08231
6.12109
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 19
2.80118
3.68324
3.72332
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000237
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 19
2.80118
3.68324
3.72332
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 20
2.09702
2.23845
2.15337
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐15
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000238
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 21
2.88295
2.22455
2.22060
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 22
1.46450
1.24819
1.21142
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐16
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000239
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 23
1.54300
1.52179
1.56508
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 24
0.67435
0.60288
0.52881
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐17
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000240
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 25
2.52953
3.13603
3.07715
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 25
2.52953
3.13603
3.07715
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐18
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000241
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 26
1.33209
1.64291
1.19690
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 26
1.33209
1.64291
1.19690
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐19
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000242
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 27
1.42688
0.90646
1.28118
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 27
1.42688
0.90646
1.28118
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐20
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000243
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 28
0.85546
1.08848
1.38770
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 29
4.26456
3.95973
4.14329
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐21
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000244
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 30
3.73638
3.56590
3.54281
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 30
3.73638
3.56590
3.54281
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐22
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000245
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 31
1.43993
1.64111
1.59776
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 1
1.56036
1.62650
1.57725
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐23
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000246
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 2
1.61236
1.52293
1.52808
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 3
2.38680
2.96222
2.61561
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐24
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000247
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 3
2.38680
2.96222
2.61561
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 4
1.09060
1.12603
1.41997
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
H‐25
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000248
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 4
1.09060
1.12603
1.41997
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 5
1.43519
1.59333
1.36018
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000249
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 6
0.59518
0.54980
0.55267
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 7
1.46146
1.74495
1.93716
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐27
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000250
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 8
1.43519
1.59333
1.36018
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 9
0.72788
0.84191
0.91201
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐28
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000251
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 10
0.79200
0.92316
0.91603
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 11
1.02018
1.10745
1.21932
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐29
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000252
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 12
2.36648
2.65442
2.61365
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 13
4.71769
5.17291
5.14399
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐30
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000253
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 13
4.71769
5.17291
5.14399
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 14
0.60768
0.87898
0.63485
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐31
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000254
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 15
‐1.38396
‐1.54605
‐1.39906
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 16
3.09936
3.30917
3.24174
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐32
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000255
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 16
3.09936
3.30917
3.24174
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 17
3.02606
2.99888
2.80485
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐33
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000256
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 18
1.45116
1.47302
1.50091
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 19
2.45172
2.48546
2.73588
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000257
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 19
2.45172
2.48546
2.73588
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐35
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000258
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000259
Appendix I – Derivation of the Median, Mean, and Linear Regression
Appendix I – Derivation of the Median, Mean, and
Linear Regression
Median
The median best represents a uniform one‐dimensional dataset.
Uniform Distribution
In probability theory and statistics, the continuous uniform distribution or rectangular
distribution is a family of probability distributions such that for each member of the family, all
intervals of the same length on the distribution's support are equally probable. The support is
defined by the two parameters, a and b, which are its minimum and maximum values.
Median
We have been taught in statistics that minimizing the sum of the differences error term
provides the best estimate for the value for a uniform data set. Define a data set as one
dimensional with values {x1, x2,…, xn}. The objective is to select a single value that best
represents this data set by minimizing the sum of the residuals.
SDE x x
n
i
m
i 1
Where:
xm
=
Best single value to represent the data set.
The result is undefined using calculus. Therefore, other logic must be used.
Organize the data from smallest to largest. Then investigate the change in total difference as
the candidate median value is raised from the smallest to the largest value in the data set.
When the candidate median value is raised above the smallest data value the difference
between the candidate median value and the smallest value increases, but the difference
between the candidate median value and all other data values decreases by an amount equal
to the increase in the difference for the smallest value times the number of data values above
the candidate median value. As the candidate median value increases, the total difference
from all values will decrease until exactly one half of the data values are above the candidate
median value and exactly one half of the data values are below the candidate median value. If
there are an even number of data values in the set, any change in the candidate median value
between the data value immediately below the half and the data point immediately above the
half will not change the total difference because the difference change in the increasing
direction and the difference change in the decreasing direction offset each other. However, if
there are an odd number of data values in the data set, the candidate median value equal to
the center data value will result in a minimum of the differences.
I‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000260
Appendix I – Derivation of the Median, Mean, and Linear Regression
This demonstrates that the medianis the best estimate for a set of uniform data because it
minimizes the sum of the error terms for the data set.
The real question is not whether the median is an appropriate estimator, but whether the
median is an appropriate estimator for the data being analyzed.
Mean
The mean best represents a normal one dimensional dataset.
Normal (Gaussian) Distribution
In probability theory, the normal (or Gaussian) distribution is a continuous probability
distribution that has a bell‐shaped probability density function, known as the Gaussian function
or informally the bell curve, where parameter μ is the mean or expectation (location of the
peak) and σ 2 is the variance, the mean of the squared deviation, (a "measure" of the width of
the distribution). σ is the standard deviation. The distribution with μ = 0 and σ 2 = 1 is called
the standard normal. A normal distribution is often used as a first approximation to describe
real‐valued random variables that cluster around a single mean value.
The normal distribution is considered the most prominent probability distribution in statistics.
There are several reasons for this:
First, the normal distribution is very tractable analytically, that is, a large number of
results involving this distribution can be derived in explicit form.
Second, the normal distribution arises as the outcome of the central limit theorem,
which states that under mild conditions the sum of a large number of random variables
is distributed approximately normally.
Third, the bell shape of the normal distribution makes it a convenient choice for
modeling a large variety of random variables encountered in practice.
For this reason, the normal distribution is commonly encountered in practice, and is used
throughout statistics, natural sciences, and social sciences as a simple model for complex
phenomena. For example, the observational error in an experiment is usually assumed to
follow a normal distribution, and the propagation of uncertainty is computed using this
assumption. Note that a normally‐distributed variable has a symmetric distribution about its
mean. Quantities that grow exponentially, such as prices, incomes or populations, are often
skewed to the right, and hence may be better described by other distributions, such as the log‐
normal distribution or Pareto distribution. In addition, the probability of seeing a normally‐
distributed value that is far (i.e., more than a few standard deviations) from the mean drops off
extremely rapidly. As a result, statistical inference using a normal distribution is not robust to
the presence of outliers (data that is unexpectedly far from the mean, due to exceptional
circumstances, observational error, etc.). When outliers are expected, data may be better
described using a heavy‐tailed distribution such as the Student's t‐distribution.
Frequency Response Initiative Report – October 2012
I‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000261
Appendix I – Derivation of the Median, Mean, and Linear Regression
Mean
We have been taught in statistics that minimizing the sum of the squares of the error term
provides the best estimate for the value for a normal data set. Let’s define a data set as one
dimensional with values {x1, x2,…, xn}. The objective is to select a single value that best
represents this data set by minimizing the sum of the squares of the residuals.
SSE x x
n
i
2
m
i 1
xm
Where:
Best single value to represent the data set.
=
SSE x 2 x x x
n
2
i
i
m
2
m
i 1
n
n
n
SSE x 2 x x x
2
i
i
i 1
i 1
n
n
m
i 1
SSE x 2 x x nx
2
i
i
i 1
2
m
m
2
m
i 1
Take the derivative of SSE with respect to xm, and set that derivative equal to zero.
SSE
x 2 x x nx
x
x
n
n
2
2
i
m
i 1
m
i
m
m
i 1
2 x x nx
SSE
x
x
x
x
x
n
n
2
i
m
i
i 1
m
i 1
m
m
2
m
m
SSE 2 x 2nx 0
x
n
i
n
1
n
x
m
i 1
m
i
x x
m
i 1
This demonstrates that the mean is the best estimate for a set of normal data because it
minimizes the sum of the squares of the error terms for the data set.
I‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000262
Appendix I – Derivation of the Median, Mean, and Linear Regression
Linear Regression
A linear regression best represents a normal two dimensional dataset.
As with the one dimensional data set, the objective is to minimize the sum of the squares of the
error terms. However, there may be differences that depend upon how we define the error
terms.
There are three alternatives available for defining the error term. It can be defined with
respect to the dependent variable alone as shown in the vertical offsets plot above. The second
is to define the error in terms of the horizontal offsets (not shown). That alternative is the
same as the first alternative when the independent variable is exchanged with the dependent
variable. The third alternative is to define the error as the perpendicular distance from the best
fit line. This is shown in the perpendicular offsets plot above. When the regression is solved
using the perpendicular offsets, both variables are considered equal with respect to
contribution to error, and the ranking of variables is not necessary.
Solution assuming an independent/dependent variable relationship
In the first example the error term is defined as one dimensional on the dependent variable
axis. This is based on the vertical offsets shown above. The result is derived as follows:
SSE y yˆ
n
i
i
i 1
2
ŷi
Where:
Best y value to represent the data set at a given x value.
=
Substitute a linear equation, ŷi = axi+b, for the estimated y value.
SSE y ax b
n
2
i
i 1
i
Since we now have two variables, a and b, the derivative must be taken with respect to each
variable. Setting each derivative equal to zero will provide two equations that can be solved for
the two unknowns, a and b.
Frequency Response Initiative Report – October 2012
I‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000263
Appendix I – Derivation of the Median, Mean, and Linear Regression
SSE y ax b 2 y ax b 0
b
b
n
n
2
i
i
i
i 1
i
i 1
SSE y ax b 2 x y ax bx 0
a
a
n
n
2
i
2
i
i
i 1
i
i
i
i 1
Rearrange terms and solve the two equations. Solve for b first.
n
n
y a x nb 0
i
i
i 1
b
i 1
n
1
n
n
y a x
1
n
i
i 1
i 1
Substitute the result for b into the second equation and solve for a.
i
b y ax
n
n
n
n
x y a x y ax x 0
2
i
i
i 1
i
i
i 1
i 1
a
x y
i
nyx
i
i 1
n
x
2
i
nx
2
i 1
Calculate the value of a and substitute into the first equation to get the value of b. These are
the most common equations used for linear regression. However, they assume that the
dependent and independent variables can be identified and that the error in the dependent
variable is more important than the error in the independent variable.
Solution without the independent/dependent variable relationship
assumption
In this section, the problem is solved using the perpendicular offsets to determine the error
terms. This provides a solution that is not dependent upon any assumption concerning the
relationship between the variables.
The first step in this solution is to determine the square of the perpendicular offset from the
regression line that represents the error term.
y ax b
SSE
1 a
2
n
i
i
2
i 1
Since we again have two variables, a and b, the derivative must be taken with respect to each
variable. Setting each derivative equal to zero will provide two equations that can be solved for
the two unknowns, a and b.
y ax b
SSE
b
b
1 a
2
n
i
i 1
I‐5
i
2
2
1 a
y ax b 0
n
2
i
i 1
i
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000264
Appendix I – Derivation of the Median, Mean, and Linear Regression
y ax b
SSE
1 a
a
a
2
n
i
i
2
i 1
2
SSE
a
1 a
y
n
2
ax b x
n
i
i 1
i
y
ax b 2a
0
1 a
2
i
i
i
2
i 1
2
Rearrange terms and solve the two equations. Solve for b first.
y a x nb 0
n
n
i
i
i 1
b
i 1
n
1
n
y
i
a
i 1
n
1
n
x
i
b y ax
i 1
This is the same result as before. Substitute the result for b into the second equation and solve
for a. The detailed intermediate equations for this solution can be found at
http://mathworld.wolfram.com/LeastSquaresFittingPerpendicularOffsets.html. After much
manipulation the following equations result:
y ny x nx
1
A
2
nyx x y
n
n
2
2
2
i
i
i 1
i 1
n
i
i
2
a A A 1
2
i 1
This solution is somewhat more complex than the vertical offset solution. That is the reason
that the vertical offset solution is commonly used. In most cases, the vertical offset solution
provides an adequate answer to the problem without the added complexity of the
perpendicular offset solution. However, when the vertical offset solution is used, it makes a
difference which variable is considered the independent variable and the dependent variable.
This can significantly affect the results when the slope is large.
Additional information requires a special case linear regression
The calculation of Frequency Response requires the use of a special case linear regression.
Frequency Response is defined as to be equal to zero when the frequency error is equal to zero.
This information requires the modification of the linear regression used to provide the best
representation of the data. The appropriate linear regression for representing Frequency
Response is a regression where the regression line crosses the origin of the axis representing
the two variables, frequency and Frequency Response (MW). Therefore, the previously
developed general solution to the problem requires modification. This is done by setting the
variable that represents the y‐intercept to zero. In the above examples, the b term must be set
to zero.
Frequency Response Initiative Report – October 2012
I‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000265
Appendix I – Derivation of the Median, Mean, and Linear Regression
Special case solution assuming an independent/dependent variable
relationship
In the first example the error term is defined as one dimensional on the dependent variable
axis. This is based on the vertical offsets but in this case the variable representing the intercept
is eliminated. The result is derived as follows:
SSE y yˆ
n
i
i
2
i 1
ŷi
Where:
Best y value to represent the data set at a given x value.
=
Substitute a linear equation, ŷi = axi, for the estimated y value.
SSE y ax
n
i
i
2
i 1
Since we now have a single variables, a, the derivative must be taken with respect to that
variable. Setting the derivative equal to zero will provide an equation that can be solved for the
unknown, a.
SSE y ax
a
a
n
i
i 1
i
2 x y ax 0
n
2
2
i
i
i
i 1
Rearrange terms and solve the equation.
n
n
n
x y a x 0
2
i
i 1
i
i
i 1
a
x y
i
i
i 1
n
x
2
i
i 1
This equation is somewhat simpler than the equation using a non‐zero intercept. In the specific
case that we are considering, the estimate of Frequency Response, the slope of the regression
line is not expected to be large, near vertical. Therefore, the assumption of dependent and
independent variables is not important to the solution. In this case, the additional complexity
added by considering the horizontal offsets is not significant to the solution and has been
eliminated from consideration.
I‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000266
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000267
Appendix J– Generator Governor Survey Instructions
Appendix J – Generator Governor Survey
Instructions
NOTE: These were the instructions for the Generators Governor Survey conducted in
September 2010.
Frequency Response Initiative
Generator Governor Survey
For the purposes of this survey, governors are defined as any device that implements Primary
Frequency Response (speed regulation) for generators.
The survey will be sent to Generator Owners and Generator Operators.
The survey includes all generators rated 20 MVA or higher, or plants that aggregate to a
total of 75 MVA or greater net rating at the point of interconnection (i.e., wind farms,
PV farms, etc.), accordance with the Statement of Compliance Registry Criteria, Rev. 5.0.
Jointly‐owned units should be reported by the operating entity.
For combined‐cycle plants, the combustion turbines and heat‐recovery (steam turbine)
units should be reported separately.
Wind farms should report on a point‐of‐interconnection basis.
If the unit is operable in more than one interconnection, complete the survey for
operation in each of the interconnections.
NOTE: The 256‐character limitation noted on the spreadsheet is a Microsoft Excel limitation on
characters in a cell. If additional space is needed, please supply supplemental documentation
as necessary.
When responding, please upload your response and any supporting documentation through the
NERC Secure Alerts System
General Questions
1.
Does your organization have a formal policy on the installation and operation of
generator governors?
Does your organization have a testing procedure for governors? If so, how often are
they tested?
2.
Unit‐Specific Questions
The following questions will all apply to each generator:
1.
J‐1
Unit name and number.
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000268
Appendix J– Generator Governor Survey Instructions
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
Balancing Authority (BA) in which the generator is operated (pull‐down).
a. If operable in more than one, please note all applicable BAs.
b. If operable in more than one interconnection, complete the survey for operation
in each of the interconnections.
Unit seasonal Net MW ratings normally reported to NERC for resource adequacy
analyses:
a. Summer Net MW rating
b. Winter Net MW rating
Prime mover (steam turbine, combustion turbine, wind turbine, etc. — pull‐down)
Fuel type (coal, oil, nuclear, etc. — pull‐down)
Unit inertia constant (H) as modeled in dynamics analyses – the combined kinetic
energy of the generator and prime‐mover in watt‐seconds at rated speed divided by
the VA (Volt‐Ampere) base.
What are the annual run hours for the unit (data for each of the last 3 years)?
What is the continuous MW rating (Pmax) of the unit?
What percent of time does the unit run at Pmax or valves wide‐open?
a. 0 to 30%
b. 31% to 60%
c. 61% to 100%
Equipped with a Governor? (Y/N) If not, no further answers are necessary.
If yes, is the governor operational? (Y/N with a comment box) If not, please explain.
a. Is the governor normally in operation? (Y/N with a comment box) (even if not
normally operated, the data on the governor is still needed)
b. What is the normal governor mode of operation? (pull‐down)
c. Is the governor response sustainable for more than one minute if conditions
remain outside of the deadband? (Y/N)
d. Are there any regulatory restrictions regarding the operation of the governor?
This should cover nuclear regulation, environmental restrictions (water
temperature, emissions), water flow, etc.
e. Does the governor respond beyond the high/low operating limit (boiler blocks)?
(Y/N)
f. Is the governor response limited by the rate of change? (Y/N)
g. Are there any other unit‐level or plant‐level control schemes that would override
or limit governor performance? If yes, please explain.
Governor Type?
Electronic (analog electro‐hydraulic);
DEH (digital electro hydraulic);
Mechanical;
Other — please specify.
Governor manufacturer and model?
a. If mixed vendor equipment is installed, please explain.
Governor Deadband setting?
a. Deadband in(+/‐) mHz
Frequency Response Initiative Report – October 2012
K‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000269
Appendix J– Generator Governor Survey Instructions
15.
16.
i. If in mHz is the deadband centered around a frequency reference (60 Hz
or current frequency)?
b. Deadband in (+/‐) RPM
i. For RPM specify number of machine poles
ii. If in RPM, is the RPM reference nominal or current RPM?
c. What is the basis for this setting?
d. Once activated, what are the conditions for which the governor action is reset?
What is the percentage (%) droop setting on the governor?
a. What is the basis for the droop setting?
Does the unit Frequency Response step into the droop curve or is it linear from the
deadband?
Capability (MW) 600.000
Frequency Response
Deadband Setting
0.036
Hz
150.00
100.00
MW Change
50.00
0.00
Step response at
dead-band.
-50.00
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
Droop Setting 5.00%
Step Implementation (step): When frequency crosses the governor dead‐band
setting the output of the governor “steps” into the 5% droop curve as if the dead‐
band did not exist.
J‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000270
Appendix J– Generator Governor Survey Instructions
Capability (MW) 600.000
Frequency Response
Deadband Setting
0.0166
Hz
150.00
100.00
MW Change
50.00
0.00
-50.00
No Step response at
dead-band.
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
Droop Setting 5.00%
Without Step Implementation (linear): When frequency crosses the governor dead‐
band setting the output of the governor adds proportional output toward the droop
curve end point.
17.
18.
Prime mover control mode – What is the normally used Turbine Control mode(s)? If
more than one is prevalently used, select a primary and explain.
Turbine manual
Thermally‐limited
Turbine following
Boiler following
Part‐load
Pre‐select
MW set point
Coordinated control
Other (please explain) If more than one is prevalently used, select a primary and
explain.
Do market rules restrict or override governor speed controls? (Y/N) If yes, please
explain.
For steam generator controls (boiler controls) or combined cycle central
station controls:
19.
Does the boiler control or combined cycle central station control have a frequency
input? (Y/N) If yes, answer the following questions:
a. Deadband in(+/‐) mHz
i. If in mHz is the deadband centered around a frequency reference (60 Hz
or current frequency)?
Frequency Response Initiative Report – October 2012
K‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000271
Appendix J– Generator Governor Survey Instructions
20.
21.
22.
23.
24.
b. Deadband in (+/‐) RPM
i. For RPM specify number of machine Poles
ii. If in RPM, is the RPM reference nominal or current RPM?
c. What is the basis for this setting?
Does the control’s Frequency Response step into the droop curve or is it linear from
the deadband?
What is the steam turbine control mode? (boiler following, turbine following,
coordinated control)
Do the unit or plant controls over‐ride governor speed control or are the control
parameters supportive? (Y/N)
Does the boiler operate under variable/sliding pressure? (Y/N)
a. What is the control/governor valve position percentage (%) during variable
pressure operation?
Do unit or plant economic controls over‐ride governor speed control? (Y/N)
Event Performance Data
The following five questions are to be answered for each generator to ascertain its performance
during the specified frequency events (one per interconnection). The frequency events data to
be reported are:
Interconnection
Date
Time
Time Zone
Eastern
8/16/2010
14:25:29
CST
Western
8/12/2010
1:06:15
CST
Texas
8/20/2010
14:44:03
CST
Québec
12/10/2009
15:09:31
EST
25.
Was the unit on‐line during the event? (Y/N)
26.
Pre‐event generation (MW) – Enter the MW output of the generator at the time just
before the event began.
27.
Post‐event generation (MW) – Enter the MW output of the generator after the
event that was reflects the response by the governor to the frequency deviation.
28.
Time to achieve post‐event response (seconds) – Enter the time (in seconds) it took
to achieve the MW response noted in question 27.
29.
Comments (256 characters) – Enter any comments necessary. If no data is available
for the event, note that here.
J‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000272
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000273
Appendix K– Generator Governor Survey Summary
Appendix K – Generator Governor Survey
Summary
The following are slides that summarize the responses of the 2010 Generator Governor Survey.
Deadband Settings
NERC 2010 GO/GOP Survey
Quality of Dead Band Data
100%
90%
21%
80%
23%
35%
37%
Unusable
49%
47%
Usable
70%
60%
50%
40%
79%
77%
65%
63%
30%
53%
51%
20%
10%
0%
East
West
Texas
No. of Units
East
West
Capacity
Texas
3
K‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000274
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Eastern Interconnection Dead Bands and Size of Units
60
55
<500 MW
500-1000 MW
>1000 MW
Summer Capacity (GW)
50
45
40
35
30
25
20
15
10
5
No Response
4
No Response
Deadband (mHz)
No Governor
5000+
500-3250
54-450
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
5
NERC 2010 GO/GOP Survey
Texas Interconnection Dead Bands and Size of Units
60
55
<500 MW
Summer Capacity (GW)
50
500-1000 MW
>1000 MW
45
40
35
30
25
20
15
10
5
5000+
500-3250
54-450
No Governor
Deadband (mHz)
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
Frequency Response Initiative Report – October 2012
K‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000275
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Western Interconnection Dead Bands and Size of Units
60
<500 MW
55
500-1000 MW
Summer Capacity (GW)
50
>1000 MW
45
40
35
30
25
20
15
10
5
No Response
Deadband (mHz)
No Governor
5000+
500-3250
54-450
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
6
NERC 2010 GO/GOP Survey
Interconnection Dead Bands Range and Size of Units
400
700
700
<500 MW
500-1000
MW
2000
540
Deadband Setting (mHz)
350
300
250
200
150
100
50
0
East
>1000 MW
<500 MW
500-1000
MW
West
>1000 MW
<500 MW
500-1000
MW
Texas
>1000 MW
7
Unit Size
K‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000276
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Interconnection Dead Bands References
N/A, 287, 14%
Texas
N/A, 96, 10%
Eastern
Other, 28, 3%
Other, 41, 2%
60 Hz, 993,
46%
Current
Frequency,
244, 25%
60 Hz, 591,
62%
Current
Frequency,
796, 38%
Current
Frequency, 81,
24%
Other, 6, 2%N/A, 7, 2%
Western
8
60 Hz, 250,
72%
Droop Settings
NERC 2010 GO/GOP Survey
Quality of Droop data
Usable
100%
Unusable
5%
6%
11%
13%
13%
87%
87%
Texas
East
15%
90%
80%
70%
60%
50%
95%
94%
89%
85%
40%
30%
20%
10%
0%
East
West
No. of units
West
Texas
10
Capacity
Frequency Response Initiative Report – October 2012
K‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000277
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Droop Settings by Number of Units
1400
East
1200
West
Texas
# of Units
1000
800
600
400
Nuclear governor
blocked
No Response
5.1‐10
5
4.01‐4.97
4
1‐3.98
.0509‐.5
0.05
.0404‐.0495
0.04
.0326‐.0396
.00128‐.03
0
0
Droop Settings (%)
Researching
200
11
NERC 2010 GO/GOP Survey
Droop Settings by Capacity
250
East
West
Texas
225
Summer Capacity (MW)
200
175
150
125
100
75
50
Researching
5.1‐10
5
No Response
Droop Settings (%)
4.01‐4.97
4
1‐3.98
.0509‐.5
0.05
.0404‐.0495
0.04
.0326‐.0396
.00128‐.03
0
0
Nuclear governor
blocked
25
12
K‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000278
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Droop Settings by Capacity Class
10
9
Droop Setting (%)
8
7
6
5
4
3
2
1
0
<500 MW
500-1000
MW
>1000 MW
<500 MW
500-1000
MW
East
>1000 MW
West
<500 MW
500-1000
MW
>1000 MW
Texas
13
Unit Size
Results of Other Survey Questions
NERC 2010 GO/GOP Survey
Survey Question: Equipped with Governor?
20, 1%
162, 4%
0, 0%
0, 0%
114, 7%
171, 4%
8, 2%
0, 0%
50, 11%
1429, 92%
4208, 92%
Western
Eastern
399, 87%
Texas
Yes
No
N/A
Unknown
15
Frequency Response Initiative Report – October 2012
K‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000279
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Is Governor Operational?
21, 1%
128, 3%
0, 0%
26, 1%
30, 2%
39, 1%
1, 0%
0, 0%
4, 1%
1378, 97%
4015, 95%
Western
Eastern
394, 99%
Texas
Yes
No
N/A
Unknown
16
NERC 2010 GO/GOP Survey
Survey Question: Is Governor Response sustainable for more
than 1 minute if conditions remain outside of deadband?
117, 8%
0, 0%
480, 11%
99, 7%
9, 0%
360, 9%
37, 9%
2, 1%
27, 7%
1213, 85%
3359, 80%
Western
Eastern
333, 83%
Texas
Yes
No
N/A
Unknown
17
K‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000280
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Does governor respond beyond the high/low
operating limit (boiler blocks)?
179, 13%
598, 14%
306, 21%
0, 0%
63, 1%
1533, 36%
58, 15%
97, 24%
17, 4%
2014, 49%
944, 66%
Western
Eastern
227, 57%
Texas
Yes
No
N/A
Unknown
18
NERC 2010 GO/GOP Survey
Survey Question: Is the governor response limited by the rate
of change? (Filter: Governor Yes)
72, 5%
0, 0%
470, 11%
949, 23%
2, 0%
554, 39%
34, 9%
803, 56%
2, 1%
121, 30%
2787, 66%
Western
Eastern
242, 60%
Texas
Yes
No
N/A
Unknown
19
Frequency Response Initiative Report – October 2012
K‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000281
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Are there any other unit-level or plant-level control
schemes that override or limit governor performance? (Filter: Governor
Yes)
65, 5%
337, 8%
0, 0%
27, 1%
700, 49%
2026, 48%
664, 46%
32, 8%
1818, 43%
2, 1%
Eastern
197, 49%
Western
168, 42%
Texas
Yes
No
N/A
Unknown
20
NERC 2010 GO/GOP Survey
Survey Question: Do market rules restrict or override governor
speed controls? (Filter: Governor Yes)
206, 5%
13, 0%
28, 2%
7, 0%
0, 0%
23, 1%
4, 1%
2, 1% 1, 0%
3966, 94%
1394, 98%
Western
Eastern
392, 98%
Texas
Yes
No
N/A
Unknown
21
K‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000282
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Does the boiler control or combined cycle
central control have a frequency input?
46, 3%
298, 7%
414, 29%
2039, 48%
1549, 37%
892, 63%
79, 20%
77, 5%
124, 31%
322, 8%
Eastern
Western
50, 13%
146, 36%
Texas
Yes
No
N/A
Unknown
22
NERC 2010 GO/GOP Survey
Survey Question: Does the boiler operate under variable
pressure?
151, 11%
169, 12%
394, 9%
1030, 24%
127, 9%
2431, 59%
72, 18%
982, 68%
353, 8%
194, 49%
Eastern
68, 17%
Texas
Yes
No
N/A
Western
65, 16%
Unknown
23
Frequency Response Initiative Report – October 2012
K‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000283
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Do unit or plant economic controls override
governor speed control?
16, 1%
48, 1%
380, 27%
1700, 40%
2173, 52%
0, 0%
114, 8%
919, 64%
287, 7%
172, 43%
Eastern
185, 46%
Western
42, 11%
Texas
Yes
No
N/A
Unknown
24
Survey Event Data
NERC 2010 GO/GOP Survey
Unit Status by Number
West
East
Unknown,
185, 12%
Unknown,
566, 12%
Offline
Generation,
566, 36%
Offline
Generation,
2197, 49%
Online
Generation,
1778, 39%
Texas
Unknown, 57,
12%
Online
Generation,
300, 66%
Online
Generation,
Offline 808, 52%
Generation,
100, 22%
26
K‐11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000284
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Unit Status by Capacity (GW)
West
East
Unknown,
17.7, 11%
Unknown,
48.1, 7%
Offline
Generation,
51.2, 31%
Offline
Generation,
186.0, 29%
Texas
Offline
Generation,
9.6, 12%
Unknown,
10.6, 13%
Online
Generation,
415.4, 64%
Online
Generation,
97.5, 58%
27
Online
Generation,
59.8, 75%
NERC 2010 GO/GOP Survey
Response of Online Units by Number
West
East
Online, No
Data on
Response,
291, 16%
Online, No
Data on
Response, 46,
6%
Expected
Response,
471, 26%
Expected
Response,
355, 44%
No Response,
302, 37%
Online, No
Opposite of
Data on
Expected Response, 43,
Response,
14%
272, 15%
No Response,
744, 43%
Texas
Expected
Response,
137, 46%
No Response,
61, 20%
Opposite of
Expected
Response, 59,
20%
Opposite of
Expected
Response,
105, 13%
28
Frequency Response Initiative Report – October 2012
K‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000285
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Response of Online Units by Capacity (GW)
East
West
Online, No
Data on
Response,
53.2, 13%
Expected
Response,
124.7, 30%
Online, No
Data on
Response,
3.4, 4%
Expected
Response,
42.7, 44%
No Response,
34.6, 35%
Texas
No Response,
159.9, 38%
Online, No
Data on
Response,
8.6, 14%
Opposite of
Expected
Response,
77.6, 19%
Opposite of
Expected
Response,
16.9, 17%
No Response,
7.8, 13%
Expected
Response,
31.6, 53%
Opposite of
Expected
Response,
11.8, 20%
29
NERC 2010 GO/GOP Survey
Response of All Units by Number
West
East
Online, No
Data on
Response,
291, 6%
No Response,
744, 17%
No Response,
302, 19%
Offline
Generation,
2197, 49%
Opposite of
Expected
Response,
272, 6%
Expected
Response,
471, 10%
Texas
Online, No
Data on
Response, 43,
9%
Offline
Generation,
100, 22%
No Response,
61, 13%
Unknown,
566, 12%
Opposite of
Expected
Response,
105, 7%
Expected
Response,
355, 23%
Online, No
Data on
Response, 46,
3%
Offline
Generation,
566, 36%
Unknown,
185, 12%
Unknown, 57
12%
Opposite of
Expected
Response, 59,
13%
Expected
Response,
137, 31%
30
K‐13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000286
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Response of All Units by Capacity (GW)
Online, No
Data on
Response,
53.2, 8%
West
East
Offline
Generation,
186.0, 29%
No Response,
34.6, 21%
Offline
Generation,
51.2, 30%
No Response,
159.9, 25%
Texas
Unknown,
48.1, 7%
Opposite of
Expected
Response,
77.6, 12%
Online, No
Data on
Response,
3.4, 2%
Expected
Response,
124.7, 19%
Online, No
Response
Data, 8.6 GW
Offline
Generation,
9.6, 12%
No Response,
7.8, 10%
Opposite of
Expected
Response,
16.9, 10%
Unknown,
10.6, 13%
Unknown,
17.7, 11%
Expected
Response,
42.7, 26%
Opposite of
Expected
Response,
11.8, 15%
Expected
Response,
31.6, 39%
31
Frequency Response Initiative Report – October 2012
K‐14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000287
Appendix L – References
Appendix L – References
Training Document ‐ Policy 1 Generation Control and Performance, February 24, 2003. NERC
Niemeyer, S. Frequency Regulation—Is Your Plant Compliant?
Ibrahim Abdur‐Rahman, Sydney & Ricardo Vera, PE
Eto, J.H. et al. 2010. Use of Frequency Response Metrics to Assess the Planning and Operating
Requirements for Reliable Integration of Variable Renewable Generation. LBNL‐4143E.
Berkeley: Lawrence Berkeley National Laboratory
Analysis of Eastern Interconnection Frequency Response, February 2011. NERC
L‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000288
Exhibit G
Status of Recommendations of the Frequency Response Initiative Report
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000289
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
The following is a list of recommendations presented in the Frequency Response
Initiative Report and an explanation of the current status of those recommendations.
----------------Recommendation 1: NERC should embark immediately on the development of a NERC
Frequency Response Resource Guideline to define the performance characteristics expected of
those resources for supporting reliability.
As a result of this recommendation, NERC is in the process of developing a Frequency
Response Resource Guideline. NERC is assembling a group of subject matter experts in
Frequency Response by conventional generating resources, as well as experts in the field
of other Frequency-responsive resources to prepare the guidelines. Additionally, a third
chapter on cohesive strategies for Balancing Authorities to obtain and provide primary
Frequency Response is being added to the guideline.
Recommendation 2: Instead of using a fixed margin, the calculation of the Interconnection
Frequency Response Obligations (“IFRO”) should use statistical analysis to determine the
necessary margin.
The standard drafting team adopted this method of statistical analysis in proposed
Reliability Standard BAL-003-1.
Recommendation 3: The starting frequency for the calculation of IFROs should be the
frequency 5% of the lower tail of samples from the statistical analysis, representing a 95%
confidence that frequencies will be at or above that value at the start of any frequency event, as
shown in table A.
The standard drafting team adopted this method of starting frequency analysis in
proposed Reliability Standard BAL-003-1.
Recommendation 4: The recommended UFLS first-step limitations for IFRO calculations are
listed in table B.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000290
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
[FN3. The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC,
based on internal stability concerns. The FRCC concluded that the IFRO starting
frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it
imposes no greater risk of UFLS operation in FRCC for an external resource loss event
than for an internal FRCC event.]
The standard drafting team adopted these UFLS first-step limitations in Table B in
proposed Reliability Standard BAL-003-1.
Recommendation 5: The allowable frequency deviation (starting frequency minus the highest
UFLS step) should be reduced to account for differences between the 1-second and sub-second
data for Point C (frequency nadir) by a statistically determined adjustment as listed in table C.
Sub-second measurements will more accurately detect Point C.
The standard drafting team adopted this method of analysis and adjusting allowable
frequency deviation in proposed Reliability Standard BAL-003-1.
Recommendation 6: The allowable change in frequency from the IFRO Starting Frequency
should be adjusted by a statistically determined value to account for the differences between the
Value B and the Point C for historical frequency events as listed in table D.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000291
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
[FN4. CBR value limited to 1.0 because values lower than that indicate the Value B is lower
than Point C and does not need to be adjusted. The calculated value is 0.989.
FN5. Based on Québec UFLS design between their 58.5 Hz UFLS with 300 millisecond
operating time (responsive to Point C) and 59.0 Hz UFLS step with a 20-second delay
(responsive to Value B or beyond) with a 0.05 Hz confidence interval. See the Adjustment for
Differences between Value B and Point C section of this report for further details.]
The standard drafting team adopted this method of analysis and adjusting IFRO starting
frequency in proposed Reliability Standard BAL-003-1.
Recommendation 7: An adjustment should be made to the maximum allowable delta frequency
to compensate for the predominant withdrawal of primary frequency response exhibited in an
interconnection until such withdrawal is no longer exhibited in that interconnection.
The standard drafting team adopted this method of analysis and adjusting the maximum
allowable delta frequency in proposed Reliability Standard BAL-003-1.
Recommendation 8: The determination of the maximum delta frequencies should be calculated
in accordance with the methods embodied in Table E – Determination of Maximum Delta
Frequencies.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000292
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
[FN6. Adjustment for the differences between 1-second and sub-second Point C observations for
frequency events.
FN7. Adjustment for the differences between Point C and Value B.
FN8. CBR value for the Eastern Interconnection limited to 1.0 because values lower than that
indicate the Value B is lower than Point C and does not need to be adjusted. The calculated value
is 0.989.
FN9. Based on Québec UFLS design between their 58.5 Hz UFLS with 300 ms operating time
(responsive to Point C)and 59.0 Hz UFLS step with a 20- second delay (responsive to Value B or
beyond).
FN10. DFCC/CBR
FN11 Adjustment for the event nadir being below the Value B (Eastern Interconnection only)
due to primary frequency response withdrawal.]
The standard drafting team adopted the recommended method of determining Maximum
Delta Frequencies (embodied in Table E) in proposed Reliability Standard BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000293
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
Recommendation 9: The Interconnection Frequency Response Obligations should be
calculated as shown in Table F: Recommended IFROs.
[FN12. IFRO =
FN13. Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI
= -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and QI = -750 MW/0.1 Hz.]
The standard drafting team adopted the recommended method of calculating Maximum
Interconnection Frequency Response Obligations (shown in Table F) in proposed
Reliability Standard BAL-003-1.
Recommendation 10: NERC and the Western Interconnection should analyze the FRO
allocation implications of the Pacific Northwest RAS generation tripping of 3,200 MW.
NERC staff has begun discussions and work with the WECC Performance Subcommittee
to analyze the implications of the Pacific Northwest RAS generation tripping. The
maximum value of the RAS action has since been determined to be 2,850 MW, only
slightly above the value for loss of two Palo Verde units recommended in the FRI report.
Verification and adjustments for load tripping credit is being pursued and this analysis
should be completed in the 3rd quarter of 2013.
Recommendation 11: Trends in frequency response sustainability should be measured and
tracked by observing frequency between T+45 seconds and T+180 seconds. A pair of indices for
gauging sustainability should be calculated comparing that value to both the Point C and Value
B.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000294
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
NERC staff has begun calculating and tracking frequency response sustainability for the
frequency events starting in 2013, and will be performing retroactive calculations of the
recommended indices for frequency events analyzed for 2011 and 2012.
Recommendation 12: Frequency response performance by Balancing Authorities should not be
judged for compliance on a per-event basis.
The standard drafting team agreed with this recommendation and did not adopt a perevent compliance measure in proposed Reliability Standard BAL-003-1. As set forth in
the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard, NERC will identify 20 to 35 frequency excursion events in each
interconnection for calculating the Frequency Bias Setting and the Frequency Response
Measure. The evaluation period for performing the annual Frequency Bias Setting and
the Frequency Response Measure calculation is December 1 of the prior year through
November 30 of the current year.
Recommendation 13: Linear regression is the method that should be used for calculating
Balancing Authority Frequency Response Measure (FRM) for compliance with Standard BAL003-1 – Frequency Response.
The standard drafting team did not adopt a linear regression method for calculating the
Balancing Authority Frequency Response Measure for compliance with BAL-003-1 –
Frequency Response. However, the standard drafting team did agree that linear
regression should be re-evaluated for use in the standard once more experience is gained
with data collected.
NERC and the Frequency Working Group will include an update of the linear regression
analysis from the FRI report during the annual review process noted under
Recommendation 14.
Recommendation 14: NERC and the Frequency Working Group should annually review the
process for detection of frequency events and the method for calculating the A and B Values and
Point C. The associated interconnection frequency event database, methods for calculating
interconnection metrics on risks to reliability, the associated probabilities, and the calculation of
the IFROs using updated data should also undergo review in an effort to improve the process.
Throughout this process, NERC should strive to improve the quality and consistency of the data
measurements.
NERC and the Frequency Working Group have set forth a process for identification of
candidate frequency events, and an annual review of the calculations. NERC staff will
work with the Frequency Working Group throughout the year to continuously refine and
improve the review process.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000295
EXHIBIT G - Status of Recommendations of the Frequency Response Initiative Report
Recommendation 15: NERC should address improving the level of understanding of the role of
turbine governors through seminars and webinars, with educational materials available to the
Generator Owners and Generator Operators on an ongoing basis.
NERC is planning to prepare training materials to share with the Generation Owner and
Balancing Authority communities. Annual training sessions for Balancing Authority
reporting and the Frequency Response resource guidelines are planned.
Recommendation 16: When the Eastern Interconnection Reliability Assessment Group
Multiregional Modeling Working Group (ERAG MMWG) completes its review of turbine
governor modeling, a new light-load case should be developed, and the resource loss criterion for
the Eastern Interconnection’s IFRO should be re-simulated.
ERAG MMWG has agreed to prepare an updated “generic governor” 2013 summer light
load case (from the 2012 case series) for evaluating Eastern Interconnection IFROs by
August 1, 2013. That case will use generic governor models to mimic the frequency
response performance characteristics determined in the “Analysis of Eastern
Interconnection Frequency Response” report published in March 2012. ERAG
Management Committee is targeting completion of the governor review and case creation
by August 1, 2014.
Recommendation 17: Eastern Interconnection inter-area oscillatory behavior should be further
investigated by NERC, including the testing of large resource loss analysis for IFRO validation.
Work on such analysis is being proposed to the NERC Planning Committee, System
Analysis and Modeling Working Subcommittee.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000296
Exhibit H
Frequency Response Initiative Supplemental Report – IFRO Simulations
(DRAFT)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000297
DRAFT
Frequency Response
Initiative
Supplemental Report – IFRO Simulations
March 2013
3353 Peachtree Road NE
Suite 600, North Tower
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013 Atlanta, GA 30326
404-446-2560 | www.nerc.com
1 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000298
NERC’s Mission
NERC’s Mission
The North American Electric Reliability Corporation’s (NERC) mission is to ensure the reliability
of the North American bulk power system. NERC is the electric reliability organization (ERO)
certified by the Federal Energy Regulatory Commission (FERC) to establish and enforce
reliability standards for the bulk power system. NERC develops and enforces reliability
standards; assesses adequacy annually via a 10‐year forecast and summer and winter forecasts;
monitors the bulk power system; and educates, trains, and certifies industry personnel. ERO
activities in Canada related to the reliability of the bulk power system are recognized and
overseen by the appropriate governmental authorities in that country.1
NERC assesses and reports on the reliability and adequacy of the North American bulk power
system, which is divided into eight Regional areas, as shown on the map and table below. The
users, owners, and operators of the bulk power system within these areas account for virtually
all the electricity supplied in the United States, Canada, and a portion of Baja California Norte,
Mexico.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load‐serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability
Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst
Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, FERC granted NERC the legal authority to enforce reliability standards with all U.S. users, owners, and operators of the
bulk power system, and made compliance with those standards mandatory and enforceable. In Canada, NERC has memorandums of
understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the
Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial
law. NERC has an agreement with Manitoba Hydro that makes reliability standards mandatory for that entity, and Manitoba has recently
adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the province. In
addition, NERC has been designated the “electric reliability organization” under Alberta’s Transportation Regulation, and certain reliability
standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been recognized as standards‐setting bodies by
the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and
British Columbia also have frameworks in place for reliability standards to become mandatory and enforceable. NERC is working with the
other governmental authorities in Canada to achieve equivalent recognition.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
i
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000299
Table of Contents
Introduction ................................................................................................................................................................................. 1
Findings ........................................................................................................................................................................................ 3
Western Interconnection ......................................................................................................................................................... 3
ERCOT Interconnection ............................................................................................................................................................ 3
Eastern Interconnection .......................................................................................................................................................... 3
Western Interconnection Test ..................................................................................................................................................... 4
Initial Test ............................................................................................................................................................................ 4
IFRO Test .............................................................................................................................................................................. 5
Findings .................................................................................................................................................................................... 6
ERCOT Interconnection Test ........................................................................................................................................................ 7
IFRO Test .............................................................................................................................................................................. 8
Findings .................................................................................................................................................................................... 9
Eastern Interconnection Test ..................................................................................................................................................... 10
Findings .................................................................................................................................................................................. 11
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
ii
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000300
Introduction
Introduction
This report is a supplement to the Frequency Response Initiative report of October 2012 for the
purpose of supporting the filing of Standard BAL‐003‐1 – Frequency Response with the Federal Energy
Regulatory Commission. This analysis was requested by the NERC Board of Trustees (Board) when the
Board accepted the initiative report. This report contains the results of stability simulation testing of
the Interconnection Frequency Response Obligations (IFROs) prescribed for the Eastern, ERCOT, and
Western Interconnections. Stability testing was not performed for the Québec Interconnection.
The following IFROs were tested:
Table A: Recommended IFROs
Eastern
Western
ERCOT
Units
Starting Frequency
59.974
59.976
59.963
Hz
Max. Delta Frequency
0.449
0.291
0.473
Hz
Resource Contingency
Protection Criteria
4,500
2,740
2,750
MW
–
300
1,400
MW
IFRO
‐1,002
‐840
‐286
MW/0.1Hz
Absolute Value of
IFRO
1,002
840
286
MW/0.1Hz
Credit for LR
2
The cases for the interconnections were tested against the following recommended Resource
Contingencies:
Table B: Recommended Resource Contingency Protection Criteria
Resource Contingency
Basis
MW
Eastern
Largest Resource Event in
Last 10 Years
August 4, 2007
Disturbance
4,500
Western
Largest N‐2 Event
2 Palo Verde Units
2,7403
ERCOT
Largest N‐2 Event
2 South Texas Project
Units
2,7504
Interconnection
R
C
2
IFRO =
P
C
3
Net winter ratings per Form EIA‐860 reporting
Net rating from ERCOT Resource Asset Registration Form (RARF)
4
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
1 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000301
Introduction
The contingencies were simulated with associated load reduction actions including 300 MW tripped by
a remedial action scheme (RAS) for the Western Interconnection and dropping of 1,300 MW5 of Load
Resources in ERCOT.
All simulations, due to limitations of the programs, assumed an initial frequency (Value A) of 60.0 Hz.
Simulations for the Western Interconnection were conducted using the General Electric PSLF program,
while simulations for the Eastern and ERCOT Interconnections were performed with the Siemens PSS®E
program.
These IFRO tests were conducted to be informative for the filing of NERC Reliability Standard BAL‐003‐
1 — Frequency Response and Frequency Bias Setting Frequency Response. These tests will be re‐run
during the annual review prescribed in the standard in the fall of 2013 to determine if adjustments
need to be made to the IFROs for 2014.
This analysis was performed by the NERC Reliability Initiatives and System Analysis staff.
5
The on‐peak Load Resource evaluated in the FRI report was 1,400 MW, but the light‐load case only included 1,300 MW of
Load Resources armed to trip.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
2 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000302
Findings
Findings
Western Interconnection
The dynamic simulation testing of the Western Interconnection IFRO indicated that the frequency
nadir remains sufficiently above the UFLS threshold of 59.5 Hz with the prescribed 840 MW/0.1 Hz
IFRO.
ERCOT Interconnection
The dynamic simulation testing of the ERCOT Interconnection IFRO revealed that a slightly higher
(about 350 MW/0.1 Hz) frequency response than the prescribed 286 MW/0.1 Hz IFRO was necessary to
keep the frequency nadir sufficiently above the UFLS threshold of 59.3 Hz. Consequently, the IFRO for
the ERCOT Interconnection may have to be adjusted when the annual review is performed in the fall of
2013. Efforts will also be made to mitigate problems with the wind energy dynamic models in the
ERCOT case before analysis is performed.
Eastern Interconnection
The IFRO for the Eastern Interconnection could not be reliably simulated with dynamics at this time
because the dynamic models for the interconnection are not yet accurate enough to confidently
predict system frequency response performance. The Eastern Interconnection Reliability Assessment
Group (ERAG) Multiregional Modeling Working Group (MMWG) has agreed to prepare an updated
“generic governor” 2013 summer light load case (from the 2012 case series) for evaluating Eastern
Interconnection IFROs by August 1, 2013. That case will use generic governor models to mimic the
frequency response performance characteristics determined in the “Analysis of Eastern
Interconnection Frequency Response” report published in March 2012. ERAG Management Committee
is targeting completion of the governor review and case creation by August 1, 2014.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
3 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000303
Western Interconnection Test
Western Interconnection Test
Initial Test
The WECC 2012‐13 LW2 (light winter) operating case was utilized for the simulations (with minor data
changes). The resource contingency tested was the tripping of two Palo Verde generating units, 2,740
MW total, as prescribe in Table B.
Figure 1: Initial WECC Simulation Test
60.10
60.05
Value A = 60 Hz
60.00
59.95
Hz
59.90
59.85
59.80
59.75
Value B = 59.79 Hz
59.70
59.65
C Point = 59.683 Hz
59.60
0.0
30.0
60.0
Time (Seconds)
The initial simulation shown in Figure 1 indicated an inherent frequency response 1,300 MW/0.1 Hz in
the case as dispatched.
Value A6 = 60.0 Hz
Value B7 = 59.790 Hz
Point C = 59.683 Hz
6
Value A frequency averaging period is T‐16 through T+0 seconds
7
Value B frequency averaging period isT+20 through T+52 seconds
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
4 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000304
Western Interconnection Test
CBR = (60 – 59.683) / (60 – 59.790) = 1.51
Delta Frequency = 60 Hz – 59.790 Hz = 0.210 Hz
Delta FrequencyAC = 60 Hz – 59.683 Hz = 0.317 Hz
Frequency Response = 2,740 MW / 0.21 Hz = 1,300 MW/0.1 Hz
IFRO Test
The frequency response for the initial case for WECC was well in excess of the IFRO of 840 MW/0.1 Hz.
Therefore, in order to test the system at the prescribed response level, the frequency response of the
case was de‐tuned by reducing the response capabilities of some generation throughout the
interconnection.
Figure 2: WECC IFRO Simulation Test
60.00
59.95
Value A = 60 Hz
59.90
59.85
Hz
59.80
59.75
59.70
59.65
Value B =59.710 Hz
59.60
C Point = 59.610 Hz
59.55
59.50
0.0
30.0
60.0
Time (Seconds)
Value A8 = 60.0 Hz
Value B9 = 59.710 Hz
Point C = 59.610 Hz
8
Value A frequency averaging period is T‐16 through T+0 seconds
9
Value B frequency averaging period isT+20 through T+52 seconds
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
5 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000305
Western Interconnection Test
CBR = (60 – 59.610) / (60 – 59.710) = 1.34
Delta FrequencyAB = 60 Hz – 59.710 Hz = 0.290 Hz
Delta FrequencyAC = 60 Hz – 59.610 Hz = 0.390 Hz
Frequency Response = (2,740 – 300 MW) / 0.29 Hz = 840 MW/0.1 Hz
The resultant frequency response of 840 MW/0.1 Hz is virtually the same as the prescribed IFRO of 840
MW/0.1 Hz calculated in the Frequency Response Initiative report, and it matched the maximum delta
frequency of 0.291 Hz.
Findings
The dynamic simulation testing of the Western Interconnection IFRO indicated that the frequency
nadir remains sufficiently above the UFLS threshold of 59.5 Hz with the prescribed 840 MW/0.1 Hz
IFRO.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
6 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000306
ERCOT Interconnection Test
ERCOT Interconnection Test
The ERCOT 2011‐12 winter off‐peak base case was used for the simulations. For this analysis, it was
found that the dynamics models for wind turbines were unstable over the period of the study (60
seconds). Since the wind turbines are not generally expected to supply primary frequency response for
resource contingencies at this time, all wind turbine dynamics were removed from the case and the
wind generators were “load netted” for the testing.
The resource contingency tested was the tripping of the two generating units at the South Texas
Project Electric Generating Station, total net generation of 2,750 MW as prescribed in Table B, coupled
with the tripping of Demand Resources of 1,300 MW at 59.7 Hz.
Figure 3: Initial ERCOT Simulation Test
60.05
60.00
Value A = 60 Hz
59.95
59.90
Hz
59.85
59.80
Value B = 59.848 Hz
59.75
59.70
59.65
Nadir= 59.565 Hz
59.60
59.55
0
6
12
18
24
30
36
40
46
52
60
Time (Seconds)
The initial simulation shown in Figure 3 indicated an inherent frequency response 954 MW/0.1 Hz in
the case as dispatched.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
7 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000307
ERCOT Interconnection Test
Value A10 = 60.0 Hz
Value B11 = 59.848 Hz
Point C = 59.565 Hz
CBR = (60 – 59.565) / (60 – 59.848) = 2.86
Delta FrequencyAB = 60 Hz – 59.848 Hz = 0.152 Hz
Delta FrequencyAC = 60 Hz – 59.565 Hz = 0.435 Hz
Frequency Response = (2,750 – 1,300 MW) / 0.152 Hz = 954 MW/0.1 Hz
IFRO Test
The frequency response for the initial case for ERCOT was well in excess of the prescribed IFRO of 286
MW/0.1 Hz. Therefore, in order to test the system closer to the prescribed response level, the
frequency response of the case was de‐tuned by reducing the response capabilities of some generation
throughout the interconnection.
Figure 4: ERCOT IFRO Simulation Test
60.10
60.00
Value A = 60 Hz
59.90
59.80
Hz
59.70
59.60
59.50
Value B = 59.527 Hz
59.40
59.30
59.20
59.10
C Point = 59.25 Hz
0
6
12
18
24
30
36
40
46
52
60
Time (Seconds)
10
Value A frequency averaging period is T‐16 through T+0 seconds
11
Value B frequency averaging period isT+20 through T+52 seconds
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
8 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000308
ERCOT Interconnection Test
Value A12 = 60.0 Hz
Value B13 = 59.527 Hz
Point C = 59.250 Hz
CBR = (60 – 59.250) / (60 – 59.527) = 1.59
Delta FrequencyAB = 60 Hz – 59.527 Hz = 0.473 Hz
Delta FrequencyAC = 60 Hz – 59.250 Hz = 0.750 Hz
Frequency Response = (2,750 – 1,300 MW) / 0.473 Hz = 307 MW/0.1 Hz
Estimation of necessary IFRO to avoid the 59.3 Hz UFLS top setting:
350 MW/0.1 Hz = 307 MW/0.1 Hz*(60 – 59.25) Hz / (59.963 – 0.012 – 59.3) Hz
Since the frequency nadir (point C) of 59.25 Hz is below the UFLS threshold of 59.3 Hz, a higher
interconnection frequency response (approximately 350 MW/0.1 Hz) is needed to keep the frequency
nadir sufficiently above the UFLS threshold of 59.3 Hz.
Findings
The IFRO for the ERCOT Interconnection may have to be adjusted when the annual review is
performed in the fall of 2013. Efforts will also be made to mitigate problems with the wind energy
dynamic models in the ERCOT case before analysis is performed.
12
Value A frequency averaging period is T‐16 through T+0 seconds.
13
Value B frequency averaging period isT+20 through T+52 seconds.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
9 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000309
Eastern Interconnection Test
The same level of simulations conducted for the Western and ERCOT Interconnections were not
possible for the Eastern Interconnection because the dynamic models for the interconnection are not
yet accurate enough to confidently predict system frequency response performance.
As stated in the Frequency Response Initiative report, NERC collaborated with the ERAG MMWG to
perform an analysis of the modeling of overall frequency response in the Eastern Interconnection as
part of the NERC Frequency Response Initiative and the Modeling Improvements Initiative. That review
was a prelude to a plan for thorough examination of the governor models in the Eastern
Interconnection dynamics study cases that are assembled by the MMWG. That report stated, “The
turbine‐governor modeling currently reflected in the MMWG dynamics simulation database is not a
valid representation of the frequency control behavior of the Eastern Interconnection.”
That project created a “generic case” dynamics model, replacing the turbine governor models in the
case with generic governor models in order to ascertain the basic characteristics of the frequency
response of the Eastern Interconnection. A simulation was made of a 4,500 MW resource loss event
that occurred on August 4, 2007.
Figure 5: Comparison of Legacy and Generic Simulations to August 4 Event
60.030
60.012
Base (Legacy
Models)
59.994
59.976
Hz
59.958
59.940
59.922
Best Generic
Model
59.904
59.886
Actual Event
59.868
59.850
0
6
12
18
24
30
36
40
46
52
60
Time (Seconds)
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
x
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000310
Eastern Interconnection Test
Figure 5 shows a comparison of the actual event frequency data and the simulations using both the
original governor data (Legacy Models) and the generic case. The 4,500 MW resource loss event is the
basis for the recommended resource loss event used in the Frequency Response Initiative report to
calculate the prescribed Eastern Interconnection IFRO. Work is still underway to improve the dynamic
models of the interconnection.
Findings
The IFRO for the Eastern Interconnection could not be reliably simulated with dynamics at this time
because the dynamic models for the Eastern Interconnection are not yet accurate enough to
confidently predict system frequency response performance. The ERAG MMWG has agreed to prepare
an updated “generic governor” 2013 summer light load case (from the 2012 case series) for evaluating
Eastern Interconnection IFROs by August 1, 2013. That case will use generic governor models to mimic
the frequency response performance characteristics determined in the “Analysis of Eastern
Interconnection Frequency Response” report published in March 2012. The ERAG Management
Committee is targeting completion of the governor review and case creation by August 1, 2014.
NERC | DRAFT Frequency Response Initiative Supplemental Report – IFRO Simulations | March 2013
11 of 14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000311
Exhibit I
Consideration of Comments
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000312
Project 2007-12
Frequency Response
Related Files
Status:
The standard will be presented to the NERC Board of Trustees for
adoption at its February meeting and if adopted, filed with regulators for
approval.
Purpose/Industry Need:
Frequency Response, a measure of an Interconnection’s ability to
stabilize frequency immediately following the sudden loss of generation
or load, is a critical component to the reliable operation of the bulk
power system, particularly during disturbances and restoration. Failure
to maintain frequency can disrupt the operation of equipment and
initiate disconnection of power plant equipment to prevent them from
being damaged, which could lead to wide-spread blackouts. There is
evidence of continuing decline in Frequency Response in the three
Interconnections over the past 10 years, but no confirmed reason for
the apparent decline. The proposed standard would set a minimum
Frequency Response obligation for each Balancing Authority, provide a
uniform calculation of Frequency Response and Frequency Bias Settings
that transition to values closer to natural Frequency Response, and
encourage coordinated AGC operation.
Draft
Action
Dates
Results
12/12/12 12/21/12
(closed)
Summary>>
Draft 4
BAL-003-1
Clean | Redline to Last
Posting
Attachment A
Clean | Redline to Last
Posting
Implementation Plan
Clean | Redline to Last
Posting
Recirculation
Ballot
Info>>
Vote>>
Full Record>>
Consideration of
Comments
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000313
Supporting Materials:
Procedure
Clean | Redline to Last
Posting
Background Document
Clean | Redline to Last
Posting
Mapping Document
VRFs and VSLs
Frequency Response
Initiative Report
FRS Form 1:
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
Excel 97 - 2003 Version
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
FRS Form 2:
Multiple BA
Interconnection
(Eastern & Western)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000314
ERCOT
Quebec Interconnection
Excel 97 - 2003 Version
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
Draft 3
BAL-003-1
Clean | Redline to Last
Posting
Successive Ballot
and Non-Binding
Poll
Updated Info>>
Summary>>
10/26/12 11/06/12
(Closed)
Info>>
Attachment A
Clean
Full Record>>
Non-binding
Poll Results>>
Vote>>
Implementation Plan
Clean | Redline to Last
Posting
Supporting Materials:
Procedure
Background Document
BAL-003-0.1b
Unofficial Comment
Form (Word)
Updated 10/16/12)
Mapping Document
Clean | Redline to Last
Comment
Period
Info>>
Submit
Comments>>
10/05/12 11/06/12
(Closed)
Comments
Received>>
Consideration of
Comments 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000315
Posting
VRF/VSL
Clean/Redline to Last
Posting
FRS Form 1:
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
Excel 97 - 2003 Version
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
FRS Form 2:
Multiple BA
Interconnection
(Eastern & Western)
ERCOT
Quebec Interconnection
Excel 97 - 2003 Version
Multiple BA
Interconnection
(Eastern & Western)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000316
ERCOT
Quebec Interconnection
Frequency Response
Technical Conferences
Unofficial Comment
Form (Word)
Draft 2
BAL-003-1
Clean | Redline to Last
Posting
Informal
Comment
Info>>
05/30/12 06/15/12
(closed)
Submit
Comments>>
Initial Ballot and
Non-Binding Poll
of VRFs and VSLs 11/30/11 12/09/11
Vote>>
(closed)
Info>>
Attachment A
Clean
Attachment B
Clean
Info>>
Submit
Comments>>
Supporting Materials:
Join Ballot Pool
Initial and NonBinding
BAL-003-0.1b
Info>>
Comment Form (Word)
Join>>
Mapping Document
Summary>>
Full Record>>
Non-Binding
Poll Results>>
Formal
Comment Period
Implementation Plan
Clean | Redline to Last
Posting
Background Document
Comments
Received>>
10/25/11 12/09/11
(closed)
10/25/11 11/23/11
(closed)
Comments
Received>>
Consideration of
Comments 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000317
FRS Form 1:
Eastern Interconnection
ERCOT
Quebec Interconnection
Western
Interconnection
FRS Form 2 for
Interconnection with
Multiple BAs:
Two-second Sample
Data
Three-second Sample
Data
Four-second Sample
Data
Five-second Sample
Data
Six-second Sample Data
FRS Form 2 for
Interconnection wit
One BA:
Two-second Sample
Data
Three-second Sample
Data
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000318
Draft 1
BAL-003-1
Clean
Attachment A
Supporting Materials:
Formal
Comment Period
BAL-003-0
Supplemental SAR
FRS Form 1 Instructions
Info>>
02/04/11 –
03/07/11
Comments
Received>>
Consideration of
Comments 4
Comments
Received>>
Consideration of
Comments 3
Submit
Comments>>
FRS Form 1
Implementation Plan
Comment Form (Word)
Field Test
Standard
Drafting Team
Nominations
Final SAR Version 3
Info>>
07/17/07 07/30/07
(closed)
Submit
Nomination>>
Draft 3
Frequency Response
SAR
Comment Period
Draft SAR Version 3
Submit
Info>>
02/08/07 03/09/07
(closed)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000319
Comments>>
Draft 2
Frequency Response
SAR
Draft SAR Version 2
Comment Period
Info>>
Submit
Comments>>
04/04/06 05/03/06
(closed)
Comments
Received>>
Consideration of
Comments 2
01/17/05 02/17/05
(closed)
Comments
Received>>
Consideration of
Comments 1
Draft 1
Draft SAR Version 1
White Paper
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000320
Consideration of Comments on First Draft of Frequency Response SAR
Background:
The Frequency Response SAR drafting team thanks all commenters who submitted comments on the first
draft of the Frequency Response SAR. The SAR was posted for comment from January 17 – February
17, 2005. The SAR drafting team asked stakeholders to provide feedback on the SAR through a special
SAR Comment Form. There were 30 sets of comments.
Based on the comments received, the drafting team has revised the SAR and is reposting it for an
additional 30-day comment period
In this ‘Consideration of Comments’ document, stakeholder comments have been organized so that it is
easier to see the summary of changes being requested of the SAR. All comments received on the first
draft of the Frequency Response SAR can be viewed in their original format at:
ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Frequency_Response_SAR_Comments_02_17_05.pdf
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Cauley at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Process Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
Page 1 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000321
Consideration of Comments on First Draft of Frequency Response SAR
Index to Questions, Comments and Responses:
1.
Do you agree there is a reliability need for specifying the quality and quantity of frequency
response?............................................................................................................................................ 3
2.
Do you agree with the scope and applicability of the proposed standard?....................................... 16
3.
Do you believe these standards are more appropriately additions to existing standards as opposed
to creating new standards? ............................................................................................................... 22
4.
Do you have any additional comments regarding the SAR that you believe should be addressed? 28
Page 2 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000322
Consideration of Comments on First Draft of Frequency Response SAR
1. Do you agree there is a reliability need for specifying the quality and quantity
of frequency response?
Summary Consideration: Most commenters agreed that there is a reliability need to specify
the quality and quantity of frequency response.
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
No
Comment
9
There is a need for governors but not for frequency response.
Governors are needed to resynchronize during restoration. But
the need for a short-term frequency response characteristic has
been obviated by the pending Version1 Balancing Standard. That
standard is designed to ensure that interconnection frequency is
never at such a level that the loss of the largest contingency will
cause instability or cascading outages. If the system is always in
such a state why would the instantaneous response to the loss of
a single contingency add to the system reliability?
The SAR has not provided any definitive need.
The SAR has not provided sufficient focus vis-à-vis who is
responsible to meet the standard (the generator, the BA, the
Load, the RA)
This proposal has not provided any additional information
concerning the need for this proposed Standard since the last
time (during the Balancing Resources and Demand consensus)
that a similar Frequency Response Requirement was
overwhelming rejected by those who commented to that proposal.
Transient frequency response has not been the target of any
major public concern. The current Version 1 Control Standard
proposal provides limits on the frequency excursions that can be
controlled by system-operators and their control systems. Relays
and other Protection Devices serve to protect those time frames
too short for an operator to respond to. What does this standard
add?
Comments
This SAR is not clear as to what it really is intended to mandate.
Does the requestor want to create a standard for Generator
Owners to install governors? Or a standard on Generator
Operators for individuals unit governor response? Or a standard
for Balancing Authorities for Area response? Or for Reliability
Authorities for Regional response? All of these are different
requirements and have different effects.
The requestor must be clear as to what is intended. To ensure
that frequency doesn’t hit a relay limit (as in the Balancing
standard?) or is it to address the need for governors when
synchronizing?
When does the standard apply? All times (which means that
NERC can go to a unit, BA or RA to check that some finite
response is available?) Just at times when large events occur
(the problem is of course whether or not the outage is near or far
from the entity being checked)? Only during test conditions (since
a unit under stress – ‘valves wide open’ has not governor
response at that time – even though it may have the greatest of
Page 3 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000323
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
responses at other times).
The requestor’s intent may be laudable but the description is no
where near ready to be considered as ‘standard material’.
Response: The drafting team (Resources Subcommittee Frequency Task Force) attempted to answer
many of the questions raised by the commenters in the Frequency Response Standard Whitepaper. We
agree that the standard needs to be clear to who and when it would apply and this is addressed in the
revised SAR. While the Interconnections may have sufficient frequency response for normal operations,
we don’t know how this response is dispersed and at what point it will pose a reliability risk. A primary
purpose of this standard is to collect information so informed decisions can be made before there is a
problem.
We disagree that the Balance Resources and Demand (BRD) standard is sufficient for all operating
states. The BRD addresses steady state and fully interconnected conditions. Refer to “A New Thermal
Governor Modeling Approach in the WECC” by Les Pereira, John Undrill, Dmitry Kosterev, Donald
Davies, and Shawn Patterson. Also, keep in mind that response has continued to decline since the last
published study, even though it should be increasing with load growth.
As you request, the draft standard addresses who is required to meet the standard (BA). The standard
will be designed such that a BA can mirror the metrics within its boundaries (evaluate generators and
LSEs) if they so choose.
The standard is not intended to establish a large set of arbitrary requirements, but will establish the
framework to collect the information to make informed engineering decisions.
The revised SAR clarifies what is expected.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
NERC should not involve itself in the development of these
standards and should allow individual interconnections to address
frequency response issues independently. For example, the
WECC is currently working on standards that will address this
concern. They will be tailored to the specific requirements of this
interconnection and will provide the best possible solution to the
problem. There may be a need to specify frequency response
requirements within some interconnections; however, it is not
necessary, or most effective for them to be defined at the NERC
level.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and, as envisioned, the proposed standard would accommodate
Interconnection differences both in amounts of response and methodology in calculating response. The
standard would identify technical and engineering principles that should be met to calculate and evaluate
the amount and distribution of frequency response within each Interconnection. The drafting team
believes that stakeholders would prefer the assurance of knowing that NERC is providing oversight to
ensure that all Interconnections have a technically sound basis for the development of respective
frequency response requirements.
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
9
The FRCC does not support the development of a Frequency
Response Standard at this time. A standard for each
Interconnection, although informative would be unenforceable as
far as identifying short term, frequency response deficient, entities
or areas. As such measurability and compliance by the relevant
entities would be all but impossible. As far as an Interconnection
allocation program for frequency response, we feel that the
“apparent” decline in response is not significant enough to
warrant a standard at this time and we would require additional
details of how such a plan would be implemented and the
potential economic impacts on the Regions that would be
Page 4 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000324
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
associated with that plan.
Response: The standard as envisioned does not mandate a specific amount of frequency response.
With regard to the “apparent” decline in frequency response, the most widely published report (Ingleson
and Nagle, 1999) documented a change in Eastern Interconnection response from 3750MW/0.1Hz in
1994 to 3390MW/0.1Hz in 1998. The Resources Subcommittee evaluation of 44 events in 2005 showed
an average frequency response well below 3000MW/0.1Hz. Theoretically, response should be increasing
over time with increasing load and generation in an Interconnection. One of the primary reasons for the
standard is to enable a better analysis of response and also enable informed decisions. As envisioned,
the standard will provide a fairly simple methodology to verify compliance.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT
(2)
P. Henderson – IESO
(2)
P. Brandien – ISO-NE
(2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
9
9
We agree in general that there is a reliability need to have
frequency response, particularly during disturbances, islanding
and restoration. The standard should provide the process for a
technically sound calculation of frequency response and bias
(both fixed and variable).
Any new standards on frequency response need not and should
not be onerous by finding BAs noncompliant with response less
than average or below some un-validated norms.
If performance is significantly less than an Interconnection norm,
the standard should not trigger an automatic non-compliance. In
these situations the BA should perform an internal
review/assessment that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be triggered to be more
responsive during disturbances, etc and satisfy the
Interconnection requirement. If the Interconnection requirement is
not met within a reasonable timeframe then the BA should be
deemed as non-compliant.
When required, the validation of governor performance could be
achieved either through online monitoring in an EMS or periodic
testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that response is highly variable eventto-event based on simultaneous load changes.
The standard should acknowledge the differing Interconnection
requirements (smaller Interconnections need greater response).
The standard should also track Interconnection and BA areas
response over time (years) and be reevaluated as performance
changes.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
Page 5 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000325
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes No
Comment
an analysis if response were measurably below the norm (this detail has been added to the detailed
description in the SAR).
There is another standard under development, (Phase III & IV MOD-027 - Verification and Status of
Generator Frequency Response) that requires Generator Owners to verify that their governors are
working as designed.
The standard would accommodate the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that could calculate the
BA’s performance to the standard.
The SAR was also changed to reflect the suggestions to accommodate:
•
Both fixed and variable bias.
•
Cases where a specific unit (e.g. nuclear) is prohibited from providing frequency response.
•
Differing Interconnection needs.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
Frequency response provided by speed governors and loads
helps to prevent load shedding and generator trips at significant
frequency excursions caused by sudden active power
mismatches in the systems. Without a sufficient frequency
response emerging during the first seconds after a frequency
disturbance, there is a danger of further cascading development
or frequency instability and system collapse cased by
underfrequency generator trips. It has been already noted that
insufficient frequency response in some parts of an
Interconnection may cause certain temporary redistribution of
power flows and reduce stability margins after frequency
disturbances that may limit the OTC on critical paths within the
Interconnection. It has been also observed that insufficient
frequency response may cause a weaker frequency recovery that
bears a greater risk of system collapse at subsequent frequency
disturbances. Therefore, frequency response is definitely a
reliability issue that needs to be addressed by a NERC standard.
Response: The Resources Subcommittee Frequency Task Force agrees that there are several issues
that must be addressed in the standard or in supporting business practices. As envisioned, the proposed
standard would not be prescriptive with regard to “how much” and “where” the response is carried.
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Manitoba Hydro , from a reliability perspective, supports the idea
of specifying the quantity and quality of frequency response and
incorporating these elements in a Standard. However, the
development of this standard should not be rushed since the
evidence provided in the Standard Authorization Request form
and in the Frequency Response Standard White paper shows
that current frequency response and projected frequency
response trends do not pose a significant potential for
compromising system reliability and for major under-frequency
load shedding to occur in the near term.
Also in the section of the white paper which examines “frequency
response standard considerations”, a broad scope and outline is
given, more detail is required especially regarding methods of
ensuring compliance.
In paragraph 2, page 9 of the white paper where the current
frequency response of the Eastern Interconnection is stated as
3100 MW/0.1 Hz with a standard deviation of 1870 MW/0.1 Hz
and the statement is made that “the fact that an under-frequency
Page 6 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000326
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
event has not happened yet is only coincidence” requires much
more detailed information regarding the origin and calculations of
these numbers before these assumptions can be made. Could it
be that instead of a frequency response closer to 1230MW/ 0.1
Hz it is actually practically closer to 3100 MW/ 0.1 Hz or even
4970 MW/ 0.1 Hz most of the time?
One understandable major concern addressed in the white paper
is the response of combined-cycle units to frequency decline and
the fact that due to a drop in combustion air volume their output
may actually decrease with a drop in frequency or even result in
unit tripping. Also there was concern with the possibility that
larger amounts of these types of units will be installed on the
system thereby potentially increasing the decline in frequency
response rate from 70 MW/ 0.1 Hz /Year (Eastern
Interconnection) .
It is also mentioned (on page 10) that with proper tuning
combined cycle units can provide correct frequency response.
Maybe part of the focus should be on finding ways of enforcing
the Current Requirements (Page 14) and including specific
frequency response requirements for combined-cycle units.
Response: The Resources Subcommittee Frequency Task Force agrees that the standard should not
rush to a decision on the amount and location of frequency response, but should set the framework for
making informed decisions. Frequency response is needed for more than protection against UFLS.
Response is also needed during disturbances and restoration. With regard to “current requirements”, the
Whitepaper listed what existed in NERC Policy, mostly as guides. There is very little in the V0 Standards
regarding governors or frequency response. We agree that the standard should not impose
unreasonable costs to demonstrate compliance. We agree that frequency response should be monitored
both at the BA and Interconnection level.
Characterizing how frequency response changes under varying interconnection load and unit
commitment conditions will be addressed by a sampling methodology.
The drafting team is pursuing the addition of functionality in the “NERC –ACE monitoring application” that
will identify generator trips and automate the calculation of Interconnection frequency response.
Evidence to date indicates that frequency response declines significantly during light load periods, even
though the exact mechanism for this is not well defined. Most of the major frequency excursions
experienced in the Eastern Interconnection have occurred during the shoulder period of the year during
either the early morning or late evening periods.
Regarding the last comment, there currently are no governor or frequency response requirements for
generators.
Energy Mark, Inc. (8)
Howard Illian
9
There is a reliability need but it is not an immediate reliability
need for all of the interconnections. The amount of Frequency
Response on the Texas Interconnection is close to the minimum
acceptable amount, and therefore, there is an immediate need for
a FRS on the Texas Interconnection. On the Western
Interconnection, the WECC keeps close tabs on Frequency
Response and takes immediate action when a problem arises
with frequency response on that interconnection. Although there
is no immediate need for a Frequency Response Standard on the
Western Interconnection at this time, the observed reductions in
Frequency Response on that interconnection make this issue an
ongoing concern. Finally, there is no current need for a
Frequency Response Standard on the Eastern Interconnection
because current Frequency Response is adequate. However, it
Page 7 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000327
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
takes significant time to develop an effective standard and put it
in place. The Balancing Resources and Demand Standard is
entering its fourth year of development with expectations of at
least another year before implementation. A Frequency
Response Standard would be expected to take a similar period to
develop. That means that it will be at least 2010 before a new
FRS would be put in place. There is no question that adequate
Frequency Response is required for reliability. There is no
question that Frequency Response on the Eastern
Interconnection is declining. There are two paths of action
available; 1) Wait until adequate Frequency Response causes
reliability problems and then begin the five year process to
develop a standard; 2) Begin development of a FRS and
determine the final need for implementation during the five year
development process. I would rather have a standard that
requires measurement that does not result in enforcement action,
and therefore, has no effect on operations, than not have a
standard when there are definite reliability problems. It will be
much easier to implement a standard for Frequency Response
before reliability problems occur than to implement a standard
after reliability problems occur. NERC should develop a
Frequency Response Standard and continue to investigate the
need for the standard during its development.
Response: The Resources Subcommittee Frequency Task Force agrees with the comments that the
standard should initially focus on measuring the amount of response and not impose restrictions on
current operations. As envisioned, the proposed standard would identify a consistent, objective
calculation of frequency response The standard would require regional and local analyses when BAs
have low response. This way, informed technical decisions can be made prior to reaching a point where
reliability is truly threatened.
MAAC (2)
John Horakh
9
There may be a reliability need in the near future. The white
paper does an excellent job of making that case. For the purpose
of commenting on a SAR that has not yet produced a proposed
Standard, I can give it the benefit of the doubt and say yes, there
is reliability need.
Response: The Resources Subcommittee Frequency Task Force appreciates your support and agrees
that there is a reliability need for this proposed standard.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
9
We agree (with qualifications). Any new standards on frequency
response need not and should not be onerous (identifying BAs
noncompliant with less than average response or some unvalidated norms).
The standard should provide the process for a sound calculation
of frequency response and bias (both fixed and variable).
There may be valid reasons why a BA is below observed norms
in response. It may meet most of its obligations with schedules.
Rather than generate an automatic non-compliance when
response is below some benchmark, the standard should require
Page 8 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000328
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
Yes
No
Comment
an internal review that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be put in more responsive modes
during disturbances, etc.
The standard should have some requirements on generators if
the BA is not providing the response outlined in the standard
(governors should be working as designed).
The standard should also track Interconnection response over
time and identify a target response (different for each
Interconnection). NERC or NAESB will want to look at how this is
allocated to BAs and generators.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned the proposed standard would not mandate a given amount of response, but would
require an analysis if response is measurably below the norm. As envisioned the proposed standard is
would acknowledge the variability inherent in measuring frequency response and would provide two
methods of capturing sufficient samples to make an objective measurement. The standard would not
preclude market solutions. The SAR detailed description has been expanded to state that the standard
will include a sound calculation for measuring frequency response with consideration of interconnection
specifics. Another detail added to the SAR requires generator units with nameplate ratings of 10 MW or
greater to be equipped with governors. There is another standard under development, (Phase III & IV
MOD-027 - Verification and Status of Generator Frequency Response) that requires Generator Owners to
verify that their governors are working as designed. Finally, the SAR was modified to accommodate both
fixed and variable bias.
Southern Company
Transmission,
Operations, Planning
and EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that significant
frequency response degradation is occurring, particularly in the
Eastern Interconnection. While not yet a crisis, these trends are
indicative of significant changes in design and operational
practices on the interconnected electrical systems of North
America which, if not managed intelligently, can cause significant
degradation in reliability. We strongly urge the industry to support
this SAR and begin the process of controlled management before
the processes behind these trends reach crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York ISO (2)
Mike Calimano
9
We agree in general that there is a reliability need to have
frequency response, particularly during disturbances, islanding
and restoration. The standard should provide the process for a
technically sound calculation of frequency response and bias
(both fixed and variable).
Any new standards on frequency response need not and should
Page 9 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000329
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
not be onerous by finding BAs noncompliant with response less
than average or below some un-validated norms. There may be
valid reasons why a BA is below observed norms in response.
For example, the BA may meet most of its obligations with
schedules or its native load may be non-responsive.
If performance is significantly less than an Interconnection norm,
the standard should not trigger an automatic non-compliance. In
these situations the BA should perform an internal
review/assessment that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be put in more responsive modes
during disturbances, etc.
When required, the validation of governor performance could be
achieved either through online monitoring in an EMS or periodic
testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that response is highly variable eventto-event based on simultaneous load changes. The standard
should acknowledge the differing Interconnection requirements
(smaller Interconnections need greater response).
The standard should also track Interconnection response over
time (years) and be reevaluated as performance changes.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
an analysis if response were measurably below the norm (this detail has been added to the detailed
description in the SAR).
There is another standard under development, (Phase III & IV MOD-027 - Verification and Status of
Generator Frequency Response) that requires Generator Owners to verify that their governors are
working as designed.
The standard would accommodate the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that could calculate the
BA’s performance to the standard.
The SAR was also changed to reflect the suggestions to accommodate:
•
Cases where a specific unit (e.g. nuclear) is prohibited from providing frequency response.
•
Differing Interconnection needs.
IESO (2)
Pete Henderson
9
We agree in general that there is a reliability need to have
frequency response, in order to maintain interconnection
frequency and particularly during disturbances, islanding and
restoration. The standard need to address both the system
needs as well as island requirements for frequency response.
The standard should provide the process for a technically sound
Page 10 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000330
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
calculation of frequency response and bias.
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that load response is highly variable
event based on time of day or year.
The standard should acknowledge smaller areas need greater
response.
Where BA areas are deficient in meeting the interconnection
requirement , they should be allowed a reasonable period of time
to take appropriate steps to make corrections before being
assessed as non compliant.
The standard should also track area response over time (years)
and be reevaluated as performance changes.
Quality should be defined. For generators it should include deadband, droop characteristics, etc.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
an analysis if response were measurably below the norm (this detail has been added to the detailed
description).
The standard accommodates the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that will calculate the
BA’s performance to the standard. The Resources Subcommittee Frequency Task Force agrees with your
“governor quality” comment and has added governor installation and operation details to the SAR’s
detailed description.
As envisioned, the standard will provide the Balancing Authority with sub-par frequency response time to
analyze their situation and make necessary changes and corrections.
ATC (1)
Peter Burke
9
Based on the NERC white paper Frequency Response Standard
Whitepaper dated April 6, 2004 that was prepared by the
Frequency task Force of the NERC Resources Subcommittee, it
would appear that the decline in frequency response of both the
Eastern and Western Interconnections is a reliability concern. As
a transmission provider, however, there is probably little that can
be done other than make sure that governor response and load
modeling can be made as accurate as reasonably possible in
conducting dynamic simulations and be aware of this issue in
studying existing as well as new generating facilities. The control
area, generation operators and turbine-generator manufacturers
need guidance provided as to their responsibilities and
obligations regarding frequency response. Changes in the load
characteristics (e.g. fewer large motors, variable speed drives, etc
) over time, plus changes in reserve sharing practices brought on
by deregulation and competition are and will affect load response
to frequency excursions. The type of generation (e.g.
combustion turbine units, combined-cycle units) being
interconnected to the system as well as the operation of the
Page 11 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000331
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
governors (e.g. blocked or improper settings) and turbines (e.g.
sliding pressure, boiler-follower, etc.) of existing generators have
a significant effect on the system frequency response.
Response: The Resources Subcommittee Frequency Task Force agrees with your technical comments
in support of this standard. The team also supports the development of the planning “MOD” standards
that address frequency response at the generator level.
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that significant
frequency response degradation is occurring, particularly in the
Eastern Interconnection. While not yet a crisis, these trends are
indicative of significant changes in design and operational
practices on the interconnected electrical systems of North
America which, if not managed intelligently, can cause significant
degradation in reliability. I strongly urge the industry to support
this SAR and begin the process of controlled management before
the processes behind these trends reach crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
Robert Blohm
9
The CPS1 equation is a single equation in two variables, primary
(governor) response and secondary response. Two variables
require two equations in order to have a unique solution. That
second equation does not currently exist and must be the
proposed Frequency Response standard that pins down the
value of primary (governor) response. Currently, the single CPS1
equation allows any Balancing Authority an infinity of solutions for
any given CPS1 value. Accordingly, Balancing Authorities have
been tending to reduce expensive primary response and increase
cheaper secondary response (AGC, regulation, load following) to
achieve a given CPS1 score, which is an average over time. The
result has been a halving of system bias in the Eastern
Response: The Resources Subcommittee Frequency Task Force appreciates your comment and your
support for the frequency response standard.
SPP Operating
Reliability Working
Group
Robert Rhodes –SPP
(2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
9
A frequency response standard is needed but only within the
scope and range of the previously provided guides in Policy 1
such as a design criteria of 5% droop, a 36 mHz deadband with
exclusions for nuclear, combined cycle and small generating
units.
Page 12 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000332
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA
(1)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force agrees with the comments and has
added statements to the detailed description to reflect the comments. However, the SAR is intended to
capture the scope of the standard and the specific parameters will be determined by the standard drafting
team.
Southern Co.
Generation (6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that frequency
response degradation is occurring, particularly in the Eastern
Interconnection. While not yet a crisis, these trends are indicative
of significant changes in design and operational practices on the
interconnected electrical systems of North America which, if not
managed intelligently, can cause degradation in reliability. We
support this SAR in an effort to begin the process of controlled
management before the processes behind these trends reach
crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
TXU Energy Delivery
Roy Boyer
9
Yes, I agree there is a reliability need for specifying the quality
and quantity of frequency response. There is ample evidence
that specifying a droop value or that specifying governors must be
in operation will not necessarily result in any useful governor
response to a sudden large drop in system frequency. So yes, I
think a SAR team should look into this matter. I would suggest the
part load can play in arresting frequency decline be included in
the scope. I would also suggest that the frequency response
needs of the regions will likely vary, so final specific requirements
should probably be made at the region level.
Response: The Resources Subcommittee Frequency Task Force agrees that load can provide frequency
response and load contribution is, by default, included in the balancing authority’s performance. The
standard is indifferent to whether response is provided by load or generation. The proposed standard
recognizes the role and importance of both the Interconnection and the Regional Reliability Organization
in the establishment of requirements. In general, it is expected there is a “base” Interconnection target
response that will be addressed in this standard. Each Interconnection would have a different target,
based on its size and historic response. There are areas (e.g. Maritimes) that require additional
response. It is expected these unique situations will be primarily addressed in the “MOD” standards. This
standard would enable improved data for the MOD standards.
MISO
Terry Bilke
9
These are my individual comments as a member of the NERC
Resources subcommittee and not those of representing any
organization.
There is a reliability need for a light-handed standard that allows
us to do a better job of ensuring response is available when
Page 13 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000333
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
required. As some entities might comment, there is adequate
response in all interconnections during “system normal”
conditions. The problem is what occurs during major
disturbances and restoration.
A primary reason the industry needs to do a better job of tracking
frequency response is the fact that response is declining when it
should actually be increasing with load and generation growth.
The standard should not be structured such that it finds BAs
noncompliant if response is below average or if response is low
for a given event. Frequency response at the BA level is
extremely variable as the measure is mingled with load
fluctuation.
The standard should guide a technically sound calculation of
response at the BA level and track interconnection performance
over time to enable informed decisions.
If a BA performs significantly below an Interconnection norm, the
standard should require the BA do an internal assessment of its
key generation to verify governors are working as designed and
that there will be frequency responsive resources for disturbances
and restoration.
If Interconnection response significantly changes over time, the
standard should be reevaluated.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
TXU Electric Delivery proposes that Frequency Response
Guidelines at the NERC level should only be in general terms and
require that each Reliability Authority establish a specific
Frequency Response Standard with detailed specifications as
appropriate for its region.
Response: The Resources Subcommittee Frequency Task Force intent was not to mandate a specific
amount of frequency response, but to require a consistent, objective calculation of frequency response.
The balancing authority and the Regional Reliability Organization must do an assessment of adequacy if
response is measurably below the norm. The proposed standard recognizes the role and importance of
the Interconnection and the Regional Reliability Organization in the establishment of requirements. In
general, it is expected there is a “base” Interconnection target response that will be addressed in this
standard. Each Interconnection would have a different target, based on its size and historic response.
There are areas (e.g. Maritimes) that require additional response. It is expected these unique situations
will be primarily addressed in the “MOD” standards. This standard would enable improved data for the
MOD standards.
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
9
Page 14 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000334
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Ed Forsythe
Yes
Alliant Energy (1)
Kenneth A. Goldsmith
9
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System
Response to Generation
Governing
9
NCPA (4)
Les Pereira
9
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE
(2)
Al Adamson – NYSRC
(2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One
(1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE
(2)
G. Campoli – NYISO (2)
9
New York State
Reliability Council (2)
Theodore Pappas
9
We Energies (3, 4, 5)
Howard Rulf
9
Calpine (6)
James Stanton
9
No
Comment
Page 15 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000335
Consideration of Comments on First Draft of Frequency Response SAR
2. Do you agree with the scope and applicability of the proposed standard?
Summary Consideration: Most commenters agreed that the proposed standard should apply
to the Reliability Authority (or Reliability Coordinator), Balancing Authority and Generator
Operator. With the revisions to the SAR, there are requirements for the Generator Owner to
ensure that certain governors meet a minimum set of criteria
There was no consensus amongst commenters on the scope of the proposed standard. The
drafting team made extensive changes to try to better define the scope.
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
No
9
Comment
Frequency Response characteristics should be dictated by the
Reliability entities as part of their respective control services to
meet the regional synchronizing requirements as well as the
longer duration control standards and of the needs of the
interconnection in which they operate.
Response: The Resources Subcommittee Frequency Task Force’s intent is that the standard be
designed such that a BA can mirror the metrics within its boundaries (evaluate generators and LSEs) if it
so chooses.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
The main theme that there needs to be a relationship between
response and frequency decline is the right approach but
requirements would be different from region to region.
Standards to manage frequency response should be developed
by individual interconnections; not NERC. The scope and
applicability should be defined by the needs of the
interconnection to provide the most benefit to system wide
reliability.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and, as envisioned, the Standard would accommodate Interconnection
differences both in amounts of response and methodology in calculating response. The drafting team
believes that stakeholders would prefer the assurance of knowing that NERC is providing oversight to
ensure that all Interconnections have a technically sound basis for the development of respective
frequency response requirements.
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC (2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One (1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE (2)
9
The applicability of this Standard to the LSE should be
considered.
Page 16 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000336
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
G. Campoli – NYISO (2)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force will add LSE to the standard’s
applicability list.
MAAC (2)
John Horakh
9
Quoted from the SAR (with corrections): This SAR is proposed
to develop a standard to measure sub-minute responses to
changes in frequency and to set minimum acceptable responses
of the system to these events. Also quoted: The measurement
selected must be accurate and, to the extent practical, easy to
implement. This seems more like a research project than a
request for a standard. There is no mention of any possible
measurements that might be in the standard. I’m afraid that
proceeding with such a vague idea of a measurement will lead
the SAR or later Standard to become bogged down with
research and field testing even more so than the Balance Load
and Demand Standard. And Balance Load and Demand did
have definite measurements in mind, thereby not requiring much
research, mainly field testing. Come back with a SAR after the
research is done, or at least started.
Response: The Resources Subcommittee Frequency Task Force agrees that the whitepaper bears
some resemblance to the description for a research project. Many in the industry are concerned with the
decline in Frequency Response, while at the same time some are asking how much of a problem is the
decline in response. The drafting team’s goal is to put the infrastructure and process in place to make
informed decisions in the future and to allow the Regions to evaluate the distribution and adequacy of
response and take mitigating action if there are areas found to be deficient. The Resources
Subcommittee Frequency Task Force disagrees with delaying the standard development. The SAR will
define the scope of the standard. The specific detailed requirements and measures will be developed by
the standard drafting team.
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
If the purpose is to purchase frequency response, then the
Market Operator needs to be includes. Will this be considered
an Ancillary Service?
Others that may need to be involved are Transmission Service
Provider, Generator Owner, Planning Authority and Resource
Planner.
Applicability should include #2
Response: The Resources Subcommittee Frequency Task Force agrees that others have roles in
providing Frequency Response, but have focused on the higher level calculation of response at the
balancing authority and Interconnection level. The primary reason for this is that there are about 150
balancing authorities. Only those balancing authorities with sub-normal response need to investigate to
the generator level. The NERC 2002 Generating Unit Statistical Brochure identifies 3694 generators of 1
MW or greater. It would be difficult (and unnecessary if the BA has good response) to monitor thousands
of generators with this standard. The standard doesn’t preclude market solutions, which NAESB may
adopt. The Resources Subcommittee Frequency Task Force agrees with the comment to include #2 in
the SAR.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
9
There is a general need for a standard, but the outcomes and
expectations should address the comments raised in question 1.
While we agree that the standard should not preclude market
solutions (e.g. allow purchasing of response as long as
deliverability and restoration criteria can be met), we have
concerns with the statement There must be a means for
sale/purchase of frequency response as for any other quantity.
Page 17 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000337
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
P. Henderson – IESO (2)
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
Comment
It is not clear what is meant by A method of allocation must be
developed.” Is this an allocation of Interconnection response to
BAs, BA allocation to generators or something different?
New York ISO (2)
Mike Calimano
Response: The Resources Subcommittee Frequency Task Force agrees with these comments, and has
revised the SAR to omit the italicized statements. As envisioned, the proposed standard would not
mandate a given amount of frequency response, but would require an analysis if response were
measurably below the norm. The standard doesn’t preclude market solutions, which NAESB may adopt.
9
NCPA (4)
Les Pereira
The scope needs to be expanded – see detailed comments in a
following section – based on extensive modeling and validation
work in WECC.
Response: The Resources Subcommittee Frequency Task Force appreciates the significant work that
has been done in this area by the WECC and has referenced some of this research in the Whitepaper.
We believe the Planning Standards under development (MOD-13 and MOD-27) deal with the governor
issues that you outline. As envisioned, this standard will provide improved data into the modeling
process.
9
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
The SAR indicates a measure of frequency response for the
Interconnection, as a measure of performance. This would be
very difficult to translate to individual entity compliance and thus
render the standard applicable to no entities.
Response: The interconnection measure of response is intended as a benchmark and as a validation of
the balancing authority’s reported performance. The revised SAR indicates that if frequency response is
outside the norm for the BA, based on its size, BAs and Regions would be required to conduct analyses
to determine the reason for the performance.
9
IESO (2)
Pete Henderson
The Frequency control standard needs to address levels
required for reliability, be consistent and verifiable, and be
simple to monitor for compliance purposes.
Response: This is the intent.
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
Scope:
The scope of the proposed standard is appropriate. However,
the reliability requirements would be better addressed by a
comprehensive review that considers the adequacy of existing
reliability standards.
Applicability:
The applicability of the proposed standard is understood to be
Reliability Authorities, Balancing Authorities, and Generator
Page 18 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000338
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Operators. However, substantial questions remain as to how
the responsibilities implied in the proposed standard will be
equitably distributed.
Response: The Resources Subcommittee Frequency Task Force appreciates your comment. The new
standard for verifying generator governor controls will be under field test through part of 2007 and then
will be finalized, balloted and then implemented. The implementation plan for MOD-027 includes
additional time for entities to become compliant with the requirements. This would mean that any work on
this standard could be delayed for several years. With the decline in Eastern Interconnection frequency
response, the drafting team thinks it would be unwise to wait for the new standards to be developed and
reviewed before developing this standard.
Your questions regarding the applicability of the responsibilities will be better defined during the standard
drafting phase of this standard.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
Generally, our answer is yes, but the matter of applicability
needs a very careful consideration. The question is whether the
proposed standard should be applied to only the reliability and
balancing authorities and plant operators, or also to the resource
and system planning authorities and generator owners. For
example, wind generators do not provide a frequency response,
whereas the response from the Combined Cycle units is limited.
This is a matter of design as well as the matter of controllability
of the primary energy source. If the generation portfolio contains
a lot of wind and CC generators, the balancing authority cannot
do much to improve its summary frequency response in general
terms. Also, if frequency responsive generators in a CA are
heavily loaded, would the new standard force the balancing
authorities to re-dispatch generation in favor of non-responsive
generation and commit more responsive generation ahead of
the non-responsive generation? Another issue is whether the
standard should specify the required response in the area or
individual responses from generators. Perhaps, NERC should
work with NASB to find the right answers before establishing the
standard. One possible solution is to establish penalties for noncompliance that would stimulate generator owners to invest in
frequency responsive generation. Another possible
recommendation could be establishing a market for frequency
response. Without resolving these difficult issues, this standard
cannot be accepted.
Response: The Resources Subcommittee Frequency Task Force agrees that there are several issues
that must be addressed in the standard or in supporting business practices. As envisioned, the draft
standard would not be prescriptive with regard to “how much” and “where” the response is carried. The
standard would allow balancing authorities, reliability coordinators, load-serving entities and Regional
Reliability Organizations to make informed decisions based on their unique situation.
Energy Mark, Inc. (8)
Howard Illian
9
Planning standards are not enough by themselves. Without
continuous measurement, there can be no assurance that those
responsible for meeting the reliability need for Frequency
Response are fulfilling those responsibilities. Only a Frequency
Response Standard that continuously measures response can
insure that the response is available when required.
Response: The Resources Subcommittee Frequency Task Force agrees with your comment. The SAR
drafting team will follow the Planning Standards under development (MOD-13 and MOD-27) that deal with
governors and frequency response to be sure there are no conflicts.
Page 19 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000339
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
TXU Energy Delivery
Roy Boyer
Yes
9
No
Comment
Yes, I agree.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MISO
Terry Bilke
9
I agree, with some qualification. While the standard shouldn’t
preclude market solutions, I don’t think it must enable a market
as the scope implies. A little more clarity on the goals of the
standard is needed.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments and has
removed the reference in the original SAR to market solutions.
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System Response
to Generation Governing
9
The proposed scope and applicability, to the extent that they are
in the given in the SAR, are good.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
We Energies (3, 4, 5)
Howard Rulf
9
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Calpine (6)
James Stanton
9
Alliant Energy (1)
Kenneth A. Goldsmith
9
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
Southern Company
Transmission,
Operations, Planning and
9
Page 20 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000340
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
Yes
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
Robert Blohm
9
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA (1)
9
Southern Co. Generation
(6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
New York State Reliability
Council (2)
Theodore Pappas
9
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
No
Comment
Page 21 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000341
Frequency Response SAR – Comment Report
3. Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Summary Consideration: There was no consensus amongst commenters on this issue.
Refinement of this SAR was delayed for a year. During that time other related standards have
undergone considerable development, and are on a schedule that would not be improved by the
addition of the requirements envisioned with the Frequency Response standard. For these
reasons, the drafting team is recommending that the new requirements for Frequency
Response be in a new, stand-alone standard.
Commenter
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
Yes
No
Comment
9
WECC has been working on frequency response
standards for a few years and is close to finalizing
standards specifically for the WECC interconnection.
We do think there is a need for standardization of
frequency response (clearly we do since WECC is
doing it) BUT this standard should be developed at the
Regional Council or Interconnection level and then
adopted by NERC as a "Standard" with regional
differences. Any new standards concerning frequency
response should be developed by the individual
interconnections.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and the proposed standard accommodates Interconnection
differences both in amounts of response and methodology in calculating response. The SAR’s detailed
description has been expanded to include broader parameters, including frequency response
calculations that are Interconnection-specific. The drafting team believes that stakeholders would
prefer the assurance of knowing that NERC is providing oversight to ensure that all Interconnections
have a technically sound basis for the development of respective frequency response requirements.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
The new standard should a stand-alone standard
because of its potential implications for control areas
and the necessity to stage the implementation of the
standard in coordination with resolution of the issues
discussed above.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
Robert Blohm
9
The SAR acknowledges that the proposed Standard
not only is complementary to the Balancing Resources
and Demand Standard, but also must be coordinated
with that Standard. The two standards could be
combined. But that is insufficient reason to oppose
development of a separate Frequency Response
Standard. Moreover, combining the standards would
reverse the great progress made in consensus on the
Balancing Resources and Demand Standard.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MAAC (2)
John Horakh
9
Adding this requirement to another standard would
only slow down the progress of both.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
ISO/RTO Standards Review
9
Unless the Version 0 (BAL-003-0 — Frequency
Page 22 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
P. Henderson – IESO (2)
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
000342
Comment
Response and Bias) can be clarified and brought in
line with this proposed standard, it should be standalone.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
NCPA (4)
Les Pereira
9
A new SAR will be more prescriptive, however there is
also need for other related sections in NERC
Operating Policy and Planning that need to be
modified – see other comments below.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
IESO (2)
Pete Henderson
9
If the existing Frequency Response and Bias Standard
Version 0 (Bal-003-0) can not be clarified and brought
in line with this proposed standard, it should be
standalone.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
9
Manitoba Hydro (1, 3, 5, 6)
Gerald Rheault
9
We Energies (3, 4, 5)
Howard Rulf
9
Calpine (6)
James Stanton
9
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
9
Page 23 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000343
Frequency Response SAR – Comment Report
Commenter
Steve Wallace – SEC (5)
S. McElhaney – FMPA (5)
Ted Hobson – JEA (1)
Yes
No
New York ISO (2)
Mike Calimano
9
New York State Reliability
Council (2)
Theodore Pappas
9
TXU Electric Delivery (1)
Travis Besier or Ellis Rankin
9
NPCC CP9, Reliability
Standards Working Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA (1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC (2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One (1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE (2)
G. Campoli – NYISO (2)
9
Progress Energy – Carolinas
(1, 3, 5, 6)
Phil Creech
9
Comment
The reliability requirements provided in the proposed
standard would be better addressed by a
comprehensive review that considers the adequacy of
the existing reliability standards (i.e., 300 - Balance
Resources and Demand)
Response: Frequency Response was consciously left out of the Balance Resources and Demand
(BR&D) standard. We agree that the Frequency Response standard should complement the BR&D
standard and believe it does.
Energy Mark, Inc. (8)
Howard Illian
9
Frequency Response is closely related to the
Frequency Bias used in the Balancing Resources and
Demand Standard and therefore this standard should
be included as an addition to that standard. If it is not
included in the BRD Standard, a separate standard
would require coordination between the two standards.
This would make the process of updating the
standards more complex.
Response: The Resources Subcommittee Frequency Task Force acknowledges that if the frequency
response requirements and measures were to be included in another standard that the Balance
Resources and Demand standards would be the most likely standard(s). The Resources
Subcommittee Frequency Task Force is working with the Balance Resources and Demand standard
drafting team to ensure that the efforts of both teams are coordinated.
Page 24 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000344
Frequency Response SAR – Comment Report
Commenter
Alliant Energy (1)
Kenneth A. Goldsmith
Yes
9
No
Comment
Version 0 of BAL-003-0, Frequency Response and
Bias; or its successor.
Response: The Balance Resources and Demand standard drafting team has a successor version of
Frequency Bias posted for review. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson – SaskPwr
Jim Maenner – WPS
Tom Mielnik – MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
Version 0 (BAL-003-0 — Frequency Response and
Bias) or its successor is a logical place. Depending on
the outcome of the V1 Balance Resource and Demand
standard, it could reside there.
Response: : The Balance Resources and Demand standard drafting team has a successor version of
Frequency Bias posted for review. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated.
Southern Company
Transmission, Operations,
Planning and EMS Divisions
(1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The intent is for the Frequency Response Standard to complement the Balance
Resources and Demand standards. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated. The ‘new’ Balance Resources and Demand standards are close to completion
and cover related but different topics from those in the proposed Frequency Response SAR. There
doesn’t seem to be any benefit in stalling the implementation of the new Balance Resources and
Demand standards while the technical details of the new Frequency Response standard are
developed, tested and then implemented.
ATC (1)
Peter Burke
9
II.B.S1M5, Test results of speed/load governor
controls.
Page 25 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000345
Comment
Comments
It may be appropriate to include this standard in the
Phase III/IV standards that address speed/load
governor controls (II.B.S1M5, Test results of
speed/load governor controls). The three following
customer demand related standards would be helpful
in defining load response to frequency excursions:
II.E.S1.M1, Plans for the evaluation and reporting of
voltage & Frequency characteristics of customer
demands.
IIE.S1.M2 Documentation or requirements for
determining dynamic characteristics of customer
demands.
II.E.S1.M3, Customer (dynamic) demand data.
Response: The drafting team will follow the development of the Phase III/IV planning standards under
development (MOD-13 and MOD-27) that deal with governors and frequency response to be sure there
are no conflicts. The Resources Subcommittee Frequency Task Force believes that a Frequency
Response standard could simplify what is proposed in the planning standards if it allowed an on-line
calculation of generator response.
NERC Frequency Task Force
Raymond L. Vice, Chairman
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL (1)
Steve Hillman – WPEK (1)
Allen Klassen – Westar (1)
9
We would recommend that this standard be
incorporated into the Balance Resource and Demand
Standard (Standard 300) or the Version 0 BAL
Standard.
Page 26 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000346
Frequency Response SAR – Comment Report
Commenter
Bill Nolte – SECI (1)
Mike Stafford – GRDA (1)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
Southern Co. Generation (6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
MISO
Terry Bilke
9
It’s not a major issue. It appears it should be include
in the Version 0 (BAL-003-0 — Frequency Response
and Bias).
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
Dick Schulz
Chair, IEEE Task Force on
Large Interconnected Power
System Response to
Generation Governing
No comment.
TXU Energy Delivery
Roy Boyer
No opinion.
Page 27 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000347
Frequency Response SAR – Comment Report
4. Do you have any additional comments regarding the SAR that you believe should be
addressed?
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
9
No
Comment
The SAR requestor has not provided any indication of a reliability
problem. Decreasing frequency response is in and of itself not a
reliability problem - more evidence is required as to the
magnitude of the threat.
Any standard that is proposed, regarding frequency response,
should consider both generator and load response. If Load
response does provide a significant portion of the frequency
response (as some people contend) then that resource must be
considered in the proposal. In short the standard must make
clear whether it is for interconnection response or for balancing
area response or for individual generator response and individual
load response.
Response: Most commenters indicated that they feel that there is a reliability-related need for a standard
to address Frequency Response.
The standard is not intended to establish a large set of arbitrary requirements, but will establish the
framework to collect the information to make informed engineering decisions. Additional detail has been
added to the SAR’s Purpose/Industry Need and the Detailed Description. The revised SAR does not
specifically consider load response but does state that the proposed standard will include requirements
for the Interconnection response, for the installation of governors and for BAs to operate their automatic
generation control function on tie-line frequency bias and for BAs to respond to requests for information
on frequency response. The revised SAR does not include requirements for generators to provide
response and does not address load response.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
Frequency response requirements are likely different for each of
the three interconnected regions and a generalized approach will
likely not meet WECC needs. The danger here is that a NERCwide approach may not be compatible with the needs of a
regional approach. Standards are currently being developed
within WECC to address the frequency response concerns of
this interconnection. We feel that if the Eastern Interconnection
needs a Frequency Response Standard, they should utilize the
NERC Frequency Response Standard Whitepaper to draft an
Eastern Interconnection-specific Frequency Response Standard.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and the proposed standard accommodates Interconnection differences
both in amounts of response and methodology in calculating response. As noted in and earlier response,
we would expect some general technical and engineering principles that should be met in order to
calculate and evaluate the amount and distribution of frequency response. Additional SAR Detailed
Description details have been added.
The drafting team believes that stakeholders would prefer the assurance of knowing that NERC is
providing oversight to ensure that all Interconnections have a technically sound basis for the development
of respective frequency response requirements.
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Below are a few general comments on the SAR:
There is general agreement with the statement “reliance on load
as the sole support to arrest the frequency can lead to a decline
in the reliability of the grid” in paragraph 3, page 4 of the white
paper. However enough information is not provided to
Page 28 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000348
Comment
substantiate statements earlier in the paragraph such as, “the
turn around in frequency from points C to B attributable to unit
governor response has markedly declined and at times is nonexistent in the eastern interconnection” and “the line from points
C to D is shifting down and becoming horizontal”.
In areas where governor response is limited it may be necessary
to explore the necessity of earmarking “high-set” blocks of load ,
as is practiced in ERCOT, to act as a supplementary to governor
response. Although it is anticipated that this approach would
probably be much more difficult and challenging to co-ordinate in
larger areas.
There should be careful thought put into the
system/interconnection performance targets for frequency
response. Perhaps the bar should be higher than preventing
UFLS for credible generation loss events, i.e., provide a margin
above this level. At the same time the standard should not
impose unreasonable costs on entities to demonstrate
compliance. The performance target should address both total
interconnection response and also area or system response
(potential islanding) and be very clear how generator operators
(or load) obligations are allocated to achieve the performance
targets.
NERC should investigate a process to monitor interconnection
frequency response to be able to measure performance.
Response: As envisioned, the standard will accommodate special needs of each Interconnection. It will
not preclude load from being part of the solution.
While not part of the standard, the Resources Subcommittee is pursuing the addition of functionality in the
“NERC ACE-Frequency monitoring application” that will identify generator trips and automate the
calculation of Interconnection frequency response. Evidence to date indicates that frequency response
declines significantly during light load periods, even though the exact mechanism for this is not well
defined. Most of the major frequency excursions experienced in the Eastern Interconnection have
occurred during the shoulder period of the year during either the early morning or late evening periods.
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC
(2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One
(1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE
9
CHANGE
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to these system events.
Page 29 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000349
Frequency Response SAR – Comment Report
Commenter
(2)
G. Campoli – NYISO (2)
Yes
No
Comment
Response: The SAR has been revised and no longer includes this phrase.
Energy Mark, Inc. (8)
Howard Illian
9
NERC has the responsibility of maintaining reliability on the
North American Interconnections. NERC cannot perform that
function effectively if it waits for reliability problems to become
apparent in system operations before it takes actions to address
those problems. NERC must be a forward looking organization
that anticipates future reliability problems and takes actions to
resolve those problems before they affect interconnection
reliability.
Response: The Resources Subcommittee Frequency Task Force agrees with the comments and has
made substantial changes to the SAR’s Purpose/Industry Needs and the Detailed Description reflecting
the industry comments.
Calpine (6)
James Stanton
9
Given the language in the accompanying White Paper: The
standard should not preclude market solutions (e.g. allow
purchasing of response as long as deliverability and restoration
criteria can be met).There must be a means for sale/purchase of
frequency response as for any other quantity. – I believe this
Standard should be developed in conjunction with NAESB. The
definition, attributes and procurement metrics of the frequency
response product will be a critical component of this Standard.
Some guidance in defining and developing this service to the
bulk interconnected system can be found in the NERC IOS
Reference Document. The Standard should build on this
previous IOS work.
Response: The Resources Subcommittee Frequency Task Force intent for this proposed standard does
not preclude market solutions. Language in the original SAR that referenced markets has been removed
and is not in the revised SAR.
We hope that the previous IOS work and the related MOD standards will provide balancing authorities a
means to obtain frequency response where needed. It is quite possible that NAESB will pick up where
the IOS left off.
MAAC (2)
John Horakh
9
It appears Frequency Response is an accepted term used for
this requirement, and therefore might be difficult to change.
However, Frequency Response is not a very good description of
the requirement. A term such as Transient Generator and Load
Response would be more descriptive.
Response: Transient Generator and Load Response probably is a more descriptive than Frequency
Response. Note that the focus of the proposed standard would be on generator response, not on load
response. . The Resources Subcommittee Frequency Task Force agrees that changing the name from
Frequency Response would likely encounter resistance.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
P. Henderson – IESO (2)
9
We appreciate the opportunity to comment and believe there is a
need for such a standard.
It needs to be recognized that there are two objectives for
governor response, namely, to provide response on an
interconnection wide basis to maintain an acceptable frequency
and secondly to control frequency in island situations. The
former may allow for averaging over an area of the response
Page 30 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
000350
Comment
requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it
should be increasing with load. The main concerns with this
decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely over optimistic and may misstate grid
stability limits.
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
Refer to our earlier comments the structure of the standard
(where lower amounts of BA response trigger an internal
assessment rather than automatic assignment of noncompliance). BAs (and ultimately generators) would only be
initially non-compliant if their response was low AND the BA
failed to perform a reliability assessment in conjunction with its
TOP. Non compliance should be assessed if the BA does not
alleviate the deficiency within a reasonable timeframe. This
default assessment would be at the BA level, but could be on an
area basis (likely islanding area or where a TSP has
responsibility for frequency responsive and black start ancillary
services).
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further
define the standard to meet its needs.
Page 31 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000351
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. A envisioned, the standard will measure response for perhaps a minute to ensure response is not
withdrawn immediately after it is provided.
The proposed standard would not mandate a given amount of response, but would requires an analysis if
response were measurably below the norm. The proposed standard would accommodate the
simplification ideas you propose, and in fact, if data is saved in a common format, the Resources
Subcommittee has a tool that could calculate the BA’s performance to the standard.
The drafting team agrees that performance requirements must be validated by the industry. As you
suggested, a long field test may be needed before justifiable minimum performance standards can be
identified.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
We appreciate the opportunity to comment and believe there is a
need for such a standard. Published studies show frequency
response is declining when it should be increasing with load.
Because there is no process in place to track BA or
Interconnection response, we don’t know whether the decline is
local or global. Primary concerns with this decreasing
performance in primary control:
1. There may be areas unable to withstand severe
disturbances.
2. Following a grid separation or collapse, control areas may
be unable to fulfill their blackstart and restoration
responsibilities, thereby becoming a burden to neighbors.
3. Because engineering models use theoretical frequency
response, they are likely overoptimistic and may misstate
grid stability limits.
Rather than putting in a complicated infrastructure or process,
we would suggest that NERC automate the calculation of
frequency response by either:
•
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
•
Embed the calculation in the NERC ACE-monitoring
application.
The standard will need to acknowledge the large variability in
individual responses at each BA due to coincident load changes
and amount and mix of generation. In addition, smaller
Interconnections likely need greater response.
Refer to our earlier comments the structure of the standard
Page 32 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000352
Comment
(where lower amounts of response trigger an internal
assessment rather than assessment non-compliance). BAs (and
ultimately generators) would only be initially non-compliant if
their response was low AND they failed to perform the reliability
assessment.
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
The standard should not preclude market solutions to providing
frequency response, but such arrangements would need to be
looked at closely to be sure they fulfill reliability needs.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the proposed standard would not mandate a given amount of response, but would
require an analysis if response were measurably below the norm. The proposed standard would
accommodate the simplification ideas you propose, and in fact, if data is saved in a common format, the
Resources Subcommittee has a tool that could calculate the BA’s performance to the standard.
The Resources Subcommittee Frequency Task Force acknowledges the variability inherent in measuring
frequency response. The standard will require capturing sufficient samples to make an objective
measurement. The proposed standard does not preclude market solutions.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. As envisioned, the standard does not mandate a specific amount of
response, but requires analysis if response is markedly below the norm. Analysis may identify the need
for corrective measures and the standard will accommodate the necessary time to make corrections.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
NCPA (4)
Les Pereira
9
Two statements are made in the SAR:
1. The purpose of the proposed SAR is to ensure that
frequency of the Interconnection remains above
underfrequency load shedding setpoints during the
transient period following the sudden loss of generation
on the Interconnection.
2. Furthermore, it is stated that “ In regard to frequency
response, one shortcoming of the recommendations in
policy today is that there is no guidance regarding how
much governor response (in MW) is required at the 5%
droop rate.”
The first is a calculated number and depends not only on the
amount of generation tripped, but also the total generation in the
Whole Interconnection at the time of trip. Obviously two very
different answers will be obtained : one with the Interconnection
intact (normal operation) and the second when islanded. Both
affect reliability.
The second issue has been thoroughly investigated in the
WECC and a new Thermal Governor modeling approach has
Page 33 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000353
Comment
been implemented in the WECC after system tests, an
exhaustive modeling validation effort and obtaining data from the
generator owners. This has been documented in two IEEE
Transaction papers described below. These papers present the
development of a new turbine-governor modeling approach in
WECC that correctly represents thermal units that have
demonstrated unresponsive characteristics such as “base
loaded” units operated with limiters, or partially responsive units
with MW-load-controllers. The May 18th 2001 system trip test for
1250 MW performed with all AGCs off indicated that only about
40% of the governors effectively responded in the real system. If
all the governors were responsive the calculated generation
pickup for governors with a 5% droop for a 0.1 Hz frequency
deviation would be 3185 MW instead of 1250 MW. The new
modeling approach has been extensively validated against
recordings from three WECC system tests and several large
disturbances, and has been approved for use in all operation and
planning studies in the WECC. The second paper describes the
steps being taken to obtain validated data for the new governor
models.
The work done by WECC indicate clearly that we do not get the
required 5% droop from all units as required by NERC. The
modeling approach taken was to model the governors in
planning and operating studies exactly as they are being actually
operated. Enforcement/compliance of the 5% droop is a
separate issue and must be addressed by operating policies.
Obviously, the SAR touches upon only part of the problem, but it
is a good start and should be expanded. It also needs to be
cross-referenced with other areas such as the 5% droop
requirement, an effective spinning reserves policy that actually
works (see the papers), and the effect on ‘governor’ powerflow
and voltage stability analysis as a result of “unresponsive”
governors.
The white paper referred by the SAR only touches upon the
WECC effort and seems to miss the whole point of the modeling
and validation work by the Governor Modeling Task Force in
WECC - and what we have achieved in WECC to address
realistic modeling of unresponsive governors in the real system.
1. "A New Thermal Governor Modeling Approach in the
WECC"
by L. Pereira, J. Undrill, D. Kosterev, D. Davies, S.
Patterson, IEEE Trans. Power Systems, vol. 18,
Issue.2, pp. 819-829, May 2003. (IEEE 2004 prize
paper). Presented at Toronto IEEE PES, July 2003.
2. “New Thermal Governor Model Selection and
Validation in the WECC” by Les Pereira, Dmitry
Page 34 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000354
Comment
Kosterev, Donald Davies, and Shawn Patterson - IEEE
TPWRS – Vol.19, No.1, pp 517-523, February 2004.
Presented at Denver IEEE PES, July 2004.
Response: The Resources Subcommittee Frequency Task Force appreciates the significant work that
has been done in this area by the WECC and has referenced some of this research in the Whitepaper.
We believe the Planning Standards under development (MOD-13 and MOD-27) deal with the detailed
governor issues that you have outlined.
The Resources Subcommittee Frequency Task Force appreciates the importance of the modeling effort
you mention. This standard is not intended to address the modeling issues, but provides the framework
and data needed to support the modeling.
The SAR was modified to include basic governor requirements.
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
9
At this time the FRCC has the highest frequency settings for load
shedding in the Eastern Interconnection (southern part of the
Region). Being a peninsula and out of necessity, the Region has
developed a well coordinated, under-frequency program for
extreme frequency excursions. Ambiguity of the requirements,
uncertainty of measurement and the lack of benefit to the Region
require that the FRCC to oppose this Standard Authorization
Request at this time.
Response: The interconnection measure of response is intended as a benchmark and as a validation of
BAs’ reported performance.
Southern Company
Transmission,
Operations, Planning and
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
We believe that the industry will be exposing the interconnected
electrical systems of North America to a significant degree of
reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be
mitigated somewhat by the turbine governor requirements of
Standard MOD-014-1 from the Phase III/IV Standards SAR, if
passed. However, the risk can be managed properly (and in the
most economical manner) only on an interconnection/balancing
authority basis, not on an individual generator basis as required
by Standard MOD-014-1.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection.
We strongly urge the industry to support this SAR.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York ISO (2)
Mike Calimano
9
We appreciate the opportunity to comment and believe there is a
need for such a standard. Published studies show frequency
response is declining when it should be increasing with load.
The main concerns with this decreasing performance are:
Page 35 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000355
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely overoptimistic and may misstate grid
stability limits.
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
Refer to our earlier comments the structure of the standard
(where lower amounts of BA response trigger an internal
assessment rather than automatic assignment of noncompliance). BAs (and ultimately generators) would only be
initially non-compliant if their response was low AND the BA
failed to perform a reliability assessment in conjunction with its
TOP. This default assessment would be at the BA level, but
could be on an area basis (likely islanding area or where a TSP
has responsibility for frequency responsive and black start
ancillary services).
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further
define the standard to meet its needs.
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Page 36 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000356
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
CHANGE
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to these system events.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. The proposed standard does not mandate a given amount of response, but requires an analysis
if response is measurably below the norm. The proposed standard accommodates the simplification
ideas you propose, and in fact, if data is saved in a common format, the Resources Subcommittee has a
tool that will calculate the BA’s performance to the standard. The Resources Subcommittee Frequency
Task Force has added to the Detailed Description requirements that all balancing authorities shall operate
their AGC function on tie-line frequency bias and that all balancing authorities shall perform frequency
response characteristics surveys when called for by NERC. The Resources Subcommittee Frequency
Task Force agrees with the sub-minute responses comment and has made the change.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. A long field test with extensive data collection may be needed before
justifiable minimum performance standards can be identified.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
As envisioned, the standard will measure the response for up to 60 seconds to ensure initial response is
not withdrawn. The standard will also provide interconnection flexibility.
The phrase noted (starting with , ‘This SAR. . . ’) was removed from the revised SAR.
IESO (2)
Pete Henderson
9
We appreciate the opportunity to comment and believe there is a
need for such a standard.
It needs to be recognized that there are two objectives for
governor response, namely, to provide response on an
interconnection wide basis to maintain an acceptable frequency
and secondly to control frequency in island situations. The
former may allow for averaging over an area of the response
requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it
should be increasing with load. The main concerns with this
decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely over optimistic and may misstate grid
stability limits.
Page 37 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000357
Comment
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments. We
agree that smaller areas need greater response, and this concept will be applied in establishing the initial
target responses for the interconnections (the historic response will bear this out). Under the ERO,
interconnections can also establish stricter targets.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. A long field test with extensive data collection may be needed before
justifiable minimum performance standards can be identified.
As envisioned, the standard will measure the response for up to 60 seconds to ensure initial response is
not withdrawn.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
I personally believe that the industry will be exposing the
interconnected electrical systems of North America to a
significant degree of reliability risk if a Frequency Response
Standard similar to the one proposed by this SAR is not adopted.
This risk can be mitigated somewhat by the turbine governor
requirements of Standard MOD-014-1 from the Phase III/IV
Standards SAR, if passed. However, the risk can be managed
properly (and in the most economical manner) only on an
interconnection/balancing authority basis, not on an individual
generator basis as required by Standard MOD-014-1.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
Page 38 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000358
Comment
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection. I
strongly urge the industry to support this SAR.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System Response
to Generation Governing
First, I make these comments based on work that I've done
principally at American Electric Power Service Corp, before my
retirement from there in November 2000, and as founding Chair
of the IEEE Task Force on Large Interconnected Power System
Response to Generation Governing. These comments are
entirely mine, and reflect no views of either body.
Second. It appears that the final standard will differ from any
single person's opinions. Thus the specific comments below
may not prevail.
Specific Comment 1:
The comment on page 4 of the SAR, "The standard should not
preclude market solutions (e.g. allow purchasing of response as
long as deliverability and restoration criteria can be met).There
must be a means for sale/purchase of frequency response as for
any other quantity." is workable only in near-normal operating
conditions. But it will fail miserably when there is any islanding
condition. An analogy:
Several skydivers agree that reserve parachutes are
a very good idea, but don't want to invest in 1
reserve each. So they agree that they'll buy one to
share among them, so each will be saved by that
spare. This means
that they will hold hands
until they pull their ripcords.
Sounded good, until they tried it, and the first guy to
pull his cord came
unhitched, had a failed main 'chute, and the spare
was on someone else.
Specific Comment 2:
The comment on page 4 of the SAR, "The measurement
selected must be accurate and, to the extent practical, easy to
implement.' may be met in the Eastern Interconnection by the
underway DOE "Eastern Interconnection Phasor Project ' and by
the similar WECC measurement systems, commonly called
"WAMS". Les Peieira's paper, cited in the White Paper, used the
WAMS measurements.
Response: The Resources Subcommittee Frequency Task Force appreciates the comments. The
proposed standard does not preclude market solutions. The SAR’s intent is to define the proposed
standard’s scope, the actual detail that you recommend will be developed during the standard drafting
phase. The phasor projects in both the Eastern and Western Interconnections may indeed be a source of
accurate and time stamped frequency data for this standard’s application.
Page 39 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000359
Frequency Response SAR – Comment Report
Commenter
Southern Co. Generation
(6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
Yes
9
No
Comment
It is believed that the industry will be exposing the interconnected
electrical systems of North America to a significant degree of
reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be
mitigated somewhat by the turbine governor requirements of
Standard MOD-014-1 from the Phase III/IV Standards SAR, if
passed. However, the risk can be managed properly (and in the
most economical manner) on an interconnection/Balancing
Authority basis, not on an individual generator basis as required
by Standard MOD-014-1.
The governor response in MW for generators is not just
dependent on the governor droop and dead-band settings, but
on the design of the plant control system (sliding pressure boiler,
nuclear pressurized water reactor, etc.). For example, nuclear
plant operators must control reactivity changes in the core and
generally cannot allow external controls to increase or decrease
power levels on demand. This standard should take such factors
into account and address frequency & MW response at the
Balancing Authority level, not at the individual generator level.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection.
We support this SAR.
Response: The Resources Subcommittee Frequency Task Force appreciates and supports your
comments. As envisioned, the standard will measure response at the Interconnection and Balancing
Authority level. Only when a Balancing Authority’s response measurably below the norm is additional
analysis involved.
MISO
Terry Bilke
9
Thanks for the opportunity to comment. I hope the SAC puts all
comments in perspective. We are in a period where the industry
is reluctant to adopt new standards that generate extra work and
compliance exposure. The reliability of the Interconnections can
benefit with minimal impact to most BAs with a light-handed
standard.
Rather than implementing a complicated process, why not
embed most of the effort in the NERC ACE-monitoring
application? Only those BAs with unusually low response would
need to drill down and do an internal assessment to determine
their ability to withstand disturbances and whether they have
responsive resources for blackstart.
Knowing where and when performance is substandard will likely
arrest the decline in performance. Minimum performance
standards could be implemented once the industry has identified
Page 40 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
000360
Comment
what is reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York State
Reliability Council (2)
Theodore Pappas
9
The Standard should define the term “event” in terms of time and
frequency deviation. The frequency deviation the event must fall
outside the droop deadband.
Response: Response: The Resources Subcommittee Frequency Task Force agrees that there should
be clear criteria set for identifying events that will be used in calculating frequency response. The SAR
was revised to indicate that the standard will require governors to provide droop characteristics within a
specified range (to be determined during standard drafting). At this point, the Resources Subcommittee
Frequency Task Force recommends each interconnection set a target excursion size that is used for
selection of samples and recommends that the target be at least equal to the traditional 36 mHz
deadband.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
TXU Energy Delivery
Roy Boyer
9
Robert Blohm
9
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA
(1)
9
ATC (1)
Peter Burke
9
Southern Company
Transmission,
Operations, Planning and
Page 41 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000361
Frequency Response SAR – Comment Report
Commenter
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
Yes
No
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
Alliant Energy (1)
Kenneth A. Goldsmith
9
We Energies (3, 4, 5)
Howard Rulf
9
Comment
Page 42 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000362
Consideration of Comments on Second Draft of Frequency Response SAR
Background:
The Frequency Response SAR Drafting Team thanks all commenters who submitted comments on the
first draft of the SAR for Frequency Response. This SAR was posted for a 30-day public comment period
from April 4, 2006–May 3, 2006. The SAR DT asked stakeholders to provide feedback on the SAR
through a special SAR Comment Form. There were 16 sets of comments, including comments from more
than 59 different people from more than 41 companies representing 6 of the 9 Industry Segments as
shown in the table on the following pages.
The primary changes to the SAR were made based on comments:
• Clarification on the role of the LSE and Generator Operator.
• Inclusion of the applicability of Reliability Principles 3, 5 and 6.
• Reduced the scope to address only the collection of data needed to model Frequency Response in
North America.
In this ‘Consideration of Comments’ document stakeholder comments have been organized so that it is
easier to see the responses associated with each question. All comments received on the SAR can be
viewed in their original format at:
http://www.nerc.com/~filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Adamski at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Update:
The original SAR on Frequency Response was submitted in large part due to a study that showed a 10+%
decline in Eastern Interconnection Frequency Response over a 5 year period, when response should be
increasing over time as an Interconnection grows. The drafting team posted a whitepaper along with the
SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern Interconnection
Frequency Response and found it to be on the order of 2800MW/0.1Hz and still trending downward.
1
The appeals process is in the Reliability Standards Process Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
January 9, 2007
Page 1 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000363
Consideration of Comments on Second Draft of Frequency Response SAR
Figure 1 Original Eastern Interconnection Frequency Response Study (Ingleson and Nagle)
Figure 2 Updated Eastern Interconnection Frequency Response (NERC Resources Subcommittee)
Based on these observations, at its June, 2006 meeting, the NERC Operating Committee
endorsed developing a frequency response standard that includes the following goals and
objectives:
- Improving Interconnection frequency response event cataloging and benchmarking
- Calculating balancing authority frequency response and requiring balancing
authorities to analyze those cases where the response is significantly below the norm
- Establishing time limits to complete the analyses
January 9, 2007
Page 2 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000364
Consideration of Comments on Second Draft of Frequency Response SAR
- Tabulating non-responsive generators
- Measuring generator response (including those units on line)
- Including regional participation and review
Unfortunately, the stakeholders who responded to the second draft of the proposed SAR offered
a wide range of opinions on what should be in the standard, without a clear consensus. Given
this, the drafting team revised the SAR to only require collection of data needed to model
frequency response in each of the interconnections. Once frequency response has been modeled
and analyzed, the Resources Subcommittee and the industry will be in a better position to
recommend specific frequency response targets for each Interconnection.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006.
January 9, 2007
Page 3 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000365
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
6
Ken Goldsmith
ALT
Baj Agrawal
APS
x
Bert Peters
APS
x
Dave Rudolph
BEPC
Bart McManus
BPA
x
x
x
x
John Anasis
BPA
x
x
x
x
Lynn Aspaas
BPA
x
x
x
x
Mike Viles
BPA
x
x
x
x
Greg Tillitson
CMRC
Edwin Thompson
ConEdison
Rhett Trease
Duke (NERC RS)
Tom Pruitt
Duke Energy Carolinas
x
x
x
x
Jeffrey T. Baker
Duke Energy Midwest
x
x
x
x
Howard Illian
Energy Mark, Inc.
Dick Pursley
GRE
David Kiguel
Hydro One Network
x
Anita Lee
IESO
x
Ron Falsetti
IESO (Ontario)
x
Kathleen Goodman
ISO-New England
x
Bill Shemley
ISO-New England
x
Jim Cyrulewski
ITC Transmission
Dennis Florom
LES
x
Donald Nelson
MA Dept of Energy and Tele.
x
Tom Mielnik
MEC
x
Robert Coish
MHEB
x
Terry Bilke
MISO
x
Pete Lebro
National Grid
Sydney Niemeyer
NRG Texas LP (NERC RS)
Alden Briggs
NBSO
Greg Campoli
New York ISO
x
James W. Ingleson
New York ISO
x
Alan Adamson
New York State Rel. Council
x
Don Badley
NWPP (NERC RS)
Brian Hogue
NPCC
x
Guy Zito
NPCC
x
Alan Boesch
NPPD
Murale Gopinathan
NU
January 9, 2007
7
8
9
x
x
x
x
x
x
x
x
x
Page 4 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000366
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
Mark Kuras
PJM
x
Joe Willson
PJM
x
Al DiCaprio
PJM
x
Robert Johnson
PSC
Rich Cornelius
RDRC
Wayne Guttormson
SaskPower
x
Tom Botello
SCE
x
Jim Busbin
Southern Company Services
x
Jim Viikinsalo
Southern Company Services
x
Marc M. Butts
Southern Company Services
x
Raymond Vice
Southern Company Services
x
Roman Carter
Southern Company Services
x
J.T. Wood
Southern Company Services
x
Wayne Guttormson
SPC
John Tolo
TEP (NERC RS)
Roger Champagne
TransEnergie (Quebec)
x
Bruce Sembeck
Tri-State Generation and
Transmission Association, Inc.
x
Nancy Bellows
WACM
x
Darrick Moe
WAPA
Terry Baker
WECC Reliability Coordination
Subc.
x
Jim Maenner
WPS
x
Pam Oreschnick
XEL
x
January 9, 2007
3
4
5
6
7
8
9
x
x
x
Page 5 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000367
Consideration of Comments on Second Draft of Frequency Response SAR
Index to Questions, Comments and Responses
1.
Do you agree that comments from the first posting of the SAR were adequately addressed? .......... 7
2.
Do you agree with the list of proposed requirements included in the detailed description of the
revised SAR?..................................................................................................................................... 12
3.
Do you agree that the proposed standard(s) would be applicable to the Reliability Coordinator,
Balancing Authority, Generator Owner, and Load-serving Entity? ................................................... 22
4.
The current standard on Bias requires a Balancing Authority to carry a minimum bias equal to 1% of
peak load. As an example, in the Eastern Interconnection, this value is double current natural
frequency response. Should the standard provide an incentive, such that a Balancing Authority can
use a bias equal to their natural response, but less than 1% of peak, if the response is above an
acceptable target? ............................................................................................................................. 25
5.
Several commenters suggested response should be measured for an extended period after a
frequency excursion, up to the point where automatic generation control (AGC) would take over.
This was to ensure initial response wasn’t withdrawn prematurely. Should the standard measure
out to 60 seconds following an excursion?........................................................................................ 28
6.
Do you have other comments on the SAR? ......................................................................................32
January 9, 2007
Page 6 of 34
1. Do you agree that comments from the first posting of the SAR were adequately addressed?
Summary Consideration: Most commenters indicated that the SAR drafting team did provide an adequate response to the comments
submitted with the first posting of the SAR.
Commenter
Energy Mark, Inc. (8)
Howard F. Illian
Yes
No
Comment
9
There is an expectation apparent in the first set of responses that indicates that the drafting
team believes they have more knowledge of the solutions that will be required than the final
standard will contain. The two greatest areas of insufficient understanding lie in the
measurement of Frequency Response at less than the full interconnection level and the effect of
the standard as envisioned on markets. These two problems are addressed in the comments to
later questions in this comment form.
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response in each of the interconnections. Once that data is collected and analyzed,
a standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
NPCC CP9 Reliability Standards
Working Group
K. Goodman – ISONE
Edwin Thompson – ConEd
Pete Lebro – Ngrid
Alan Adamson – NYSRC
Bill Shemley – ISONE
Ron Falsetti – IESO
Murale Gopinathan – NU
Ralph Rufrano – NYPA
R. Champagne – TransÉnergie
David Kiguel – Hydro One
Greg Campoli – NYISO
Jim Ingleson – NYISO
Alden Briggs – NBSO
Don Nelson – MA Dept. of Tel.
and Energy
Brian Hogue – NPCC
Guy Vito – NPCC
January 9, 2007
9
No - The intent of this SAR is unclear which highlights that this issue requires additional studies
and investigation. In the future, it may be beneficial to develop a standard after a reliabliity
issue is identified, and a specific standard can be developed and implemented to address the
issue.
Page 7 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000368
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: We agree that there needs to be additional studies and investigation. There were varying opinions on the scope of the second draft
of the SAR. The drafting team revised the scope of the SAR again to focus solely on collection of data needed to model frequency response in
each of the interconnections. Once that data is collected and analyzed, a standard can be proposed that includes performance requirements that
will motivate entities to operate in ways that keep frequency response within an acceptable range.
9
PJM Corporate Development
Div. (2)
Al DiCaprio
Joseph D. Willson
Mark Kuras
The Resources Subcommittee in a response to the first draft states "A primary purpose of this
standard is to collect information so informed decisions can be made before there is a problem."
It is clear from that reply that the Resources Subcommittee wishes to undertake an analysis of
the system and needs to collect additional information. This data collection effort may be
laudable but it does not rise to the level of being a federally enforced mandatory standard. What
if later on the 'data' were to show there is no problem, then there will be a need to rescind the
standard and repay those who were non-compliant to a data collection effort.
In their response to the first draft, the Resources Subcommittee cite a WECC study. But they
have no similar study for the East. The Resources Subcommittee still has not shown that the
decrease in sub-minute response is either (1) a problem or (2) nothing more than an indication
that a larger system has more inertia and therefore less response that the smaller system in the
past.
This SAR, with its present theoretical focus, posits the BA as the responsible entity for governor
response. Even those who agreed with the first posting that Frequency Response is an
important issue - stated that a standard cannot define fixed norms (MRO, NYISO, IESO (2) ).
The BA is not responsible to instantaneous response -at best it can establish a capacity
obligation but it can't guarantee continuous response.
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response in each of the interconnections. Once that data is collected and analyzed,
a standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
IESO (2)
Ron Falsetti
January 9, 2007
9
9
Yes, with respect to the responses to the IESO's comments. However, the revised SAR appears
to get somewhat mixed up between sub-minute frequency response performance with a longer
term (> 1 minute) performance, and lacks clarity on what the proposed standard is intended to
stipulate.
Is the proposed standard intended to stipulate:
(a) a minimum frequency response performance level with which to determine if follow-up
analysis is to be conducted, or,
(b) requirements for calculating, measuring, reporting and analyzing frequency response, or,
(c) both, in addition to,
(d) requirements for generators to be equipped with governors and if so, the target to be
responding to?
Page 8 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000369
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
If (a) is not specified in the standard, we see a difficulty in stipulating the threshold for (b) and
the target for (d).
From the SDT's response to our previous comments ("The new requirements may need to be
field tested for an extended duration before compliance with the requirements becomes
mandatory. A long field test with extensive data collection may be needed before justifiable
minimum performance standards can be identified"). It is our belief the standard is intended to
stipulate (b) only. We see this as a necessary first step. However, it may then beg the question
of the need of having a standard to develop the basis for a future standard. Might there not be
other alternatives to achieve (b) such as by means of a request from the standing committees or
NERC to the BAs and the regions to compile this information?
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response within each interconnection. Once that data is collected and analyzed, a
standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
BPA (1, 3, 5, 6)
Bart McManus
John Anasis
Lynn Aspaas
Mike Viles
9
We are still concerned with a NERC standard countering some aspects of the standard we are
in the process of drafting in WECC, so will continue to be active on the drafting team to insure it
does not adversely impact the WECC standard.
Response: We encourage WECC to be actively involved in the drafting of the standard. Note that the drafting team revised the scope of the
SAR so that the SAR focuses solely on the collection of data needed to model frequency response in each interconnection. This should not
conflict with WECC’s work on its frequency response standard.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
9
ATC LLC (1)
Jason Shaver
9
NERC Resources Subcommittee
Raymond Vice – SOCO
John Tolo – TEP
Rhett Trease – Duke
Sydney Niemeyer – Texas
9
January 9, 2007
Page 9 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000370
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Don Badley – NWPP
Carlos Martinez – CERTS
Robert Rhodes – SPP
Tom Vandervort – NERC
Terry Bilke – MISO
Bill Herbsleb – PJM
Larry Akens – TVA
Bart MaManus – BPA
Mike Pitishnak – ISONE
Gerry Beckerle – Ameren
Yes
IESO (1)
Anita Lee
9
Midwest Reliability Organization
(2)
Terry Bilke
Wayne Guttormson
Jim Maenner
Al Boesch – NPPD (2)
Terry Bilke – MISO (2)
Bob Coish – MHEB (2)
Dennis Florom – LES (2)
Ken Goldsmith – ALT (2)
Todd Gosnell – OPPD (2)
W. Guttormson – SPC (2)
Tom Mielnik – MEC (2)
Darrick Moe – WAPA (2)
P. Oreschnick – XEL (2)
Dick Pursley – GRE (2)
Dave Rudolph – BEPC (2)
Joe Knight – MRO (2)
9
Southern Company Transm. (1)
Marc Butts
9
January 9, 2007
No
Comment
Page 10 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000371
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Raymond Vice
Jim Busbin
Roman Carter
J.T. Wood
Jim Viikinsalo
Yes
Southern Company Transm. (1)
Marc Butts
Raymond Vice
Jim Busbin
Roman Carter
J.T. Wood
Jim Viikinsalo
9
January 9, 2007
No
Comment
Page 11 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000372
Consideration of Comments on Second Draft of Frequency Response SAR
2. Do you agree with the list of proposed requirements included in the detailed description of the revised SAR?
Summary Consideration: Most commenters disagreed with the proposed requirements included in the second draft of the SAR. The drafting
team revised the SAR to focus solely on the collection of data needed to model frequency response in each interconnection. Additional SARs may
be proposed in the future to propose requirements for operating in ways that support frequency response.
Commenter
Yes
No
Comment
The requirements on individual generator are unnecessary. The requirements should be on a
group of generators in a control area to achieve a desired response. Thus, one could have
some generators which are being operated as non responsive and the others which are
responding well to offset for those which are not responsive.
Additionally, the 10 MW size requirements are too restrictive and unnecessary. It should be
plant based and should apply to plants of 100 MW or more aggregate capacity. In any
realistic scenario, the smaller plants are not expected to contribute much to frequency
response and hence subjecting them to frequency response requirements is uneconomic.
Arizona Public Service Co. (1, 5)
Baj Agrawal
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional SARs may be proposed with specific performance requirements for generators.
IESO(1)
Anita Lee
9
The purpose is definitely suggested for under frequency conditions. However, when
specifying that the generators shall have governors with droop etc... the role of the governor
is for both high and low frequency conditions and not just underfrequency FRR. In a market
environment it is very possible that not every generator will provide FRR services. Thus, the
governor and governor deadband should be a requirement to interconnect to a power
system. Generators that provide FRR shall have responsive governor and prime mover.
The standard is based on balancing area response which will include generators and in some
jurisdications will include load. So is the intent that whatever load is considered, additional
FRR resources such as generators are used to provide the required FRR?
What about load as FRR providers? Some industrial facilities are capable to dynamically vary
the load of the facility to frequency (ie virtual governor). The standard should apply to FRR
providers which can be generators and loads.
We agree that generator owners have an obligation to have working governors or provide
explanations why not. The "10 MW" requirement should be evaluated for consistency with
other standards. This should not hold up the progress of the SAR, but should be evaluated
by the ultimate standard drafting team.
Response: The SAR drafting team agrees that governors must work for both high and low frequency events. One methodology under
discussion would monitor both high and low events. The logic behind capturing low frequency (typically associated with trips of large
generators) is that these events are much more common than large loss of load.
January 9, 2007
Page 12 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000373
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Any resource (load or generation) within the BA can provide frequency response. As envisioned, the standard would have provided a
methodology whereby a BA could monitor its FRR providers. Load, by default, would have been measured along with generators when the BA
calculated its performance.
We agree that all generators may not need to provide frequency response. As envisioned, as long as the BA had adequate response, it would
have had some flexibility under the proposed standard. Note, however, that the SAR has been revised and no longer includes these
performance requirements. The SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional SARs may be proposed with specific performance requirements
for generators.
As each new standard is developed, greater attention will be paid on the ‘applicability’. The threshold of ’10 MW’ will need to be reviewed from
a reliability-related perspective rather than ‘consistency across all standards’ perspective.
IESO (2)
Ron Falsetti
9
The intent of some of the requirements is again unclear to the IESO, for example.
(i) Does Bullet #2 mean the flexibility in the calculation and reporting process or in the
target/minimum frequency response level?
(ii) Assuming Bullet #4 a requirement, and one which relates to the minimum level of
frequency response, how is this requirement stipulated at this time while data collection and
follow-up analysis are to be proposed as standard requirements and field testing has yet to
commence? Same comment applies to Bullet #9.
(iii) Bullet #6 appears to go beyond the sub-minute time frame. Further, we are unable to
understand the leading sentence "Will not mandate a given amount of frequency response".
We feel it is important that if poor frequency response performance in the sub-minute time
frame is to be assessed and improved, specific target which may well be the minimum
amount of frequency recovery would need to be stipulated.
(iv) Bullet #7 also appears to be beyond the sub-minute time frame, which is to mandate
AGC but which should be covered by other BAL standards.
(v) Bullets #8 and #1 appear to be the main requirements for the proposed standard that are
achievable at this time.
(vi) As mentioned in (ii) above, we are unable to visualize how the range and target of
response be stipulated in the standard before Bullets #1 and #8 are implemented.
(v) If generators are allowed to seek exception, the standard should provide some basic
premise that bounds the exception cases rather than leaving the door wide open and the
decision solely to the judgment of the BAs and RROs.
Response: ”Flexibility to meet the needs of each Interconnection” was intended to mean some flexibility in calculation (for example ERCOT is
interested in “point C” (the extreme) of an event, but this point is not observable and has little value in the East. The WECC has expressed
January 9, 2007
Page 13 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000374
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
concern for extended contribution of response (perhaps out several minutes). As envisioned, there would have been different target levels in
each Interconnection. Interconnections would have been able to choose to have a tighter target droop setting.
Bullet 4 relates to a statistically-sound measurement of frequency response at both the Interconnection and BA level. The data would have
been collected and reported each year of the standard. In effect, the data collection in the first year of the standard would have served as the
field test.
“Long term target measure” intended to imply that the BA would be measured on many events over the year and its performance would have
been evaluated on the whole, not on single events.
It is true operation of AGC goes beyond the sub-minute window of time. The intent of this bullet was that the bias a BA provides should match
its natural frequency response. Just as was originally intended in Policy 1, a BA calculates its natural response in one year and uses those
observations to operate in the next year. The drafting team envisioned the same would occur in the originally proposed standard. The
establishment of the “12 month basis” either on a calendar year or on a rolling 12 month period like CPS1 would have been determined during
standard drafting.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional SARs may be proposed with specific performance requirements
for generators.
NPCC CP9 Reliability Standards
Working Group
January 9, 2007
9
The proposed requirements nor the White Paper adequately make the case that there is a
need for a frequency response standard at this time. However, it is recommended that the
subject be further investigated. The analysis should evaulate if a frequency response
standard that addresses the three major short term frequency control components (inertial
response, governor response, and automatic generation control) are required. The report
writers should include a broad range of participants including (at least) 3 OEM's (original
equipment manufacturers) representing steam, gas and hydro generation control. Some
specific issues that should be addressed are:
1. Inertial Response: Evaluate historical changes in the inertial response of the electric grid
as a result of changing power equipment designs and types of load. For example, the
addition of new industrial and aero-derivative turbine-generators have lower inertia-power
ratios than tranditonal nuclear/fossil units and, in addition, they are not base loaded (as a
result of more efficient dispatching and improved power plant controls).
2. Governor Response: Evaulate generation governor performance as a result of newer,
more configurable prime mover controls. Digital controls provide increased plant reliability,
however, this may be at the expense of decreased governor response. For example, the use
of main steam pressure controls on steam units and low NOx controls on gas turbines may
Page 14 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000375
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
produce unexpected droop output responses.
3. Automatic Generation Control (AGC): Perform a control area survey to determine if there
is sufficient regulation capacity within control areas to maintain generation and load balance.
Include a review of incentives and penalties for generators to respond accurately and reliably
to AGC signals.
Response:
When the first draft of the SAR was posted for comment, the drafting team asked stakeholders if they felt that there was a reliability-related
need for a standard that focuses on frequency response, and most stakeholders indicated there is a reliability-related need for a frequency
response standard.
While we don’t know the exact amount of frequency response needed for each interconnection, a 12 year decline in response when it is
expected to be increasing and without knowledge of where the response is low is a reliability concern.
Failure of generators to follow AGC signals would appear to be either a CPS issue or a business practice.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
Energy Mark, Inc. (8)
Howard F. Illian
9
Requirements that apply to individual generators cannot be implemented as indicated in the
standard without failing to comply with Market Interface Principle 2. Frequency Response
(Governor Response) have economic costs associated with standing ready to supply. These
costs have been documented in EPRI Reports on Ancillary Services. If any generator is
given an exception to not provide a response, that generator will also be given a market
advantage resulting from the savings they will receive by not providing a response. The SAR
as currently written will create a market advantage for all generators below 10 MW and all
generators that are given an exception to the governor response requirement. The
alternatives to these generator requirements are either not have a competitive market and
decide the provision of frequency response administratively (the old VIU method), or
determine who provides frequency response through a competitive market process.
Response: We appreciate the comments on Market Interface Principle 2. As envisioned the original SAR proposed measuring the
approximately 140 Balancing Authorities rather than the roughly 4000 individual generators (NERC 2004 Generating Unit Statistical Brochure).
The SAR intended to be indifferent to what entity provides response (whether load, large generator or small generator). It was intended to
measure the BA, with the expectation that the BA would have had to document exceptions that would have been reviewed by the BA and the
Region for reliability implications. As envisioned, the drafting team did not expect owners to install many small generators rather than one
larger generator to avoid providing data for the standard.
January 9, 2007
Page 15 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000376
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Note that the SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once
more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
9
Not totally, I need to understand more of what would be required to meet the obligation of
Generator owners to equip generating units with nameplate ratings of 10 MW or greater, with
a governor capable of providing immediate and sustained response to frequency deviations.
Response: As envisioned, all generators would have governors that respond to frequency deviations. The BA and the Region would need to
be aware of exceptions for study purposes. If the BA’s performance were significantly below the norm, an analysis and assessment would
have been required.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators.
BPA (1, 3, 5, 6)
January 9, 2007
9
RE: bullet 2: Instead of flexibility to meet interconnection needs, each interconnection should
have its own requirements on frequency response, this is due to the unique frequency
response of each interconnection.
re bullet 4: This Standard will need to measure frequency response for the duration of the
frequency deviation. Measuring it until frequency recovers will overlap with the Balance
Resources and Demand standard slightly, but will give much better results than simply going
out a few minutes.
re bullet 6: Target levels should be BA specific to insure there is not an incentive to lean on
other BA's. How will the target levels be calculated?
Re bullet 7: BAs must be free to operate their automatic generation control in any method
they desire. The tie-line frequency bias is used for compliance monitoring, but must not be a
requirement for the actual automatic generation control algorithm. Recommend this be
modified to state: Balancing Authorities will calculate an Area Control Error for monitoring
purposes using tie-line frequency bias.
re bullet 8: WECC should call FRC surveys for WECC instead of NERC.
re bullet 9: Recommend generating unit nameplate of 10 MW plus multi-unit installations of
10 MW or greater be required to have a governor(s) capable of providing immediate and
sustained response to frequency deviations.
Re bullets 9 and 10: Currently wind generation does not have governor response capability.
Due to the amount of wind integration planned in the next decade, new installations should
have a requirement for frequency responsive units. Historically, requirements have provided
incentive for manufacturers to modify machine design (low-voltage ride-through capability,
voltage control capability) to meet the requirements.
Page 16 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000377
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: We agree – the proposed standard would have assumed that each interconnection had a unique frequency response.
Regarding bullet 4, some thought would have to be given on how to measure over the entire duration of a frequency disturbance (typically up to
15 minutes for a DCS event) and how to remove AGC response from the estimate of frequency response. Suggestions are welcome.
However, the Interconnection would be able to define specific requirements.
Regarding bullet 8, WECC has the right to call FRC Surveys for WECC, as does NERC (historically through the NERC OC and Resources
subcommittee)
We agree with your comment regarding bullet 9.
Regarding wind generation, governor response is normally provided by calling on more energy from the prime mover when frequency drops.
We are unsure how this would normally be done with wind, unless the goal would be to under-utilize the wind during normal operation and then
call for full available energy when the frequency drops. Again, this standard as originally proposed, was intended to measure BA response- as
long as the pool of generation within the BA provided adequate response, it would have allowed the BA flexibility on which generators provide
that response.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators. This will allow analyses to focus on the different types of response and should, eventually, facilitate the
development of another standard that includes performance requirements aimed at providing a specified amount of frequency response.
ATC LLC (1)
Jason Shaver
January 9, 2007
9
The SAR identifies Load-Serving Entities as a function that will be affected by any
requirements that are developed from this SAR. Question three, on this comment form, goes
one step further and asked the industry if the proposed standard would be applicable to
Load-Serving Entities. ATC was unable to determine from the detailed description section
any requirements that would apply to a Load-Serving Entity. With that being said ATC
suggests that language be added to the SAR that would require the Load-Serving Entities to
be responsible for procurement of adequate frequency response.
ATC found bullet number six lacks a clear description of the standard that could be
developed. ATC recommends that this bullet be rewritten to better inform the industry of the
type of standard the SAR requestor wants developed. Is the SAR requestor requesting a
standard that will not mandate frequency response, but instead recommend a frequency
response? ATC, in general, feels that standards should require something not make
recommendation. or, Is the SAR requestor requesting that a standard be develop that would
set long-term Interconnection target levels and then require the industry to meet those targetlevels? ATC is in support of a standard that would require entities to set long-term target
levels and require other entities to meet the determined target levels. ATC is not in support
Page 17 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000378
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
of a standard that requires functions to set long-term target levels but not require other
entities to meet those levels. Lastly, this bullet should clearly identify who are the
responsible entities.
ATC is concerned that Generator Owners could be allowed to categories the same
generating units differently. A Generator Owner that aggregates their units for purposes of
determining a voltage schedule (VAR-001-1) should then not be allowed to individualize their
units for this standard to escape under the nameplate rating of 10 MW.
Response: We agree that the LSE is the ultimate beneficiary of frequency response. However, since the standard isn’t mandating a particular
amount of frequency response for individual events, it would seem inappropriate to have the LSE obtain a given amount of frequency response
for any specific event.
As originally proposed, this standard would have been primarily a technical/preparedness standard. Initially, the target levels of frequency
response would have been based on observed interconnection history.
We agree that bullet # 6 needs additional clarification for it to be understood. The long-term measure was envisioned to be an annual metric,
based on a calendar year or on a rolling 12 month basis like CPS1 that captures many events over the year to come up with a composite
estimate of performance. It was expected that the standard would allow interconnections to set their own frequency response limits. Absent
specific frequency response bounds for an interconnection, the standard would have used recent history. The standard was intended to focus
on the frequency response needs of each interconnection, and would have allocated a portion of each interconnection’s frequency response
responsibility to each of the interconnection’s Balancing Authorities.
Note that the SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once
more is known about frequency response, additional standards may be proposed with specific performance requirements for generators. This
will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
PJM Corporate Development Div.
(2)
January 9, 2007
9
The SAR is still not clear about what is to be developed in the standard. Of the ten bulleted
items several seem to show a misunderstanding between a sub-minute frequency response
obligation and Automatic Generation control. The RS must make clear what it wants to do.
Sub-minute frequency response occurs with or without frequency bias; sub-minute frequency
response is not helped or hurt by having AGC. This is a major problem with the proposal. It is
not clear and it is not definitive.
Item 1 indicates the standard will be a Report
Item 2 states the standard will be flexible (that is mandated in the Process Manual)
Item 3 seems to indicate that non-compliance will be met with a requirement to analyze the
incident (if this is standard is so important why isn't every event critical?)
Item 5 is the most unusual - the standard will not mandate a response but will provide
Page 18 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000379
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
"LONG-TERM" targets (how is it that a sub-minute response gets translated into a long-term
target?)
Item 6 is to mandate AGC. This is not related to sub-minute frequency response.
Item 7 is to mandate a post-incident survey. Again this is a good idea but it a data collection
mandate - it is not a frequency response standard. The RS has the tools to collect that
information today, without the need to resort to mandatory penalties.
Item 10 will allow generators to seek exceptions (which means that the RS will allow a
generator to opt out and still require the BA to comply. In the absurd case that all generators
opt out (let's say the BA has only nuclear units) then according to the RS, the BA is held noncompliant. This is just not a good idea.
In summary: #1 is a calculation and report on response but no measure of performance; #3
requires a BA and the RRO to perform an analysis if response is measurable (by what
amount) below the norm (which is a constantly moving value); #4 is the only possibility for
true standard; #9 generators must have governors is more a certification issue than a BA
standard. Three of the bullets are not requirements (#2, #5, and #10). Two of the bullets are
already in other standards while two of the bullets duplicate each other. The SAR team needs
to better describe exactly what is being proposed to be in the standard so that the industry
can evaluate the proposal. The industry does not need to get involved in a research project.
Response: The standard was intended to measure response within the first minute (or longer if determined it was needed by the
interconnection) following a frequency disturbance (which is prior to the timeframe when AGC contributes to frequency stabilization). Since
natural frequency response is much less than Bias for most control areas, AGC will make a contribution to frequency stabilization over a period
of time.
Regarding item 1, part of this technical/readiness standard was envisioned as a report, much as BAs are responsible to calculate and report
CPS or DCS. Refer to the NERC Reliability Standards Process Manual for the different types of standards.
Regarding item 2, thank you.
Regarding item 3, the standard would not have required analysis of single events, but rather performance over a 12-month period.
Regarding item 5, as envisioned, the BA would have calculated its response based on several events over the long term (12 months).
Interconnection performance is tracked by the Regions and NERC over years.
Item 6 refers to using a bias in AGC that is reflective of the BA’s natural frequency response. However, based on comments, the Resources
Subcommittee agrees this requirement more appropriately belongs in the AGC standard.
January 9, 2007
Page 19 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000380
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
Regarding item 10, the SAR was not proposing that generators may opt out of participation. As envisioned, generators were expected to have
governors that respond to frequency. Exceptions would have been documented. Nevertheless, the standard would have measured overall
BA response.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators. This will allow analyses to focus on the different types of response and should, eventually, facilitate the
development of another standard that includes performance requirements aimed at providing a specified amount of frequency response.
Duke Energy Carolinas (1, 3, 5,
6)
Tom Pruitt
9
9
Generally, yes, but more clarity is desired on a number of points, e.g., who decides which
generators will be granted exemptions - the BA or the RRO; who sets the criteria - BA or
RRO. In addition, I think some of the proposed requirements may conflict with each other as
details are driven out; if a number of a BA's generators applied for and were granted
exemptions from governor response, the (anticipated) 5% droop range may need to be
adjusted for the generators which do provide governor response for the BA.
Governor response is not the only equipment consideration at the plant/unit. Plant/unit control
systems also should be operated so that the desired unit response will occur and be
sustained.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
This will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
NERC Resources Subcommittee
9
Re Bullet 7 - BAs must be free to operate their automatic generation control in any method
they desire. The tie-line frequeency bias is used for complinace monitoring, but should not
be a requirement for the actual automatic generation algorithm. Recommend this be
modified to state : Balancing authorities will calculate an Area Control Error for compliance
reporting purposes using tie-line frequency bias.
Response: Based on comments, the Resources Subcommittee recommends this requirement more appropriately belongs in the AGC
standard.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
ITC Transmission (1)
Jim Cyrulewski
January 9, 2007
9
However some bullets need further clarification
Bullet 2: The standards process allows for regional differences. What more flexibility is
needed?
Page 20 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000381
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Beth Howell
Mike Moltane
Van Greening
Yes
No
Comment
Bullet 6: Keep this bullet simple by simply stating target levels will be set for BAs and RROs
to take actions cited. Also a sub-bullet needs to be added on what are options to get
additional frequency response; specifically for the BAs. In particular what can the BAs do if
the Generation Owners do not provide adequate response. The BAs don't have generation
interconnection agreements, the transmission owners do.
Response: As originally envisioned, the primary differences would have been at the Interconnection level. For example, it was envisioned that
there might be more than one authorized method that could be used by a BA to calculate response.
We agree that transmission owners have interconnection agreements that provide leverage to get generators to perform through “good utility
practices” provisions.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
Midwest Reliability Organization
(2)
9
In particular we agree that generator owners have an obligation to have working governors or
provide explanations why not. The 10 MW requirement should be evaluated for consistency
with other standards. This should not hold up the progress of the SAR, but should be
evaluated by the ultimate standard drafting team.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
This will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
With respect to the 10 MW threshold - As each new standard is developed, greater attention will be paid on the ‘applicability’. The threshold of
’10 MW’ will need to be reviewed from a reliability-related perspective rather than ‘consistency across all standards’ perspective.
Southern Company Transm. (1)
January 9, 2007
9
Page 21 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000382
Consideration of Comments on Second Draft of Frequency Response SAR
3. Do you agree that the proposed standard(s) would be applicable to the Reliability Coordinator, Balancing Authority,
Generator Owner, and Load-serving Entity?
Summary Consideration: Although most commenters agreed with the proposed applicability, the drafting team has reduced the scope of the
proposed standard, and the proposed applicability has been changed. The revised SAR shows that, in addition to the functional entities listed
above, the Generator Operator may have some requirements in the proposed standard.
Commenter
Yes
No
9
Tri-State G&T (1)
Bruce Sembeck
Comment
Since the standard is concerned with governor regulated frequency response of generating
units that applicability should also apply to the Generator Operator (currently this box is not
checked). It will ultimately be the Generator Operators responsibility to ensure frequency
responsiveness of the units, e.g. ensuring that the unit is not operating in Valve Wide Open
mode.
Response: Note that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection.
We will include generator operator as an applicable entity.
9
PJM Corporate Development
Div. (2)
This question would require an assumption of what the standard would be. If the standard is to
provide sub-minute frequency response, then the only entity should be the generator owner.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
9
IESO. (2)
Ron Falsetti
Not having a good handle on what the standard is intended to achieve and stipulate, we are
unable to comment on whom the standard should apply to. Among the ones included in the
question, we are unclear on the role of the RC in requiring anyone to install devices or take
actions to improve frequency response in day to day operation.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
We expect the Reliability Coordinator’s role to be limited (most likely only alerting other Reliability Coordinators of generation or load events
causing significant frequency excursions)
9
Duke Energy Midwest (1, 3, 6)
Jeff Baker
IESO (1)
Anita Lee
January 9, 2007
9
9
The Generator Operator may also have some responsibilities, such as the selection of control
modes.
We're not sure what the LSE can do regarding the standard. They cannot control response
from load. The exception may be coordination of frequency response with UFLS.
Planners may have some responsibilities with regard to new interconnections and also using
observed frequency response in models as opposed to theoretical response.
Page 22 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000383
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The LSE does need to provide some of this data and is listed as an applicable entity in the revised SAR.
BPA (1, 3, 5, 6)
9
9
The only portion we can think of that would applicable to the Load-serving entity is for the
load-serving entity to report their underfrequency load shedding settings. We believe LSEs
should be removed as applicable entities.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The LSE does need to provide some of this data and is listed as an applicable entity in the revised SAR.
Duke Energy Carolinas (1, 3, 5,
6)
Tom Pruitt
9
However, the standard applies to each entity in different ways. The lion's share of
responsibility lies with the BA to insure that the aggregate of the Gen Owners responses
provide the response needed.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
WECC Reliability Coordination
Subc.
9
The only portion we can think of that would applicable to the Load-serving entity is for the
load-serving entity to report their underfrequency load shedding settings. We believe LSEs
should be removed as applicable entities.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
ATC LLC (1)
Jason Shaver
9
Please see comment in questions two about the Load-serving Entity.
Response: Please see the response to your comment on question 2.
Midwest Reliability Organization
(2)
9
The Generator Operator may also have some responsibilities, such as the selection of control
modes.
We're not sure what the LSE can do regarding the standard. They cannot control response
from load. The exception may be coordination of frequency response with UFLS.
Planners may have some responsibilities with regard to new interconnections and also using
observed frequency response in models as opposed to theoretical response.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
NERC Resources
Subcommittee
9
The proposed standards may apply to LSEs when demand side resources are utilized for
frequency control, but will not apply to many of the LSEs. There may also be cases where
Generator Operators have obligations under the standard.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
Energy Mark, Inc. (8)
January 9, 2007
9
The requirements applicable to the Generator Owner and Load-serving Entity may only
Page 23 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000384
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Howard F. Illian
Yes
No
Comment
include requirements for measurement processes, not necessairly requirements to provide
any frequency response.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
NPCC CP9 Reliability
Standards Working Group
9
If required.
9
Also pertains to Generator Operator.
Response: Thank you.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. In
the revised SAR, the Generator Operator is responsible for providing data when the BA’s performance is below an Interconnection target.
Southern Company Transm. (1)
January 9, 2007
9
Page 24 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000385
Consideration of Comments on Second Draft of Frequency Response SAR
4. The current standard on Bias requires a Balancing Authority to carry a minimum bias equal to 1% of peak load. As
an example, in the Eastern Interconnection, this value is double current natural frequency response. Should the
standard provide an incentive, such that a Balancing Authority can use a bias equal to their natural response, but
less than 1% of peak, if the response is above an acceptable target?
Summary Consideration: While most commenters supported this suggestion, there was not consensus on the scope of the proposed
requirements, and the drafting team revised the SAR to focus solely on collecting data needed to model frequency response in each of the
interconnections. The drafting team will forward these comments to the Director of Standards Development so that they can be addressed by the
Balance Resources and Demand standard drafting team or another drafting team. This shall serve as a summary response to all comments
provided.
Commenter
Yes
IESO. (2)
Ron Falsetti
BPA (1, 3, 5, 6)
January 9, 2007
9
No
Comment
9
(i) The question seems to get the sub-minute and longer-term targets intertwined. We are
unclear on which "standard be provided an incentive". Is it the proposed sub-minute
standard which has yet to be determined or the current standard on Bias? If it is the
former, then this question seems a bit premature as we don't even know what the
performance target for sub-minute response should be. If it's the latter, then the issue
belongs to other BAL standards.
9
The RS again is avoiding the issue of what sub-minute frequency response it MUST
mandate. The 1% is related to the frequency bias setting (basically a long term average
response). The BRD deals with the longer term issue of frequency response - this
standard was designed for the shorter-term response.
If the RS is willing to accept under-biased systems then it would seem to be going against
conventional wisdom, and should explain why it would even consider such an idea. If the
real intent of this frequency SAR is to establish a minimum frequency response value
then the SAR needs to state that.
Perhaps the SAR should establish a minimum 1 minute response for every generator (if
they can't provide it they are obligated to contract for it from another unit) and maybe a 1
minute average over a week, month, or year if a longer term value is needed. However,
since the SAR authors state the problem is sub-minute response, it is suggested that the
long term response is better be addressed by the BRD standard.
In addition the SAR does not adequately address the load portion of the frequency
response. The standard seems to presuppose the solution is having governors.
9
The standard should not provide an incentive, but the standard should provide a
methodology that would allow a Balancing Authority to calculate a bias based on their
natural response, provided that response is above an acceptable target.
Page 25 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000386
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Southern Company Transm. (1)
9
The 1% minimum frequency bias is obsolete and does not take into account the changes
in interconnection frequency response over recent years. If not modified, it will lead to
increased frequency oscillations within the interconnections and needless maneuvering of
generating assets with associated wear and tear on these assets.
IESO(1)
Anita Lee
9
There should be a safeguard in place, such that if frequency performance declines, the
industry reverts to the 1% minimum.
Midwest Reliability Organization (2)
9
There should be a safeguard in place, such that if frequency performance declines, the
industry reverts to the 1% minimum.
Energy Mark, Inc. (8)
Howard F. Illian
9
There is a minimum frequency response below which the interconnection will be less
reliable than acceptable. We currently do not know what this value is but we do know
that a value exists. We also know that this value is less than the 1% of peak load
specificed in the current standards. A standard that arbitrairly requires a 1% of peak load
response without a technical justification based on reliability cannot be called a reliabiltiy
standard. However, even though we do not know the minimum frequency response
below which the interconnection will be less reliable than acceptable, we can perform the
work necessary to estimate a reasonable value for a minimum frequency response and
assign responsibility for that response among the Balancing Authorities on an
interconnection. A Frequency Response Standard without this characteristic cannot
maintain reliability of the interconnection.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
9
I believe that an incentive should be included in the standard.
Duke Energy Carolinas (1, 3, 5, 6)
Tom Pruitt
9
Calculation of each BA's bias should be based on a rigorous analysis which demonstrates
that the BA can provide the expected response, regardless of peak load. This is
consistent with the proposed requirements - 'technically-sound calculation and report of
frequency response' and 'Will not mandate a given amount of frequency response'.
ATC LLC (1)
Jason Shaver
9
Although ATC is in support of this recommendation, we feel that it should be classified as
an "allowable exemption" not an "incentive".
NERC Resources Subcommittee
9
The 1% minimum frequency bias should be evaluated to take into account the reliability
requirements of the interconnections. frequency response over recent years. We suggest
that the minimum bias be addressed during the development of the Frequency Response
Standard. It is unclear what the word "incentive" means above.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
9
However this requirement still does not address the need for enough frequency response
on the system.
January 9, 2007
Page 26 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000387
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Mike Moltane
Van Greening
January 9, 2007
Yes
No
Comment
Page 27 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000388
Consideration of Comments on Second Draft of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended period after a frequency excursion,
up to the point where automatic generation control (AGC) would take over. This was to ensure initial response
wasn’t withdrawn prematurely. Should the standard measure out to 60 seconds following an excursion?
Summary Consideration: There was not consensus on the scope of the proposed requirements, and the drafting team revised the SAR to
focus solely on collecting data needed to model frequency response in each of the interconnections. The drafting team modified the SAR to
specify that data will be collected to measure response over a period up to 5 minutes. This window may be reduced during the standard drafting
phase. This should provide sufficient data to analyze frequency response and should help identify the window of time where frequency response
appears to be masked by Automatic Generation Control action.
Commenter
Yes
No
Comment
I did not provide an answer but believe that this is a decision that could be made over time
and not necessarily with the inception of the standard.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
Response: We agree.
Arizona Public Service Co. (1, 5)
Baj Agrawal
9
Most of the frequency recovery happens in first 30 seconds. Thus anything more than 30
seconds is unnecessary. It is also seen that the response of a unit varies greatly within that
30 seconds period. Thus, it is very important that the measured response be the average
response over the 30 seconds period and not be the response at 30 seconds.
Response: We agree that frequency response should be measured over a period of time (as opposed to a measure for a single event).
Southern Company Transm. (1)
9
AGC response begins within only a few seconds after the disturbance with a maximum ramp
rate achieved within three to five minutes. Governor response and load frequency response
typically peak within 30 seconds. There is some logic to monitoring governor respone for
sustainability past its initial peak, but we have not seen anything about that in this SAR.
Response: There was no consensus on this matter. The drafting team modified the SAR to specify that data will be collected to measure
response over a period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window
of time where frequency response appears to be masked by AGC action.
9
The standard should measure out to when the frequency recovers. This could be up to the 15
minute DCS limit. AGC control may or may not kick in within 60 seconds depending on
deadbands, etc. However, generators on setpoint control may hold for between 10 and 60
seconds then drop back off prior to AGC pulses reaching the generator. In order to see the
full response of a BA it is necessary to see data for the full event rather than just the first
minute. Rather than overlapping the BRD standard, this will work hand-in-hand with this
standard.
Response: There was no consensus on this matter. The drafting team modified the SAR to specify that data will be collected to measure
response over a period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window
January 9, 2007
Page 28 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000389
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
of time where frequency response appears to be masked by AGC action.
9
NPCC CP9 Reliability Standards
Working Group
Comment
This question is not clear. AGC control pulses generation every 5 seconds, therefore, the
measurement should be based on the amount of time it takes to restore the generation load
balance.
Response: In general, following a unit trip, frequency will not recover until the contingent BA has replaced the energy that was lost. This
typically takes up to 15 minutes. Unless over-biased, a non-contingent BA will not contribute AGC response to a frequency event.
9
PJM Corporate Development Div.
(2)
Unsure as to what is being suggested here. The SAR drafters need to be specific about what
requirements are needed and how they will be measured. The details contained in the white
paper are supporting information but they do not define the standard that is being proposed.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections.
NERC Resources Subcommittee
9
9
AGC response begins within only a few seconds after the disturbance with a maximum ramp
rate achieved within three to five minutes. Governor response and load frequency response
typically peak within 30 seconds. There is logic to monitoring governor response for
sustainability past its initial peak and this should be investigated during standard
development.
Response: We agree with this comment. The drafting team modified the SAR to specify that data will be collected to measure response over a
period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window of time where
frequency response appears to be masked by AGC action.
IESO(1)
Anita Lee
9
Sixty seconds is a reasonable balance to capture the period prior to AGC response.
Response: Agree – However, several commenters indicated there may be value in analyzing response for several minutes and the drafting
team modified the SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient
data to analyze frequency response and should help identify the window of time where frequency response appears to be masked by AGC
action.
IESO. (2)
Ron Falsetti
9
This should cover the entire spectrum of immediate response before AGC kicks in.
Response: Agree However, several commenters indicated there may be value in analyzing response for several minutes and the drafting team
modified the SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to
analyze frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Energy Mark, Inc. (8)
Howard F. Illian
January 9, 2007
9
There are two issues associated with this question. The first is that the change in
instantaneous frequency be limited to within a range that limits the risk of a cascading outage
on the interconnection. The second is that each generation technology provides a different
response characteristic within the first minute after a sudden frequency excursion. Work
Page 29 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000390
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
performed at NIPSCo and published by IEEE indicated that a measurement interval of one to
two minutes worked well for the measurement of frequency response. Without specific
knowledge of the nature of the individual responses that make up the sustained frequency
response to an excursion, it may be difficult to justify the selection of a measurement interval
shorter than one-minute that might put some generation technologies at a disadvantage with
respect to the measurement method. This is a subject that the drafting team should
technically evaluate before including a specific measurement period in the standard.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Duke Energy Carolinas (1, 3, 5, 6)
Tom Pruitt
9
At least. Based on the words in the SAR Purpose statement, 'this proposed standard
coordinates with and complements the Balance Resources and Demand standards, which
addresses Interconnection frequency control generally 5 minutes and longer', it seems that
this standard should cover out to the 5 minute mark of an event. AGC actions will commence
at the first scan cylcle or two after the event (5 -15 secs), but the actual generation response
may not settle out for several minutes, depending on the type and amount of generation on
AGC at the time.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Midwest Reliability Organization
(2)
9
This is a significant issue, because if the governor system withdraws the unit's support prior to
the recovery of frequency, this does have a problematic impact. A period of at least 60
seconds should be considered, and 60 seconds may not be adequate as often frequency
recovery of the interconnection extends beyond the initial 60 seconds.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
9
Needs to be verified with a field trial.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action. Note that the
January 9, 2007
Page 30 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000391
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
drafting team modified the scope of the entire SAR to focus solely on collecting data needed to model frequency response in each of the
interconnections.
ATC LLC (1)
Jason Shaver
January 9, 2007
9
Page 31 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000392
Consideration of Comments on Second Draft of Frequency Response SAR
6. Do you have other comments on the SAR?
Commenter
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
Comment
Reliability and Market Interface Principles 3, 5 and 6 should be checked as well.
Response: We made this change.
PJM Corporate Development Div. (2)
Please be clear about the terminology. Frequency response comes in many flavors - sub-minute;
several minutes; and hours. The RS seems to touch on all of them in this proposal.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. The data collection will include data to model and analyze
frequency response up to five minutes.
Southern Company Transm. (1)
In our opinion, this SAR, or one like it, is required to ensure that the primary frequency response of the
interconnections and the BAs do not deteriorate to a point where 1) the interconnection can not
adequately respond to major generator trips (including potential multiple contingencies which, though
rare, do happen) and 2) primary frequency response of the BAs is inadequate to support islanding
during severe local disturbances, thus allowing local disturbances to cascade into regional or
interconnection wide disturbances. Primary frequency response is declining in at least the Eastern and
Western Interconnections. WECC has taken a proactive approach to addressing this problem, but
there is no similar work being done in the Eastern Interconnection. This SAR, or one like it, is needed
to take the best practices in the industry, wherever they may be found, and utilize them to protect the
interconnections from disturbances that could be avoided if we take action now rather than waiting until
the problems actually occur.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. Your support is very much appreciated.
IESO. (2)
Ron Falsetti
January 9, 2007
(i) The SAR does not address the load portion of the frequency response but it indicates that the
standard would apply to the LSEs as well. Please clarify or eliminate LSE from the Reliability Function
check list.
(ii) We feel that the SAR needs to be very clear on what the proposed standard is intended and what
will be included. Conducting calculation, measuring and report on frequency excursion events followed
by analysis would help to ascertain whether or not poor performance exists. However, the
determination of poor performance also relies on having a minimally acceptable level to gauge. If the
standard is to provide requirements for calculation, reporting and conducting analysis only, then there
Page 32 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000393
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Comment
needs to be some general guideline on the threshold for reporting and analyzing, which in turn begs the
question of should this "guideline" be included as the initial standard, whose compliance would not be
enforced until sufficient experience has been gained and field test conducted, with possible revision as
experience and field test so suggest. Absent a minimum performance level, the requirements for
governor setting would be difficult to determine.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. The Load-serving Entity will need to provide some of the
data needed to model frequency response.
Energy Mark, Inc. (8)
Howard F. Illian
The current measurement methods for determining individual Balancing Authority Frequency Response
may not be reliable. This is because the current measurement methods only capture a small sample of
the frequency responses provided limited to only several minutes per year. The metering methods we
currently use on the interconnection can shed some light on this problem. Since the each BA
measures its Tie Line Error with common metering with adjancent BAs, the sum of the Tie Line Errors
over the total interconnection must equal zero at all times. Each tie line has a positive error for one BA
and a negative error of equal value to the other BA that the tie line connects. If the errors must sum to
zero, then the change in errors must also sum to zero between any two points in time. Since the
Frequency on an interconnection is the same throughtout the interconnection at any point in time for
the purpose of the frequency response measurement, the change in frequency between two points in
time must also be the same throughout the interconnection. Therefore, the change in tie-line error
divided by the change in frequency must indicate a total frequency response for the interconnection as
measured by the sum of the individual BA frequency responses must be equal to zero. In other words,
there is a BA or a set of BAs that cause each frequency response on the interconnection. Only
knowledge of the distribution of individual frequency responses among BAs will provide the necessary
information to determine whether or not the frequency response indicated by current measurement
methods will maintain adequate reliablity. It may not be the average frequency response to large
events that indicates interconnection reliability, but the distribution of frequency responses among BAs
including both the positive and negative responses. Therefore, the measurement methods included in
the standard should have the goal of capturing the distribution of both positive and negative frequency
responses over the entire range of frequency operation should be a goal of standard. The
measurement methods suggested will not accomplish this goal.
Response: We agree with the concerns on errors induced in the measurement process. The standard will be designed to capture enough
events to provide a statistically-sound estimate of Balancing Authority response. We also agree that the distribution of responses needs to be
considered.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
I believe we have to address the frequency issue, but feel that it can be developed over time proactivly.
Response: The revised SAR focuses solely on the collection of data needed to model frequency response. The data can be analyzed and
additional standards can be developed that build on the results of those analyses. This supports your suggestion that the standard(s) be
January 9, 2007
Page 33 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000394
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
developed proactively over time.
Comment
NERC Resources Subcommittee
In our opinion, this SAR, or one like it, is required to ensure that the primary frequency response of the
interconnections and the BAs do not deteriorate to a point where 1) the interconnection can not
adequately respond to major generator trips (including potential multiple contingencies which, though
rare, do happen) and 2) primary frequency response of the BAs is inadequate to support islanding
during severe local disturbances, thus allowing local disturbances to cascade into regional or
interconnection wide disturbances. Primary frequency response is declining in all Interconnections,
Eastern, Western and ERCOT. WECC and ERCOT have taken a proactive approach to addressing
this problem, but there is no similar work being done in the Eastern Interconnection. This SAR, or one
like it, is needed.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. Your support is very much appreciated.
January 9, 2007
Page 34 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000395
Consideration of Comments on Second Draft of Frequency Response SAR
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000396
Consideration of Comments on 3rd Posting of Frequency Response SAR
The Frequency Response SAR Requesters thank all commenters who submitted comments on
Draft 3 of the Frequency Response SAR. This SAR was posted for a 30-day public comment
period from February 8 through March 9, 2007. The requesters asked stakeholders to provide
feedback on the standard through a special standard Comment Form. There were 26 sets of
comments, including comments from more than 59 different people from 39 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team did not make any changes to the SAR
(except to update the descriptions of the Reliability Functions to match the latest version of the
Functional Model) and is recommending that the Standards Committee authorize moving this
SAR forward to standard drafting.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000397
Consideration of Comments on 3rd Posting of Frequency Response SAR
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Dan Boezio (G8)
AEP
9
2.
Jason Shaver
American Transmission Co.
9
3.
Bart McManus
Bonneville Power
Administration
9
4.
James Murphy
Bonneville Power
Administration
9
5.
John Anasis
Bonneville Power
Administration
9
6.
Brenda Anderson
Bonneville Power
Administration
9
7.
Brent Kingsford
California ISO
2
3
4
5
6
7
8
9
9
9
8.
Ed Thompson
(G2)
ConEd
9.
Michael Gildea
Constellation Generation
10.
Doug Hils (G3)
Duke Energy
11.
Howard F. Illian
Energy Mark, Inc.
12.
Steve Myers (G1)
ERCOT
9
9
9
9
13.
Bruno Jesus (G2)
Hydro One Networks
9
14.
Roger
Champagne (G1)
Hydro Québec
TransÉnergie
9
15.
Ron Falsetti (G1)
IESO
9
16.
Kathleen
Goodman (G1)
ISO-NE
9
17.
Bill Shemley (G2)
ISO-NE
9
18.
Brian Thumm
(G3)
ITC Transmission
19.
Jim Cyrulewski
(G3)
JDRJC Associates
20.
Michael Gammon
Kansas City Power & Light
9
21.
Jim Useldinger
KCPL
9
9
9
Page 2 of 31
June 30, 2007
10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000398
Consideration of Comments on 3rd Posting of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
(G8)
22.
Jason Atwood
(G8)
Kelson Energy
23.
Don Nelson (G2)
MA Dept. of Tele. And
Energy
24.
Robert Coish
Manitoba Hydro
25.
Alan R. Oneal
MidAmerican Energy Co.
26.
Jason Marshall
(G3)
Midwest ISO Stakeholders
Standards Collaboration
Participants
27.
Herb
Schrayshuen
National Grid
28.
Randy McDonald
(G2)
NBSO
29.
Guy V. Zito (G2)
NPCC
9
9
9
9
9
9
9
9
9
9
9
30.
Sydney Niemeyer
NRG Texas, Qualified
Scheduling Entity
31.
Jerad Barnhart
NStar
32.
Mike Calimano
(G1)
NYISO
9
33.
Greg Campoli
(G1)
NYISO
9
34.
Ralph Rufrano
(G2)
NYPA
35.
Theodore Papaps
NYSRC
36.
Al Adamson (G2)
NYSRC
9
9
9
9
9
37.
Pete Kuebeck
(G8)
OG&E
38.
Al DiCaprio
PJM
9
39.
Alicia Daughtery
PJM
9
40.
Joseph Willson
PJM
9
41.
Tom Bowe
PJM
9
42.
Mike Pfeister
Salt River Project
9
43.
Jim Busbin (G6)
Southern Company
Services, Inc.
9
44.
Marc Butts (G6)
Southern Company
Services, Inc.
9
45.
J.T. Wood (G6)
Southern Company
Services, Inc.
9
46.
Roman Carter
Southern Company
Services, Inc.
9
47.
Raymond Vice
Southern Company
Services, Inc.
9
Page 3 of 31
June 30, 2007
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000399
Consideration of Comments on 3rd Posting of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
48.
Jim Viikinsalo
Southern Company
Services, Inc.
49.
Tom Higgins
Southern Company
Services, Inc.
9
50.
Terry Crawley
Southern Company
Services, Inc.
9
51.
Ron Beck
Southwestern Power
Administration
9
52.
Bill Grant (G8)
Southwestern Public
Service
9
53.
Wayne Galli (G8)
SPP
54.
Steve Massey
(G8)
Westar Energy
55.
Mich Crouch (G8)
Western Farmers
9
56.
Greg Pieper
Xcel Energy Services
9
57.
Michael Ibold
Xcel Energy Services
58.
Steve Beuning
Xcel Energy Services
59.
David Lemmons
Xcel Energy Services
6
7
8
9
10
9
9
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as
part of a group
G1 - IRC Standards Review Committee
G2 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G3 – Midwest ISO Stakeholders Standards Collaboration Participants (MISO SSC)
G4 – TVA
G5 – Public Service Commission of SC (PSC of SC)
G6 – Southern Company Transmission (Southern Co)
G7 – MRO
G8 – Southwest Power Pool Operating Reliability Working Group
Page 4 of 31
June 30, 2007
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000400
Index to Questions, Comments, and Responses
1.
Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?..............................................................................................................6
2.
The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard? ............................................................................................. 12
3.
The SAR drafting team modified the SAR to clarify that data will be collected to model up
to 5 minutes of frequency response. This should help identify the window of time where
frequency response appears to be masked by AGC action. Do you agree with this
clarification? ....................................................................................................... 17
4.
Should a field trial be initiated, whereby a set of events for each Interconnection is posted
throughout the year, to be used by BAs to calculate their 2007 Frequency Response? ... 22
5.
Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR. .................... 26
Page 5 of 31
June 30, 2007
000401
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection needed to support the
development of accurate models of Frequency Response in North America?
Summary Consideration:
The majority of the comments agreed with the reduced scope of the SAR, which now focuses only on the data collection that is
needed to support the development of accurate models of Frequency Response in North America. For most of the commenters
that did not support the reduced scope, the SAR Drafting Team believes there may be a misunderstanding with respect to the
use of the Target Frequency Response. The SAR Drafting Team explained to those commenters that the Target Frequency
Response does not set a minimum for any particular Balancing Authority. Rather it sets a benchmark, beyond which additional
data is needed from the Balancing Authority.
Question #1
Commenter
SWPA
Yes
No
Comment
The
scope
of
this
SAR
is
for
data
collection,
should not include establishing a Target
; Frequency Response as stated in Paragraph and
#5.
Response: The SAR Drafting Team appreciates your input, but disagrees with your conclusion. There should always be a
purpose for going to the trouble and expense of capturing and analyzing data. The SAR Drafting Team considers the
establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and
one of the two fundamental reasons why this SAR was initially drafted. The SAR Drafting Team believes there may be a
misunderstanding with respect to Target Frequency Response, which does not set a minimum for any particular Balancing
Authority. The Target Frequency Response sets a benchmark, beyond which additional data is needed from the Balancing
Authority.
Xcel Energy Services
agree with the proposed scope except that items 5 and 6 do not deal specifically with
; We
data collection and therefore are beyond the scope of the SAR. We are concerned over
establishing a Target Frequency Response. This is presumptious in that it advances a
proposed remedy before first meeting the intent of the SAR-determining the cause for
the percieved decline in frequency response. We support Items 6a. and 6b. if referenced
to item 4 as modified as follows: Modify 4 to require generator level reporting when the
Frequency Response for a BA is less than [75]* percent of the Previous Years observed
Frequency Response. Delete items 5 and 6.
Response: In response to your first comment on Paragraph 5, the SAR Drafting Team considers the establishment of a
Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and one of the two
fundamental reasons why this SAR was drafted initially. The reason for establishing the target frequency response is to
determine the point at which additional data is needed from a given Balancing Authority.
In response to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
Page 6 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000402
Question #1
Commenter
Yes No
Comment
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them.
PJM
primary objective of this SAR is to collect data; to analyze the data; and only then
; The
to recommend a performance value. The SAR DT insists that collecting data is a
Technical Standard. The RSDP states:
"Technical standards…will contain Measures (not measuring - AMD) of physical
parameters…" At this point this SAR proposal does not contain such a measure, it does
not even assert that the measure is really needed (hence the need to analyze the data).
Page 19 (of 43) of the RSPM states “The drafting team may recommend the scope of the
standard be reduced to allow the effort to move forward, while still remaining within the
scope of the SAR. Reducing the scope of the SAR is acceptable if the drafting team finds,
for instance, THAT ADDITIONAL TECHNICAL RESEARCH IS NEEDED PRIOR TO
DEVELOPING (emphasis added) a portion of the standard or issues need to be resolved
before consensus can be achieved on a portion of the standard. “The highlighted section
applies directly to the scope of this SAR. The SAR Team recognizes work is needed.
There is no question about that. The Team should do that work BEFORE proposing a
mandatory standard.
PJM supports the concept of doing such a study, and would encourage NERC to assign a
group to do such a study, but PJM does not agree that collecting data rises to the level of
a valid NERC reliability standard.
Response: NERC’s Reliability Standards Development Plan: 2007 - 2009 describes the characteristics of a Reliability
Standard as follows: “ Although reliability standards have a common format and process, several types of reliability standards
may exist, each with a different approach to measurement:
Technical standards related to the provision, maintenance, operation, or state of bulk power systems will likely contain
measures of physical parameters and will often be technical in nature.
Performance standards related to the actions of entities providing for or impacting the reliability of the bulk power
systems will likely contain measures of the result of such actions, or the nature of the performance of such actions”.
Collecting, correlating and analyzing data on a continental scale is not a simple matter. The SAR Drafting Team believes that
the scale of this project and the potential importance of the conclusions to be developed per the specifications in Paragraphs
5 and 6 more than warrant the use of the NERC Reliability Standards Process to address them. Directed research can be
Page 7 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000403
Question #1
Commenter
Yes No
Comment
investigated during the standard development effort.
IESO
do not agree with the reduced scope of this SAR. It does not require a standard to
; We
enable a data collection task(s). Data collection procedures and processes, charged by a
standing committee, e.g. the OC, or respective working groups, would be more than
sufficient.
Response: The SAR Drafting Team believes that the scale of this project, the ongoing nature, and the potential importance
of the conclusions to be developed per the specifications in Paragraphs 5 and 6 more than warrant the use of the NERC
Reliability Standards Process to address them. We believe the Standing Committees would play a vital role in evaluating the
initial results of the standard.
SPP ORWG
not agree with the notion in point 5 regarding the need for a Target Frequency
; Do
Response for each interconnection at this time. It is beyond the scope of this technical
SAR to propose anything other than collection of data to support the study.
Do not agree with point 6 of the description. In order to get a handle on what is really
going on, all Balancing Authorities should be required to produce data valid to the study.
Also the language in point 6 is poorly worded compared to the right wording in 6a and
6b. 6a and 6b should be included in the SAR and 6 should be removed.
Response: The SAR Drafting Team appreciates your input, but disagrees with your conclusion. The SAR Drafting Team
considers the establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the
Interconnections and one of the two fundamental reasons why this SAR was drafted initially. The reason for establishing the
target frequency response is to determine the point at which additional data is needed from a given Balancing Authority.
With respect to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them. The intent of the Target Frequency Response is to determine the point where additional data is required. The SAR
Drafting Team does not recognize the specific wording that you are referring to in Paragraph 6 and request clarification.
KCP&L
not agree with the notion in point 5 regarding the need for a Target Frequency
; Do
Response for each interconnection at this time. It is presumptuous to advance a remedy
prior to determining cause of the perceived decline in frequency response. Allow the
techincal SAR to perform its function to determine cause. Any appropriate remedy in
operating standards should become apparent.
Do not agree with point 6 of the description. In order to get a handle on what is really
Page 8 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Yes
000404
No
Comment
going on, all Balancing Authorities should be required to produce data valid to the study.
Also the language in point 6 is poorly worded compared to the right wording in 6a and
6b. 6a and 6b should be included in the SAR and 6 should be removed.
Response: We appreciate your input, but disagree with your conclusion. The SAR Drafting Team considers the
establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and
one of the two fundamental reasons why this SAR was drafted initially. The reason for establishing the target frequency
response is to determine the point at which additional data is needed from a given Balancing Authority.
In response to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them. The intent of the Target Frequency Response is to determine the point where additional data is required. The SAR
Drafting Team does not recognize the specific wording that you are referring to in Paragraph 6 and request clarification.
Hydro Québec
believe there might be other means than Reliability Standards to accomplish this
; ; HQT
TransÉnergie
data collection.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate.
NPCC CP9
of NPCC's participating members believe there are other means to accomplish this
; ; Many
phase of the initiative and that appropriate revisions to existing standard(s) may address
the issue determined by the data analysis could be proposed.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate.
NYISO
NYISO is uncertain if this is the appropriate means to require data collection for
; ; The
purposes of developing models. A review should be made to be certain that this
proposed scope meets the criteria for a standard.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate. Note that the NERC Standards Committee and the industry as a whole are currently
performing just such a review, as you request, by commenting on this draft SAR.
Page 9 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Energy Mark, Inc.
Yes
000405
No
Comment
At
this
time
information
is
not
available
that would provide a sound technical basis for
;
the development of a performance standard. However, with the recent increased
interest in Frequency Response, new data and analysis could become available at any
time that would change the focus from a technical standard to a performance standard.
If new information and analysis becomes available during the development of the
technical standard, consideration should be given to how the development of the
technical standard could delay the development and implementation of a performance
standard. Must the technical standard be completed and approved before work can start
on a performance standard?
Response: The SAR Drafting Team agrees that there may be technical issues which may allow the Standard Drafting Team
to accomplish the functional purpose of this SAR differently than anticipated by the SAR Drafting Team. This is allowed for in
the NERC Reliability Standards Process Manual, page 19, as noted by PJM above.
It is anticipated by the SAR Drafting Team that the work set forth in the SAR will aid in determining if a Performance
Standard is required and, if so, how the standard should be structured. A SAR for a Frequency Response Performance
Standard can be written and submitted to the NERC Standards Committee at any time.
This standard would be a start, at least, at bringing to light where and why response is
MidAmerican Energy
;
being lost. It may well be that exposure and peer pressure, as well as the tiered
Co.
reporting requirements, will keep plant and operations personnel abreast of their
obligations for providing reserves of all types.
Response: The SAR Drafting Team appreciates your support.
Southern
Frequency response and its dynamic behavior is a complex issue that requires detailed
;
analysis and study to understand. This in turn requires sufficient high quality data be
obtained to support the development of models and concepts. The data could be
collected voluntarily, but without the force of NERC standards behind it not many people
are going to devote the resources required to collect the data. We strongly support this
effort.
Response: The SAR Drafting Team appreciates your support.
ISO New England
;
Bonneville Power
Administration
American
Transmission Co.
CAISO
ERCOT
;
;
;
;
Page 10 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Manitoba Hydro
MISO
NRG Texas
NYSRC
Salt River Project
American Electric
Power
ITC Transco
Yes
No
Comment
;
;
;
;
;
;
;
Page 11 of 31
000406
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000407
2. The proposed standard would have requirements for the following functional entities: Reliability Coordinator,
Balancing Authority, Generator Owner, Generator Operator, and Load-serving Entity. Do you agree that these are the
right functional entities for the proposed standard?
Summary Consideration:
The majority of the commenters supported the functional entities for which the proposed standard would be applicable,
specifically the Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and Load-Serving Entity. All
commenters that responded that they did not agree to the proposed functional entities requested clarification on the
applicability to a Load-serving Entity (LSE).
The SAR Drafting Team explained that the LSE functional entity was added in response to stakeholder comments received on
the first draft of the SAR. The SAR Drafting Team also explained to commenters that various industry experts estimate that as
much as 1/3 of the total Interconnection Frequency Response may be supplied by Load Frequency Response (the other 2/3 is
supplied from Turbine Governor Support). Thus information from the LSE concerning the composition and variations of load
served within the Interconnection can be critical in understanding total Interconnection Frequency Response.
One commenter suggested that if there is a future performance standard, it would be unreasonable to implement a technical
standard that requires functional entities to provide data. The SAR Drafting Team does not see the linkage between requiring
data from entities in order to qualify and quantify Frequency Response with the interconnections and NOT including all these
entities in a Frequency Response Performance Standard.
Question #2
Commenter
PJM
Yes
No
;
Comment
The proposal as written appears to be headed towards mandating a given unit response.
As such there would be an obligation on the Generator Operator - there does not seem
to be any requirements that would apply to the Generator Owner - unless of course the
requestor includes a requirement to install a governor (this has, to date, be an implied
obligation just as having a turbine has been an implied obligation). If the requestor does
intend to assert an obligation on the Generator Owner to install a governor then the
question arises should that be a standard or should that be a part of the Certification of
a GO?
It is not clear what the LSE requirements are in this proposal.
Response: The stated purpose of this SAR is to collect and analyze data in order to determine the Frequency Response for
each Interconnection, recommend a target Frequency Response for each Interconnection and determine the cause of any
significant variations in Frequency Response within each of the Interconnections.
In response to your comment on applicability to LSEs, various industry experts estimate that as much as 1/3 of the total
Interconnection Frequency Response may be supplied by Load Frequency Response (the other 2/3 is supplied from Turbine
Page 12 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000408
Question #2
Commenter
Yes No
Comment
Governor Support). Thus information from the LSE concerning the composition and variations of load served within the
Interconnection can be critical in understanding total Interconnection Frequency Response. The applicability to LSEs was
added at the specific request of commenters in a previous version of the SAR.
SWPA
serving entities should not be included due to the characteristics of load and
; Load
frequency. Load Serving Entities should contribute data to determine FRC.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR. Note that your two statements seem to contradict each other.
NPCC CP9
participating members question the need to include the applicability to the LSEs in
; NPCC
this SAR and requests the drafting team to explain this.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
NYSRC
; Explain the applicability of the SAR to LSEs.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
SPP ORWG
standard can not be imposed on the response of load to frequency. Load Serving
; AEntities
can only provide data.
Response: The SAR Drafting Team agrees that the role of the LSE will primarily be to supply data concerning the
composition and variations of load served within the Interconnection. There is nothing in the SAR imposing a response
requirement on any of the functional entities.
Hydro Québec
question the need to include the applicability to the LSEs in this SAR and requests
; We
TransÉnergie
the drafting team to explain the purpose.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
Page 13 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #2
Commenter
IESO
Yes
No
000409
Comment
For
the
purpose
of
data
collection,
assigning
responsibility to the Balancing Authority,
; Generator Operator and Load-serving Entity would
suffice.
Response: Most of the data will be collected from the entities you list. However, the SAR Drafting Team believes the other
entities included in the SAR have some of the data that is needed for this standard. For example the Generator Owner might
have relevant data that may not be available from the Generator Operator.
ISO New England
New England does not see a need to include the applicability to the LSEs in this SAR
; ISO
and requests the drafting team to explain this.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
American
does not see the need to identify the Load Serving Entity in the Applicability section.
; ATC
Transmission Co.
The SDT should provide an explanation as to the reasoning behind the selection of Load
Serving Entities.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
Energy Mark, Inc.
agree that the proposed list includes those entities that would be affected by a
; ; Itechnical
standard. However, there are many questions that must be resolved before
any standard that affects the Generation Owner, Generation Operator or Load-serving
Entity can be implemented. These questions relate to how a performance standard can
or should be implemented. If there is no reasonable expectation that they would be
included in a future performance standard, it would be unreasonable to implement a
technical standard that requires these three functional entities to provide data. In a fair
market that allows voluntary participation by Generation Owners, Generation Operators
and Load-serving Entities, the direct application of a Frequency Response Performance
Standard to these entities is not currently possible without creating unreasonable
inequities in the market. Any standard applied directly to one generator but not another
will create unreasonble inequities in a market. Since each generation technology has
different Frequency Response capabilities, only a solution that provides Frequency
Response through a market based mechanism can be fairly implimented in a market.
Under these conditions, the measurement methods and data collection for a technical
standard should only be applied to those entities that would have resposibilities under a
Page 14 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #2
Commenter
Yes
000410
No
Comment
performance standard. The correct alternative for collecting data from these entities is
to collect it indirectly through the Balancing Authority or Reliability Coordinator that
would be directly affected by a performance standard. The inclusion of Generation
Owner, Generation Operator, and Load-serving Entity directly in the data collection will
lead to the development of data collection systems that will need to be replaced, if and
when, a performance standard is developed. This is an inefficient way to develop the
technology for a new standard.
Response: The SAR Drafting Team appreciates your input, but disagrees with some of your conclusions.
The SAR Drafting team does not see the linkage between requiring data from entities in order to qualify and quantify
Frequency Response with the interconnections and NOT including all these entities in a Frequency Response Performance
Standard.
Available Frequency Response and its distribution within an Interconnection may require that certain generators be treated
differently than others due to their location and electrical characteristics. How this difference is compensated is neither
within the scope of this SAR nor within NERC’s authority.
The SAR drafting team agrees with your statement about the data collection being performed in the most efficient manner.
Salt River Project
Ultimately there may be some impact to the Planning Coordinator and/or Resource
;
Planner if a frequency response requirement is specified. Could there be an extreme
scenario where an entity would have to consider shedding load to meet some frequency
reserve criteria?
Response: The SAR Drafting Team does not anticipate that the standard resulting from this SAR will contain any
requirement for specific Frequency Responses from the Interconnections or the Balancing Authorities. Future standards are
beyond the scope of this SAR. The SAR Drafting Team would expect that in any standard (whether dealing with transmission,
dynamics or reserves) load shedding only makes sense if the entity cannot withstand the next contingency.
Xcel Energy Services
To the extent information is needed from these entities, they are appropriate to list. It
;
is possible that the LSE is not required.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
American Electric
The role of the load serving entity in item 6b is unclear.
;
Power
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
Page 15 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000411
Question #2
Commenter
Yes No
Comment
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
ERCOT
;
CAISO
Bonneville Power
Administration
KCP&L
Manitoba Hydro
MidAmerican Energy
Co.
MISO
NRG Texas
NYISO
Southern
ITC Transco
;
;
;
;
;
;
;
;
;
;
Page 16 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000412
3. The SAR drafting team modified the SAR to clarify that data will be collected to model up to 5 minutes of frequency
response. This should help identify the window of time where frequency response appears to be masked by AGC
action. Do you agree with this clarification?
Summary Consideration:
Most comments agreed that the clarification helped to identify the window of time when frequency response appears to be
masked by AGC action. Several commenters requested more specific information on the sample rates and the specific data that
would be collected. The SAR Drafting Team explained that this type of information will be developed in the standard
development process and not captured in the SAR. The SAR drafting team agreed to forward these comments to the Director
of Standards Development so that they can be addressed by the Frequency Response Standard Drafting Team.
Question #3
Commenter
SWPA
Yes
No
Comment
Need
more
specific
information
regarding
rates. The 5-minutes of frequency
; response should identify time periods priorsample
to and after the event.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
SPP ORWG
5 minute time is adequate, but it lacks substance. Small changes in load and
; The
generation due to frequency response are very difficult to separate from normal load
changes and AGC action on generation units (as was pointed out). It is important to
include in the description of data collection that the 5 minutes should include 1 minute of
data prior to a study event and 4 minutes after a study event. It is also important to
include a sample rate, such as 4 seconds (obviously, faster samples are better, but may
not be practical).
The SAR, as written, lacks specifics on what data is required to perform a valid study.
Some examples of necessary data may include, but are not limited to, AGC pulses,
special protection systems, generator MW, tie line MW, frequency, etc.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Drafting Team. We expect the data sampling rate to
Page 17 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Yes No
be on existing SCADA periodicity.
Xcel Energy Services
000413
Comment
Further clarification is needed around the time period for which data will be collected. It
important to note that description of the 5 minutes data collection period should include
1 minute before and 4 minutes after the event.
Response: In response to your first comment, the SAR Drafting Team agrees with the comment. Specific information, such
as sampling rate and specific data requirements, will be developed in the standard development process and not captured in
the SAR. The five minute period was proposed based on comments to a prior version of the SAR. Some commenters were
concerned that governors were withdrawing response shortly after the initial excursion. The SAR drafting team will forward
these comments to the Director of Standards so that they can be addressed by the Frequency Response Standard Drafting
Team. We expect the data sampling rate to be on existing SCADA periodicity.
;
In response to your second comment, the SAR Drafting team agrees that data is required both before and after the
contingency to be analyzed.
ITC Transco
minutes of data seems arbitrary. If the collection period were extended to 15
; Five
minutes, it would coincide with the Disturbance Control period.
Response: Thank you for your comment. The SAR Drafting Team agrees with the comment. Specific information, such as
sampling rate and specific data requirements, will be developed in the standard development process and not in the SAR.
The five minute period was proposed based on comments to a prior version of the SAR. Some commenters were concerned
that governors were withdrawing response shortly after the initial excursion. The SAR drafting team will forward these
comments to the Director of Standards so that they can be addressed by the Frequency Response Drafting Team. We expect
the data sampling rate to be on existing SCADA periodicity.
PJM
noted above PJM does not consider collecting data in order to decide what a
; As
requirement should be as grounds for a standard. Thus the sampling period which is
outside of a NERC standard, can be defined in whatever way the group doing the
sampling desires.
Response: Specific information, such as sampling rate and specific data requirements, will be developed in the standard
development process and not captured in the SAR. The five minute period was proposed based on comments to a prior
version of the SAR.
NYSRC
is not clear what type of data is going to be collected from this requirement. AGC
; It
response is continuous. What is the justification for the specific "five minutes" reffered
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
Page 18 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000414
Question #3
Commenter
Yes No
Comment
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
NPCC CP9
is not clear what type of data is going to be collected from this requirement. AGC
; It
response is continuous. What is the justification for the specific "five minutes" referred
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary and
NPCC participating members would like the drafting team to explain why 5 minutes is
necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not in the SAR. The five minute period was
proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
KCP&L
5 minute time is adequate, but it lacks substance. Small changes in load and
; The
generation due to frequency response are very difficult to separate from normal load
changes and AGC action on generation units (as was pointed out). It is important to
include in the description of data collection that the 5 minutes should include 1 minute of
data prior to a study event and 4 minutes after a study event. It is also important to
include a sample rate, such as 4 seconds (obviously, faster samples are better, but may
not be practical).
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Energy Mark, Inc.
with the concept of measuring Frequency Response for an extended period after
; ; Ia agree
disturbance, but I do not agree that the reason is related to masking by AGC action. If
the Frequency Bias for a Balancing Authority is set to a value that approximates the
actual Frequency Response, the AGC action will always provide the correct response for
Page 19 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Yes
No
000415
Comment
reliable interconnection performance. The Frequency Response should be measured for
an extended period after a disturbance to identify entities that are prematurely
withdrawing their expected frequency response support from the interconnection. This
has been demonstrated for entities that have outer loop control that only includes
scheduled deliveries without adjustment for frequency response.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Hydro Québec
requests clarification as to what data and at what periodicity will be collected from
; ; We
TransÉnergie
the identified entities.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
ISO New England
New England requests clarification as to what data and at what periodicity will be
; ; ISO
collected.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
MISO
minutes is acceptable. There may be merit in collecting 15 minutes of data to cover
; ; Five
the DCS window. The data should be readily available since the BAs are already
examining this data to determine their compliance with the DCS standard. The final
decision can be made during the standards drafting phase.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
Page 20 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000416
Question #3
Commenter
Yes No
Comment
sampling rate to be on existing SCADA periodicity.
NYISO
is not clear what type of data is going to be collected from this requirement. AGC
; ; It
response is continuous. What is the justification for the specific "five minutes" reffered
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary and
NPCC participating members would like the drafting team to explain why 5 minutes is
necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
ERCOT
This time frame should be sufficient for determination of frequency response. If it is
;
intended that this data should also be useful for evaluating generating unit governor
functioning, a longer time may be appropriate.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Manitoba Hydro
Ten minutes might be more useful, especially in any areas where it appears to take a
;
long time to settle down after a frequency deviation event. This could be left up to the
discretion of operators and balancing authorities in any areas where slow or bumpy
returns to normal frequency levels are experienced.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not in the SAR. The five minute period was
proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards Development so that they can be addressed by the Frequency Response Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Page 21 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Salt River Project
Southern
NRG Texas
MidAmerican Energy
Co.
IESO
Bonneville Power
Administration
CAISO
American Electric
Power
Yes
No
Comment
;
;
;
;
;
;
;
;
Page 22 of 31
000417
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000418
4. Should a field trial be initiated, whereby a set of events for each Interconnection is posted throughout the year, to be
used by BAs to calculate their 2007 Frequency Response?
Summary Consideration:
Most commenters indicated that a field trial should be initiated whereby a set of events for each Interconnection is posted
throughout the year, to be used by Bias to calculate their 2007 Frequency Response.
Question #4
Commenter
Yes
No
Comment
Only if field trials are deemed to have very high probability of not causing significant
difficulties on overly sensitive network area.
Response: The SAR Drafting Team agrees that no field trial should adversely impact the reliability of the Bulk Power System.
is not a new concept. I support institution of the standard as written so a start can
MidAmerican Energy
; This
Co.
be made to identify and, with luck, remediate the decline in frequency response.
Response: Thank you for your support.
Bonneville Power
does not believe a field trial is needed for this standard. The standard should be
; BPA
Administration
written and implemented with the levels of noncompliance structured around data
submittal.
Response: Thank you for your support.
PJM
are field trials for standards (which this question is directed) and there are field
; There
trials for good ideas. This proposed SAR would seem to fall into the second category;
and while posting events is interesting, it does not rate being a NERC standard.
Collecting and posting data can be effected without a standard.
Response: Thank you for your comment.
NYSRC
;
;
;
Manitoba Hydro
Energy Mark, Inc.
This would be a good way to insure that every entity select a similar set of events for
calculation of their Frequency Response, but it will not insure conformity of the results.
The difficulty with any method for selecting a common set of events is that each of those
events is caused by a disturbance within one or more of the Balancing Authorities on the
interconnection. Those entities that cause the disturbance will experience a different
frequency response than those entities that are responding. The net effect is that the
sum of the responses for all of the entities on the interconnection must sum to zero.
This means that each entity must eliminate those disturbances for which they are the
cause, from the set of disturbances they use to estimate their response. The real
advantage is an entity cannot influence the results of the measurement through
selection of the events they choose to include in the calculation.
Page 23 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000419
Question #4
Commenter
Yes No
Comment
Response: Thank you for your comment. The SAR drafting team will forward these comments to the Director of Standards
so that they can be addressed by the Frequency Response Standard Drafting Team.
MISO
This should not be a problem as BAs should already be performing this calculation in the
;
annual determination of their frequency bias.
Response: Thank you for your comment.
NRG Texas
A field trial may indicate the need for more or different data for the proper calculation of
;
a BAs Frequency Response.
Response: Thank you for your comment.
ERCOT
A field trial would be beneficial to ensure that no gaps in the need for data exist. This
;
could relate to whether other data is needed or whether data for a longer time is
needed.
Response: Thank you for your comment.
IESO
A field test is a must and would definitely provide useful information on the types of
;
event that would necessiate such data collection (The threshold needs to be clarified
though - e.g. should it be >10MW loss of generator or some other threshold?), and any
specific areas that need to be worked on in order to ensure that all relevant and required
data is collected.
Response: Thank you for your comment. The SAR Drafting Team agrees with the comment. Specific information, such as
sampling rate and specific data requirements, will be developed in the standard development process and not in the SAR.
The SAR drafting team will forward these comments to the Director of Standards so that they can be addressed by the
Frequency Response Standard Drafting Team. We expect the data sampling rate to be on existing SCADA periodicity.
Southern
Currently BAs in the Eastern Interconnection have little, if any, way to actually calculate
;
their frequency responses. As a result, most default to the one percent minimum. A
good database of disturbance events will provide the information to calculate BA
frequency response more accurately while at the same time allowing the NERC OC/RS to
determine if the one percent minimum is appropriate in the EI today.
Response: Thank you for your comment.
Hydro Québec
;
TransÉnergie
CAISO
;
ISO New England
KCP&L
NPCC CP9
;
;
;
Page 24 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #4
Commenter
NYISO
SPP ORWG
Salt River Project
Xcel Energy Services
American Electric
Power
ITC Transco
SWPA
Yes
No
Comment
;
;
;
;
;
;
;
Page 25 of 31
000420
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000421
5. Please provide any other comments (that you have not already provided in response to the first three questions on this
form) that you have on the revised SAR.
Question #5
Commenter
Comment
Bonneville Power
BPA agrees with the necessity of a frequency response standard. BPA highly encourages that this
Administration
effort be implemented as soon as possible.
Response: Thank you for your support.
Constellation
Specific to the Requirement 6 a which states:
Each Generator Operator that operates a generator larger than [10 MW]*, shall provide data
to its Balancing Authority, as required in item 6, to support this standard and for use in
developing models of Frequency Response in the associated Interconnection.
Balancing Authorities may seek Speed Droop characteristics for our generators. Speed Droop is a
design characteristic of the steam turbine (or the prime mover's governor response in the case of a
combustion turbine or diesel) .
Our concern is the only data we may be able to provide would be turbine manufacturer design data.
For our older units where turbine control systems have been retrofitted and upgraded with more
modern controls, we may not really know the speed droop characteristic of the unit. Collecting
performance data to demonstrate the speed droop is extremely difficult if not impossible on a large
unit. (Requires the grid connection frequency be allowed to "droop" as the generator is loaded).
Hence, as now written, Constellation Generation is not clear how we could comply.
Response: The SAR Drafting Team anticipates that Frequency Response information will be collected directly from measured
quantities on the grid or the generator bus. We do not anticipate using design curves or other archival data.
Energy Mark, Inc.
One of my concerns is a majority of entities in NERC must agree that there is a need for a standard
before the standard process moves forward. This could have undesirable long-term results with
respect to the quality of the standards that are developed. This standard provides a good example of
this problem. From what I have observed, both the Texas and Western Interconnections have
concluded that there is a reliability need for a Frequency Response Standard on their
interconnections. Unfortunately, reasonable opposition from the Eastern Interconnection will prevent
the development of a common standard for those two interconnections. The only alternative will be
for the Texas and Western Interconnections to each develop their own standards for Frequency
Response without considering ways of making those two standards similar to each other. If the
Eastern Interconnection, after a few years, finds that it needs a Frequency Response Standard, it will
then become necessary for a new standard to be developed that applies to all three interconnections.
Page 26 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
000422
Comment
If each interconnection has a different Frequency Response Standard, it means there is no standard
at all, but three different rules for NERC. The next logical step is to develop a common standard for
all three interconnections requiring the first two standards developed by the Texas and Western
Interconnections separately be modified to conform to a North American Standard on Frequency
Response. Combining these three separate needs into a single standard will result in a natural
opposition to change by those interconnections that have already implemented an interconnection
standard that meets their individual needs. This will make it very difficult to gain the support
necessary to enact a common standard for NERC. This multi-step development can only be avoided
by having all three interconnections participate and contribute to standards identified and developed
by individual interconnections. I believe that NERC needs to find a way to address this problem. If
they do not, the standard development and approval process will lead to fractured standards and an
unacceptable fractured standard process for NERC. One alternative might be to find a way for all
interconnections to participate in the solution of individual interconnection problems as part of the
standard development process.
Response: Thank you for your comment. We believe the Standards Development Procedure provides the solution you are
seeking. The proposed SAR sets the foundation for a technical standard for a common way to measure and evaluate
frequency response. Should a Region or Interconnection determine they need a more stringent, performance-based
standard, there is a means to pursue a difference.
Hydro Québec
Being a single Balancing Authority Interconnection, there might be a need for a «regional» difference
TransÉnergie
for the Québec Interconnection when specific value will be established. Same as ERCOT, frequency
response will be based on the change in generation (or load) rather than Tie-Line deviation.
Response: We agree with this comment. The SAR Drafting Team anticipates that specific regional differences will be
addressed in the Standard and not in the SAR.
IESO
While we felt that the previous SAR was unclear on the intent, this SAR has such a reduced scope that
the intended task does not require a reliability standard to achieve . A task team charged by a
standing committee (the OC), would suffice. The requirements proposed in the SAR can be set as
conditions for completing the data collection effort by the task team.
Response: The SAR Drafting Team disagrees and believes that the scale of this project, the ongoing nature, and the
potential importance of the conclusions to be developed per the specifications in Paragraphs 5 and 6 are sufficiently important
to warrant the use of the NERC Reliability Standards Process.
KCP&L
The reasoning for this technical standard is based on the perception that the frequency response of
the electrical system is declining and a concern that the interconnect's ability to arrest significant
system disturbances is slowly being compromised. Although it is not disagreeable that a study be
conducted to determine if an actual decline in frequency response is occuring and then to determine
cause, it is diagreeable to propose a potential remedy for a problem that may not exist or, dependent
on the findings, in inappropriate remedy.
Page 27 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
000423
Comment
One reason a decline in frequency response may be perceived occuring is a result of more on-line
generating units being fully loaded. That means when a frequency decline occurs there are less units
able to respond because they are already loaded. That does not mean the interconnection is at risk.
As long as Balancing Authorities are maintaining their reserve obligations, even large contingencies
should be manageable. However, over the years because of the trend to get more out of invested
generation resources, it would give the appearance of a decline in frequency response since most
frequency degradations are a result of losses of generation and a resultant decline in system
frequency and those are what is studied and scrutinized. The August 14, 2003 disturbance was an
opportunity to study the frequency response of all on-line generating units due to the frequency event
resulting in a high frequency. High frequency is the only event where all on-line generating units will
respond.
Proposing the establishment of a Target Frequency Response for the interconnect before concluding if
an actual decline in frequency response is occuring and the subsequent cause(s) for the decline is
finding a solution before defining the problem. Any standards involving frequency response needs to
also consider the role system reserves play in the interconnect as well as the frequency response of
generators and system load to frequency. As long as generating reserve obligations are being met to
meet current Reliability Standards and Regional Operating Criteria there may not be a need to go
further dependent on the outcome of the study proposed by this SAR.
Response: The SAR Drafting Team agrees with you speculations, but strongly believes that actual field data must be
collected and analyzed to determine the specific processes impacting Frequency Response. It may well be that no further
action will be required, but that is beyond the scope of this SAR.
I have concern about the "shall"s in the standard, in that there is no apparent enforcement behind
MidAmerican Energy
the requirements for data submittals. If I'm wrong in this, then I would be comfortable with the
Co.
effectiveness possible. If I'm right, what is to be done with an entity which finds it convenient not to
report?
Response: The SAR Drafting Team anticipates that the Standard that evolves from this SAR will have measures for such
things as failure to report and other practical details.
NRG Texas
Frequency Response of Resources is vital to the reliability of an interconnection. Large differences
between the measured Frequency Response of a BA, its Bias setting and the models of Frequency
Response may indicate a reliability risk. Updating the models with accurate Frequency Response data
will improve the evaluation of this reliability risk. Please implement this process as soon as possible.
Response: The SAR Drafting Team agrees and thanks you for your support.
NYSRC
The results of the data collection efforts should be used to develop a standard governing frequency
response.
Page 28 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000424
Question #5
Commenter
Comment
Response: The SAR Drafting Team agrees and thanks you for your support.
Southern
This SAR starts the process toward understanding frequency behavior, particularly in the Eastern
Interconnection. In our opinion this is a necessary first step in determining whether we need
frequency response allocations or other measures to ensure the sustained frequency performance
that is required for reliable operations.
Wherever possible, the scope and extent of data collection required for generators, their dynamic
models including all associated control devices, and any other system data parameters covered under
this SAR be limited such that it should not duplicate or exceed system modeling data requirements of
any other NERC standard. One important system modeling parameter not emphasized in this SAR is
the characteristic behavior of load at each substation (constant power, constant current, etc.), which
would seem to have a significant effect on overall frequency response of the interconnected system.
It is quite possible that advancements in consumer appliances and electronics, and their proliferation
of use, have collectively changed the overall characteristics of system load to a composite state that
is significantly different from modeling assumptions made within the previous few years.
Response: The SAR Drafting Team agrees and thanks you for your support.
SPP ORWG
The reasoning for this technical standard is based on the perception that the frequency response of
the electrical system is declining and a concern that the interconnect's ability to arrest significant
system disturbances is slowly being compromised. Although it is not disagreeable that a study be
conducted to determine if an actual decline in frequency response is occuring and then to determine
cause, it is diagreeable to propose a potential remedy for a problem that may not exist or, dependent
on the findings, in inappropriate remedy.
Types of generating units online (e.g., wind generation, combined cycle, etc) and their subsequent
loading will have an influence on the frequency response of the system. As long as Balancing
Authorities are maintaining their reserve obligations, even large contingencies should be manageable.
However, over the years because of the trend to get more out of invested generation resources, it
would give the appearance of a decline in frequency response since most frequency degradations are
a result of losses of generation and a resultant decline in system frequency and those are what is
studied and scrutinized. The August 14, 2003 disturbance was an opportunity to study the frequency
response of all on-line generating units due to the frequency event resulting in a high frequency.
High frequency is the only event where all on-line generating units will respond.
Proposing the establishment of a Target Frequency Response for the interconnect before concluding if
an actual decline in frequency response is occuring and the cause(s) for the decline is finding a
solution before defining the problem. Any standards involving frequency response need to also
Page 29 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
000425
Question #5
Commenter
Comment
consider the role system reserves play in the interconnect as well as the frequency response of
generators and system load to frequency. As long as generating reserve obligations are being met in
accordance with current Reliability Standards and Regional Operating Criteria there may not be a
need to go further dependent on the outcome of the study proposed by this SAR.
Response: The SAR Drafting Team disagrees and believes that a fundamental understanding of frequency response in each
of the Interconnections is necessary to ensure reliability of the Bulk Power System. This is particularly important as new,
untested technologies are integrated into the Bulk Power System with potentially unanticipated outcomes. Although no follow
up Standards may be required after the Frequency Response Standard is developed, there is a potential risk to
Interconnection reliability unless we do implement this SAR and Standard and develop a firm understanding of specifically
how Frequency Response operates.
It appears that there is a misunderstanding of the Target Frequency Response in that this does not set a minimum for any
particular Balancing Authority. The Target Frequency Response sets a benchmark, beyond which additional data is needed
from the Balancing Authority.
Salt River Project
The SAR includes some requirement language pertaining to generators greater than 10 MW. Old NERC
Policy included language requiring frequency responsive governors "unless restricted by regulatory
mandates". This makes sense for most nuclear facilities. Another type of restriction on governors
involves small hydro units that are dependent on water order. For this type of unit there truly is no
governor response yet the unit capabilities may exceed 10 MWs. Please consider these types of
exemptions as work progresses on this SAR and resulting standard.
Response: Your comments are good and will be provided to the Standard Drafting Team as it wrestles with the specific
details of this project. The SAR does not propose to set a mandatory level of governor response for each generator. The
proposed standard requires data and an identification of which generators are not providing response should the Balancing
Authority be below the Target Response.
Xcel Energy Services
Establishing a Target Frequency Response is premature. It advances a proposed remedy in advance
of first meeting the intent of the SAR-determining the cause for the percieved decline in frequency
response. It is our view that the percieved decline of frequency response, if that turns out to be the
confirmed as a true decline, of itself does not necessarily indicate an significantly increased threat to
reliability. As long as generating reserve obligations are being met to meet Reliability Standards and
the real time regulating reserves are being carried, also to meet Standards, there may not be a need
to go further depending on the outcome of the study proposed by the SAR.
Response: The SAR Drafting Team does not anticipate that a Target Frequency Response will be developed until such time
that it can be technically supported as required by the NERC Reliability Standards Process.
PJM
PJM would also note that the proposal references two distinct parameters - the Natural response of a
BA; and the natural response of a unit. It is not clear how the requestor intends to link the two
parameters. The sum of the units' natural responses will not equal the natural response of the BA.
Page 30 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
000426
Comment
Does the requestor intend to link the two, or to keep them separate? As written it appears that the
requestor intends for the BA to be held responsible for an annual measured value. The SAR DT does
not recognize that during different times there are different number of units opperating and available
to respond. The SAR DT makes no mention of whether or not a BA(?) would have to shed load to
maintain such frequency response (for those periods when all units are at full load). The SAR DT
makes no mention of distance from an event. An event in NE will effect more response in NE then in
Florida - how will that be addressed? PJM would ask for clarification on what the requestor would
intend to mandate.
FERC has recognized the need to include suppliers that use load control - how does this SAR intend to
address such 'natural response suppliers'?
As written this proposal becomes an ambiguous standard as it obligates a BA to get data from a
generator ( as opposed to directly obligating generators to supply the data to the analysis team - this
is important from the perspective of who would be non-compliant if the data were not supplied - the
BA or the GO?).
PJM would suggest that NERC create a Frequency Project, budget the project through its members
rather then create a standard and risk imposing non-compliance penalities for what potentially could
be a non-issue. Deal with this for what it is - a research activity.
Response: The SAR Drafting Team appreciates your thoughtful comments but does not agree with your conclusions. Many
of the details you are concerned about will be worked out as part of the details addressed by the Standards Drafting Team.
The SAR Drafting Team does not anticipate that this SAR will mandate any specific frequency response. The stated purpose
of this SAR is to collect and analyze data in order to determine the Frequency Response for each Interconnection, recommend
a target Frequency Response for each Interconnection and determine the cause of any significant variations in Frequency
Response within each of the Interconnections.
In response to your suggestion to create a Frequency Project, the NERC Standards Development Procedure Manual allows for
the development of SAR/Standard to collect and analyze data as needed to ensure the reliability of Interconnections.
SWPA
Data collection and FRC assessments should also take into account loss of load, not just loss of
generation. If load is lost, causing a high frequency excursion, FRC should be observed on heavily
loaded generators.
Response: You are correct; however the collection of statistically significant load loss data has proven to be very difficult, if
not impossible, in the past. The SAR Drafting Team will forward your comments to the Director of Standards so that they can
be addressed by the Frequency Response Standard Drafting Team.
Page 31 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000427
Consideration of Comments
BAL-003-1 – Frequency Response and Frequency Bias Setting
Project 2007-12 - 1st Draft
There are a few places where the team missed
providing a comment in response to a
The Frequency Response and Frequency Bias Setting
suggestion – these are highlighted in yellow.
Drafting Team thanks all commenters who submitted
In general, the team did a good job of
comments on the 1st draft of BAL-003-1 – Frequency
responding!
Response and Frequency Bias Setting. This standard
was posted for a 30-day public comment period from
February 4, 2011 through March 7, 2011. The stakeholders were asked to provide feedback on the
standards through a special electronic comment form. There were 36 sets of comments, including
comments from more than 139 different people from approximately 86 companies representing 10 of
the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received the drafting team made the following changes to the proposed
Standard:
•
Removed the Single Event Frequency Response Data (SEFRD) definition from the standard.
•
Modified the definitions for Frequency Response Measure (FRM) and Frequency Response
Obligation (FRO).
•
Modified the proposed definition of Frequency Bias Setting.
•
Modified FRS Form 1 to correct errors, allow for adjustments and provide clarity.
•
Separated Attachment A Background Document into two documents; 1) Attachment A – Supporting
Document detailing the methodology to be followed for calculations, and 2) Background Document
detailing the rational for the development of the requirements.
•
Created Attachment B – Process for Adjusting Bias Setting Floor to clarify the methodology to be
used in reducing the present 1% minimum Frequency Bias Setting.
•
Added measures, VRFs and VSLs.
There were a couple of minority issues that the team was unable to resolve, including the following:
•
A few stakeholders requested the SDT to consider a standard for generators to support the
Balancing Authority in achieving the targeted level of Frequency Response. The team stated that
this was outside the scope of the industry approved SAR. The SDT further stated that any entity
could submit a SAR addressing this issue to the SC for consideration and that the SDT supported this
option.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000428
•
A couple of comments stated they believed that the standard should support the development of a
market for supporting a Balancing Authority in achieving the target Frequency Response. The SDT
explained that this standard would provide for the metrics for Frequency Response while the
market would define itself. The SDT further stated a market could be created by a region, subregion, ISO, RTO or other entity as appropriate to facilitate compliance however the NERC
Reliability Standards do not establish markets.
In this “Consideration of Comments” document stakeholder comments have been organized so that it
is easier to see the responses associated with each question. All comments received can be viewed in
their original format at:
http://www.nerc.com/filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000429
Index to Questions, Comments, and Responses
1.
The SDT has developed three new terms to be used with this standard.
•
Single Event Frequency Response Data (SEFRD) The individual sample of event data from a
Balancing Authority which represents the change in Net Actual Interchange (NIA), divided by
the change in frequency, expressed in MW/0.1Hz.
•
Frequency Response Measure (FRM) The median of all Single Event Frequency Response Data
observations reported annually on FRS Form 1.
•
Frequency Response Obligation (FRO) The Balancing Authority’s contribution to the total
aggregate Frequency Response needed for reliable operation of an Interconnection assigned
by the ERO.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area?.................................................................................................................................. 12
2.
The SDT has modified the definition for the term Frequency Bias Setting. The current definition
and revised definition are shown below to show the changes proposed. Do you agree with this
new definition for Frequency Bias Setting? If not, please explain in the comment area…………….. 25
3.
The proposed purpose statement in the draft standard is: To require sufficient Frequency
Response from the Balancing Authority to maintain Interconnection Frequency within predefined
bounds by arresting frequency deviations and supporting frequency until the frequency is restored
to schedule. To provide consistent methods for measuring Frequency Response and determining
the Frequency Bias Setting. Do you agree with this purpose? If not, please explain in the comment
area. ……. ............................................................................................................. ………35
4.
Requirement 1 identifies a minimum level of Frequency Response. R1. Each Balancing Authority
shall achieve a Frequency Response Measure (FRM) (as detailed in Attachment A and calculated
on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO).
Do you agree with the concept that a Balancing Authority should be required to achieve a
minimum level of Frequency Response and the method for measurement? If not, please explain in
the comment area. .......................................................................................................44
5.
Requirement 2 identifies when the Balancing Authority must implement its Frequency Bias Setting.
R2. Each Balancing Authority shall implement the Frequency Bias Setting (fixed or variable)
provided by the ERO into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effective coordinated secondary control, using the results from the
calculation methodology detailed in Attachment A.
Do you agree with this implementation? If not, please explain in the comment area.…. .............56
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000430
6.
Requirement 3 mandates that a Balancing Authority operate its Automatic Generation Control
(AGC) on Tie Line Bias unless it becomes adverse to the integrity of its system.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Bias, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s
Area.
Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it becomes
adverse to its system? If not, please explain in the comment area below.…. ............................67
7.
Do you agree with the proposed Implementation Plan for this standard? If not, please explain in
the comment area.…. ....................................................................................................79
8.
This standard proposes to eliminate the 1% minimum Frequency Bias over a period of 4 years as
outlined in the Implementation Plan. Do you agree that the elimination of the 1% minimum will
bring Frequency Bias closer or equal to natural Frequency Response? If not, please explain in the
comment area.. ............................................................................................................90
9.
Do you agree with the drafting team that this standard should be field tested? If not, please
explain in the comment area.…. ......................................................................................99
10. Attachment A of the proposed standard describes the criteria for selecting events to be analyzed.
Do you agree with the criteria as described in Attached A? If not, please explain in the comment
area.…. ..................................................................................................................... 105
11. The proposed standard has a document attached to it that describes the SDT’s reasoning for the
Requirements (Attachment A - Frequency Response Background Document). Do you agree with
the SDT that this document is useful and provides a clear understanding of the Requirements? If
not, please explain in the comment area.…. ..................................................................... 115
12. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s FRM.
Do you agree with the SDT that this is the proper method to calculate its FRM? If not, please
explain in the comment area and if possible provide an alternate method to calculate FRM.…. . 127
13. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s
Frequency Bias Setting. Do you agree with the SDT that this is the proper method to calculate its
Frequency Bias Setting? If not, please explain in the comment area and if possible provide an
alternate method to calculate Frequency Bias Setting.…. ................................................... 135
14. The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS Form 1 for
calculating FRM and Frequency Bias Setting. Do you agree with the SDT that this document
provides a clear understanding of how to use the form? If not, please explain in the comment
area.…. ..................................................................................................................... 142
15. The SDT is soliciting comments on methods of obtaining Frequency Response to meet the FERC
Order 693 directive. If possible please provide any thoughts you may have on this subject.….... 149
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000431
16. If you are aware of any conflicts between the proposed standard and any regulatory function, rule
order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.…. ..................................................................................................................... 126
17. Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1.…. .................................... 131
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000432
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Kurtis Chong
Independent Electricity System Operator
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC
NA
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC
1
7. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8. Brian D. Evans-Mongeon Utility Services
NPCC
8
9. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
2
3
4
5
6
7
8
9
10
X
000433
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Kathleen Goodman
ISO - New England
NPCC
2
12. David Kiguel
Hydro One Networks Inc.
NPCC
1
13. Michael R. Lombardi
Northeast Utilities
NPCC
1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC
1
15. Bruce Metruck
New York Power Authority
NPCC
6
16. Chantel Haswell
FPL Group, Inc.
NPCC
5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
18. Robert Pellegrini
The United Illuminating Company
NPCC
1
19. Saurabh Saksena
National Grid
NPCC
1
20. Michael Schiavone
National Grid
NPCC
1
21. Wayne Sipperly
New York Power Authority
NPCC
5
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
2.
Group
Terry L. Blackwell
Santee Cooper
X
2
3
X
4
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Glenn Stephens
Santee Cooper
SERC
1
3. Rene Free
Santee Cooper
SERC
1
4. Wayne Ahl
Santee Cooper
SERC
1
5. Jim Peterson
Santee Cooper
SERC
1
3.
Group
Additional Member
Carol Gerou
MRO's NERC Standards Review
Subcommittee
Additional Organization
X
Region Segment Selection
1. Mahmood Safi
Omaha Public Utility District
MRO
1, 3, 5, 6
2. Chuck Lawrence
American Transmission Company
MRO
1
3. Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4. Jason Marshall
Midwest ISO Inc.
MRO
2
5. Jodi Jenson
Western Area Power Administration
MRO
1, 6
6. Ken Goldsmith
Alliant Energy
MRO
4
7. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
8. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000434
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
10. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
11. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
12. Scott Nickels
Rochester Public Utilties
MRO
4
13. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
14. Richard Burt
Minnkota Power Cooperative, Inc.
MRO
1, 3, 5, 6
4.
Brent Ingebrigtson
Group
Additional Member
LG&E and KU Energy
Additional Organization
Region
PPL Electric Utilities Corporation NA - Not Applicable 1
2. Annette Bannon
PPL Generation LLC
NA - Not Applicable 5
3. Mark Heimbach
PPL Energy Plus
NA - Not Applicable 6
Group
Jason Marshall
Additional Member
1, 3
2. Terry Harbour
Midamerican Energy
MRO
1
3. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
4. Mike Moltane
ITC Holdings
RFC
1
Group
Sam Ciccone
5
6
7
8
9
10
X
Region Segment Selection
1. Robert Thomasson Big Rivers Electric Cooperative SERC
6.
4
X
Midwest ISO Standards Collaborators
Additional Organization
3
Segment Selection
1. Brenda Truhe
5.
2
FirstEnergy
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Dave Folk
FE
RFC
1, 3, 4, 5, 6
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
7.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
Region Segment Selection
1. Jamie Murphy
BPA, Transmission Technical Operations WECC 1
2. Bart McManus
BPA, Transmission Technical Operations WECC 1
3. Dave Kirsch
BPA, Transmission Technical Operations WECC 1
4. Deanna Phillips
BPA, FERC Compliance Office
8.
Group
Additional Member
1. John Allen
Robert Rhodes
WECC 1, 3, 5, 6
SPP Standards Development
Additional Organization
City Utilities of Springfield, MO
Region Segment Selection
SPP
1, 4
8
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000435
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Michelle Corley
Cleco
SPP
1, 3, 5
3. Lisa Duffey
Cleco
SPP
1, 3, 5
4. Jeff Elting
Nebraska Public Power District
MRO
1, 3, 5
5. Denney Fales
Kansas City Power & Light
SPP
1, 3, 5, 6
6. Louis Guidry
Cleco
SPP
1, 3, 5
7. Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
8. Rick Koch
Nebraska Public Power District
MRO
1, 3, 5
9. Errol Ortego
Louisiana Energy and Power Authority SPP
10
10. David Pham
Empire District Electric
SPP
1, 3, 5, 6
11. Don Schmit
Nebraska Public Power District
MRO
1, 3, 5
12. John Stephens
City Utililties of Springfield, MO
SPP
1, 4
13. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
14. Jim Useldinger
Kansas City Power & Light
SPP
1, 3, 5, 6
15. Barry Warren
Empire District Electric
SPP
1
16. Bryn Wilson
Empire District Electric
SPP
1
9.
Albert DiCaprio
Group
IRC Standards Review Committee
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Patrick Brown
PJM
RFC
2
2. Matt Goldberg
ISO-NE
NPCC
2
3. Dan Rochester
IESO
NPCC
2
4. Steve Myers
ERCOT
ERCOT 2
5. Mark Thompson
AESO
WECC 2
6. Greg Van Pelt
CAISO
WECC 2
7. Charles Yeung
SPP
SPP
2
8. Terry Bilke
Midwest ISO
RFC
2
9. Greg Campoli
NYISO
NPCC
2
10. Kathleen Goodman ISO-NE
NPCC
2
11. Ben Li
IESO
NPCC
2
12. Jason Marshall
Midwest ISO
RFC
2
13. Don Weaver
NBSO
NPCC
2
10.
Gerald Beckerle
Group
SERC OC Standards Review Group
X
X
9
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000436
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. John Neagle
AECI
SERC
1, 3, 5
2. Larry Akens
TVA
SERC
1, 3, 5, 9
3. Chris Adams
EKPC
SERC
3, 5, 9, 1
4. Joel Wise
TVA
SERC
1, 3, 5, 9
5. Ron Wyble
CWLD
SERC
1, 5, 9
6. Andy Burch
EEI
SERC
1, 5
7. Rene' Free
Santee Cooper
SERC
1, 3, 5, 9
8. Glenn Stephens
Santee Cooper
SERC
1, 3, 5, 9
9. Robert Thomasson
BREC
SERC
1, 3, 5, 9
10. Gene Delk
SCE&G
SERC
1, 3, 5
11. Mike Oatts
Southern
SERC
1, 3, 5
12. Sam Holeman
Duke
SERC
1, 3, 5
13. Marc Butts
Southern
SERC
1, 3, 5
14. Melinda Montgomery Entergy
SERC
1, 3
15. Ron Carlsen
Southern
SERC
1, 3, 5
16. Tim Hattaway
PowerSouth
SERC
1, 3, 5, 9
17. John Troha
SERC
SERC
10
11.
Michael Gammon
Group
Additional Member
Kansas City Power & Light
X
X
X
X
X
X
Additional Organization Region Segment Selection
1. Jennifer Flandermeyer Kansas City Power & Light SPP
1, 3, 5, 6
2. Denney Fales
Kansas City Power & Light SPP
1, 3, 5, 6
12.
Individual
Janet Smith
Arizona Public Service Company
X
X
13.
Individual
Cindy Martin
Southern Company
X
X
14.
Individual
James Eckelkamp
Progress Energy
X
X
X
X
15.
Individual
Rob Coulbeck
ENBALA Power Networks
16.
Individual
Joe O'Brien
NIPSCO
X
X
X
X
17.
Individual
John Canavan
NorthWestern Energy
X
18.
Individual
Howard F. Illian
Energy Mark, Inc.
19.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
X
X
10
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000437
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
20.
Individual
Isaac Read
Beacon Power Corporation
21.
Individual
Bryan Taggart
Westar Energy
22.
Individual
Thomas Washburn
FMPP
23.
Individual
Chris Adams
EKPC
24.
Individual
Kathleen Goodman
ISO New Engand Inc.
25.
Individual
Hao Li
Seattle City Light
X
X
26.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
27.
Individual
JC Culberson
ERCOT
28.
Individual
Howard Rulf
We Energies
29.
Individual
Thad Ness
American Electric Power
X
X
X
X
30.
Individual
Greg Rowland
Duke Energy
X
X
X
X
31.
Individual
LeRoy Patterson
Patterson Consulting, Inc.
32.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
33.
Individual
Todd Bennett
Associated Electric Cooperative, Inc.
X
X
X
X
34.
Individual
Mark Thompson
Alberta Electric System Operator
X
35.
Individual
Dan Rochester
Independent Electricity System Operator
X
36.
Individual
Alice Ireland
Xcel Energy
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000438
1. The SDT has developed three new terms to be used with this standard.
• Single Event Frequency Response Data (SEFRD) The individual sample of event data from a Balancing Authority which
represents the change in Net Actual Interchange (NIA), divided by the change in frequency, expressed in MW/0.1Hz.
• Frequency Response Measure (FRM) The median of all Single Event Frequency Response Data observations reported
annually on FRS Form 1.
• Frequency Response Obligation (FRO) The Balancing Authority’s contribution to the total aggregate Frequency
Response needed for reliable operation of an Interconnection assigned by the ERO.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment area?
Summary Consideration: The majority of the commenters disagreed with the proposed definitions for this standard. The primary
concerns cited are the definitions, and the calculations and methodology associated with the definitions, are not clear.
Many commenters expressed concern that the FRM methodology did not allow exclusion of events that, if included, would mask true
frequency response. Commenters also indicated that the ‘average’ and not the ‘median’ should be used for the FRM calculation. Other
observations include inconsistency between the FRM definition and its calculation on FRS Form 1; that proposed language allows the ERO
to unilaterally change FRO value; and that definitions seem more focused on the frequency excursion curve point B value and not point C
value. Suggestions for improving the standard include making it clear that 25 events are used for determining FRM; that definitions should
specify how to calculate each term; and that FRM should take into account nonconforming load.
In response to industry comments, the SDT has deleted the SEFRD definition from the standard; revised the FRO and FRM definitions; and
also improved the calculations. With regards to use of the median for calculating FRM, in general, statisticians use the median as the best
measure of central tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less
influenced by noise in the measurement process. FRS Form 1 has been modified to allow for adjustments to the load and generation. To
allay industry concern over the ERO’s role, the SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to
perform the tasks specified in the standard is necessary.
In regards to concerns over the frequency excursion curve point B value, the SDT explained that while point B measurements have some
data quality challenges to be mastered, point C measurements are not practical at this time for Balancing Authorities in an Interconnection
with more than one Balancing Authority. The SDT intends to study point B and point C relationships of each Interconnection with more
than one Balancing Authority to address this issue during the field trial.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the
BAs. The SDT is evaluating a probabilistic method during the field trial.
Organization
Yes or No
Question 1 Comment
12
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000439
Organization
Patterson Consulting, Inc.
Yes or No
No
Question 1 Comment
From the definition, it is not clear whether SEFRD is a Balancing Authority's 1) data collected for each
frequency event, 2) calculated Frequency Response for a selected event, 3) Net Actual Interchange divided by
the change in frequency for a selected event, or 4) some combination of these interpretations. If the SDT
determines that adjustments to Net Actual Interchange should be made such as adjustments for joint-owned
generation and nonconforming loads as suggested in the field test document, then since this definition requires
Frequency Response to be determined from Net Actual Interchange, this definition would require changing to
allow those adjustments. I suggest defining SEFRD as
"The individual sample of event data from a Balancing Authority that is necessary to calculate its
Frequency Response on FRS Form 1, expressed in MW/0.1Hz."
FRM: This definition and its calculation in FRS Form 1 do not match. FRS Form 1 calculates FRM as "The
median of Single Event Frequency Response Data observations reported annually on FRS Form 1 [for events
external to the Balancing Authority]." (Brackets added for emphasis.) The FRS Form 1 calculation appears more
appropriate based on data collected, since data are not reported and calculations are not adjusted to
compensate for contingencies within the Balancing Authority. Regardless, the difference between definition and
calculation makes it impossible for a Balancing Authority to know the expected performance measure.
FRO: The definition should be changed to remove the opposing concepts of performance and obligation. For
example: FRO is defined to be "The Balancing Authority's contribution to the total aggregate Frequency
Response…" FRM, not FRO, is the Balancing Authority's contribution toward the aggregated Frequency
Response. FRO is
"The Balancing Authority's allocation of the interconnection's required Frequency Response…" or "The
Balancing Authority's required Frequency Response needed for reliable operation of an Interconnection
…”
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT has modified the definition for FRM to read “The median of all the Frequency Response observations reported annually on FRS Form 1.”
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
Santee Cooper
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes.
Change in frequency needs to be more specific, such as the frequency difference between B and A measured
at B. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
13
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000440
Organization
Yes or No
Question 1 Comment
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs
will be held accountable. Also, the definitions do not explain who will determine the value of each BA’s FRO
and the method used to determine the FRO value.Should the definition of Frequency Response Measure be a
median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
LG&E and KU Energy
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between two physical locations B and A measured at B. Frequency
deviation used in the calculation needs to be the deviation observed by the BA performing the calculation.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
standard does not explain who will determine the value of each BA’s FRO nor the method used to determine
the FRO value.
Should the definition of Frequency Response Measure be a median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
14
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000441
Organization
SERC OC Standards Review
Group
Yes or No
No
Question 1 Comment
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between B and A measured at B.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs
will be held accountable.
Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used to
determine the FRO value.
Should the definition of Frequency Response Measure be a median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
The ERO is the responsible party for determining a BA’s FRO. The explanation of who determines the BA’s FRO as-well-as how the BA’s FRO
is determined is now contained in the revised Attachment A.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
South Carolina Electric and Gas
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between B and A measured at B.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
15
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000442
Organization
Yes or No
Question 1 Comment
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”
The review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the
BAs will be held accountable.
Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used to
determine the FRO value.
Should the definition of Frequency Response Measure be a median or mean value? May need to clarify what
FRS stands for.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
The ERO is the responsible party for determining a BA’s FRO. The explanation of who determines the BA’s FRO as-well-as how the BA’s FRO
is determined is now contained in the revised Attachment A.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
MRO's NERC Standards Review
Subcommittee
No
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data and still comply. Average values would prevent this from happening.
Should FRM be clear that it includes at least 25 events in the definition? While that can be garnered from
Attachment A, it is not specified in the Form 1 instructions. We are concerned that the regulators may argue
that 25 events do not apply because an attachment is not part of the standard.
Response: Based on analysis of data the SDT has determined that the median value is the proper method to be used in defining FRM.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of
Requirement.
Midwest ISO Standards
Collaborators
No
that
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data and still comply. Average values would prevent this from happening.
Should FRM be clear that it includes at least 25 events in the definition? While that can be garnered from
Attachment A, it is not specified in the Form 1 instructions. We are concerned that the regulators may argue
16
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000443
Organization
Yes or No
Question 1 Comment
that 25 events do not apply because an attachment is not part of the standard.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
Requirement.
We Energies
No
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data points and still comply. Average values would prevent this from
happening.Should FRM be clear that it includes at least 25 events in the definition? While that can be
garnered from Attachment A, it is not specified in the Form 1 instructions. We are concerned that the
regulators may argue that 25 events do not apply because an attachment is not part of the standard.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
Requirement.
Westar Energy
No
For FRM, why is median used rather than average?
The method in the standard for dsetermining FRM needs to allow for excluding some events due to nonconforming loads, scan rates, intermittent resources, large interchange ramps, etc that may cause the actual
response during the 16 seconds to actually be opposite of the expected response.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
Bonneville Power Administration
No
FRO definition - BPA feels uncomfortable supporting this standard when the ERO is given a blank check to
FRO. The methodology for determining the FRO must be spelled out in detail in order to allow all entities an
opportunity to comment on that methodology.
Response: The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is
17
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000444
Organization
Yes or No
Question 1 Comment
No
In the past tie line flow changes that did not have the expected response for the given frequency deviation
have been excluded from the determination of Frequency Bias. It appears that this exclusion does not carry
forth in the determination of Frequency Response Measure. Therefore, non-conforming loads, intermittent
resources and other events/issues within a Balancing Authority could very well mask its natural frequency
repsonse thereby setting the Balancing Authority's Frequency Bias and its Frequency Response Obligation
incorrectly. Then the Balancing Authority is obligated to respond and will be measured for compliance against
an incorrect value. This being the case, we can support the definition of Single Event Frequency Response
Data but have reservations about Frequency Response Measure and Frequency Response Obligation.
necessary.
SPP Standards Development
Response: The SDT agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
Note that based on other stakeholder concerns, the definition of SEFRD has been deleted.
IRC Standards Review
Committee
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI
for frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange
and does not really reflect the frequency response of a contingent BA. Either the definition needs to be
changed to accommodate single BA Interconnections (such as ERCOT and Hydro Quebec), or regional
variances for them need to be written by the SDT. A BA’s frequency response is composed of load frequency
response, governor response, and, for BAs external to the resource loss, change in Net Interchange. Some
approximation may be achieved by recognizing that the magnitude of frequency deviation is attenuated by
load frequency response and governor response (or frequency activated demand response to reduce load).
The definition of FRM specifies the median of all SEFRD observations reported annually. What is the
technical basis for selecting the median rather than the mean?
The definition of FRO raises questions. The discretely administered determination of FRO described in the
draft Attachment A sets too stringent a requirement; particularly for the smaller Interconnections which may
also have large size generation resources just as do the larger Interconnections.
To “assure that Point C will not encroach on the first step UFLS” is significantly more stringent than existing
and historical performance for those smaller Interconnections. Such assurance will assuredly prove to be
very expensive.In fact, we question the need to define FRM and FRO since they can easily be stipulated in
18
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000445
Organization
Yes or No
Question 1 Comment
the standard requirements. Having them defined and added to the ever-growing NERC glossary creates
unnecessary work to maintain the glossary, unless these terms are used by other NERC standards for which
consistent meaning need to be established. For example, R1 can easily be reworded as:”R1: Each Balancing
Authority shall achieve a median of all Single Event Frequency Response Data observations reported
annually on FRS Form 1 that is equal to or more negative than its contribution obligation to the total
aggregate Frequency Response needed for reliable operation of an Interconnection assigned by the ERO.\
”Similar wording changes can be made to the FRS Form 1 to eliminate the need to define these two
terms.Further, the Attachment A states that the SDT is evaluating a risk based approach to establishing an
Interconnection Frequency Response Obligation which can be based on a probability function. If the N-2
criteria is established, it will be unlikely to be possible to change that if the new approach is viewed as a
reduction in required performance. As an example, in the ERCOT Interconnection, it is recognized that the
present level of required frequency responsive reserve cannot in all scenarios assure that Point C will not
encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the
minimum load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in
ten years based upon actual history. The cost of precluding such an event would be astronomical.
Response: The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the
definitions in the standard so they can be added to the approved NERC Glossary of Terms.
The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the BAs. The SDT is
evaluating a probabilistic approach during the field trial.
ERCOT
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI
for frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange
and does not really reflect the frequency response of a contingent BA. Either the definition needs to be
changed to accommodate single BA Interconnections (such as ERCOT and Hydro Quebec), or regional
variances for them need to be written by the SDT. A BA’s frequency response is composed of load frequency
response, governor response, and, for BAs external to the resource loss, change in Net Interchange. Some
approximation may be achieved by recognizing that the magnitude of frequency deviation is attenuated by
19
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000446
Organization
Yes or No
Question 1 Comment
load frequency response and governor response (or frequency activated demand response to reduce load).
The definition of FRM specifies the median of all SEFRD observations reported annually. What is the
technical basis for selecting the median rather than the mean?
The definition of FRO raises questions. The discretely administered determination of FRO described in the
draft Attachment A sets too stringent a requirement; particularly for the smaller Interconnections which may
also have large size generation resources just as do the larger Interconnections. To “assure that Point C will
not encroach on the first step UFLS” is significantly more stringent than existing and historical performance for
those smaller Interconnections. Such assurance will assuredly prove to be very expensive.
In fact, we question the need to define FRM and FRO since they can easily be stipulated in the standard
requirements. Having them defined and added to the ever-growing NERC glossary creates unnecessary work
to maintain the glossary, unless these terms are used by other NERC standards for which consistent meaning
need to be established. For example, R1 can easily be reworded as:”R1: Each Balancing Authority shall
achieve a median of all Single Event Frequency Response Data observations reported annually on FRS Form
1 that is equal to or more negative than its contribution obligation to the total aggregate Frequency Response
needed for reliable operation of an Interconnection assigned by the ERO.”
Similar wording changes can be made to the FRS Form 1 to eliminate the need to define these two
terms.Further, the Attachment A states that the SDT is evaluating a risk based approach to establishing an
Interconnection Frequency Response Obligation which can be based on a probability function. If the N-2
criteria is established, it will be unlikely to be possible to change that if the new approach is viewed as a
reduction in required performance. As an example, in the ERCOT Interconnection, it is recognized that the
present level of required frequency responsive reserve cannot in all scenarios assure that Point C will not
encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the
minimum load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in
ten years based upon actual history. The cost of precluding such an event would be astronomical.
Response: The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the
definitions in the standard so they can be added to the approved NERC Glossary of Terms.
The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the BAs. The SDT is
20
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000447
Organization
Yes or No
Question 1 Comment
evaluating a probabilistic approach during the field trial.
Progress Energy
No
The proposed definition for SEFRD assumes that there is no change in the Net Scheduled Interchange (NIS)
as a result of the event. However, a dynamic schedule for load or generation based on data obtained with a
two second scan rate will impact the NIS, and therefore the corresponding load or generation response will
offset the change to NIA. Therefore, the definition of SEFRD should replace "NIA" with "change in NIA minus
NIS".
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
Energy Mark, Inc.
No
Comment 1: I agree with the definition of the Single Event Frequency Response Data.
Comment 2: I do not agree that the Frequency Response Measure should be the median of all SEFRD
observations reported annually on FRS Form 1.
Comment 3: The regression values presented on FRS Form 1 have not been calculated correctly.
Comment 4: Since the FRM is going to be used to set the value for the Frequency Bias Setting and the
Frequency Bias Setting represents a straight line though the origin of zero frequency error and zero megawatt
error, the best representation of the data for setting this paramater can be achieved through the use of a
regression.
Comment 5: Only a regression will weight the impact of each SEFRD correctly. The use of median or mean
will not provide the best estimate for use as the Frequency Bias Setting.
Comment 6: The standard has been written to include a samlple size (25) large enough to enable effective
statistical methods of analysis. What justification is there to then ignor those well proven methods and revert
to methods designed to address problems where the sample sizes are insufficient to support sound statistical
analysis methods.
Response: (1) The SDT thanks you for your affirmative response, however several other stakeholders disagreed with the definition of SEFRD and the drafting
team has removed the proposed definition from the revised standard.
(2, 4, 5) With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
(3) The SDT has corrected FRS Form 1.
(6) Research conducted by the Frequency Response Standard Drafting Team (FR SDT) indicated that a Balancing Authority’s FRM will
converge to a reasonably stable value with 20 to 25 samples. The FR SDT as well as the NERC Frequency Response Initiative is evaluating
other methods of FRM. The SDT is not ignoring methods of proven statistical design and the chosen method does require at least 25
21
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000448
Organization
Yes or No
Question 1 Comment
samples.
EKPC
No
These definitions should be revised to include specifics on how to calculate each term.
The FRM calculation method should take into account large non-conforming loads.
A median will not reflect the true nature of the system.
Response: The SDT does not believe the definition should include the specific calculation and therefore has incorporated the calculation methodology in
Attachment A.
The FRM calculation, using FRS Form 1, has been modified to now include adjustments.
Based on analysis of data the SDT has determined that the median value is the proper method to be used in defining FRM.
Duke Energy
No
The definition of SEFRD would conflict with any alternative measurement of frequency response. The SEFRD
makes no provision for the impacts of generation loss experienced by a contingent BA, impacts of nonconforming loads, or impacts of schedule ramps.
The FRM also makes no such provisions. The resulting FRM for a BA experiencing one or more of these
impacts for one or more SEFRDs will be skewed and completely miss the intended measurement of the BA’s
response to frequency excursions. In addition, as it is not yet clear how provision of Frequency Response by
one BA to meet a portion of another BA’s requirement would be achieved, Duke Energy cannot say that a
simple measure of the NIA against the frequency deviation will capture the net of the response desired.
Regarding the definition of FRO, the industry should agree on the methodology which would be used for the
ERO to determine the response desired for the Interconnection that is used for allocation of the FRO, and not
leave it as a parameter subject to change outside of the standards process. The definition is only acceptable if
the assignment by the ERO is based upon a methodology supported by the industry and subject to change
only through the standards process.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
The methodology that the ERO will use for determining the FRO is now outlined in the new Attachment A.
methodology in the balloting phase of the standard.
Associated Electric Cooperative,
Inc.
No
The industry will either accept or reject this
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is
actually an internally calculated value derived from a set of event sample data, and not really a “sample” value
at all. So, I believe the SEFRD definition needs further work.
22
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000449
Organization
Yes or No
Question 1 Comment
2) FRM is defined by undefined terms “FRS” and “FRS Form 1”.
3) FRO – fine
4) FRS - “Frequency Response Survey”
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
FRS Form 1 is the name of the form to be used for calculating FRM.
Alberta Electric System Operator
No
The frequency response has 2 aspects: arresting frequency deviation (Point C) and deviation where
frequency has settled (Point B). The proposed SEFRD and FRM seem all based on the Point B, however the
intention in purpose statement is towards Point C... It is not clear to AESO that these proposed SEFRD and
FRM based on settled frequency deviation (Point B) are technically sufficient to address the concern of
arresting frequency deviation (Point C).
Response: The SDT recognizes that point C is the primary reliability concern. However, while Point B measurements have some data quality challenges to be
mastered, point C measurements are not practical at this time for Balancing Authorities in an Interconnection with more than one Balancing Authority. The SDT
intends to study point B and point C relationships of each Interconnection with more than one Balancing Authority to address this issue.
Independent Electricity System
Operator
No
We concur with the definitions for SEFRD, FRM and FRO but do not believe that the latter two terms (FRM
and FRO) need to be defined since they can easily be stipulated in the standard requirements. Having them
defined and added to the ever-growing NERC glossary creates unnecessary work to maintain the glossary,
unless these terms are used by other NERC standards for which consistent meaning need to be established.
For example, R1 can easily be reworded as:”R1: Each Balancing Authority shall achieve a median of all
Single Event Frequency Response Data observations reported annually on FRS Form 1 that is equal to or
more negative than its contribution obligation to the total aggregate Frequency Response needed for reliable
operation of an Interconnection assigned by the ERO.”Similar wording changes can be made to the FRS
Form 1 to eliminate the need to define these two terms.
Response: Several stakeholders indicated concerns with the definition of SEFRD and the team has removed this definition from the revised standard.
The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the definitions in the
standard so they can be added to the approved NERC Glossary of Terms.
FirstEnergy
Yes
For the definition of FRM, we are not clear as to the rationale for choosing the median value instead of the
mean.
Response: The SDT thanks you for your affirmative response and clarifying comment.
23
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000450
Organization
Yes or No
Question 1 Comment
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
Southern Company
Yes
Comments: The Frequency Response Measure should be based on either the median or average of all
SEFR’s as currently defined. Due to the varied nature of frequency responsive resources online it should
never be based on meeting response on a single event.
Response: The SDT thanks you for your affirmative response and clarifying comment.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
Seattle City Light
Yes
Manitoba Hydro
Yes
ENBALA Power Networks
Yes
NIPSCO
Yes
NorthWestern Energy
Yes
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
FMPP
Yes
American Electric Power
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
24
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000451
2. The SDT has modified the definition for the term Frequency Bias Setting. The current definition and revised definition
are shown below to show the changes proposed.
Frequency Bias Setting
Current Definition in NERC Glossary: A value, usually expressed in MW/0.1 Hz, set into a Balancing Authority ACE
algorithm, that allows the Balancing Authority to contribute its frequency response to the Interconnection.
Revised Definition: A value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz, set into a
Balancing Authority Area Control Error equation that allows the Balancing Authority to contribute its Frequency
Response to the Interconnection.
Do you agree with this new definition for Frequency Bias Setting? If not, please explain in the comment area.
Summary Consideration: Many of the commenters did not agree with the new definition proposed for Frequency Bias Setting. Several
commenters recommend revising the Frequency Bias Setting definition and have offered suggestions for the SDT to consider. In response,
the SDT has revised the Frequency Bias Setting definition to better address concerns raised by industry.
The revised definition is:
Frequency Bias Setting: A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal through secondary
control systems.
Some commenters also questioned if the definition of Frequency Response also needed to be revised, however in reviewing the current
definition of Frequency Response the SDT believes that the current definition is both accurate and appropriate. Concern was also raised
regarding what constitutes variable bias. - Fixed bias is a value approved by the ERO whereas variable bias is a methodology for
determining the Frequency Bias Setting approved by the ERO.
Organization
Santee Cooper
Yes or No
No
Question 2 Comment
We suggest the following changes to the definition: A value, fixed or variable, expressed in MW/0.1 hertz, as
part of a Balancing Authority’s Area Control Error (ACE) equation that influences its Automatic Generation
Control (AGC) to provide frequency response without secondary control action withdrawing the response.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
ENBALA Power Networks
No
: ENBALA would modify the above as follows: A value, (either a fixed or variable Frequency Bias), usually
25
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000452
Organization
Yes or No
Question 2 Comment
expressed in MW/0.1 Hz, set into a Balancing Authority Area Control Error algorithm equation that allows the
Balancing Authority AGC System to ignore the export or import caused by the Primary Frequency Response.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
Westar Energy
No
We propose the following:A value, (either a fixed or variable), expressed in MW/0.1 Hz, set into a Balancing
Authority Area Control Error equation that allows the Balancing Authority to contribute its SECONDARY
Frequency Response to the Interconnection.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
EKPC
No
"Frequency Bias” should not be used in the definition."Usually" can be omitted.
Response: The SDT has modified the definition and “frequency bias” is not used in the revised definition. The definition now reads “A number, either fixed or
variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency
Response contribution to the Interconnection, and discourage response withdrawal through secondary control systems.”
LG&E and KU Energy
No
We suggest the following changes to the definition:
1. Delete the word “usually”
2. Replace “set into” with “as part of”.
3. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is part of its
frequency response usually minutes after the initial event and is dependent upon generation units being on
AGC control and capable of responding.)
4. The suggested changes would result in the following definition:A value, (either a fixed or variable
Frequency Bias), expressed in MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE)
equation that influences its Automatic Generation Control (AGC) to provide its frequency response while
Interconnection frequency is not at its scheduled value.
Response: The SDT did adopt the suggestion to remove, “set into” and replaced this phrase with, “included”, however the team did not adopt the suggestion to
26
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000453
Organization
Yes or No
Question 2 Comment
delete the word, ‘usually’ as the inclusion of this word recognizes that there may be rare instances when the Frequency Bias Setting could be expressed in other
than MW/0.1 Hz. The SDT did not adopt the third proposed change because it can cause confusion since primary Frequency Response cannot be delivered by
AGC.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.”
SERC OC Standards Review
Group
No
We suggest the following changes to the definition:
1. Delete “Frequency Bias” in the parenthetical expression - (“Frequency Bias” should not be used to define
Frequency Bias)
2. Delete the word “usually”
3. Replace “set into” with “as part of” as defined in BAL-001.
4. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is usually minutes
after the initial event and is dependent upon generation units being on AGC control and capable of
responding.)
5. The suggested changes would result in the following definition”A value, fixed or variable, expressed in
MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to continue to provide its frequency response while Interconnection
frequency is not at its scheduled value.
Response: The SDT has modified the definition and “frequency bias” is not used in the revised definition and the phase, “set into” was replaced with “included”.
The SDT did not adopt the suggestion to delete the word, ‘usually’ because there may be rare instances when the Frequency Bias Setting is expressed in other
than MW/0.1 Hz. The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in
a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and
discourage response withdrawal through secondary control systems.”
Midwest ISO Standards
Collaborators
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably
be changed to “maintain”. The goal is to ensure AGC does not withdraw frequency response and that it is
maintained while frequency is depressed. We are not sure if Frequency Response has a precise enough
definition and it is part of the definition of Frequency Bias Setting. The definition of Frequency Response
really just reflects how it is measured. It does not define what it really is which is the dynamic response of
load, generation, and other frequency responsive devices to a perturbation in frequency.
27
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000454
Organization
Yes or No
Question 2 Comment
The drafting team should also consider resolving the definition of Frequency Bias. Is it needed? It is often
confused with Frequency Bias Setting and is often used interchangeably with Frequency Response even
though the meanings are slightly different.
Response: The SDT has modified the definition of Frequency Bias Setting. The definition now reads “A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the
term “contribution” better describes the action that has taken place.
The SDT has reviewed the current definition of Frequency Response and believes that the current definition is both accurate and appropriate.
We Energies
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably
be changed to “maintain.” The goal is to ensure AGC does not withdraw frequency response and that it is
maintained while frequency is depressed. We are not sure if Frequency Response has a precise enough
definition and it is part of the definition of Frequency Bias Setting. The current NERC Glossary definition of
Frequency Response really just reflects how it is measured, it does not define Frequency Response.
Frequency Response is the dynamic real power response of load, generation, and other devices to a
perturbation in frequency.
The drafting team should also consider resolving the definition of Frequency Bias. Is it needed? It is often
confused with Frequency Bias Setting and is often used interchangeably with Frequency Response even
though the meanings are slightly different.
Response: The SDT has modified the definition of Frequency Bias Setting. The definition now reads “A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the
term “contribution” better describes the action that has taken place.
The SDT has reviewed the current definition of Frequency Response and believes that the current definition is both accurate and appropriate.
SPP Standards Development
No
We would suggest inserting 'secondary' in front of Frequency Response at the end of the sentence and delete
'Frequency Bias' following 'variable' at the beginning of the sentence.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the modified definition is more appropriate than the recommended change. The
SDT does not believe it is necessary to differentiate between primary and secondary Frequency Response in the definition.
IRC Standards Review
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the
28
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000455
Organization
Yes or No
Committee
Question 2 Comment
context of these requirements? Should it be Frequency Bias Setting, instead?
“Fixed” seems to be straightforward, but what is “variable”?
How often must Frequency Bias Setting change in order to be considered to be “variable”?
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
If the ERO provides the Frequency Bias Setting then it is considered fixed. If the ERO accepts a methodology for determining the Frequency Bias Setting then it is
considered variable.
ERCOT
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the
context of these requirements? Should it be Frequency Bias Setting, instead? “Fixed” seems to be
straightforward, but what is “variable”? How often must Frequency Bias Setting change in order to be
considered to be “variable”?
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
If the ERO provides the Frequency Bias Setting then it is considered fixed. If the ERO accepts a methodology for determining the Frequency Bias Setting then it is
considered variable.
Progress Energy
No
A bias, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority's Area
Control Error equation to account for the Balancing Authority's Frequency Response contribution to the
interconnection, and prevent response withdrawal through secondary control systems.
The changes suggested are to clarify that biasing of the ACE equation "allow[s]" primary frequency response
to continue beyond the initial event window by accounting for it in the ACE input to secondary control systems
(i.e. AGC). It's important to note that Primary Frequency Response will occur no matter what the Bias value is
set to in the ACE equation, and biasing "supports" the response until the frequency is restored".
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the revised definition agrees with your comment related to supporting the
response until frequency is restored. The SDT also believes that it is impossible to “prevent” withdrawal and that you can only try to discourage withdrawal.
NIPSCO
No
Frequency Bias and Frequency Response are not the same thing and that may be why "F" & "R" were not
29
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000456
Organization
Yes or No
Question 2 Comment
capitalized in the present definition.
I think the word "secondary" should appear per R2 finishing something like this: "to contribute to secondary
(non-immediate)Interconnection frequency control.", removing Frequency Response altogether.(I do
understand that you are bringing the FR and Bias closer together).
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the modified definition is more appropriate than the recommended change. The
SDT does not believe it is necessary to differentiate between primary and secondary Frequency Response in the definition.
Energy Mark, Inc.
No
Comment 7: The definition should be:"A value, (either a fixed or variable Frequency Bias), usually expressed
in MW/0.1 Hz, set into a Balancing Authority Area Control Error equation that indicates to the Balancing
Authority its contribution of Frequency Response to the Interconnection.
Comment 8: The Frequency Bias Setting does not allow or disallow the Frequency Response to be
contributed. The BA will contribute its natural Frequency Response to the interconnection through the
independent actions of its loads and generators. The only influence that the Frequency Bias Setting has is
that it causes the AGC System, and hopefully other outer-loop control systems, to include that natural
Frequency Response when developing control actions to implement through AGC in response to BA
balancing requirements in a time frame well after the Frequency Response has been provided by the
independent actions of its loads and generators.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
The SDT agrees with comment #8.
American Electric Power
No
If “the proposed standard’s intent is to collect data needed to accurately analyze existing Frequency
Response, set a minimum Frequency Response obligation, provide a uniform calculation of Frequency Bias
Settings that transition to values closer to Frequency Response, and encourage coordinated AGC operation”,
it appears the current and stated definition is precluding the process for determination of the Frequency Bias
Setting itself.
I believe it is too early to state in definition the frequency bias setting to be based on MW/0.1 Hz, when this
appears to be more of the expected response.
Using the word usually does not appear to be defining anything.To eventually get to an acceptable
performance measure with reliability basis the project needs to be expanded to also address associated
30
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000457
Organization
Yes or No
Question 2 Comment
governor droop issues, which inherently affect response.
When the current definition references using “either a fixed or variable Frequency Bias”, it does not state
whether or not to be applied in the calculation to either load or generation. The current Standard uses 1% of
yearly estimated peak demand for BAs that serve load, when the actual load at time of disturbance could be
greatly different. Response is more directly related to the amount of Generation on-line and active AGC within
the BA at time of trip.MW/0.1 Hz states more of expected result of response than defining Frequency Bias
Setting.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”The “MW/0.1 Hz” term represents the units of Frequency Bias and is not intended to reference
magnitude.
Issues dealing with governor droop are outside of the scope of the industry approved SAR.
The SDT agrees with the last comment which is why the SDT also supports using a variable bias where appropriate.
Duke Energy
No
Duke Energy would suggest not using “Frequency Bias” in the definition of “Frequency Bias Setting”.
In addition, Duke Energy would like to point out that ACE does not allow Frequency Response; response will
occur with or without the ACE equation. The Frequency Bias Setting is needed so that the AGC does not
negate what may be provided in frequency response. The bias component of ACE provides the feedback so
that a BA may sustain the intended amount of response with secondary control as long as Actual Frequency
deviates from Scheduled Frequency. Duke Energy would suggest the following:”A fixed or variable value
usually expressed in MW/0.1 Hz, set into a Balancing Authority Area Control Error equation to bias the control
of resources so that Interconnection frequency is driven toward the Scheduled Frequency.”
Response: The term Frequency Bias has been removed from the definition.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.”
Associated Electric Cooperative,
Inc.
No
SEFRD - I had to read this definition several times because “The individual sample of event data” is actually
an internally calculated value derived from a set of event sample data, and not really a “sample” value at all.
So, I believe the SEFRD definition needs further work.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
31
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000458
Organization
Yes or No
MRO's NERC Standards Review
Subcommittee
No
Southern Company
Yes
Question 2 Comment
Frequency Bias SettingA value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz,
set into a Balancing Authority Area Control Error algorithm equation that allows the Balancing Authority to
contribute its frequency Frequency rResponse to the Interconnection.
Comments: Not sure the word “allows” is the right word. Perhaps use something in terms of preventing
withdrawal of Primary Frequency Response with words like “...equation that prevents the withdrawal of the
Balancing Authority’s Primary Frequency Response to the Interconnection.”
Response: The SDT thanks you for your affirmative response and clarifying comments. The revised definition does not use the word, “allows.”
The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to
account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal through secondary control
systems.”
FirstEnergy
Yes
Although we support the definition, we suggest the word “contribute” be changed to “maintain”.
Response: The SDT thanks you for your affirmative response and clarifying comments.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the term “contribution” better describes the
action that has taken place.
Patterson Consulting, Inc.
Yes
Beacon Power Corporation
Yes
NorthWestern Energy
Yes
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
32
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000459
Organization
Yes or No
Alberta Electric System Operator
Yes
Independent Electricity System
Operator
Yes
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
South Carolina Electric and Gas
Question 2 Comment
We suggest the following changes to the definition: 1. Delete “Frequency Bias” in the parenthetical expression
- (“Frequency Bias” should not be used to define Frequency Bias)
2. Delete the word “usually”
3. Replace “set into” with “as part of” as defined in BAL-001.
4. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is part of its
frequency response usually minutes after the initial event and is dependent upon generation units being on
AGC control and capable of responding.)
5. The suggested changes would result in the following definition”A value, fixed or variable, expressed in
MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value.
Response: The term, “Frequency Bias” was deleted, the phrase, “set into” was replaced with, “included in”. The other suggestions were not adopted. The SDT
has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s
Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal
through secondary control systems.” The SDT believes that the modified definition addresses your concerns but provides for additional clarity as to the action
that has taken place.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
33
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000460
Organization
Yes or No
Question 2 Comment
Response: Please refer to the SDT response to Question 17.
34
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000461
3. The proposed purpose statement in the draft standard is: To require sufficient Frequency Response from the Balancing
Authority to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and
supporting frequency until the frequency is restored to schedule. To provide consistent methods for measuring Frequency
Response and determining the Frequency Bias Setting.
Do you agree with this purpose? If not, please explain in the comment area.
Summary Consideration: Several of the commenters agree with the purpose statement of the draft standard as written. Most of the
feedback received disagreeing with the purpose statement reflects general comments and suggestions for the SDT to consider. A major
concern identified is that the minimum level of Frequency Bias Setting established needs to be determined based on extensive data
analysis of field trial results. Some commenters even stated that the standard should not be revised until the field trial is completed,
performance criteria and measures determined, and results vetted by industry. Several commenters expressed concern with making the
Balancing Authority the only entity responsible for maintaining interconnection frequency and arresting frequency decline; with an
observation that the purpose statement presumes that each Balancing Authority must have generation online to meet a predetermined
frequency response obligation. It was pointed out that on occasion small Balancing Authorities may not have generation online and instead
rely on load regulation and energy agreements to meet their energy needs. Another commenter indicated that since NERC and FERC have
differentiated Frequency Response from Frequency Regulation, the standard should only apply to unplanned contingencies that occur.
In response to these general comments the SDT notes that the minimum Frequency Response level used during the field trial uses a
deterministic approach and the actual level of Frequency Response required in the final version of the draft standard will be based on field
trial results. Issues involving governor droop, dead-band settings, and governor operation are outside the scope of the project’s approved
SAR. The purpose statement does not mandate generation dispatch for Frequency Response. This standard only prescribes a minimum
Frequency Response obligation for reliable BES operation. Each entity must determine how to meet its Frequency Response obligation
using existing resources and agreements.
Another commenter noted that the purpose statement addresses several concepts that do not share a common timeframe. In response,
the SDT has revised Attachment A to explain the relationship for the different time frames associated with these concepts.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 3 Comment
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012
35
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000462
Organization
Yes or No
Question 3 Comment
Modifications to this schedule require both NERC and FERC approval.
Midwest ISO Standards
Collaborators
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
We Energies
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis, field trial data, the Frequency Response
Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical conference,
and the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
LG&E and KU Energy
No
The proposed purpose statement as provided in this question is not the same as the purpose statement for
BAL-003-1 as posted on the Project 2007-12 page of the NERC website. The posted purpose on the NERC
website is:To require sufficient Frequency Response from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the
frequency is restored. To schedule and provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.The version posted in the question appears to correct errors in the
last sentence of the purpose statement given in the project page.
We do not agree with the purpose statement as posted on the project page.In addition, we suggest the
following edits to what appears to be a corrected purpose statement as provided in this question:To require
sufficient Frequency Response from the Balancing Authority to maintain Interconnection Frequency within
predefined bounds by arresting frequency deviations due to contingencies on the interconnected BES and
supporting frequency until the frequency is restored to schedule. To provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting.
As NERC/FERC has differentiated Frequency Response from Frequency Regulation, the standards
36
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000463
Organization
Yes or No
Question 3 Comment
addressing Frequency Response should clearly be related to unplanned contingencies occurring on the
interconnected BES.
Response: The SDT believes adequate Frequency Response is important during both normal and emergency operations however it is easier to measure
Frequency Response during a contingency which is why the SDT favors this rationale.
IRC Standards Review
Committee
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. We request that the results of the Field Trial should be published and
discussed BEFORE any changes are made. The standard should be put into place later; it is premature at
this time. Since this is to be a data gathering process to be used to determine appropriate performance
parameters, the purpose statement of the Field Trial should be changed to read as follows:To determine
require sufficient Frequency Response arranged by from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by responding to and arresting frequency deviations and supporting
frequency until the frequency is restored to schedule. To identify and establish provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting and Frequency Response
Obligation.We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon
Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
37
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000464
Organization
Yes or No
Question 3 Comment
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
ISO New Engand Inc.
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. The standard should be put into place later; it is premature at this time.
Since this is to be a data gathering process to be used to determine appropriate performance parameters, the
purpose statement of the Field Trial should be changed to read as follows:To determinerequire sufficient
Frequency Response arranged by from the Balancing Authority to maintain Interconnection Frequency within
predefined bounds by responding to and arresting frequency deviations and supporting frequency until the
frequency is restored to schedule. To identify and establishprovide consistent methods for measuring
Frequency Response and determining the Frequency Bias Setting and Frequency Response Obligation.We
should not write the new standard and its requirements until this Field Trial work has been accomplished; to
do so possibly would result in difficulty changing the standard requirements based upon Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
38
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000465
Organization
Yes or No
Question 3 Comment
Modifications to this schedule require both NERC and FERC approval.
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
ERCOT
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. We request that the results of the Field Trial should be published and
discussed BEFORE any changes are made. The standard should be put into place later; it is premature at
this time. Since this is to be a data gathering process to be used to determine appropriate performance
parameters, the purpose statement of the Field Trial should be changed to read as follows:To determine
require sufficient Frequency Response arranged by from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by responding to and arresting frequency deviations and supporting
frequency until the frequency is restored to schedule. To identify and establish provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting and Frequency Response
Obligation.We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon
Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
39
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000466
Organization
Yes or No
Question 3 Comment
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
Kansas City Power & Light
No
This purpose statement presumes that each Balancing Authority (BA) will have generation online to meet a
predetermined frequency response obligation. There are many small BA’s that do not have any generation
online and rely on load regulation agreements and energy agreements to provide their energy needs during
parts of the year. This purpose statement would not allow a BA to operate without generation online.
Response: The purpose statement does not mandate generation dispatch for Frequency Response. This standard only prescribes a minimum Frequency
Response obligation for reliable BES operations. Each entity must determine how to meet this obligation using existing resources and agreements.
NIPSCO
No
Yes, "Interconnection frequency", small "f".
Response: The SDT thanks you for this comment and has corrected the error.
American Electric Power
No
AEP believes the statement should read “To require sufficient Frequency Response from governors and AGC
of Generators within the Balancing Authority to maintain Interconnection Frequency within predefined bounds
by arresting frequency deviations and supporting frequency until the frequency is restored to schedule.To
provide consistent methods for measuring Frequency Response from governors and AGC of Generators
within the Balancing Authority for determining the overall Frequency Bias Setting threshold.Since
Generators are directly responsible for response, applicability must be added to Generator Operators.
Response: The drafting team disagrees with this recommendation because the FERC Order 693 requires a technology neutral performance standard for the purpose
of providing Frequency Response.
Patterson Consulting, Inc.
No
The purpose should not expect Frequency Response to maintain frequency beyond a few minutes, perhaps
15 minutes for example. This purpose statement suggests the requirements will be "...to maintain
Interconnection Frequency within predefined bounds by arresting frequency deviations and support frequency
until the frequency is restored to schedule..." The phrase "until the frequency is restored to schedule" is
problematic since regulation must bring frequency to schedule. Frequency Response, and the associated
requirements, should not be expected to substitute for poor regulation beyond the first few minutes.
Response: The focus of the standard is to establish sustainable primary frequency control which can seamlessly coordinate with secondary frequency control for
maintaining system frequency.
40
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000467
Organization
Independent Electricity System
Operator
Yes or No
Question 3 Comment
No
We do not have any issue with the general intent of the scope statement, but have a difficulty in seeing the
BA being the only entity held responsible for maintaining interconnection frequency and arresting frequency
deviations. When there is a sudden and sizable change to system resource or demand, the system frequency
will change. The first response to such deviation would be the generators’ governors. This will provide a
mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick in to
supplement the mitigation need. To hold only the BA responsible for maintaining interconnection frequency
arresting frequency deviations would be only part of the solution. The industry needs to have a discussion to
determine who should be held responsible for providing governor responses, and by what mechanism.
We suggest that BAL-003 development be withheld until this discussion takes place and a decision is made
on who and how the governor response shall be provided.
Response: The SDT thanks you for your comment. This issue concerning the BA being the only entity being held responsible has been discussed and the SDT
understands your concern. However, governor droop requirements, dead-band settings and governor operation are outside the scope of the project approved
SAR. The SDT believes that the Generator Verification standards will help address these concerns. The SDT encourages entities to develop a SAR to address
generators.
For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of response required may be established in the final
version of the standard using field trial information obtained.
The SDT does not agree with your comment concerning withholding the development of a standard addressing Frequency Response. The development of a
standard addressing Frequency Response was identified in FERC Order 693. FERC further directed the ERO to finalize a standard addressing Frequency Response
in an order in February 2010 within six (6) months which they later granted an extension. The project schedule adopted for the development of the BAL-003
standard has been approved by the FERC and includes filing a standard by May, 2012. Modifications to this schedule would require both NERC and FERC
approval.
ENBALA Power Networks
Yes
ENBALA strongly agrees that a Frequency Response standard is necessary to ensure reliable operation of
the bulk power system. We fully support all efforts to understand the declining trend, and the development of
accurate models, of Frequency Response in each Interconnection.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Manitoba Hydro
Yes
The new more likely improved method of measuring Frequency Response is welcome. This should be an
improvement over the existing methods of using 1% of projected peak load, or average of DCS events.
Calculating projected peaks leave lots of room for error and limiting calculations to only DCS events likely
does not reflect accurate BIAS.
41
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000468
Organization
Yes or No
Question 3 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Alberta Electric System Operator
Yes
The purpose statement mentioned arresting deviation, restored to schedule and frequency bias setting,
which are all at different time frames. The AESO suggests that NERC provide some clarification of the
relationships for the different time frames.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Refer to Attachment A for clarification of the relationships for the different time frames.
Duke Energy
Yes
Seattle City Light
Yes
Santee Cooper
Yes
FirstEnergy
Yes
Bonneville Power Administration
Yes
SPP Standards Development
Yes
SERC OC Standards Review
Group
Yes
Arizona Public Service Company
Yes
Southern Company
Yes
Progress Energy
Yes
NorthWestern Energy
Yes
Energy Mark, Inc.
Yes
Beacon Power Corporation
Yes
42
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000469
Organization
Yes or No
Westar Energy
Yes
FMPP
Yes
EKPC
Yes
South Carolina Electric and Gas
Yes
Associated Electric Cooperative,
Inc.
Yes
Northeast Power Coordinating
Council
Question 3 Comment
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
43
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000470
4. Requirement 1 identifies a minimum level of Frequency Response.
R1. Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO).
Do you agree with the concept that a Balancing Authority should be required to achieve a minimum level of Frequency
Response and the method for measurement? If not, please explain in the comment area.
Summary Consideration: Most commenters supported the concept however a significant majority did not agree with the method for
measurement. In general commenters indicated the sample size of 25 events for determining FRM is too small; insufficient information
was provided to address the use of variable bias; the FRM and FRO definitions were unclear with questionable determination methods; and
the standard should reference Reserve Sharing Groups. Some commenters also indicated that the measure may not apply to a single BA
interconnection; that the draft standard dictated how compliance is provided with respect to Attachment A and FRS Form 1 references;
that requirements would not allow a BA to operate without generation online; and expressed concern that the BA may not own and operate
resources yet will still have the compliance obligation.
The SDT is currently evaluating a probabilistic method for determining the FRO. After consideration of industry comments, the SDT
converted Attachment A into two documents - a calculation methodology included with the standard, and a separate supporting document
providing requirement rationale. The SDT revised the definitions for FRO & FRM; incorporated Reserve Sharing Groups into the draft
standard; modified FRS Form 1 to allow for adjustments; and clarified how an entity is to show compliance. The SDT also provided an
explanation addressing the use of Variable Bias and provided an administrative procedure for the ERO’s FRO determination.
R1. Each Balancing Authority or Reserve Sharing Group (RSG) shall achieve an annual Frequency Response Measure (FRM) (as detailed in Attachment
A and calculated on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each BA or RSG to maintain an adequate level of Frequency Response in the Interconnection.
Organization
Santee Cooper
Yes or No
No
Question 4 Comment
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
LG&E and KU Energy
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
44
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000471
Organization
Yes or No
Question 4 Comment
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
SERC OC Standards Review
Group
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
South Carolina Electric and Gas
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
MRO's NERC Standards Review
Subcommittee
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outline in NERC’s October 25, 2010 compliance filing.
The effects of the nonconforming load should be considered in the calculation of the frequency response
obligation in order to get accurate results.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
45
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000472
Organization
Yes or No
Question 4 Comment
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the project
schedule will require both NERC and FERC approval.
The deterministic allocation method does not consider the effects of nonconforming load.
Midwest ISO Standards
Collaborators
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outline in NERC’s October 25, 2010 compliance filing.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the project
schedule will require both NERC and FERC approval.
We Energies
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis, field trial data, the Frequency Response
Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical conference,
and the plan outline in NERC’s October 25, 2010 compliance filing.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the
project schedule will require both NERC and FERC approval.
Bonneville Power Administration
No
BPA agrees that there should be a minimum level of Frequency Response, but disagree with the way the
measure is obtained in the requirement.
o R1 - BPA suggests replacing “achieve” with “calculate”. Achieve: indicates it is a performance.
o R1 - BPA does not agree with the requirements in Attachment A not being in the standard. These should
not be modified without full review and voting by members.
o R1 - BPA believes that there should be more description on Variable Bias. What variable bias number
should we use: average, minimum, peak for the event? BPA feels that the peak bias of each event would be
appropriate.
Response: The SDT believes the intent of the standard is for each BA to “achieve” its Frequency Response Obligation.
46
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000473
Organization
Yes or No
Question 4 Comment
The SDT is not incorporating additional standard requirements by means of Attachment A information however the SDT recognizes the need to convert
Attachment A into two documents. The first document will remain part of the standard as Attachment A and describe the calculation methodology utilized. The
second document will explain the rationale for the requirements as supplemental standard information.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT agrees Variable Bias
requires more description and will review this concern during the field trial.
IRC Standards Review
Committee
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be
achieved. However, the measure as described does not apply to all Interconnections. It does not apply to
single BA Interconnections such as ERCOT and Hydro Quebec.
This requirement should be added later-not included now; and it should clarify what the BA must do and what
the response providers must do. BAs do not own and operate the resources. An entity which does own or
operate the resources may also be registered as a BA, but an entity which does not own or operate resources
may also be registered as a BA. Therefore, it is important to detail what a BA must do and also to detail what
the resource owner or operator must do. The resource owner may be registered as a GO or a TO or even a
DP. The resource operator may be registered as a GOP, a TOP, or a LSE. The BA must establish an
operations plan, using data provided to it by the resource owners and or operators, that will meet the
performance requirements. The BA must then deploy the proper amount of response through AGC or verbal
instructions to supplement the automatic responses that the resources will provide, must calculate the actual
responses after-the-fact, and report the performance as required. The resources must, as standards already
provide, comply with the deployments and instructions provided by the BA. However, if an entity which is
functioning as a BA does not own its resources, nor does it directly operate those resources, the BA cannot
ensure the achievement. The standard must not create an organizational or contractual arrangement that
dictates how the compliance is provided. It should state what must be done, not how. If entities choose to
write and enter into such arrangements, that should be permissible, but not required.
Specific to R1, the wording does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not
seem to correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
Response: This standard is intended to apply to all Interconnections. The SDT has modified the definition for FRO to read, “The Balancing Authority’s share of
the required Frequency Response needed for the reliable operation of an Interconnection.”
The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must determine how to
meet this minimum obligation.
FRS Form 1 has been revised to allow for adjustments.
ERCOT
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be
achieved. However, the measure as described does not apply to all Interconnections. It does not apply to
47
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000474
Organization
Yes or No
Question 4 Comment
single BA Interconnections such as ERCOT and Hydro Quebec. This requirement should be added later-not
included now; and it should clarify what the BA must do and what the response providers must do. BAs do
not own and operate the resources. An entity which does own or operate the resources may also be
registered as a BA, but an entity which does not own or operate resources may also be registered as a BA.
Therefore, it is important to detail what a BA must do and also to detail what the resource owner or operator
must do. The resource owner may be registered as a GO or a TO or even a DP. The resource operator may
be registered as a GOP, a TOP, or a LSE. The BA must establish an operations plan, using data provided to
it by the resource owners and or operators, that will meet the performance requirements. The BA must then
deploy the proper amount of response through AGC or verbal instructions to supplement the automatic
responses that the resources will provide, must calculate the actual responses after-the-fact, and report the
performance as required. The resources must, as standards already provide, comply with the deployments
and instructions provided by the BA. However, if an entity which is functioning as a BA does not own its
resources, nor does it directly operate those resources, the BA cannot ensure the achievement. The
standard must not create an organizational or contractual arrangement that dictates how the compliance is
provided. It should state what must be done, not how. If entities choose to write and enter into such
arrangements, that should be permissible, but not required. Specific to R1, the wording does not correspond
to the figures shown in the FRS (Form 1) in that the FRM (the median) is -14.5 whereas the FRO is -15.8. The
FRO is more negative than the FRM, which does not seem to correspond to what’s stipulated in R1 (FRM to
be equal or more negative than its FRO).
Response: This standard is intended to apply to all Interconnections. The SDT has modified the definition for FRO to read, “The Balancing Authority’s share of
the required Frequency Response needed for the reliable operation of an Interconnection.”
The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must determine how to
meet this minimum obligation.
FRS Form 1 has been revised to allow for adjustments.
Kansas City Power & Light
No
This requirement presumes that each Balancing Authority (BA) will have generation online to meet a
predetermined frequency response obligation. There are many small BA’s that do not have any generation
online and rely on load regulation agreements and energy agreements to provide their energy needs during
parts of the year. This requirement would not allow a BA to operate without generation online.
Under Requirement 1, item 2a in Attachment A suggests governor deadband as 36MHz (Megahertz).
Suggest what is intended is 36mHz (millihertz).
The Frequency Response Obligation determination for the interconnection as described in Attachment A is a
crude method and will result in obligations that will exceed the FRO that is intended. This will result in
additional cost to BA’s that is unnecessary to achieve the purpose of maintaining sufficient generation online
to arrest frequency degradation events caused by loss of generating resources.
48
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000475
Organization
Yes or No
Question 4 Comment
The current NERC method for calculating a BA’s actual frequency response are inaccurate and provide
misleading guidance in the actual frequency response of a BA. These methods need considerable
improvement before any attempts to hold a BA to an expected level of frequency response as this proposal
has stated.
Response: The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must
determine how to meet this minimum obligation.
The SDT has removed the reference to governor deadband.
The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of the draft
standard may be based on analysis of data obtained from the field trial. The SDT is also evaluating a probabilistic method for determining the FRO.
The SDT has modified FRS Form 1 to correctly calculate Frequency Response.
Southern Company
No
Comments: Proposed Standard
Comment 1: BAL-003-1, Requirement R1. The requirement should be made less prescriptive by removing
references to Attachment A and FRS Form 1. The responsible entity should understand the fundamental and
basic requirement - to achieve a Frequency Response Measure. Where the methodology is specified or how
the BA is supposed to achieve it should be a matter of compliance and/or implementation and not a part of
the basic requirement. Proposed language is as follows: Each Balancing Authority shall achieve a Frequency
Response Measure (FRM) that is equal to or more negative than its Frequency Response Obligation (FRO).
Response: The SDT believes that Requirement 1 needs to reference FRS Form 1 in order for the calculation methodology to be consistent for all interconnections
and has removed the reference to Attachment A. The SDT has also revised FRS Form 1 to correctly calculate Frequency Response and to allow for adjustments.
Progress Energy
No
Progress Energy believes the Eastern Interconnection does not have the same issues with frequency
experienced in the other two interconnections, and that load response is significant enough in the
interconnection to arrest and stabilize frequency as long as BAs do not withdraw that effect (accurate biasing
of the ACE equation).
We also believe this standard should reference standrd PRC-024 related to accurate relay settings to allow
out of bounds operations related to frequency and voltage deviations.
Response: Under certain system conditions the response of frequency sensitive load to a frequency excursion may be sufficient to arrest and stabilize frequency
following an event. The eastern interconnection may also demonstrate greater stability as compared to the other interconnections. However, frequency stability
is not assured to be achieved in this manner for all system conditions, even for the eastern interconnection irrespective of Frequency Bias setting accuracy.
The intent of BAL-003 is independent of PRC-024 intent. Specifically the purpose of BAL-003 is to better match a Balancing Authority’s Frequency Bias Setting to
its Frequency Response Characteristic, which should also reduce the probability for UFLS activation. The purpose of PRC-024 is to ensure generation remains
49
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000476
Organization
Yes or No
Question 4 Comment
connected during a tolerable frequency or voltage excursion. Furthermore, consideration of voltage deviations is outside the scope of the approved project.
NIPSCO
No
Yes and no, similar to BAL-002 I think this should read "Each Balancing Authority or Reserve Sharing Group
shall ....., With so many BA's I believe the RSGs will be play a big role in this compliance ... This comment
applies to only R1,
Response: The SDT has revised Requirement R1 to reference Reserve Sharing Groups.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The SDT agrees that compliance should not be based on an individual event but based on a series of events.
Energy Mark, Inc.
No
Comment 9: I agree that each BA should be required to provide a minimum level of Frequency Response to
provide for its share of the total Frequency Response required for interconnection reliability.
Comment 10: I also agree with the methods used to measure SEFRD subject to my comments on FRS Form
1.
Comment 11: I do not agree that the method suggested for setting the FRO will achieve the desired goal of
maintaining interconnection reliability. The measurement method offered only evaluates the supply of
Frequency Response. It does not evaluate the demand (need) for Frequency Response. Since frequency
error is the difference between the demand and supply any effective measure for maintaining reliability due to
frequency error must include both the demand and supply parts of this balance. As a consequence, the
method will be blind to changes (good or bad) in the demand for Frequency Response. Changes in the
demand for Frequency Response will require subsequent changes in the supply for Frequency Response that
this standard fails to address until the following year and leaves the interconnection at risk for unreliable
operation.
Comment 12: The requirements associated with Frequency Response as defined in this standard will not
assure interconnection reliability. Frequency Response is a two part service. The first part of this service is
the rate at which energy is supplied in proportion to frequency error. This first part is commonly represented
as the Frequency Response and the corresponding Frequency Bias Setting. The second part of the service
is the amount of capacity that the BA stands ready to supply at this stated proportion in response to frequency
error. Failure to effectively specify and measure the amount of capacity that the BA stands ready to supply at
the stated proportion could put the interconnection at reliability risk when the required amount of capacity is
50
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000477
Organization
Yes or No
Question 4 Comment
not included in the operating plan.
Response: Comment 11 - The FRO provides a target for ensuring robust frequency response is achieved by all Balancing Authorities. Both FRO and FRM values
are considered by the algorithm determining the Frequency Bias Setting for the next year. While there is mutual dependence between supply and demand with
respect to frequency response, the resultant frequency deviation is more important than the cause as it is the effect on system operations realized that
determines the magnitude of control response required for reliability. It is expected robust frequency control will yield smaller frequency deviations during events
and in turn require less incremental control response than currently realized for maintaining frequency.
Comment 12 – Capacity is an important yet independent consideration. First, responsive robust control is necessary. Next, the Frequency Bias Setting must
better approximate the Frequency Response Characteristic for improved control response. Adequate capacity is an implicit assumption for reliable grid operation.
Hydro-Quebec TransEnergie
No
The proposed method is good to measure frequency response at point “B”. However, point “C” is not taken in
consideration in this measure.
As for the FRO, a N-2 criteria is more stringent for an Interconnection with less units than a large
Interconnection. The risk associated with coincidental events is much higher in a large Interconnection. For
this reason, we believe that N-1 criteria should be considered for a small Interconnection like Quebec.
Response: The SDT agrees that the size of an Interconnection can make a difference in Frequency Response. This standard is intended to apply to all
Interconnections. The SDT has modified the definition for FRO. The definition now reads “The Balancing Authority’s share of the required Frequency Response
needed for the reliable operation of an Interconnection.” A smaller Interconnection can and should request a variance if needed.
Westar Energy
No
The lagging measure is a concern. The ERO should be required to provide an updated proposed/possible list
of frequency events monthly so BA's can determine their FRM through out the year so corrective action can
be taken if needed.Prior year events should be excluded (just to get to 25 events). This could result in begin
non-compliant twice for the same events.
Response: The SDT recommends posting selected events quarterly to give BAs time to evaluate their compliance. The SDT has evaluated the method for
assessing compliance and has determined compliance is best demonstrated on a quarterly basis using a rolling 12 months data period.
FMPP
No
The proposed Requirement 1 states: Each Balancing Authority shall achieve a Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative than its
Frequency Response Obligation (FRO).Attachment A states that if a year occurs in which there are not 25
events that meet the remaining criteria below, then the most recent 25 events (as defined below) will be used
for determination of an entity’s compliance with the FRM requirement and storage of SEFRD.
Problem - by using events from last year to determine an entity’s compliance with a Requirement for this year
puts the entity in double jeopardy for last year’s events, which were already used for compliance for last year.
51
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000478
Organization
Yes or No
Question 4 Comment
Response: The SDT recommends posting selected events quarterly to give BAs time to evaluate their compliance. The SDT has evaluated the method for
assessing compliance and has determined compliance is best demonstrated on a quarterly basis using a rolling 12 months data period.
EKPC
No
The method for measurement is not detailed.
Also, the method indicates a lagging indicator. Hows is the BA to ensure its compliance through the year?
Response: FRS Form 1 now details the measurement method.
An entity can use the Criteria for Selecting Events to confirm compliance during the year. The SDT recommends posting selected events quarterly to give BAs
time to evaluate their compliance.
ISO New Engand Inc.
No
We have a difficulty seeing the BA being the only entity held responsible for maintaining interconnection
frequency and arresting frequency deviations. When there is a sudden and sizable change to system
resource or demand, the first response to a frequency deviation caused by this change would be the
generators’ governors. This will provide a mitigating effect for the immediate seconds up to minutes. The
frequency bias setting will then kick in to supplement the mitigation need. The governors are owned by the
Generator Owners; the BAs do not own these facilities and hence can do little to address frequency response
during this initial period.
Response: While the SDT has described possible methods for obtaining Frequency Response compliance with this standard, the SDT is not prescribing a
particular method for entities to implement. Governor operation is outside the scope of the approved project SAR. Any entity may submit a SAR request to
modify or create a standard.
American Electric Power
No
Between the definition and the requirement in Attachment A, it is unclear if FRM is a reliability-supported,
performance-based measure, or instead, if it is a calculated number based on previous performance. As
written, it is unclear if this is a performance-based requirement, or simply a calculation that should be utilized
in some way. In any event, the requirement needs to be re-written to clarify its intent.
Response: The SDT has modified the definition of FRM to read “The median of all the Frequency Response observations reported annually on FRS Form 1.”
Duke Energy
No
Duke Energy agrees that a BA should be required to achieve a minimum level of Frequency Response,
however Duke Energy believes the method for measurement needs improvement - please see comments to 1
and 2 above.Duke Energy agrees with the concept that a Balancing Authority should be required to achieve a
minimum level of Frequency Response however the method for measurement should also allow exclusion of
certain events, such as when the frequency deviation is associated with the BA’s contingent loss of
generation, or when an event is coincident with a significant change in ramped interchange.
It is not clear how the FRO will be determined - Duke Energy believes that the industry should agree on the
methodology which would be used for the ERO to determine the response desired for the Interconnection and
52
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000479
Organization
Yes or No
Question 4 Comment
how the allocation for the FRO would be determined for each Balancing Authority.
The calculation of FRO allocation (in Attachment 1) is not clear on whether the peak load and generation data
used is historic data or forecasted data.
It is also not clear how the assignment of the FRO would accommodate a mid-year change in Balancing
Authority size or other attribute that could change the calculated response.
Duke Energy questions if a BA providing better response than its allocated FRO in any year should be held to
achieving that in the following year - Duke Energy believes that should be the decision of the BA if it chooses
to achieve more than the minimum requirement applied to others.
Response: The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
The Industry will agree on the methodology for determining the FRO by submitting approval ballots on the standard.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and describe the
calculation methodology utilized. The second document will explain the rationale for the requirements as supplemental standard information.
The FR SDT agrees that mid-year changes need to be addressed and will review this issue during the field trial.
A BA’s FRO is not based on the previous year’s compliance. FRO is determined using the methodology described in Attachment A.
Patterson Consulting, Inc.
No
Requiring a Balancing Authority to provide Frequency Response and measuring that Frequency Response
consistently, is critical to maintaining reliability. The requirement is long overdue and the concept is a good
one. The method for measurement in FRS Form 1 is not consistent with the definition of FRM.
The desired "averaging" of input data over specific time ranges by the Balancing Authority as it completes
FRS Form 1 appears only in the background and instructions for FRS Form 1. Since this "instruction"
document will not be a part of the standard, it is not obvious that Balancing Authority's will be compelled to
provide consistent data. Therefore, the standard will fail to achieve the stated purpose of providing
"...consistent methods for measuring Frequency Response...".
Attachment A, other than the section providing guidance regarding event selection, appears to be
explanatory, contextual, and instructional in content. These aspects are important, but should not be
requirements. Attachment A should include only the event selection process and calculations associated with
requirements, including an explanation of what is necessary if variable Frequency Bias Settings are
implemented. If other "requirements" are included in Attachment A, they should be moved to the standard.
FRS Form 1 should be an attachment to the standard as this form contains and performs the required
calculations. The remaining information in Attachment A should become either a standalone (technical)
document, or be combined with information such as "FRS Form 1 Background and Instructions" and
renamed. As further clarification regarding the ambiguity identified in the previous paragraph, Attachment A
53
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000480
Organization
Yes or No
Question 4 Comment
could be interpreted as additional requirements on the Balancing Authority, ERO, or both. The language and
scope is not sufficiently clear to identify whether statements are informative or requirements. This lack of
clarity makes it impossible for entities to identify requirements, acquire appropriate tools and resources
related to requirements, and to provide suitable performance to meet requirements. For example, the
statement "A final listing of official events to be used in the calculation will be available from NERC by
December 10 each year." may be intended as a requirement rather than a statement suggesting a typical
schedule. Further, if the previous statement is a typical schedule, then the statement "The ERO will use the
following criteria for the selection of events to be analyzed." could be interpreted as merely the typical process
to be used, but not a binding one.
Response: The SDT has modified FRS Form 1 to allow for adjustments.
The SDT has modified the Attachment A documentation to clarify the calculation methodology.
The SDT has modified the Requirements and added measures to clarify how an entity is to show compliance.
Alberta Electric System Operator
Yes
The AESO agrees that there should be certain minimum requirement(s) of Frequency Response. In
Attachment A, it mentioned that it will be based on the protection criteria and Point C, and the FRM is
determined based on the settled deviation. The AESO suggests that the SDT describe how the FRM be
related with the FRO as they are determined by different time frames. The AESO suggests NERC investigate
the measure and method of separate FRM / FRO for different time frames, or provide technical evidence that
the proposed FRM / FRO can also address the technical concerns in different time frames.
Response: The FRO is a determined value providing a target for ensuring robust frequency response is achieved by all Balancing Authorities. The FRM is the
medium value of observations for the time period. The intent is for FRM to always be equal or more negative than the FRO, signifying robust control resulting in
proper frequency response. As such, the determination timeframes does not have to be the same for each value.
Independent Electricity System
Operator
Yes
We agree with the BA being one of the responsible entities to achieve a minimum level of FR, and the method
of measurement. However, R1 does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not
seem to correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
Response: FRS Form 1 has been modified to correct calculations and to allow for adjustments (not exclusions) to the load and generation.
Arizona Public Service Company
Yes
What is meant by discretely administered determination, under the heading "Frequency Obligation and
Allocation" of Attachment A? Please explain.
Response: The SDT has provided an administrative procedure for the ERO to follow in Attachment A.
54
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000481
Organization
ENBALA Power Networks
Yes or No
Question 4 Comment
Yes
ENBALA does believe that a BA should be responsible for a minimum level of Frequency Response as
calculated on Form 1 and reflected in its FRO. Furthermore, we feel that additional data collected on the
frequency nadir, such as the metric suggested in the recent Lawrence Berkeley National Laboratory of nadirbased frequency response, would be useful in assessing the current inertial response capabilities and level of
risk for under-frequency load shedding.
Response: The FRO is a determined value providing a target for ensuring robust frequency response is achieved by all Balancing Authorities. The FRM is the
medium value of observations for the time period. The intent is for FRM to always be equal or more negative than the FRO, signifying robust control resulting in
proper frequency response. As such, the determination timeframes does not have to be the same for each value.
Beacon Power Corporation
Yes
The concept of requiring each Balancing Authority to achieve some level of Frequency Response and
calculate it consistently is appropriate and necessary.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SPP Standards Development
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
Associated Electric Cooperative,
Inc.
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
55
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000482
5.
Requirement 2 identifies when the Balancing Authority must implement its Frequency Bias Setting.
R2. Each Balancing Authority shall implement the Frequency Bias Setting (fixed or variable) provided by the ERO into its Area Control Error
(ACE) calculation beginning on the date specified by the ERO to ensure effective coordinated secondary control, using the results from the
calculation methodology detailed in Attachment A.
Do you agree with this implementation? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters did not agree with the implementation plan specified in Requirement R2.
Many of the comments received echo concerns raised in comments for question 4 such as the Attachment A calculation methodology is not
clear; there was insufficient information provided to address the use of variable bias, and FRO determination was questionable. Several
commenters were concerned with the role assigned to the ERO, questioning how the ERO will use the FRM to determine the required BA
Frequency Bias Setting and if the ERO was the correct entity to perform this action. Commenters also expressed concerns with performing
an FRM analysis at the end of the year over the holiday period, suggesting the implementation time should be increased from one month to
two months. Some commenters also expressed concern that CPS and L10 compliance may be adversely affected by the requirements
proposed for calculating the Frequency Bias Setting.
In response to the comments received from industry, the SDT has revised Attachment A to clarify the calculation methodology; revised
Requirement R2 to clarify how an entity implements the Frequency Bias Setting provided by the ERO; and also modified FRS Form 1 to
allow for adjustments. Regarding FRO determination, the SDT is using a deterministic approach and also evaluating a probabilistic
method. With respect to ERO actions, the SDT is evaluating whether modifications to the NERC Rules of Procedure are necessary to ensure
the ERO provides the necessary support. The SDT also will develop a second draft standard attachment, Attachment B, to define the
methodology for lowering the minimum Frequency Bias Setting required, including maintaining a safety margin.
R2. Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable)
validated by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively coordinated
Tie Line Bias.
Organization
Santee Cooper
Yes or No
No
Question 5 Comment
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation?
What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
56
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000483
Organization
Yes or No
Question 5 Comment
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
LG&E and KU Energy
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
SERC OC Standards Review
Group
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
South Carolina Electric and Gas
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
We suggest defining the date as by the end of the first business day following the deadline for Frequency Bias
Setting implementation.
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
57
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000484
Organization
Yes or No
Question 5 Comment
effectively coordinated Tie Line Bias control.”
The SDT does not believe the suggestion to define the date is necessary since there is language in the standard stating the ERO will allow sufficient time to
implement the Frequency Bias Setting.
MRO's NERC Standards Review
Subcommittee
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible
for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is an implied
obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are
left wondering who has the responsibility for determining the Frequency Bias Setting.
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias than underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is overbiased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
Midwest ISO Standards
Collaborators
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible
for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is an implied
obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are
left wondering who has the responsibility for determining the Frequency Bias Setting.
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias than underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is overbiased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
58
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000485
Organization
Yes or No
Question 5 Comment
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the
responsibility for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is
an implied obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly.
Thus, we are left wondering who has the responsibility for determining the Frequency Bias Setting.
and provide a safety margin.
We Energies
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to over-bias than under-bias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is over-biased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
FirstEnergy
No
We cannot agree at this time since Attachment A of the materials posted do not include sufficient details
regarding the calculations used. Furthermore, there is no obligation imposed on the ERO to provide neither a
reasonable time frame for implementation of the Frequency Bias Setting nor a requirement for the ERO to
follow the methodology detailed in Attachment A. The team should consider adding a requirement for the
ERO or clarifying where this obligation is covered in NERC’s Rules of Procedure.
Response: Attachment A has been revised to clarify the calculation methodology.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary.
Bonneville Power Administration
No
R2 - BPA believes that the ERO should not be providing the BA the Frequency Bias Settings for the BA.
R2 points to Attachment A as having the calculation methodology, but there is no methodology spelled out in
Attachment A, there are simply data requirements, delta frequency that will be included in surveys, tools to be
used, etc.
The statement ‘natural frequency response’ is in Attachment A many times, but it is never spelled out. What
is meant by this phrase. This differs dramatically depending on when the event occurs due to different
generating patterns, different types of load (frequency responsive versus not frequency responsive), etc.
59
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000486
Organization
Yes or No
Question 5 Comment
The methodology needs to spell out how this will be taken into account when calculating the correct frequency
bias.
Secondly, how would this be done for variable bias?
Response: Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
Attachment A has been revised to clarify the calculation methodology.
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT will provide
additional and sufficient direction related to variable bias after review of this issue during the field trial.
The term “natural frequency response” is no longer in Attachment A but it is used in the new Background Document. The SDT believes that this term is
describing the response for any individual event and if calculated the statistical summation of multiple events. This term is more a work of art and not science
and therefore is not capitalized or defined.
SPP Standards Development
No
We would suggest ending the sentence at the second ERO, deleting the phrase '...to ensure effective
coordinated secondary control, using the results from the calculation methodology detailed in Attachment A.'
This phrase is more of an explanation of why this is being done rather than a part of an actual requirement.
Response: The SDT believes this language provides additional clarity and should remain as is. The SDT has removed the reference to Attachment A.
IRC Standards Review
Committee
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. Please clarify.
Also, it should not be necessary for the ERO to do the determination for all the Interconnections. There are
already in place methods for this by the existing ERCOT and WECC Interconnections. The SRC suggests
that the ERO may not be the appropriate technical entity. The ERO may be the appropriate entity to serve as
the receiver of the forms and analyze results for the Eastern Interconnection, but existing processes are
already in place elsewhere. It should be sufficient that those processes continue and submit copies of Form 1
to the ERO. This may also be appropriate for Hydro Quebec.
In addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the
BAs to implement the settings. The proposed language says only that the BA shall implement it on the date
specified, but it doesn’t address the need for that date to include some implementation time.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
60
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000487
Organization
Yes or No
Question 5 Comment
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common methodology applicable
to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
ERCOT
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. It should not
be necessary for the ERO to do the determination for all the Interconnections. There are already in place
methods for this by the existing ERCOT and WECC Interconnections. The SRC suggests that the ERO may
not be the appropriate technical entity. The ERO may be the appropriate entity to serve as the receiver of the
forms and analyze results for the Eastern Interconnection, but existing processes are already in place
elsewhere. It should be sufficient that those processes continue and submit copies of Form 1 to the ERO.
This may also be appropriate for Hydro Quebec.
In addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the
BAs to implement the settings. The proposed language says only that the BA shall implement it on the date
specified, but it doesn’t address the need for that date to include some implementation time.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common methodology applicable
to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Kansas City Power & Light
No
The Frequency Response Obligation determination for the interconnection as described in Attachment A is a
crude method and will result in obligations that will exceed the FRO that is intended. This will result in
additional cost to BA’s that is unnecessary to achieve the purpose of maintaining sufficient generation online
to arrest frequency degradation events caused by loss of generating resources.
The current NERC method for calculating a BA’s actual frequency response are inaccurate and provide
misleading guidance in the actual frequency response of a BA. These methods need considerable
improvement before any attempts to hold a BA to an expected level of frequency response as this proposal
61
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000488
Organization
Yes or No
Question 5 Comment
has stated.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial. The SDT is also evaluating a probabilistic method to determine the FRO.
FRS Form 1 has been modified to correctly calculate Frequency Response.
Southern Company
No
Comments: Comment 2: BAL-003-1, Requirement R2. The requirement should be made less prescriptive by
removing references to the calculation methodology and Attachment A. The responsible entity should
understand the fundamental and basic requirement - to implement the Frequency Bias Setting into its Areas
Control Error calculation. Proposed language is as follows: Each Balancing Authority shall implement the
Frequency Bias Setting (fixed or variable) provided by the ERO into its Area Control Error (ACE) calculation
beginning on the date specified by the ERO to ensure effective coordinated secondary control.
Comment 3: BAL-003-1, Requirement R2 and Section 1.4 Additional Compliance Information. The SDT
should consider whether or not the ERO has compliance obligations pursuant to the obligations mentioned in
the proposed Standard. Requirement R2, states that the ERO should provide the BA with the Frequency Bias
Setting and the specified date to begin the calculation. The R1 Supplemental Information section states that
the ERO is obligated to post the official list of events. The R2 Supplemental Information section states that
the ERO is obligated to validate the FRM and Frequency Bias Settings and disseminate the Frequency Bias
Settings Report along with the implementation date. These obligations should be confirmed and properly
incorporated into Standard if appropriate.
Response: The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common
methodology applicable to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Energy Mark, Inc.
No
Comment 13: I agree that the BA shall implement the Frequency Bias Setting provided by the ERO into it
Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effective
coordinated secondary control.
Comment 14: I do not agree that the results from the calculation methodology detailed in Attachment A will
provide the correct Frequency Bias Setting. My comments on the calculation methodology are included
elsewhere in my comments on Attachment A and FRS Form 1.
Response: Comment 13 – The SDT thanks you for your affirmative comment. Note that based on comments from other stakeholders, the language in
Requirement R2 was modified to state, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) “validated” by the ERO, into its Area Control Error (ACE) calculation . . .”
62
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000489
Organization
Yes or No
Question 5 Comment
Comment 14 - Please see the SDT response to your Attachment A and FRS Form 1 comments.
EKPC
No
The method is not clear in Attachment A.
Response: Attachment A has been revised to clarify the calculation methodology.
Seattle City Light
No
Currently a Balancing Authority has only about one month over holiday periods(December 10 to January 10)
to assemble its data and calculate the Frequency Response Measure (FRM). Further, Attachment A requires
the ERO to use at least 25 events for the calculation of FRM. Seattle City Light (SCL) believes that one month
is insufficient time given the number of events required. So SCL recommends additional time, such as two
months or to reduce the number of events to be included in annual reviews.
Response: The SDT recommends posting the selected events on a quarterly basis which should provide ample time for BAs to provide the information.
American Electric Power
No
It appears this standard deviates from past practice for calculating frequency bias. It is unclear how this might
affect the CPS Bounds L10 calculation.
Response: The Frequency Bias Setting calculation remains the same. The SDT is only modifying the “minimum Frequency Bias Setting” threshold. The SDT
understands reducing the minimum Frequency Bias Setting will affect L10 and ACE values which is why the SDT proposes monitoring these parameters and
undoing the modification if adverse results are realized.
Duke Energy
No
Duke Energy believes that this needs to be restated. Will the ERO perform the calculations to determine each
BA’s Bias?
Will the ERO provide ample time between publication of the settings and the date of implementation?
If effective coordinated secondary control is desired, other related operational parameters (e.g., L10) need to
be set at the same time.
Since measurement and reporting of operational performance is primarily on a monthly basis (e.g.,
CPS1/CPS2), the implementation date should be on or near the first of a month, but during normal working
hours (so that adequate support personnel are available).
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
63
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000490
Organization
Yes or No
Question 5 Comment
also define implementation timing.
The SDT understands reducing the minimum Frequency Bias Setting will affect L10 and ACE values which is why the SDT proposes monitoring these parameters
and undoing the modification if adverse results are realized.
The SDT is not proposing to change the methodology presently used to set the timing of the implementation of the Frequency Bias Setting.
Patterson Consulting, Inc.
No
The concept of requiring a Balancing Authority to implement its Frequency Bias Setting at a specific time and
using a specific calculation is meaningful. This requirement is not clearly worded, however. If the intent of
Requirement 2 is to identify "...when the Balancing Authority must implement its Frequency Bias Setting..." the
requirement should stop after "...on the date specified by the ERO." The remaining portion of the requirement
explains the need for the requirement and should be moved to supporting material.
Attachment A does not have a "calculation methodology" associated with the Frequency Bias Setting unless
the language describing historical practice and the benefits of moving a Frequency Bias Setting closer to a
Balancing Authority's natural Frequency Response are intended to constitute a "calculation methodology."
FRS Form 1 has the "calculation methodology" of using the minimum (since the value is negative) of last
year's FRM, next year's FRO, and percentage of next year's peak load or generation. Attachment A does not
mention this methodology and the requirement does not mention FRS Form 1. The clause "..., using the
results from the calculation methodology detailed in Attachment A." appears to place an obscure requirement
on the ERO since the ERO is the entity providing the Frequency Bias Setting to be implemented by the
Balancing Authority. If the ERO is intended to use the value from FRS Form 1, after verifying data and
calculations, then state that expectation explicitly and clearly. Otherwise, the ERO could set Frequency Bias
Settings in another manner after observing the Form 1 values.
The requirement for the ERO to provide a Frequency Bias Setting to each Balancing Authority begs the
question of how variable bias will be implemented. Historically, the Balancing Authority implements its
algorithm with oversight from NERC (Resources Subcommittee). The manner and expectation for providing
data and algorithms related to variable bias are inadequate.
Response: The SDT has modified the language in Requirement R2 to clarify the role of the ERO. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Attachment A has been revised to clarify the calculation methodology.
FRS Form 1 has been modified to correctly calculate Frequency Response and to allow for adjustments (not exclusions) to the load and generation.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT will provide
64
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000491
Organization
Yes or No
Question 5 Comment
additional and sufficient direction related to variable bias after review of this issue during the field trial.
Alberta Electric System Operator
Yes
The AESO suggests that the standard should provide a description on how the ERO would determine the
frequency bias setting and the relation to the FRO.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
NIPSCO
Yes
I guess the ERO will calculate the Bias, interesting.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
Manitoba Hydro
Yes
The implementation schedule seems reasonable.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Westar Energy
Yes
FMPP
Yes
Progress Energy
Yes
ENBALA Power Networks
Yes
NorthWestern Energy
Yes
Independent Electricity System
Operator
Yes
65
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000492
Organization
Arizona Public Service Company
Northeast Power Coordinating
Council
Yes or No
Question 5 Comment
Yes
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
66
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000493
6.
Requirement 3 mandates that a Balancing Authority operate its Automatic Generation Control (AGC) on Tie Line Bias unless it becomes
adverse to the integrity of its system.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Bias, unless such operation would have an
Adverse Reliability Impact on the Balancing Authority’s Area.
Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it becomes adverse to its system? If not, please
explain in the comment area below.
Summary Consideration: Approximately half of the comments received agreed that a Balancing Authority should operate its AGC in Tie
Line Bias unless an Adverse Reliability Impact occurs. Many of the dissenters were concerned with the apparent conflict with BAL-005.1b
Requirement R6, efforts of the Balancing Authority Reliability-based Controls (BARC) SDT with modifying BAL-005, and concern that the
draft standard should not dictate an AGC operating control mode. Other commenters indicated the language of Requirement R3 needed to
be revised for clarity and that the requirement could place a reporting burden on the Balancing Authorities. It was also noted that a single
BA Interconnection does not operate AGC using Tie Line Bias mode.
In response to industry comments received, the SDT has revised Requirement R3 by adding Overlap Regulation Service language and
allowing the AGC operating mode to be changed for an Adverse Reliability Impact.
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode
to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.
Organization
Santee Cooper
Yes or No
No
Question 6 Comment
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE. We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
67
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000494
Organization
LG&E and KU Energy
Yes or No
No
Question 6 Comment
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
SERC OC Standards Review
Group
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
South Carolina Electric and Gas
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
68
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000495
Organization
Yes or No
Question 6 Comment
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Bonneville Power Administration
No
R3. BPA does not believe this standard should dictate the control mode for AGC. That is better suited to be
in BAL-001 and should not be repeated in this standard - the ACE used for reporting is spelled out in BAL-001
R1 and is also discussed in BAL-005 R6. R3 should be removed from this standard, not modified to fit with
what is stated in BAL-001 or BAL-005.
Response: This standard is proposed to go into effect prior to implementation of the BARC draft standard. A determination of which reliability standard should
specify the AGC control mode used for system operations can be made once development of the BARC draft standard is completed.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
IRC Standards Review
Committee
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
ISO New Engand Inc.
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
69
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000496
Organization
Yes or No
Question 6 Comment
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
ERCOT
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
Kansas City Power & Light
No
The impact of operating in an inappropriate AGC control mode is bigger than the BA’s own balancing area.
The control of the area affects other BA’s around a BA and if enough BA’s are involved, can affect an
interconnection. Recommend the requirement be modified to consider the reliability impact on its own
balancing area, the balancing areas of adjacent BA’s and the interconnection.
Response: The SDT agrees and has modified Requirement R3 to read, “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
Southern Company
No
Comments: Agree only to the extent that an accurate frequency measurement is available to the BA. If not
frequency measurement is available, then that should be considered an adverse condition and thus TLB is
not appropriate. In other words, one small BA maintaining TLB may not cause the condition in the Glossary
definition of Adverse Reliability Impact but it is still not appropriate for them to stay on TLB.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
70
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000497
Organization
NIPSCO
Yes or No
No
Question 6 Comment
Yes, It was proposed that AGC be replaced by Automatic Resource Control (ARC) in the standards but did
not pass. The SDT may want to monitor this related effort.
Response: The SDT is using approved definitions listed in the NERC Glossary of Terms. Changes to current NERC Glossary of Terms definition language not
used in this standard would need to occur as a separate project.
Energy Mark, Inc.
No
Comment 15: Requirement 3 as written is unenforceable because it is too difficult to define “unless such
operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
Comment 16: What if operation out of Tie line Bias control does not have an Adverse Reliability Impact on
the Balancing Authority’s Area, but does have an Adverse Reliability Impact on another BA?
Comment 17: A document follows that provides an initial starting justification for the elimination of this
Requirement. See following “Requirements for AGC Operation, January 25, 2011.”Requirements for AGC
Operation, January 25, 2011
Introduction:As of the date of these comments there are two requirements in the NERC Standards that
address the operation of AGC.
•
•
The first is in BAL-003-0.1b - Frequency Response and Bias, Requirement R3.R3. Each Balancing
Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such
operation is adverse to system or Interconnection reliability.
The second is in BAL-005-0.1b - Automatic Generation Control, Requirement R7.R7. The Balancing
Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the
Interconnection. If AGC has become inoperative, the Balancing Authority shall use manual control to
adjust generation to maintain the Net Scheduled Interchange.
These requirements are misdirected and, for compliance purposes, they are difficult to measure effectively.
This paper provides the technical basis for replacing these requirements with new requirements that will not
only achieve the intent of these requirements, but do so in a more effective and measurable manner.
Background:
Automatic Generation Control (AGC) is a computer control system contained in the Control Center EMS that
performs a number of critical functions related to the balancing function necessary to maintain frequency and
associated reliability. Among the functions it performs are:
1) the collection of telemetered and local data useful for determining the appropriate control actions,
2) the calculation of Area Control Error (ACE),
3) determination of desired control actions that should be sent to those resources available for
automatic dispatch, and
71
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000498
Organization
Yes or No
Question 6 Comment
4) sending the actual control signals to implement that dispatch.
Most AGC Systems have three basic modes of operation,
1) Tie-line Frequency Bias,
2) Constant Net Interchange and
3) Constant Frequency.
The ACE Equation is the basis for all three modes of operation.
•
•
•
In the Tie-line Frequency Bias mode, all of the ACE Equation is used as an input to control action
determination.
In the Constant Net Interchange mode, only the Tie-line Error portion of the ACE Equation is used as
an input to control action determination. The Constant Net Interchange mode would normally be
used when there is no information available to indicate interconnection frequency.
In the Constant Frequency mode, only the Frequency Bias portion of the ACE Equation is used as an
input to control action determination. The Constant Frequency mode of operation would be used
when the Tie-line Error is known to be misleading, inaccurate or unavailable. It is also used when
there are no tie-lines in service as in the case of a single BA interconnection or during islanded
operation.AGC Systems have been used in the industry since before the development of digital
computers.
Initially AGC Systems did little more than send instructions to generators based on evaluation of the ACE
Equation. They have become more sophisticated since their inception and implement greater complexity in
their evaluations of appropriate dispatch actions to the point that they include forecasting, reliability and
economics within their algorithms. Modern AGC Systems determine control actions based on the collection of
much more data than is included in the ACE Equation. This additional data includes: short-term load
forecasts and forecast error estimates as influenced by weather; individual non-conforming load forecasts and
forecast error; forecast interchange transaction information; generating unit ramp and response rates;
generating unit economic operating points including valve position; generating unit incremental economic
costs including start-up and maintenance; Hydro unit river flow limits as related to the operation of other units
on the same waterway; energy storage capabilities and available energy; Inadvertent Interchange energy
account balances; time error; and current control performance scores.
As AGC Systems have evolved, the control mode in which they are operating, Tie-line Frequency Bias,
Constant Net Interchange, or Constant Frequency, provides less and less information about the control
actions that they implement. In a modern AGC System the control mode provides little information about how
control actions are being determined and implemented. In fact, only someone experienced in AGC
programming and implementation would have the knowledge necessary to determine whether or not an AGC
System is providing reasonable control actions or control actions consistent with Tie-line Frequency Bias
Control. Even someone with the necessary experience observing the operation of a modern AGC System for
72
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000499
Organization
Yes or No
Question 6 Comment
a short period of time will be incapable of determining whether or not that system is providing effective or
adequate control. Therefore, neither of the two requirements is effectively enforceable from a practical point
of view.
Perspective:A couple of examples are offered to add perspective to the problem.
Example 1:R3 includes the requirement, “Each Balancing Authority shall operate its Automatic Generation
Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection
reliability.” There are three conditions when operation on Tie-line Frequency Bias control may be adverse to
the system or Interconnection reliability.
1. The first is when the Tie-line Error data used in the ACE Equation is incorrect. The ACE Equation
will be incorrect when there are errors in the Actual or Scheduled Tie-line flow values. This condition
will occur when there is telemetry failure of one or more tie-lines, when there is an unidentified
scheduling error, or when there is a separation that causes a tie-line metering point to be located on a
separate island due to interconnection separation or islanding. Telemetry failure will be indicated by
the quality bits associated with the Tie-line telemetry. If AGC is disabled to identify a scheduling error,
there should be an operating log entry. If AGC is disabled because of a separation, there will also be a
log entry.
2. The second is when the actual frequency is determined to be incorrect. If measured frequency is
incorrect, this condition should be indicated by an operating log entry and transfer to the redundant
frequency device to provide measured frequency. When the actual frequency fails, this condition will
be indicated by the quality bits associated with the measured frequency value and transfer to the
redundant frequency device to provide measured frequency.
3. The third is when operation of AGC would provide control different from the desired control to
address some emergency condition in the BA or elsewhere on the interconnection. If the operation of
AGC would be adverse to system or Interconnection reliability and is disabled for this reason, this
condition should be indicated by an operating log entry.In all cases, there should be a record of the
reason for the use of other than Tie-line Frequency Bias control and records indicating the reason for
the use of other control modes. In all cases, other than the third indicated above, an error in the value
of ACE is the reason for not using Tie-line Bias Control and the quality bits for ACE or ACE component
data should provide a reasonable explanation for the condition. The third case occurs with such
infrequency that there should be no need for a special rule to address this condition.
Example 2:R7 includes the requirement, “...If AGC has become inoperative, the Balancing Authority shall use
manual control to adjust generation to maintain the Net Scheduled Interchange.” Cases have been observed
of an AGC System that does not perform as well as the manual dispatch used when the AGC System is
inoperative. If a BA has a CPS1 score of 120% when using AGC and a CPS1 score of 125% when
performing manual dispatch, should that BA be penalized for not having its AGC continuously operating?
What is the goal? Is the goal to operate on AGC regardless of the result or is the goal to operate in a manner
73
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000500
Organization
Yes or No
Question 6 Comment
that provides the best measured control?
Alternatives:Since these requirements are not effectively measurable or enforceable, can a requirement or
requirements be written to provide an equivalent to the intent of the old requirements addressing AGC
operation?The industry has three alternatives to address this issue:
1. Retain requirements that are directed at the AGC System understanding that they are effectively not
measureable or enforceable.
2. Eliminate requirements that are directed at the AGC System with the understanding that they were
not contributing to reliability.
3. Determine an alternative method to evaluate, measure and enforce a requirement that will achieve a
goal similar to the goal originally intended by the implementation of the AGC System requirements.
Elimination of the requirement is an appropriate solution. However, if it is determined that a replacement
measure is required, then the solution to this problem lies with the third alternative above.
Solution:There is already a requirement that effectively enforces the intent of the above requirements.
Instead of requiring the BA to control in a particular manner, CPS1, BAAL and DCS require the BA to achieve
specific results with their control actions. All three measures require the BA to calculate ACE using Tie-line
Frequency Bias for determination of their Reporting ACE. The requirements specify that at least 50% of the
data must be valid for the one-minute average data to be included in the measures. The requirements for
redundant frequency measurement devices assure that the BA will have the actual frequency data available
to perform the necessary calculations. The data retention requirements specify the data they must retain to
demonstrate that their control achieved the stated goals.
Finally, this approach is consistent with the White House Executive Order on Improving Regulation and
Regulatory Review in Section 1(b)(4) stating that regulatory agencies must: “to the extent feasible, specify
performance objectives, rather than specifying the behavior or manner of compliance that the regulated
entities must adopt;...”
Response: Comment 15 & 16: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service
shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an
Adverse Reliability Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Comment 17: The SDT recognizes that from a compliance perspective it can be difficult to ascertain if an Adverse Reliability Impact exists. Nonetheless, the SDT
is very concerned with adversely affecting primary Frequency Response when operating without AGC. The SDT believes revised language using NERC glossary
defined terms will support proper compliance enforcement. It is expected entities will provide an explanation each time AGC Tie Line Bias mode is not used for
74
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000501
Organization
Yes or No
Question 6 Comment
the compliance auditor to assess.
EKPC
No
Tie line bias is calculated using (NAI-NSI) while frequency bias is -10B(FA-FS).
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
Duke Energy
No
Duke Energy agrees to the simple statement posed in the question; however, the requirement goes beyond
that by using a defined term, Adverse Reliability Impact, which has a relatively narrow focus on extreme
conditions. If a single BA lost a significant amount of its tie-line telemetry or its frequency sources, cascading
outages and/or grid separation would not necessarily be imminent but it would be imprudent to remain in Tie
Line Bias mode. Go back to the original language for the requirement - “Each Balancing Authority shall
operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is
adverse to system or Interconnection reliability.”
Response: The SDT has revised Requirement R3 language and believes the use of NERC glossary defined terms in the Requirement provides necessary clarity
for compliance.
Patterson Consulting, Inc.
No
While this requirement is in the existing standard, it places a significant reporting burden on a Balancing
Authority to demonstrate compliance during audits for little reliability gain.
In addition for single Balancing Authority interconnections, operating in this AGC mode is functionally
equivalent to operating in flat frequency mode. This may cause some interconnections to seek a variance, just
to avoid compliance complications. Perhaps this requirement could be replaced with a requirement for
Balancing Authorities to contribute to frequency performance as well as balance commitments and resources,
or to calculate the ACE it uses to report in other standards in a specific manner. As written, it could be
interpreted to create a violation when AGC suspends or is offline.
Response: The SDT has taken into consideration the reporting burden on the Balancing Authority to demonstrate compliance.
provide an explanation each time AGC Tie Line Bias mode is not used for the compliance auditor to assess.
It is expected that entities will
The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has been revised
to clarify this situation.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
75
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000502
Organization
Yes or No
Question 6 Comment
standard will take into account the work completed on this standard.
FirstEnergy
Yes
Although we mostly agree with the requirement, we believe it can be improved. We suggest that the team add
wording in the requirement to allow for brief periods where meters or communication channels fail and trip the
AGC off Tie Line Bias. In most areas, if merely one BA trips off bias it would not have an adverse affect on
BES reliability and furthermore, the BA can take alternative measures for these periods such as manual AGC.
We suggest the team add wording similar to the second sentence of requirement R7 of BAL-005 which states:
“If AGC has become inoperative, the Balancing Authority shall use manual control to adjust generation to
maintain the Net Scheduled Interchange.”
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Arizona Public Service Company
Yes
As long as Appendix 1 interpretation remains in effect for WECC Auto Time Error Payback. WECC BAs
operate in Tie-Line and Time.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Hydro-Quebec TransEnergie
Yes
However the “Tie Line Bias” AGC mode is not appropriate for a Single Balancing Authority operating in an
Interconnection. HQT uses the Flat Frequency mode.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has been revised
to clarify this situation.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Beacon Power Corporation
Yes
As R3 has not significantly changed, will the Interpretation of Requirement 3 from BAL-003-0.1b still be
applicable to BAL-003-1?
76
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000503
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
When this standard is approved and implemented it will replace all previous standards and interpretations.
Westar Energy
Yes
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
We Energies
Yes
American Electric Power
Yes
SPP Standards Development
Yes
Midwest ISO Standards
Collaborators
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
Yes
Independent Electricity System
Operator
Yes
NorthWestern Energy
Yes
Progress Energy
Yes
ENBALA Power Networks
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
77
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000504
Organization
Yes or No
Question 6 Comment
Response: Please refer to our response to Question 17.
78
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000505
7.
Do you agree with the proposed Implementation Plan for this standard? If not, please explain in the comment area.
Summary Consideration: The majority of the comments received stated that they did not agree with the proposed implementation plan
for this standard. The main concerns were that the implementation plan would take several years to fully implement, that adjustment to
the Frequency Bias Setting could not occur without first modifying the existing BAL-003-0.1b standard, and a preference for aligning
implementation plan effective dates with the regulatory approval date. Several commenters expressed concern regarding the accuracy and
clarity of Attachment A and how field testing efforts integrated into the implementation plan. One commenter observed that it would be
ideal for the standard to require the use of variable bias.
In response to industry comments the SDT has revised Attachment A for correctness and clarity; changed all references in the standard
and associated documents for BAL-003 to read “BAL-003-0.1b”; and removed the table showing the annual reduction schedule for the
minimum bias setting. The SDT has provided a revised plan for reducing the minimum Frequency Bias Setting - the ERO will monitor the
results of the reductions and make necessary corrections. Details for the reduction plan have been provided as Attachment B to the
standard.
Organization
Santee Cooper
Yes or No
No
Question 7 Comment
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard.
The values currently shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly
peak demand per 0.1 Hz change. For BAs that do not serve native load, percent “of upcoming years
maximum generation/0.1 Hz should be changed to percent of its estimated maximum generation level in the
coming year/0.1 Hz change.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval which is why the implementation plan specifies reducing the bias setting on an annual basis.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
LG&E and KU Energy
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change
79
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000506
Organization
Yes or No
Question 7 Comment
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
South Carolina Electric and Gas
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
MRO's NERC Standards Review
Subcommittee
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
plan makes no mention of a field trial. It should.
Please change all BAL-003-0 to BAL-003-0.1b.
Response: The SDT did change all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Midwest ISO Standards
Collaborators
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
80
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000507
Organization
Yes or No
Question 7 Comment
plan makes no mention of a field trial. It should.
Please change all BAL-003-0 to BAL-003-0.1b.
Response: The SDT has changed all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
We Energies
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
plan makes no mention of a field trial. It should.Please change all BAL-003-0 to BAL-003-0.1b
Response: The SDT has changed all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
FirstEnergy
No
We believe that the implementation plan should include information regarding the field trial and how it fits in
with the phase-in implementation. It appears as though the field trial is being conducted based on 2010 data
and will be concluded upon completion of the development of the standard but we think this could be clarified.
Furthermore, as stated in the process manual, a field test “should include at a minimum the data collection
and analysis or field test plan, the implementation schedule, and an expectation for periodic updates of the
results.” The field test information posted is not clear on the implementation schedule of the field test as well
as when and how periodic updates will be available.
Response: The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the Field Trial. The SDT has removed
the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another method for reducing the minimum Frequency Bias Setting
in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
Bonneville Power Administration
No
From a compliance perspective, it is administratively very burdensome to have portions of two different
versions of a standard applicable at the same time, as specified in the Implementation Plan for BAL-003-1.
81
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000508
Organization
Yes or No
Question 7 Comment
This type of structure adds an additional layer of complexity to all parts of the compliance administration
process, as necessary to distinguish between the separate versions of the standard. Rather than create and
prolong this type of situation over a 4 year time period, BPA asks that BAL-003-0 be retired in its entirety and
that the contents of BAL-003-1 be expanded to also include R5, as specified in BAL-003-0. This change
resolves the identified issues while also ensuring that all requirements of BAL-005 are in effect, as originally
intended.
The Implementation Plan for BAL-003-1 also includes a proposal to modify the specified limiting percentage
of Native Load on a sliding scale over a 4 year time period. BAL-003-3 R5, as approved, explicitly specifies
1% as a minimum value for monthly average Frequency Bias Setting. As such, changing this value results in
a change in the requirement itself. Instead of being done through an Implementation Plan, these types of
changes should be made as specific modifications to the requirement in question. To resolve this issue, BPA
asks that the sliding scale specified for percentage of peak load specified in the Implementation Plan be
incorporated directly into BAL-003-1 as a part of the specified text of R5. This change meets the intended
goal of applying a sliding scale to this value over time while assuring that the underlying change is
implemented as a change to the requirement through the Standards Development Process.
Response: The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias
Setting. The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is
proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary
correction. Please refer to Attachment B for reduction plan details.
IRC Standards Review
Committee
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier
than the schedule shown could result in the unintended consequence of non-compliance enforcement for
performance that is caused by the change rather than by the non-performance of the functional entity
.Also, the effective dates given in the Implementation differ from those in the draft standard. Different
requirement numbers are expressed in each.
Some of the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as
early as May 2011. We do not believe that the BAL-003-1 standard will be approved by the industry or the
NERC BoT at that time and that does not even take into account regulatory approval (or 12 months after BoT
adoption in those jurisdictions where no regulatory approval is required).
How can a standard begins to phase out while the successor standard is not anywhere near becoming
effective?If the SDT wants to propose a gradual replacement of the current R5, we would suggest that the
phase-out steps be tied to the date that the standard becomes effective.
Response: The SDT has removed the table showing the reduction schedule for the minimum bias setting.
82
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000509
Organization
Yes or No
Question 7 Comment
The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted. The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and
make necessary corrections. Please refer to Attachment B for reduction plan details.
ERCOT
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier
than the schedule shown could result in the unintended consequence of non-compliance enforcement for
performance that is caused by the change rather than by the non-performance of the functional entity.
Also, the effective dates given in the Implementation differ from those in the draft standard. Different
requirement numbers are expressed in each.
Some of the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as
early as May 2011. We do not believe that the BAL-003-1 standard will be approved by the industry or the
NERC BoT at that time and that does not even take into account regulatory approval (or 12 months after BoT
adoption in those jurisdictions where no regulatory approval is required). How can a standard begins to phase
out while the successor standard is not anywhere near becoming effective?
If the SDT wants to propose a gradual replacement of the current R5, we would suggest that the phase-out
steps be tied to the date that the standard becomes effective.
Response: The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Kansas City Power & Light
No
How can hard dates for the phasing out of the current R5 be in the implementation plan for a standard under
development? The concept of phasing out R5 and phasing in R2 could be done, however, this would take
considerable thought as to how to implement that. This current proposed implementation plan should be
carefully reconsidered.
83
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000510
Organization
Yes or No
Question 7 Comment
Response: Thank you for your comments. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the
Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Progress Energy
No
We agree with the graduated implementation for the FRO portion of the standard, but feel NERC needs to
loosen the minimum frequency bias requirement immediately so that it matches the newly required frequency
response. There are also other areas within the EMS the besides BA's frequency bias that should be
addressed such as secondary frequency response systems that should also be included in this standard.
Additionally, if the industry was truly concerned with matching bias values to actual response, they would
switch to variable frequency bias. Variable bias requires additional up front work along with general
maintenance, but it truly is the best way to accurately bias the ACE equation.
Response: The SDT believes that gradually relaxing the present standard is the prudent way to proceed. The SDT believes that it is necessary to observe the
affect each decrement to the present standard has during all four seasons to assure reliability is not adversely impacted.
The SDT has revised the plan for reducing the minimum Frequency Bias Setting and is proposing another method for reducing the minimum Frequency Bias
Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
The SDT agrees that use of a variable, non-linear bias setting is the best solution.
We also agree with you that variable, non-linear bias setting would be a superior way to go.
NIPSCO
No
"Effective Date" section at the top of the Standard does not match the Implementation plan; I think there is an
R4 missing in the second part of 1.3 .In the implementation plan add RSG to "Compliance with the Standards"
5 year phase-in on removing the 1% is a good idea
Response: The SDT has corrected the errors noted. The SDT has revised the plan for reducing the minimum Frequency Bias Setting and is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Energy Mark, Inc.
No
Comment 18: The Proposed Effective Date in the implementation plan is inconsistent with the Effective Data
in the Draft Standard.
Comment 19: The completion of the implementation plan does not occur until 2015. This lengthy plan stems
from a standard that only measures reliability annually and provides only an annual window for changing
84
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000511
Organization
Yes or No
Question 7 Comment
parameters such as Minimum Frequency Response. Alternative methods that measure reliability more
frequently could me implemented with a shorter implementation plan.
Response: The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT believes that gradually relaxing the present standard is the prudent way to proceed. The SDT believes that it is necessary to observe the affect each
decrement to the present standard has during all four seasons to assure reliability is not adversely impacted. The SDT has revised the plan for reducing the
minimum Frequency Bias Setting and is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of
the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
Beacon Power Corporation
No
Why is it appropriate to delay implementation of this standard for over 12 months after applicable approval?
This seems an unnecessary delay considering the intent to operate under a field test. Similarly, delaying
implementation of R2 for over 2 years seems unnecessary. Based on the suggested schedule for measuring
FRM and implementing Frequency Bias Settings, there may be rationale to implement the standard on the
first calendar year following approval. However, delays beyond the beginning of the next calendar year should
require conclusive justification.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
EKPC
No
Specific dates should be tied to regulatory approval.
Response: The SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
85
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000512
Organization
ISO New Engand Inc.
Yes or No
No
Question 7 Comment
We do not agree that a meaningful Implementation Plan can be developed until such time as the data
gathering/field testing is completed. Therefore, we believe this Standard may be premature.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
American Electric Power
No
It is unprecedented that an implementation plan would require following some (but not all) requirement(s)
within multiple versions of the same standard. This would make following the standard very difficult. Having to
piece together multiple documents into a coherent requirement would be very difficult to achieve. There needs
to be a definitive start and stop date for each version, rather than a phase in and phase out across multiple
versions. We disagree with setting preselected dates beginning months away. Timing should be driven by
applicable regulatory approval, as opposed to dates which appear to be arbitrarily selected.
Going from 100% of the load-based, frequency bias calculation to 0% is unclear without correlating it to
something else being phased in over time.It is very hard to follow how BAL-003-0 R5 relates to BAL-003-1.
More work needs to be done by the SDT to explain how these relate to one another.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Attachment A has been revised for clarity. FRS Form 1 has been revised to correct calculation errors and allow for adjustments.
Duke Energy
No
Duke Energy does not agree with having prescribed dates for the gradual reduction of the minimum
Frequency Bias Setting, as the implementation may drive significant issues which could delay, or halt the
implementation at a certain level. It is not clear what process would be used to give the “go-ahead” to move to
86
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000513
Organization
Yes or No
Question 7 Comment
the next level (agree?).
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Patterson Consulting, Inc.
No
The implementation plan should address implementing these requirements at the same time for all Balancing
Authorities within an interconnection, regardless of regulatory approvals. The present implementation plan will
require some Balancing Authorities within an interconnection to operate to the new standard while other
Balancing Authorities operate to the old standard if multiple regulatory jurisdictions exist as they do within two
interconnections. This could lead to uncoordinated and unreliable operation within an interconnection.
Response: The SDT does not believe that staggered implementation will lead to uncoordinated and unreliable operation within an interconnection because these
changes affect secondary control. With regards to your comment concerning different “regulatory jurisdictions”, this issue is outside the scope of the project
approved SAR.
Independent Electricity System
Operator
No
We have a difficulty understanding the basis for some of the dates in the implementation plan.Some of the
implementation steps (retiring R5 of BAL-003-0) start as early as May 2011. We do not believe that the BAL003-1 standard will be approved by the industry or the NERC BoT at that time and that does not even take
into account regulatory approval (or 12 months after BoT adoption in those jurisdictions where no regulatory
approval is required). How can a standard begins to phase out while the successor standard is not anywhere
near becoming effective?If the SDT wants to propose a gradual replacement of the current R5, we would
suggest that the phase-out steps be tied to the date that the standard becomes effective.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
87
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000514
Organization
Yes or No
Question 7 Comment
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Southern Company
Yes
We did not want to vote on Question 7, but clicked 'yes' in error.
Response: The SDT thanks you for your clarifying comment.
Westar Energy
Yes
Yes, if field testing validates the standard.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Associated Electric Cooperative,
Inc.
Yes
NorthWestern Energy
Yes
ENBALA Power Networks
Yes
SPP Standards Development
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
SERC OC Standards Review
Group
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change.
88
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000515
Organization
Yes or No
Question 7 Comment
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Attachment A has been revised for clarity.
Arizona Public Service Company
AZPS has a few questions:
1) has frequency performance been affected by the on-going RBC field trial,
2) what steps will be taken to isolate this field trial from the effects of the RBC field trial,
3) will the frequency bias reduction to 0.8% of peak load include a CPS2 grace-period for thos BAs not
involved in the RBC field trial?
Response: 1) The Frequency Response SDT cannot respond on RBS field trial matters.
2) This standard is meant to addresses primary control and the settings of the bias which would have an impact on the measures of the RBS field trial. SDT has
revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the Field Trial. The SDT has removed the table showing the
reduction schedule for the minimum bias setting. The SDT believes that it is necessary to observe the affect each decrement to the present standard has during
all four seasons to assure reliability is not adversely impacted. The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which
the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the
revised plan is doable and prudent.
3) The Frequency Response SDT anticipates the RBC field trial will be concluded when this standard takes effect. The SDT is proposing that standards
requirements take effect for all entities within a regulatory jurisdiction at the same time.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
89
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000516
8. This standard proposes to eliminate the 1% minimum Frequency Bias over a period of 4 years as outlined in the Implementation Plan. Do
you agree that the elimination of the 1% minimum will bring Frequency Bias closer or equal to natural Frequency Response? If not, please
explain in the comment area.
Summary Consideration: Comments received indicate commenters are divided over whether elimination of the 1% minimum will bring
Frequency Bias closer or equal to the natural Frequency Response. Many commenters indicated that the Frequency Bias Setting will never
match the Frequency Response and that it is far better for reliability to over bias than under bias. Commenters also expressed concern
with how the Frequency Response Obligation (FRO) will be calculated; the rationale for the phase out schedule; and the impact this
proposal will have on secondary control.
The FR SDT refined language to indicate it is better to have a somewhat over bias condition, provided additional details on how the FRO is
calculated, explained the rationale for the phase out schedule proposed; including developing a reasonable, practical and accurate
measurement for natural Frequency Response.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 8 Comment
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.
We do not question the plan to change the minimum Frequency Bias Setting over a period of 4 years per se
in attempt to optimize AGC response by matching the Frequency Response of the system. However,
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias that underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency Bias Setting was chosen
to ensure that BAs are always over-biased. The standard needs to allow some margin in the Frequency Bias
Setting to ensure that the bias setting is overbiased.
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
Midwest ISO Standards
Collaborators
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
90
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000517
Organization
Yes or No
Question 8 Comment
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.We do not question the plan to change the minimum Frequency Bias Setting over a
period of 4 years per se in attempt to optimize AGC response by matching the Frequency Response of the
system. However, frequency Response of the interconnection is constantly changing. As a result, the
Frequency Bias Setting will never match the Frequency Response exactly. It is better to overbias that
underbias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency Bias
Setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some margin in
the Frequency Bias Setting to ensure that the bias setting is overbiased.
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
We Energies
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.We do not question the plan to change the minimum Frequency Bias Setting over a
period of 4 years per se in an attempt to optimize AGC response by matching the Frequency Response of the
system. However, frequency Response of the interconnection is constantly changing. As a result, the
Frequency Bias Setting will never match the Frequency Response exactly. It is better to over-bias than
under-bias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency
Bias Setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some
margin in the Frequency Bias Setting to ensure that the bias setting is over-biased
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
Bonneville Power Administration
No
Until the calculations used for FRO are spelled out and how natural Frequency Response is to be measured,
BPA cannot agree that elimination of the 1% minimum will bring Frequecy Bias closer or equal to natural
Frequency Response.
Response: The SDT has provided clarification in Attachment A, Attachment B and the Background Documents.
IRC Standards Review
No
Please provide the technical basis for the 4-year phase-out schedule.
91
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000518
Organization
Yes or No
Committee
Question 8 Comment
The SRC suggests that incremental changes should be made and evaluated to determine whether they are
indeed beneficial before additional changes are made. Until a standard is defined, it is not appropriate to set
an implementation date on the transition.
Also, please clarify that the process is to gather data, analyze that data to determine what has been the actual
frequency response, and then to determine the Frequency Bias Settings to be closer to or equal to the natural
frequency response, and is not saying that the next actual frequency response must equal the Frequency
Bias Setting that the ERO has assigned. There is a subtle difference here that must be clarified in order to
avoid the unintended consequence of “punishing” an entity for not providing a response equal to the
Frequency Bias Setting.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
The intent of the Implementation Plan proposed was to evaluate the effectiveness of each setting change before additional refinement to the Frequency Bias
Setting is made and incorporated into the AGC algorithm. This has been removed from the Implementation Plan. The SDT has chosen an alternate method for
reducing the minimum Frequency Bias Setting.
Standard language is not intended to penalize entities for not providing a response equal to its Frequency Bias Setting. The intent of the standard is to establish a
Frequency Response Obligation (FRO) representing the minimum response required for reliable interconnected operations. The Frequency Bias Setting can differ
from the determined FRO value as appropriate for reliability for which compliance will only evaluate if the Frequency Bias Setting is refined correctly and
implemented in a timely manner.
ERCOT
No
Please provide the technical basis for the 4-year phase-out schedule. The SRC suggests that incremental
changes should be made and evaluated to determine whether they are indeed beneficial before additional
changes are made. Until a standard is defined, it is not appropriate to set an implementation date on the
transition.
Also, please clarify that the process is to gather data, analyze that data to determine what has been the actual
frequency response, and then to determine the Frequency Bias Settings to be closer to or equal to the natural
frequency response, and is not saying that the next actual frequency response must equal the Frequency
Bias Setting that the ERO has assigned. There is a subtle difference here that must be clarified in order to
avoid the unintended consequence of “punishing” an entity for not providing a response equal to the
Frequency Bias Setting.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
The intent of the Implementation Plan proposed was to evaluate the effectiveness of each setting change before additional refinement to the Frequency Bias
Setting is made and incorporated into the AGC algorithm. This has been removed from the Implementation Plan. The SDT has chosen an alternate method for
92
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000519
Organization
Yes or No
Question 8 Comment
reducing the minimum Frequency Bias Setting.
Standard language is not intended to penalize entities for not providing a response equal to its Frequency Bias Setting. The intent of the standard is to establish a
Frequency Response Obligation (FRO) representing the minimum response required for reliable interconnected operations. The Frequency Bias Setting can differ
from the determined FRO value as appropriate for reliability for which compliance will only evaluate if the Frequency Bias Setting is refined correctly and
implemented in a timely manner.
Kansas City Power & Light
No
Simply eliminating the minimum frequency response and establishing an FRO obligation for each BA will not
result in a knowledge that a BA has moved closer to its natural frequency response. First, there is an
underlying assumption that the FRO dictated for the BA will be “matched” by a BA’s resources to achieve a
natural response close the FRO and until improved methods of calculating a BA’s actual frequency response
are developed, there will be no accurate way of determining if a natural response is close to the FRO
obligation.
Response: The intent of the first sentence in the comment above is not clear. There is no underlying assumption that natural response will match the
frequency response obligation. However, the compliance process will provide a stimulus to the BA to achieve at least that level of frequency response.
The FR SDT is expending considerable effort to develop a reasonably accurate measurement of natural response, and is in the process of choosing among several
promising metrics.
NorthWestern Energy
No
Page 2 implies that there is currently too much frequency response based on the 1% of peak demand method
of establishing frequency bias. Even though NWE does not use the 1% method, NWE feels that the 1%
minimum has been a tried and true method of providing frequency response in the Western Interconnection.
Without the 1% minimum (and BA’s using a natural response less than the 1%), the total interconnection
frequency response would decrease according to research. This would lead to decreased interconnection
bias, causing other operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The opening sentence of this comment appears to be a misstatement. The FR SDT believes a gap exists between the natural Frequency Response
and the Frequency Bias Settings calculated based on the 1% of peak demand criteria, resulting in excessive and unnecessary regulation occurring that is related
to high frequency conditions following DCS events and other circumstances. The FR SDT agrees that a reduction in the 1% of peak demand criteria for the
Frequency Bias Setting can adversely affect the overall Interconnection Frequency Bias Setting, L10 values, and possibly CPS 2 compliance also.
Westar Energy
No
The 1% requirement should be phased out with the implementation of this standard.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
FMPP
No
There still needs to a floor value; 1% may not be the correct value, but zero is not the correct floor.
93
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000520
Organization
Yes or No
Question 8 Comment
Response: The floor will not be zero. Each Balancing Authority will have a required FRO contribution reflective of the natural Frequency Response in its
Frequency Bias Setting.
American Electric Power
No
Please see response to question 7.
Response: Please see our response to Question 7.
Duke Energy
No
Duke Energy agrees that a gradual reduction (in magnitude) of the minimum as part of the field test is needed
to determine what is the “right” amount of response needed, but the changes cannot be done in a vacuum.
Duke Energy continues to be concerned with the impact that the changes to the Frequency Bias Setting
(“FBS”) will have on the bounds guiding secondary control (CPS1, CPS2 and the draft Balancing Authority
ACE Limit or “BAAL” currently under a Field Trial under NERC Project 2010-14). Eastern Interconnection
Frequency Response: For those not familiar with the work of the FRRSDT or the NERC Resources
Subcommittee around Frequency Response, the estimated response for the Eastern Interconnection on
average appears to be less than half of the Interconnection’s total FBS in magnitude today. If the decision
was made to hold Frequency Response at its current level, this standard could result in the FBS being
reduced for many, if not most, Balancing Authorities to about half of what it is today. The FRO allocation
would eventually drive what the minimum FBS needs to be, with the FBS needing to be greater than or equal
to the FRO, or perhaps FRM, in magnitude at a minimum.
Estimating the impact: To look further into the secondary control performance implications of BAs using a
reduced FBS, Duke Energy took four sample months of clock-minute data for twelve BAs, cut the
Interconnection total and each BA’s FBS in half, recalculated each BA’s clock-minute ACE taking out half of
the bias component, and then calculated CPS1, CPS2 and BAAL estimated performance based upon those
changes. Recognizing that the secondary control and resulting ACE of the BAs would be different and
dependent upon the standards to be met, the results were not intended to estimate what the performance of
the BAs would be, but were intended to help indicate where the problem areas existed based upon today’s
operation measured to a tighter control criteria. Impact on CPS1 and BAAL: The two bounds that are
frequency-dependent, CPS1 and the draft BAAL, are cut in half for any given frequency by cutting the FBS in
half. For CPS1 the impact of reducing the FBS looked reasonable with the results leaning toward overall
improvement in CPS1 for almost half or better of the BAs (5 of 12, 8 of 12, 6 of 12, and 12 of 12) for the given
months even with the tighter bounds, but more analysis may be needed. Though CPS1 looks manageable,
the sample set did not include small BAs, and some BAs already in the 100-120% range appeared more at
risk. For BAAL the longest duration of ACE exceeding the low or high BAAL stayed the same or got worse in
all cases. As with today where the BAAL bounds get wider as frequency gets closer to 60 Hz where the
majority of operation occurs, the additional flexibility of operation is offset by the BAAL bounds getting tighter
than the CPS2 limits as frequency deviates farther from 60 Hz. With BAAL cut in half for this scenario,
compliance will be more challenging and costly to manage to not exceed 30 minutes for any event. One of the
94
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000521
Organization
Yes or No
Question 8 Comment
unknowns is whether the Frequency Trigger Limit for the BAAL calculation will stay where it’s at or be
lowered, as the current value was based upon UFLS at 59.82 Hz, rather than today’s UFLS of 59.7 Hz. The
BARCSDT under NERC Project 2010-14 has more work ahead before any changes can be proposed.Impact
on CPS2: Though the industry is not seeing a reliability need to tighten secondary control in normal operation,
the industry can’t avoid such “tightening” with CPS2 limits directly dependent upon the FBS of the Balancing
Authority and total FBS of the Interconnection. For the four months reviewed where CPS2 limits were cut in
half, if one looked at the results individually the drop in CPS2 performance across the twelve BAs ranged from
2.6% to 33.8%, 4% to 33.5%, 3.8% to 37.8%, and 3.1% to 35.1%, with a median of 19.4%, 18.4%, 20.3% and
18.9% for the four months. Noting that CPS2 performance must be 90% or greater on a monthly basis,
improving CPS2 performance by even 10% translates to over 70 hours of operation in a month where
additional secondary generation control and other actions may be required. Duke Energy notes also that with
less error in the ACE, the results indicate that the distribution of ten-minute events exceeding L10 would move
closer toward the 50-50 chance that CPS2 will be forcing control action even though the ACE is in support of
the Interconnection frequency (results showing the average moving from 27-34% to 39-43% of the ten-minute
periods exceeded when in support of Interconnection frequency).Conclusion: Duke Energy does not believe
there is a reliability need pushing the industry to tighten secondary control to the degree discussed above
simply as a result of reducing the Frequency Bias Setting. If the calculated Frequency Response of the
Interconnection stayed at its current level, what would be the justification for tightening the secondary control
requirements of CPS1, CPS2 and the proposed BAAL? Duke Energy supports taking more of the error out of
the ACE equation by having the FBS closer to the estimated Frequency Response of the Balancing Authority,
however, Duke Energy does not believe the result should be a significant increase in secondary control costs
to meet the CPS1, CPS2, or draft BAAL requirements.
Response: The SDT appreciates receiving this analysis of the impact Frequency Bias setting can have on secondary control. Please continue to analyze and
share this technical data to the extent possible with the SDT. The SDT will perform comparable analyses during the field trial for determining the proper balance
between having less “over control” than is perceived with respect to possibly increasing the secondary control cost incurred by individual Balancing Authorities
because a smaller Frequency Bias Setting is utilized.
Alberta Electric System Operator
No
The standard seems to propose to replace the 1% minimum frequency bias with the new proposed FRO. The
AESO finds it difficult to comment on if it is not clear on how the FRO is determined.
Response: The Frequency Response Obligation is used for determining if there is sufficient primary Frequency Response for reliability. The minimum Frequency
Bias Setting to be used in AGC will have a floor value needed to assure reliable control, and can be different than the Frequency Response Obligation.
The SDT has modified Attachment A to provide additional clarity regarding the calculation methodologies.
Independent Electricity System
Operator
Yes
We do not have an opinion on the proposed elimination but do have a difficulty understanding the phase-out
plan. Please see our comments under Q7, above.
95
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000522
Organization
Yes or No
Question 8 Comment
Response: The FR SDT has created Attachment B to provide clarifying language for the phase-out plan.
Please refer to the SDT response to question #7.
SPP Standards Development
Yes
While we agree that we think such a change will move the industry in the right direction, we have nothing
upon which to base that opinion. On the other hand, the 1% minimum does provide a safety net for the
interconnection. Moving away from the minimum requirement over a 4-year period should give us the
necessary operating experience to become more confident in our numbers.
Response: The goal of the phase-out plan is to determine the best Frequency Bias Setting floor value to use for reliability that is based on a measured and
cautionary approach.
Southern Company
Yes
Comments: Agree only to the extent that the natural Frequency response can be accurately determined.
Response: The FR SDT is investing considerable effort on behalf of industry to develop a reasonable, practical and accurate measurement of natural frequency
response and also a process for choosing the best of several promising metrics.
Progress Energy
Yes
We have seen actual system operations harmed by the current, excessive biasing requirement on several
occasions.
Response: The SDT thanks you for your affirmative response and clarifying comment.
NIPSCO
Yes
Obviously it will bring it closer. The 4 year phase-in is a great idea.
Response: The SDT thanks you for your affirmative response and clarifying comment..
Manitoba Hydro
Yes
Yes, the removal of the 1% of projected peak load which has a large window of probability for error should
improve BIAS calculations.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Patterson Consulting, Inc.
Yes
Moving Frequency Bias Settings closer to natural Frequency Response is critical to improving observation,
reporting, and control.
Response: The SDT thanks you for your affirmative response and clarifying comment.
South Carolina Electric and Gas
Yes
96
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000523
Organization
Yes or No
EKPC
Yes
Energy Mark, Inc.
Yes
Beacon Power Corporation
Yes
ENBALA Power Networks
Yes
SERC OC Standards Review
Group
Yes
FirstEnergy
Yes
Santee Cooper
Yes
LG&E and KU Energy
Yes
Arizona Public Service Company
Yes
Seattle City Light
Yes
ISO New Engand Inc.
Question 8 Comment
With .4% peak load being a typical actual frequency response lately for Balancing Authorities, the 1% of peak
load to .8% of peak load transition seems prudent. Perhaps a further reduction to .6% may be useful as well,
but lesser floors may in effect result in AGC too often canceling out the primary frequency response being
provided.
Response: The SDT thanks you for your clarifying comment.
Associated Electric Cooperative,
Inc.
I agree with this emerging standard’s recognizing that the arbitrary 1% of peak-load should be refined by
being lowered to better reflect each BA’s expected frequency response.
Response: The SDT thanks you for your clarifying comment.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
97
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000524
Organization
Yes or No
Question 8 Comment
Response: Please refer to the SDT response to Question 17.
98
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000525
9. Do you agree with the drafting team that this standard should be field tested? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters agreed that this standard should be field tested. Most commenters indicated
that the implementation plan should include information regarding the field trial and also be coordinated with the field trial schedule.
Individual commenters suggested that the field trial is not required if detailed calculations and definitions were provided to entities for
implementations and the field trial should not serve as a pre-established standard.
In response to industry feedback received, the SDT is presently field testing the methodologies for calculating FRM and FRO. The reduction
of the Frequency Bias Setting is no longer part of the field trial. The SDT has defined a process for the ERO to follow to reduce the
minimum Frequency Bias Setting once this proposed standard has been approved..
Organization
FirstEnergy
Yes or No
Question 9 Comment
No
We believe that the implementation plan should include information regarding the field trial and how it fits in
with the phase-in implementation. It appears as though the field trial is being conducted based on 2010 data
and will be concluded upon completion of the development of the standard but we think this could be clarified.
Furthermore, as stated in the process manual, a field test “should include at a minimum the data collection
and analysis or field test plan, the implementation schedule, and an expectation for periodic updates of the
results.” The field test information posted is not clear on the implementation schedule of the field test as well
as when and how periodic updates will be available.
Response: Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing
another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections.
Please refer to Attachment B for reduction plan details.
Bonneville Power Administration
No
BPA believes that this standard as written should not be field tested. The calculations to be used to set
frequency bias must be spelled out in detail and the definition of natural Frequency Response under multiple
loading conditions must also be detailed. Once these conditions have been adequately met, there will not be
a need for a field trial.
Response: Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing
another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections.
99
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000526
Organization
Yes or No
Question 9 Comment
Please refer to Attachment B for reduction plan details.
MRO's NERC Standards Review
Subcommittee
Yes
The field test is not identified in the implementation plan. It should be.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary correction. Please refer
to Attachment B for reduction plan details.
Midwest ISO Standards
Collaborators
Yes
The field test is not identified in the implementation plan. It should be.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
SPP Standards Development
Yes
Field testing will provide an opportunity to learn as we move forward with the standard. Modifications can be
made as experience is gained and knowledge is acquired.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary correction. Please refer
to Attachment B for reduction plan details.
IRC Standards Review
Committee
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
100
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000527
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
ERCOT
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
ISO New Engand Inc.
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Arizona Public Service Company
Yes
What criteria will be used to evaluate the field trial? What constitutes acceptable/non-acceptable results?
[see also, comments to question 7]
Response: Please refer to our comments for Question 7.
Progress Energy
Yes
This plan should be field tested, although it feels as though this is less of a "field test" based on engineering
judgement and more of trial and error testing. This problem should be studied to determine what is necessary
101
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000528
Organization
Yes or No
Question 9 Comment
to manage system frequency within desired limits for the worst single contingency during the period of time
the system is most vulnerable (minimum load). The result should be spread proportionally to all BAs in the
interconnection, and those BAs should respond to and bias their ACE equation by the required value.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Attachment A has been revised to clarify the calculation methodology.
NIPSCO
Yes
Great idea
Response: The SDT thanks you for your affirmative response and clarifying comment.
Westar Energy
Yes
This is a major change and field testing is required to valid the standard and allow for revisions based on
testing results
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Manitoba Hydro
Yes
Yes, to ensure the eastern interconnection frequency health does improve with these new methods and if it
does each BA will have a more accurate and fair BIAS setting.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
American Electric Power
Yes
The changes proposed should be thoroughly tested before any implementation.
102
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000529
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Patterson Consulting, Inc.
Yes
A field test will provide valuable refinment and verification of parameters, and should identify unexpected
ramifications.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
South Carolina Electric and Gas
Yes
We do agree that a field test should take place but more details on the field test would be helpful.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Independent Electricity System
Operator
Yes
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Santee Cooper
Yes
103
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000530
Organization
Yes or No
LG&E and KU Energy
Yes
SERC OC Standards Review
Group
Yes
Kansas City Power & Light
Yes
Southern Company
Yes
ENBALA Power Networks
Yes
NorthWestern Energy
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
EKPC
Yes
We Energies
Yes
Alberta Electric System Operator
Yes
Duke Energy
Yes
Seattle City Light
Yes
Northeast Power Coordinating
Council
Question 9 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
104
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000531
10. Attachment A of the proposed standard describes the criteria for selecting events to be analyzed. Do you agree with the criteria as
described in Attached A? If not, please explain in the comment area.
Summary Consideration: Comments received indicate the majority of commenters agree with having criteria for selecting events to be
analyzed and requested clarification on the rationale for the criteria proposed. Research performed by the FRR SDT indicates analysis
using 25 events and mean frequency data values will result in stable, consistent results.
Many commenters also expressed concern that the selection criteria was too stringent; that criteria language would omit selection of
events worth reviewing; that Balancing Authorities should have flexibility in choosing which event data is selected and also have ability to
modify submitted data for ensuring accuracy; and that using event data from the prior year could create double jeopardy. The intent for
frequency values selected is to ensure most generators responsive to the interconnection will experience a governor response. The FRR
SDT also agrees that interconnection subject matter experts and Balancing Authorities require the flexibility to select noteworthy events of
interest, flexibility to identify which events to include or exclude for analysis, and allowance for modifying data for quality and other
relevant concerns. The FRR SDT also believes that in those years where 25 acceptable events do not exist, stability and consistency
concerns outweigh any adverse impacts from utilizing a few events from the previous year for analysis and that actual impact on current
year results will be negligible.
After reviewing comments, the FRR SDT has revised Attachment A language for clarity. The team separated the rationale into a separate
document and also revised Form-1.
Organization
Santee Cooper
Yes or No
No
Question 10 Comment
In Attachment A, item 2.b. states that “The time from the start of the rapid change in frequency until the point
at which Frequency has largely stabilized should be less than 18 seconds.” It appears that this statement
was to ensure that frequency is rapidly decaying; however, frequency could continue to decay beyond 18
seconds and should still be considered an event.
Item 3 states that point A is calculated as “an average” is this considered to be an average of all samples or
selected samples.
Also, we would like to know how the different thresholds for the interconnections were determined.
We are also concerned with how the threshold would affect compliance to the standard if it was ever required
to be measured on an event basis, particularly those events close to the threshold dead-band settings. Words
such as “assumed” should be avoided.
Please explain how the number of 25 events was determined for the list of frequency events and explain how
those events will be distributed throughout the year (i.e., on and off-peak, and seasonal).
105
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000532
Organization
Yes or No
Question 10 Comment
Events that meet the selection criteria should be posted by the ERO on a monthly basis. This will allow BAs
to evaluate their performance throughout the year.
Response: The intent for using the words “largely stabilized” in the sentence provides desired flexibility for selecting events for analysis. For example, if
frequency drops from 60 Hz to 59.94 Hz in 6 seconds and then continues to decay to 59.935 Hz over the next 20 seconds; then this event would be selected for
analysis.
With respect to point A, all available samples for the time window specified are averaged. The number of samples obtained for averaging will be determined by
the Balancing Authority’s EMS scan rate.
Each Interconnection threshold will be determined by subject matter experts who have knowledge of the historical events being analyzed, CERTS research and
field trial results. It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis
difficult to validate.
Analysis of metrics being considered by the SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event samples
obtained for the year being reviewed. The SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection criteria
specified.
The SDT proposes posting event data on a quarterly basis so Balancing Authorities can periodically analyze data during the year.
Attachment A has been divided into two separate documents; a revised Attachment A containing the calculation methodology and a Background Document
explaining the development rationale for the standard’s requirements and measures.
Bonneville Power Administration
No
BPA does not agree with the criteria described in the attachment. 36 mHz is not a large enough deviation to
adequately measure frequency response. There is no need to go to that small of a deviation in order to
insure that 25 events are found over the course of a year.
Response: The FR SDT will consult with WECC subject matter experts to refine the frequency deviation selection criteria for the western interconnection. Keep
in mind the selection threshold will be adjusted over time, as supported by evidence, to ensure reasonable selection criteria is utilized.
SPP Standards Development
No
While Criteria 5 allows for the ERO to exclude 'non-conforming' SEFRD points there isn't a mechanism
provided that instructs us on how to exclude those points in FRS Form 1.
Would we be required to reach out for an additional point to get us back to 25 if a point is excluded? Who
excludes the point in question? Is it the BA or is it the ERO? Will the ERO have sufficient knowledge to
exclude the point in question?
In Critieria 2.a. the first sentence should read "The frequency deviation (Point A minus Point C) must
exceed...". Also, 36 MHz should be 36 mHz.
Response: The SDT has developed a new version of FRS Form 1, and it clarifies the process of how a Balancing Authority excludes an event. The ERO will not
106
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000533
Organization
Yes or No
Question 10 Comment
exclude events.
The Balancing Authority would not be required to replace an excluded event with another event since analysis of metrics being considered by the SDT shows the
median or mean frequency data analyzed will converge to a stable state using only 20 event samples obtained for the year being reviewed. Analysis also shows
that the median value is more consistent than the mean value when the sample set includes data for an event that otherwise should have been excluded from the
analysis.
The SDT thanks you for catching the typographical error referencing 36 mHz. The SDT has revised Attachment A and this value is no longer referenced..
IRC Standards Review
Committee
No
The criteria for events selection are acceptable, but the criteria stated in Attachment A for performance
required by the FRO is too stringent. Criteria requiring avoidance of Point C encroachment on step 1 of the
UFLS program is more stringent than proven performance that now exists. To make this change will be very
costly and will not provide for a commensurate increase in reliability.
Response: FRO values have not yet been selected. The intent is to choose FRO values that are necessary for the reliability of each interconnection.
ERCOT
No
The criteria for events selection are acceptable, but the criteria stated in Attachment A for performance
required by the FRO is too stringent. Criteria requiring avoidance of Point C encroachment on step 1 of the
UFLS program is more stringent than proven performance that now exists. To make this change will be very
costly and will not provide for a commensurate increase in reliability.
Response: FRO values have not yet been selected. The intent is to choose FRO values that are necessary for the reliability of each interconnection.
Southern Company
No
Comments: Selecting events just outside the governor deadband (e.g. 36 mHz in the EI) is not a good idea in
that it assumes too much precision in the response by governors at the deadband boundary. This will result
in a less accurate natural Frequency Response calculation for those large events where knowing an accurate
Frequency Response value is most critical. In other words the event selection “deadband” should be
somewhat larger than the Governor deadband even those this will result in somewhat fewer events in the final
set.
Response: The intent is to choose among the largest frequency deviation events to obtain a meaningful sample set for analysis accuracy. The FR SDT is open
to suggestions to refine the selection criteria for each interconnection. A balance needs to be established between having an inadequate sample resulting in less
computational accuracy versus having a sample that is not representative of actual response occurring for the larger frequency deviation events of concern.
Progress Energy
No
It should be explicitly stated that point C must be outside the standard frequency deviation deadband
referenced from 60.0 Hz, not a deviation of more than the frequency deviation deadband from the predisturbance frequency. Most of the new electronic govenors operate with a 60 Hz center instead of changes
in frequency relative to the current value.
107
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000534
Organization
Yes or No
Question 10 Comment
Additionally, the first limit under number 2 should be 36 mHz, not 36 MHz as they are a factor of 10^9
different.
Lastly, the event selection criteria listed in Attachment A uses the frequency as measured at Point C to qualify
an event, in an effort to ensure that the deviation exceeds the governor deadband. However, Point C is an
instantaneous point which will differ in value within the interconnect based on how close the loss of generation
is to the measuring point due to the elasticity of frequency across the interconnect during the inertial
response. Therefore, local readings by the BA should be allowed to exempt a specific event if the local
frequency did not exceed 36 mHz.
Response: It is expected that the selection criteria will yield events with Point C that clearly exceed the generator governor deadband and result in a response
action. While the distance between the measuring point and the loss of generation location will cause different Point C (and other) frequency values being
measured at different system locations, the variation in Point C frequency values among the different locations will not be significant for most events or most
Balancing Authorities. Keep in mind each Balancing Authority will use its EMS local frequency data for determining sample points A and B. The FR SDT
anticipates selecting events that will not require the Balancing Authority to exclude events because of local frequency values measured. The FR SDT will consider
high local frequency as a possible selection criteria exclusion factor in the next revision of Form 1.
NorthWestern Energy
No
Should state “ The Point C value is the minimum of frequency samples and should be within 8 seconds after
the start of the rapid change”. NWE feels some instances could be more than 8 seconds and “should” would
allow for this if it occurred.
Response: The original intent was to exclude such events however the SDT understands some of these events may provide interesting and valuable
information. Language proposed would give subject matter experts selecting the events necessary leeway to include such events. The SDT will consider
changing “shall” language to give subject matter experts more flexibility with selecting events.
Hydro-Quebec TransEnergie
No
The criteria to determine what should be considered as a frequency event should be defined by
Interconnection. For example, HQT has no dead band on governors; therefore the 36 mHz is not applicable.
If more than 25 events occurred within a year, will they all be selected or only a set of 25 will be? Who will
perform this selection and base on what criteria.
Response: Event selection criteria will be specified on an interconnection basis after consulting with subject matter experts for that interconnection. Selected
events will be chosen by subject matter experts for that interconnection.
Westar Energy
No
The lagging measure is a concern. The ERO should be required to provide an updated proposed/possible list
of frequency events monthly so BA's can determine their FRM through out the year so corrective action can
be taken if needed.
Prior year events should be excluded (just to get to 25 events). This could result in begin non-compliant twice
for the same events. If a BA is over performing in the first of the year and adjusts in the second half of the
108
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000535
Organization
Yes or No
Question 10 Comment
year then those second half of the year events are used in the next year, it could cause an inappropriate
violation.
BA's need the ability to exclude some events based on measure issues with specific events including scan
rates, unusual intermittent resource changes, non-conforming load, unusual ramping of load or interchange
during the event.
Response: Based on comments received from industry, the SDT proposes posting event data on a quarterly basis so Balancing Authorities can periodically
analyze data during the year.
Generally, each Balancing Authority will have 25 acceptable events occur each calendar year. Using a few events from the preceding year is not expected to
adversely affect accuracy of analysis results. The SDT is re-evaluating exclusionary criteria and is also developing a process to permit reasonable adjustments to
an event for atypical circumstances.
FMPP
No
Attachment A states that if a year occurs in which there are not 25 events that meet the remaining criteria
below, then the most recent 25 events (as defined below) will be used for determination of an entity’s
compliance with the FRM requirement and storage of SEFRD.
Problem - by using events from last year to determine an entity’s compliance with a Requirement for this year
puts the entity in double jeopardy for last year’s events, which were already used for compliance for last year.
Attachment A states that events occurring during periods in which either significant interchange schedule
ramping or load ramping is likely, should be excluded if other events are available for measurement purposes.
Questions - What is significant?How can the ERO determine significant interchange schedule ramping is
likely?Likely for how many BAs?It would be better to define significant and let the BA exclude any events that
meet this definition, since each BA will be ramping differently. Since SEFRD is defined as the individual
sample of event data from a Balancing Authority which represents the change in Net Actual Interchange
(NIA), divided by the change in frequency, expressed in MW/0.1Hz, whenever a BA includes an event with a
“significant” change in NIA due to a large interchange schedule ramp, the FRM is totally skewed, and should
not be included. If other events are available means that if other events are not available then an entity’s
compliance is going to be based on an event or events that has been skewed for the BA by significant
interchange schedule ramp.
Response: Generally, each Balancing Authority will have 25 acceptable events occur each calendar year. Using a few events from the preceding year is not
expected to adversely affect accuracy of analysis results. The SDT is re-evaluating exclusionary criteria and is also developing a process to permit reasonable
adjustments to an event for atypical circumstances. The SDT does not expect subject matter experts will select events with rapid load change or large schedule
change activity. Large schedule changes typically occur between 7 AM and 8 AM, and 10 PM and 11 PM, with 10 minute ramps across the top of the hour.
Having Balancing Authorities exclude these kinds of events could be problematic because balancing areas are different in size from one Balancing Authority to the
next. The SDT has developed a manual correction capability for the sampling process which, when used in conjunction with median value rationale, should
minimize the impact data skewing tendencies may have on analysis results.
109
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000536
Organization
American Electric Power
Yes or No
No
Question 10 Comment
Attachment A only appears to be attempting to address the frequency bias setting for AGC portion of overall
frequency response without addressing the governor response portion issue. Attachment A still tries to
address the issue solely at the Balancing Authority level without addressing criteria at the Generator &
Generator Operator levels.
WECC has stated through previously submitted comments from its three extensive validation result tests on
frequency response with respect to 5% droop for a 0.1 Hz frequency deviation that actual response would be
2.5 times greater if the proper governor response actually occurred. The studies also showed only 40% of the
governors effectively responded. Extensive test result studies such as WECC’s should not be ignored.
Attachment A criteria does not address the lack of frequency response from contributing factors associated
with actual governor response, impact of droop setting, amount of BA generation actually on-line at time of
event, maximum loading of generation and amount of BA imported interchange to meet load.
Response: The need for an accompanying generation SAR has been discussed and is outside of the current FR SDT scope. Verification of generator governor
response is important. The FR SDT encourages entities to continue studying generator governor response and related contributing factors cited.
Patterson Consulting, Inc.
No
I agree that criteria for event selection are needed, although these criteria appear to be unnecessarily
subjective. Items 1 and 2 are appropriate. However, item 3 seems to eliminate many events that should be
reviewed. For example, item 3 would eliminate any event with an initial frequency that is not 60 Hz, depending
on the subjective determination of "near" and "relatively steady."
Similarly, items 5 and 6 add more subjectivity to the selection of events, but may be necessary. It is not clear
that criteria listed in Attachment A are required to be used since much other content appears to be
explanatory, contextual, and instructional. These explanatory, contextual, and instructional aspects are
important, but should not be requirements.
Attachment A should be limited to event selection and calculations necessary to support the stated
requirements. Instructional, etc. information should be moved to another document. If other "requirements"
are included in Attachment A, they should be moved to the standard.
FRS Form 1 should be an attachment as this form contains and performs the required calculations. The
remaining information in Attachment A should become either a standalone (technical) document, or be
combined with information such as "FRS Form 1 Background and Instructions" and renamed.
As further clarification regarding the ambiguity identified in the previous paragraphs, Attachment A could be
interpreted as additional requirements on the Balancing Authority, ERO, or both. The language and scope are
not sufficiently clear to identify whether statements are informative or requirements. This lack of clarity makes
it impossible for entities to identify requirements, acquire appropriate tools and resources related to
requirements, and to provide suitable performance to meet requirements. For example, the statement "A final
listing of official events to be used in the calculation will be available from NERC by December 10 each year."
may be intended as a requirement rather than a statement suggesting a typical schedule. Further, if the
110
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000537
Organization
Yes or No
Question 10 Comment
previous statement is a typical schedule, then the statement "The ERO will use the following criteria for the
selection of events to be analyzed." could be interpreted as merely the typical process to be used, but not a
binding one. In short, the purpose and intention of Attachment A is not communicated unambiguously.
Response: Item 3 was intended as guidance to give subject matter experts flexibility in choosing the best possible events for analysis. The SDT recognizes that
in some years valid but less than ideal events from a selection criteria perspective may be chosen for analysis. The SDT will improve document clarity and also
consider if it is prudent to make selection criteria hard or soft requirements.
Attachment A has been divided into two separate documents; a revised Attachment A containing calculation methodology and a Background document explaining
the development rationale for the standard requirements and measures.
Xcel Energy
No
1) Using 25 events is likely excessive in the Western Interconnection. Several of the past few years have had
less than 10 events. Given the extent to which generation is built and resource profiles change, projecting 25
events will include events in the bias calculation that are less reflective of the current generation profile and
skew our bias results.
2) Calculating point A as “...an average over the period from -16 second to 0 seconds” for any event that
meets the criteria set in Attachment A means that Point A will likely be within 1-2 mHz of 60 Hz, regardless of
starting system conditions. This can cause data to be skewed, as the response will appear to be less if the
frequency immediately before the event is further from 60 Hz than the average. Further, it requires additional
data. If there is some corrupted data in the 16 seconds prior to the event, it may be required to throw out
event data. The 16 seconds prior to the event is not useful data.
3) Point 5 addresses excluding events “...in which significant interchange schedule ramping or load ramping is
likely...” Not only are the FRO and FRM definitions too vague, they require analysis of real time generation
and load ramping that may not be realistic. Attachment A should likely include specific criteria for removing
events, including lack of reasonable data and, as described here, significant schedule or load ramping, where
“significant” is defined.
Response: The SDT has reviewed your concern and determined that the WECC would have sufficient event data to analyze. Keep in mind an ERO specified
event can be excluded if data quality issues associated with FRS Form 1 exist. Also, manual adjustment to the actual net interchange value for schedule ramping
can be performed for completing FRS Form 1. Event selection criteria will allow sufficient flexibility for subject matter experts to avoid periods of rapid load
change (e.g., morning pickup and declining late evening load) and ten minute ramps across the top of the hour to the extent possible. The intention is to guide
the subject matter experts in choosing the best data set available so that relatively few adjustments, if any, will be needed.
LG&E and KU Energy
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
111
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000538
Organization
Yes or No
Question 10 Comment
distributed throughout the year (i.e., on and off-peak, and seasonal).The criteria in Attachment A should
include how and where the arresting frequency is measured
Response: The SDT thanks you for your affirmative response and clarifying comments.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event samples
obtained for the year being reviewed. The SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection criteria
specified.
Generally, subject matter experts will use high speed frequency recorder data to select events for analysis. Technology is now available that allows crosschecking data at multiple locations for the same event.
SERC OC Standards Review
Group
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
distributed throughout the year (i.e., on and off-peak, and seasonal).
Response: The SDT thanks you for your affirmative response and clarifying comment.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
South Carolina Electric and Gas
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
distributed throughout the year (i.e., on and off-peak, and seasonal).
112
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000539
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
Arizona Public Service Company
Yes
AZPS would recommend using a lesser number of events and more severe events in the calculation.
Response: The SDT thanks you for your affirmative response and clarifying comment.
A balance needs to be established between having an inadequate sample resulting in less computational accuracy versus having a sample that is not
representative of actual response occurring for the larger frequency deviation events of concern.
NIPSCO
Yes
Pretty good
Response: The SDT thanks you for your affirmative response and clarifying comment.
EKPC
Yes
Please provide detailed information on the 25 events that will be chosen for the event.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been revised to include an improved detailed description of the criteria selection process.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
Manitoba Hydro
Yes
Yes, 25 events should be sufficient to determine the FRM, while not overburdening the resources performing
the analysis.
113
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000540
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Duke Energy
Yes
Seattle City Light
Yes
We Energies
Yes
Energy Mark, Inc.
Yes
ENBALA Power Networks
Yes
Kansas City Power & Light
Yes
Midwest ISO Standards
Collaborators
Yes
FirstEnergy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
AESO suggests that the criteria should also consider including some frequency events where the BA has
controlled separation from a region. In the case of Alberta, the frequency deviation is larger than most
regional frequency deviations and provides a better measure on Frequency Response. Would the proposed
standard permit for BA's to choose these events for inclusion in the determination of the frequency response?
Response: This is not a common occurrence. Very few Balancing Authorities operate in this manner. The expectation is events will be selected by the Balancing
Authorities. The Balancing Authority may exclude events from consideration for specific conditions such as data quality issues.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
114
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000541
11. The proposed standard has a document attached to it that describes the SDT’s reasoning for the Requirements (Attachment A - Frequency
Response Background Document). Do you agree with the SDT that this document is useful and provides a clear understanding of the
Requirements? If not, please explain in the comment area.
Summary Consideration: Several of the commenters did not agree that the Attachment A – Frequency Response Background document
in its current form was useful and provided a clear understanding of the Requirements. In general most commenters indicated that
Attachment A required correction, greater clarity and did not adequately explain the calculation methodology. The SDT has split
Attachment A into two separate documents, revised Attachment A to better explain the calculation methodology, and improved the
document’s clarity. The SDT also revised FRS Form 1 and the background document for clarity. Several commenters stated Requirement
R2 needed additional explanation so the SDT revised Requirement R2. Several commenters also expressed concern the standard was not
well defined as drafted so Requirement R5 was inserted back into the draft standard to resolve this concern. Another concern identified
that language appeared to give the ERO a blank check to make changes to the standard without an industry vote. Other commenters
requested a better explanation for how FRO is determined and why the median value is considered a reliable statistical measure for
calculating FRM.
R2. Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable)
validated by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively coordinated
Tie Line Bias control.
R5. In order to ensure adequate control response, each Balancing Authority shall use a monthly average Frequency Bias Setting whose absolute
value is at least equal to one of the following:
•
The maximum percentage of the Balancing Authority Area’s estimated yearly Peak Demand within its metered boundary per 0.1 Hz change as
specified by the ERO in accordance with Attachment B.
•
The minimum percentage of the Balancing Authority Area’s estimated yearly peak generation for a generation-only Balancing Authority per
0.1 Hz change as specified by the ERO in accordance with Attachment B.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
No
Question 11 Comment
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
115
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000542
Organization
Yes or No
Question 11 Comment
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.
On page 3 in the last paragraph of the Frequency Response Obligation and Allocation section, we suggest
expanding the explanation of why Frequency Response Obligation is based on (peak generation + peak
load)/2. This will result in less responsibility of Frequency Response today for a generator only control area
than there currently is. Since load does respond to frequency, we are not suggesting this is wrong. We think
it simply needs to be expanded upon in the explanation.
Does load contribute the same amount as generation? If not, perhaps the ratio of gen and load response to
total response should be reflected in the calculation.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
The SDT believes that there is presently no obligation on the generator only BA and that the proposed FRO will place an obligation on the generator only BA. The
SDT has modified Attachment A to provide additional clarity concerning the calculation methodology.
The SDT believes that this is a methodology that is technologically neutral and provides an FRO allocation across all geographic areas.
Midwest ISO Standards
Collaborators
No
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.On page 3 in the last paragraph of the Frequency Response Obligation and
Allocation section, we suggest expanding the explanation of why Frequency Response Obligation is based on
(peak generation + peak load)/2. This will result in less responsibility of Frequency Response today for a
generator only control area than there currently is. Since load does respond to frequency, we are not
suggesting this is wrong. We think it simply needs to be expanded upon in the explanation. Does load
contribute the same amount as generation? If not, perhaps the ratio of gen and load response to total
response should be reflected in the calculation.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
The SDT believes that there is presently no obligation on the generator only BA and that the proposed FRO will place an obligation on the generator only BA. The
116
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000543
Organization
Yes or No
Question 11 Comment
SDT has modified Attachment A to provide additional clarity concerning the calculation methodology.
The SDT believes that this is a methodology that is technologically neutral and provides an FRO allocation across all geographic areas.
We Energies
No
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
FirstEnergy
No
We believe that more work is needed on this document and the requirements to provide for more clarity.
Response: The SDT has modified the Background Document to provide additional clarity concerning the reasoning behind the proposed requirements.
Bonneville Power Administration
No
Overall comment: Attachment A does not adequately spell out the methodology that is to be used to
determine the correct frequency bias for a Balancing Authority. In order for this standard to go forward, the
methodology must be explicitly spelled out and moved into the standard, not attached as a background
document that can be changed without vote.
o Frequency Bias Setting vs. Frequency Response
o RAS events should not be excluded.
These events are designed to not have response on the system, even though there may be some primary
response.
o Paragraph 1 - “each BA has one month” conflicts with the standard that says prior to January 10th or 45
days (1.4 Additional Compliance Information).
o 2.a - BPA is assuming the Drafting Team meant 36 mHz. 36 mHz is very small and can be achieve during
normal frequency deviations.
Point C “within 8 seconds” must be moved to 10 to 12 second range in order to work in WECC.
o 2.b - Why so far back on the -16 seconds?
o Third from the last paragraph - BPA cannot support a standard that isn’t well defined, doesn’t adequately
spell out the methodology behind the requirements and essentially gives the ERO a blank check to make
117
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000544
Organization
Yes or No
Question 11 Comment
changes to the standard without a vote.
o Second to last paragraph -If you have a poor responding BA control less than they are currently the better
responding BA will respond more due to the lower interconnection frequency. This will punish the BAs that
have good response and reward those that have poor response, depending on the methodology used to
calculate correct frequency bias terms.
o Frequency Bias Setting Floor - BPA cannot support a standard that isn’t well defined and essentially gives
the ERO a blank check to make changes to the standard without a vote.
o Frequency Response Obligation and Allocation - BPA cannot support a standard that isn’t well defined and
essentially gives the ERO a blank check for assigning an FRO to each BA. If this is the method for defining
FRO, then it should be included in the requirements section of the standard. However, this section does not
spell out how the FRO will be calculated other than that it will be based on the (peak generation + peak
load)/2. The full methodology for calculating the FRO must be detailed and put in the standard.
Response: The SDT has modified Attachment A and the Background Document to provide additional clarity concerning the calculation methodology and the
reasoning behind the proposed requirements. The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard
Requirement is enforceable as part of that Requirement.
The SDT has modified the FRS Form 1 to allow for adjustments. Any adjustment will have to be justified.
The SDT has corrected the mistake in Paragraph 1.
You are correct concerning the 36 mHZ and this has been corrected. The SDT is only using this to provide a minimum value for selection of events.
The SDT has analyzed several different time periods for the Point A, Point B and Point C values. The SDT has chosen the time periods based on this analysis as
detailed in Attachment A and FRS Form 1.
The SDT is proposing to use -16 seconds in order to account for varying AGC scan rates to obtain an average.
The SDT does not believe that there is any requirement presently in place that identifies good or poor responding BAs. The SDT further believes that a BA that is
providing proper Frequency Response recognizes the importance and will continue to provide the necessary Frequency Response. Those BAs that are not
providing adequate and sustained Frequency Response will be identified through the measure.
The SDT disagrees with your comment that this proposed standard gives the ERO a “blank check” to modify the standard. The proposed standard is attempting to
bring the Frequency Bias Setting and the natural Frequency Response closer together and not attempting to set a floor.
The SDT has modified Attachment A to provide additional clarity concerning the calculation methodologies. The SDT has been advised by NERC Legal that an
attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that Requirement.
SPP Standards Development
No
While we agree that Attachment A is useful, it hasn't quite got to the point where it clearly helps us understand
the requirements as well as the calculations and other determinations that must accompany the standard.
118
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000545
Organization
Yes or No
Question 11 Comment
Response: The SDT recognizes this and has responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
IRC Standards Review
Committee
No
Attachment A is useful, but it does not provide a clear understanding of all topics and issues. This is
evidenced by the questions and comments the SRC is submitting.
Response: The SDT recognizes this and have responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
ERCOT
No
Attachment A is useful, but it does not provide a clear understanding of all topics and issues. This is
evidenced by the questions and comments the SRC is submitting.
Response: The SDT recognizes this and have responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
Southern Company
No
We did not want to vote on question 11 - clicked 'NO' in error Comments:
Attachment A
Comment 1: The initial draft of BAL-003 - Attachment A provides a range of valuable background details and
historical information about Frequency Response. However, all of this information is not pertinent to the BAs
ability to understand and comply with the Standard. The SDT should consider utilizing the Standards
Processes Manual (page 39) which provides a detailed description of various alternatives to an attached
supporting document. Document types include References, Guidance, Supplements, Training Material,
Procedures, and White Papers.
Comment 2: The Standards Processes Manual (page 39) makes clear that supporting “documents may
explain or facilitate implementation of the standards but do not themselves contain mandatory requirements
subject to compliance review.” Draft BAL-003 - Attachment A may be in contradiction to the Manual because
it suggests mandatory requirements for the BA. Refer to page one where a statement provides that the BA
must, within one month after receiving a listing of official events, assemble its data and calculate a Frequency
Response Measure. This obligation is not stated in BAL-003 or the proposed BAL-003-1. The Manual
explains that any mandatory requirements must be incorporated into the standard in the standards
development process. The SDT should first evaluate whether or not this is a requirement and second, if
alternative language may alleviate confusion.
Response: Attachment A has been split in to two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
119
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000546
Organization
Yes or No
Question 11 Comment
No
While the attachment provided insite into the distribution of the FRO for each BA, it lacks clarity on whether
the interconnection FRO is based on the largest category C event that occurred, or if this event is based on a
study.
Requirement.
Progress Energy
Additionally, if the event is from actual data, what happens if the interconnection is shown to need less
response than it currently has due to the response of frequency dependent loads.
What happens to BAs that "have only load with no native generation" if they do not meet their FRO? Are they
going to be required to meet their FRO through load managmenet schemes?
Response: Attachment A has been split in to two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised for clarity.
The SDT believes that a BA that is providing proper Frequency Response recognizes the importance and will continue to provide the necessary Frequency
Response. Those BAs that are not providing adequate and sustained Frequency Response will be identified through the measure. The FRO is and will be
determined based on the methodology detailed in Attachment A.
If A BA does not meet the Requirements then it will be found noncompliant. The proposed standard is setting a minimum Frequency Response but not
prescribing a method to meet the requirements. However, the SDT has identified methods of obtaining Frequency Response in the standard.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The SDT, in consultation with the NERC Frequency Response Initiative, has performed empirical studies that demonstrate the median is more resilient
to data quality problems and statistical outliers.
Energy Mark, Inc.
No
Comment 20: The document is useful, but it needs a number of modifications to provide a clear
understanding of the Requirements.Frequency Bias Setting vs. Frequency Response Section:
Comment 21: In bullet 1 the use of the word “storage” is unclear.
Comment 22: In bullet 3, The two boxes indicating that the Point A and Point B values are averages should
also indicate that the averaging periods for these calculations vary with the scan rate used to collect the data.
The correct averaging periods were presented in a table from the NERC Reference Document Understand
120
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000547
Organization
Yes or No
Question 11 Comment
and Calculating Frequency Response developed by Frequency Response Standard Drafting Team. These
scan values used for averaging should be included in the instructions.Frequency Response Obligation and
Allocation Section:
Comment 23: In the second paragraph of this section there is no supporting analysis that indicates the level
of reliability that the selection of “the largest category C event (N-2).” Without such analysis, there is no way
to determine the level of reliability that will be supported by this “target contingency protection criteria.” A
reliability criterion that supports an unknown level of reliability is no reliability criteria at all.
Comment 24: In paragraph four of this section, determination of the “administrative procedure to assign an
FRO to each BA for the upcoming year” is removed from the stakeholders and given to the ERO and the
NERC RS to determine. This is unacceptable in a stakeholder driven process without more information about
how this determination will be made.
Comment 25: In paragraph five of this section, an initial method is offered to determine the proportion of total
Frequency Response that each BA will use as their FRO. This method is not influenced by the need for
Frequency Response in any manner. It therefore, creates perverse incentives for BAs attempting to make
decisions concerning Frequency Response and fails to meet the requirement that “A reliability standard shall
neither mandate nor prohibit any specific market structure.” This is explained in greater detail later in my
comments in response to Questions 16 and 17.Methods of Obtaining Response Section:
Comment 26: In the first paragraph, it is suggested that the Frequency Response Obligation could be fulfilled
by participating in Reserve Sharing Group (RSG). RSGs were created because of the “non-coincident”
nature of the need for Contingency Reserve among BAs. In creating RSGs, all of the BAs in the RSG could
reduce the amount of Contingency Reserve that they individually held while still meeting the reliability
requirements associated with recovering from disturbances. The savings achieved by reducing individual
reserve and sharing reserves provided strong economic incentives to support the infrastructure to create,
manage and operate these RSGs. Unlike Contingency Reserves, Frequency Responsive Reserves are
always needed on a “coincident” basis because the frequency is the same throughout the interconnection.
The strong economic incentives associated with the supply of Contingency Reserves by RSGs do not exist
when considering the “coincident” need for Frequency Responsive Reserves. At best, there is only a small
reduction in need for reserves on an event by event basis and that small effect is significantly reduced when
the averaging period for event measurement is extended over time as the draft standard suggests, one year
average measurement period for Frequency Response.
Comment 27: In the second paragraph, it is suggested that the problem of obtaining Frequency Response be
passed to the RSGs rather than addressing it directly in this standard or in other standards under
development. In the distant past, the term “spinning reserve” was weakly related to the amount of Frequency
Responsive reserve available. However, in current NERC standards there is no defined relationship between
“spinning reserve” and Frequency Responsive Reserve. Therefore, there is no reason to pass this problem to
RSGs. However, if an RSG, after investigating the provision of Frequency Response chose to address the
problem, there should be no objection to an RSG taking responsibility of its members’ Frequency Response
121
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000548
Organization
Yes or No
Question 11 Comment
Obligations in a manner similar to a single BA.
Comment 28: In the third paragraph, it is suggested that “as long as all BAs within the RSG use the same
events for calculating FRM, BAs within the RSG may allocate a portion of their FRM to another RSG
participant.” When one considers that there are expected to be over 25 events in the annual calculation, the
probability that all BAs in a RSG will have the data available for the same 25 events should be expected to be
small, especially for large RSGs. Does selection of events for the RSG members in a manner to insure the
same 25 events offer an opportunity to bias the sample?
Response: Comment 20 – Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the
standard and a new document titled, “Frequency Response Standard Background Document”, that explains the reasoning behind the requirements. These
documents have also been revised to provide clarity.
Comment 21 – The SDT has removed the reference to “storage” from the documents.
Comment 22 – The SDT agrees and has included averaging periods based on AGC scan rates.
Comment 23 – The SDT agrees that further development is needed in this area, and will review this issue during the field trial and provide more definitive
analyses.
Comment 24 – The SDT has revised Attachment A to clarify the calculation methodology.
Comment 25 – The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region,
ISO, RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Comments 26 & 27 & 28 – The SDT appreciates these observations and has taken these comments under consideration including modifying the standard
regarding RSGs.
FMPP
No
It is useful, but Attachment A is not clear.
Response: Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised for clarity.
American Electric Power
No
As stated earlier, attempting to follow requirement(s) within multiple versions of the same standard would be
very difficult. In addition, more examples should be provided.
Response: Requirement R5 has been inserted back into this version of the draft standard and should eliminate the concern of trying to operate using multiple
versions of the same standard. This standard will replace all versions of BAL-003 currently in effect.
The SDT has also revised Attachment A and FRS Form 1 to provide clarity.
122
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000549
Organization
Yes or No
Duke Energy
No
Question 11 Comment
Attachment A is useful, however R2 of the standard references a “calculation methodology detailed in
Attachment A” and it isn’t clear to us what part of Attachment A is the methodology.
Also, in Attachment A the term “Interconnection Frequency Response Obligation” is used, but the definition of
FRO says it’s a BA value, so that’s inconsistent.
Overall, we agree that the document is helpful; however, we do believe additional explanation is necessary for
Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed from
the Balancing Authority.
There is an implied obligation that the ERO will determine the Frequency Bias Setting but it is not stated
explicitly. Under the proposed standard, who has the responsibility for determining the Frequency Bias
Setting?
Response: The SDT has also revised Attachment A and FRS Form 1 to provide clarity.
The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide further clarity
as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency
Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
Patterson Consulting, Inc.
No
The historical, contextual, and instruction information is valuable and needs to be associated with this
standard. This material should not be included in Attacment A, though, as described in previous responses. In
addition, there are inconsistent use of definitions and terms in the document that should be corrected.
Response: Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised to provide clarity.
South Carolina Electric and Gas
Yes
It would be helpful to have a heading to transition from the criteria section to the reasoning section.
Also, the title of attachment A should include "Frequency Response" before "Background Document."
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
NIPSCO
Yes
Not sure if all the requirements need to be explained, we'll wait for future postings.
123
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000550
Organization
Yes or No
Question 11 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
Westar Energy
Yes
The attachment should be updated as the proposed standard is revised and the standard becomes effective
and field test results are available.
The typical frequency response curve with points A,B and C should be included and therefore part of the
standard.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity. The SDT will evaluate and determine if additional modifications are necessary prior to posting for industry approval.
The frequency curve points A, B and C are identified in FRS Form 1 and therefore are part of this standard.
Manitoba Hydro
Yes
While Attachment A is useful, it could be improved by adding a graph to better illustrate Point A and C and the
4 second data sampling rate.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
Seattle City Light
Yes
EKPC
Yes
ENBALA Power Networks
Yes
SERC OC Standards Review
Group
Yes
Kansas City Power & Light
Yes
124
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000551
Organization
Yes or No
Independent Electricity System
Operator
Yes
Santee Cooper
Yes
LG&E and KU Energy
Yes
Arizona Public Service Company
Question 11 Comment
AZPS agrees it is useful, however, more clarity of how the FRO is determined and how the FRO differs from
the FRM.
Response: The SDT thanks you for your comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
The FRO is the minimum amount of Frequency Response needed to comply with this standard. The FRM is the measure of the Frequency response provided
during an event.
Alberta Electric System Operator
AESO suggests that this document should provide a clear description and discussion of the concerns,
response measures at different aspects or time frames of frequency response (inertial response, governor
response, AGC response; arresting deviation and settled deviation),and should provide technical evidence or
reasons why the proposed standard can address the related concerns.
Response: The SDT thanks you for your clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
ISO New Engand Inc.
Attachment A is useful, but it does not provide a clear understanding of all topics and issues.
Response: The SDT thanks you for your clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
125
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000552
Organization
Northeast Power Coordinating
Council
Yes or No
Question 11 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
126
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000553
12. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s FRM. Do you agree with the SDT that this is
the proper method to calculate its FRM? If not, please explain in the comment area and if possible provide an alternate method to calculate
FRM.
Summary Consideration: Several of the commenters agreed that the calculation in FRS Form 1 is the proper method for calculating the
FRM. Many commenters expressed concern that the FRM calculation method was simplistic, did not capture all contributing factors, and
that use of the median value may result in a determination of noncompliance for otherwise compliant conditions. Regarding FRS Form 1,
many calculation errors were identified and several commenters indicated that the information provided was neither clear nor complete.
There was general consensus for conducting a field trial during which consideration of other statistical methods will be evaluated by the
SDT. A few commenters believe that the 1% of peak formula currently in use should be maintained. Another comment indicated that
certain events including contingent Balancing Authority events should not be used for the calculation. One commenter indicated more
study is needed to determine how to account for energy flowing across a Balancing Authority’s Area since this flow could affect frequency
response. Concern was also expressed indicating there is not a reliability basis or replacement for addressing the AGC Frequency
Response phase out approach for Requirement R5.
In response to industry comments the SDT has revised FRS Form 1 (including calculations) to allow for adjustments to the calculations.
The SDT affirms that the median is the preferred measure for eliminating statistical outliers which have a tendency to skew analysis
results. Other statistical methods will be considered by the SDT during the field trial. The SDT agrees there needs to be a floor Frequency
Response Setting threshold however the current 1% of peak of peak load/generation threshold is causing many Balancing Authorities to
over bias, causing unnecessary ACE and frequency undulations. The drafting team is proposing a phased approach for reducing the
Frequency Bias Setting value to less than 1% of peak load/generation for Balancing Authorities with actual Frequency Response is currently
less than this value. This approach is detailed in Attachment B.
Organization
Bonneville Power Administration
Yes or No
Question 12 Comment
No
RAS events and Contingent BA events shouldn’t be used in the calculation. The FRS Form 1 has a basic
flaw that needs correction. For Balancing Authorities that have frequency response wheeled across them by
other BAs (for example, with BPA, any contingency that occurs in the south will have frequency response
from BCHydro wheeled across it) and the associated losses will show as less frequency response by the BA
that is being wheeled across. BPA recommends that the generation and load be measured, primarily
generation, in order to find the frequency response of the BA. Since few, if any, BAs directly measure their
total load, the calculated load will have the same issue due to the responses wheeling across the BA (load is
generally calculated as total generation minus total interchange). Therefore, more study needs to be done to
determine how to account for the energy flowing across a BA.
Response: The drafting team has taken the suggestion to exclude RAS events for frequency response analysis and will study this further should there be a need
to incorporate more events to perform frequency response analysis.
127
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000554
Organization
Yes or No
Question 12 Comment
The method of analyzing a BA response is formed on a net metered basis to obtain the BA response. The response is not summed across intermediate BAs for
loss consideration and ultimate delivery of energy. In the case of Bias the deviation from present metering is an indication of response and load change within
the BA as noted in the response. Frequency response could be calculated by measuring each generator and load bus change but then there are distribution
losses reflected in the numbers. The generally accepted method presently assumes that change in loss for the frequency response MW delivery is not significant
when delivered by many sources.
SPP Standards Development
No
We do not necessarily agree that it does. Please see our response to Question 1.For the 2010 survey NERC
provided the Points A and Points B for the listed events in the provided spreadsheet. FRS Form 1 does not
contain that information, only the delta frequency. Please include the Point A and Point B frequencies for the
SEFRD events in FRS Form 1.
Response: Please refer to our response for Question 1. The drafting team has revised FRS Form 1 and Points A and B values are calculated in FRS Form 2 and
shown in FRS Form 1. These values will differ for each BA based on readings at the BAs location rather than a specific location in the interconnection.
IRC Standards Review
Committee
No
It is one method, but not necessarily the only proper method. Not all existing methods need to be replaced.
The SRC suggests scan data could be used so that different metrics can be evaluated.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
ERCOT
No
It is one method, but not necessarily the only proper method. Not all existing methods need to be replaced.
The SRC suggests scan data could be used so that different metrics can be evaluated.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
ISO New Engand Inc.
No
It is one method, but not necessarily the only proper method.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
Kansas City Power & Light
No
This method is too simplistic and does not take into account normal statistical variations in metering accuracy
and resolution for generation and tie-lines, does not take into account the natural variations of generation due
to mechanical variations, and does not take into account the impact of load control actions on generation.
Without taking these variations into account, the outcome is the wild calculation results that have been seen
in the current submissions by BA’s that should be an indication that the method needs considerable work to
be considered useful.
128
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000555
Organization
Yes or No
Question 12 Comment
Response: The drafting team disagrees that the method needs to address SCADA support concerns cited. There should be a documented reason for each error
which can be excluded. The field trial evaluation will identify errant calculations and any need for further revision.
Progress Energy
No
Progress Energy believes you can, and should calculate a frequency response for BAs with the contingency
also. We are also not certain that a strict median response should be used as it provides opportunity for BAs
to perform moderately most of the year and make up for it with a few days slightly above their desired median
target when they should take measures to hit their target every time within a standard deviation tolerance
(excluding outliers)
Response: We thank you for your support. The SDT, in consultation with the NERC Frequency Response Initiative, has performed empirical studies that
demonstrate the median is more resilient to data quality problems and statistical outliers. The SDT believes that this measurement methodology using the
median value is the most appropriate method at this time.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly. Page 2 implies that there
is currently too much frequency response based on the 1% of peak demand method of establishing frequency
bias. Even though NWE does not use the 1% method, NWE feels that the 1% minimum has been a tried and
true method of providing frequency response in the Western Interconnection.Without the 1% minimum (and
BA’s using a natural response less than the 1%), the total interconnection frequency response would
decrease according to research. This would lead to decreased interconnection bias, causing other
operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The drafting team agrees that calculated frequency response varies from event to event. This is because there are multiple Balancing Authorities
interconnected and each BA has a small frequency response contribution compared to the variation in its load and generation experienced at any given moment.
This is why the drafting team is proposing to use the median value of events selected during the year as a measure of “average” response. The median is the
preferred measure to eliminate population statistical outliers which have tendency to skew results.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing testing using a bias setting value of less than 1% for BAs with frequency response that is less than the 1% value currently
calculated in order to better match the natural response. The drafting team agrees there needs to be a floor threshold however the current 1% threshold is
causing many BAs to over-bias, resulting in ACE and frequency undulations.
Please identify the research indicating control problems would occur using a minimum bias setting that is less than 1%.
129
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000556
Organization
Yes or No
Question 12 Comment
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
Energy Mark, Inc.
No
Comment 29: I agree that a method similar to the one suggested can be used to calculate the BA's FRM.
However, there are a number of errors in the suggested FRS Form 1.Data Entry Tab:
Comment 30: The calculation of SEFRD in column G is incorrect for events marked as Internal Contingency
in Column I. This calculation must also include the change in internal generation due to the Internal
Contingency. This adjustment must either be explained in the “Balancing Authority FRS Form 1 Background
and Instructions” or the calculation must be modified using a column added to the NERC FRS Form 1
(between column J and K) to include the size of the Internal Contingency in MW.
Comment 31: The calculation in cell L22 is incorrect because it includes the incorrect calculations from the
lines that indicate Internal Contingency. If the calculation in column G is corrected this cell will also be
corrected.
Comment 32: The calculation in cell L23 is incorrect because it includes the incorrect calculations from the
lines that indicate Internal Contingency. If the calculation in column G is corrected this cell will also be
corrected.
Comment 33: The calculation in cell L24 is incorrect. It provides the intercept of the linear regression for the
Frequency Response using the Intercept function. It should provide the slope of the regression of the change
in NAI from Column F to D regressed against the change in Frequency, Column B, using the LINEST function
with a forced fit through the origin, using the function y = mx. The correct value for the sample data in the
NERC FRS Form 1 is -24.7, not -16.2.
Comment 34: The calculation in cell L27 is incorrect. It provides the intercept of the linear regression for the
Frequency Response using the Intercept function. It should provide the slope of the regression of the change
in NAI from Column F to D regressed against the change in Frequency, Column B, using the LINEST function
with a forced fit through the origin, using the function y = mx. The correct value for the sample data in the
NERC FRS Form 1 is -22.5, not -33.9.
Comment 35: Cell M19 and M31 should read “...Frequency Response Obligation...”, not “...Frequency
Requirement Obligation...”
Comment 36: The regression methods described in Comments 33 & 34 above provide the best method to
calculate FRM. The linear regression method described is the only method of those suggested that properly
weights the data with respect to its influence on the value of FRM. Using the median fails to weight the data
at all. Using simple averaging weights the smaller events more than the larger events in the sample as
compared to their influence on the best estimate for FRM.
130
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000557
Organization
Yes or No
Question 12 Comment
Response: Comments 29,31, 32, 33, 34 and 35 – FRS Form 1 has been revised and corrected
Comments 30 – FRS Form 1 has been extensively revised and instructions for its use have be clarified.
Comment 36 – The SDT is evaluating several calculation methodologies. The SDT will propose the most suitable method in its final draft of this standard.
American Electric Power
No
The FRS Form 1 is actually calculating prior performance results from identified events to determine future
measure. The calculation method to determine a BA’s FRM still is not capturing all contributing factors that
occur in real time and have an impact at time of event occurrence to determine frequency response
performance to be measured. The calculation method and FRM needs to be more complete to include all of
these contributing factors such as magnitude of actual generation on line at time of occurrence that is capable
of governor & AGC response, actual generator loading, scheduled interchange imports to balance or meet
load demand, etc. The calculation method and FRM also needs to be more dynamic to allow inclusion of
these variable contributing factors to be able set proper measure and identify lack of performance to actually
address the issue, if there truly is one. There needs to be some form of measure at the actual generator level.
Measuring a BA’s aggregate response will not address contributing generators having negative governor or
AGC frequency response, and puts the entire burden on the BA when the performance issue to be resolved is
more at generator level.
There appears to be no reliability basis or replacement for addressing the AGC frequency response phase out
approach for R5 implementation plan. Without a reliability results based study to support this approach, it
appears on the surface that there is the potential to lose some of the AGC part of response.
Variable energy resources that are non-responsive must also be addressed in the overall calculation and
measure. Because the electric industry has evolved with unbundling of generation/transmission and
implementation of energy markets, there needs to be an ancillary service component for frequency response
to address the factor of independent players that impact the lack of or negative frequency response issue.
When impacting entities have financial factors that conflict with reliability intent, the reliability performance
process can be compromised and made more difficult to achieve.
Response: FRS Form 1 has been revised.
The dynamic measure as suggested implies the BA should have a dynamic response incorporated into its frequency bias setting as a variable component.
The SDT believes that the current 1% of peak of peak load/generation threshold is causing many Balancing Authorities to over bias, causing unnecessary ACE and
frequency undulations. The drafting team is proposing a phased approach for reducing the Frequency Bias Setting value to less than 1% of peak load/generation
for Balancing Authorities with actual Frequency Response that is currently less than this value. This approach is detailed in Attachment B.
The drafting team welcomes the initiative of companies to offer a NAESB solution for ancillary services which is beyond the scope of this SAR.
131
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000558
Organization
Yes or No
Duke Energy
No
Question 12 Comment
Other factors need to be considered and incorporated in the calculation. See comments to 1 and 2 above.
Response: Please see our response to Questions 1 and 2.
FRS Form 1 has been revised and the drafting team will list specific reasons for revisions and event exclusion.
Patterson Consulting, Inc.
Yes
Pending modifications based on results from the field test and subsequent operation under the new standard,
FRS Form 1 is a good start for calculating a Balancing Authority's Frequency Response Measurement and
Frequency Bias Setting.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
South Carolina Electric and Gas
Yes
The form must have clear instructions on its use and meanings of the terms.FRS Form 1 and Instructions
should be included as an attachment to the BAL-003-1 standard.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Santee Cooper
Yes
The form must have clear instructions on its use and meanings of the terms. The form should include the
ability to take into account changes in metered non-conforming loads.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised to allow for adjustments such as non-conforming load.
LG&E and KU Energy
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
FirstEnergy
Yes
Although the method seems acceptable in theory, the results of the field test will be needed to validate the
methodology.
Response: We thank you for your affirmative response and clarifying comment.
132
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000559
Organization
SERC OC Standards Review
Group
Yes or No
Yes
Question 12 Comment
The form must have clear instructions on its use and meanings of the terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
ENBALA Power Networks
Yes
ENBALA also believes that including an additional metric, such as the metric suggested in the recent
Lawrence Berkeley National Laboratory of a nadir-based frequency response, would be useful in assessing
the current inertial response capabilities and level of risk for under-frequency load shedding.
Response: We thank you for your affirmative response and clarifying comment.
The SDT will consider your suggestion during the field trial.
NIPSCO
Yes
Seems straightforward compared to other methods
Response: We thank you for your affirmative response and clarifying comment.
EKPC
Yes
The form should include clear instructions for use and clear definitions for terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Manitoba Hydro
Yes
Although it can be difficult for some events to determine the NIA and load values for the A & B points(due to
significant signal variations), this is still the best known method at this time.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Seattle City Light
Yes
We Energies
Yes
Westar Energy
Yes
133
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000560
Organization
Yes or No
FMPP
Yes
Arizona Public Service Company
Yes
Midwest ISO Standards
Collaborators
Yes
Independent Electricity System
Operator
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
Question 12 Comment
The standard uses median of multiple SEFRD for the calculation of FRM, which is a reasonable method. The
AESO suggests NERC considers the alternative "zero-cross linear regression" method for the FRM
calculation. The key difference of "zero-cross linear regression" is that it puts more weight on events with
bigger frequency deviation. As the standard is to address the concerns related with large frequency error that
could cause UFLS, the more weight put on larger events seems more reasonable.
Response: We thank you for your input and suggested method will be considered during the field trial.
Refer to the response to Question 17.
Northeast Power Coordinating
Council
Response: Please see our response to Question 17.
134
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000561
13. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s Frequency Bias Setting. Do you agree with
the SDT that this is the proper method to calculate its Frequency Bias Setting? If not, please explain in the comment area and if possible
provide an alternate method to calculate Frequency Bias Setting.
Summary Consideration: Many of the commenters agreed with requiring the use of FRS Form 1 for calculating a Balancing Authority’s
Frequency Bias Setting. Most commenters agreed with the concept but expressed concern that FRS Form 1 had errors, incorrect
calculations, did not provide consideration for variable bias, and instructions were vague. Some commenters indicated that the
methodology was too simplistic and use of the median value is not an adequate approach. Comments were also received suggesting the
current 1% of peak methodology is a proven method that should be maintained and each Balancing Authority should be allowed to
determine its Frequency Bias Setting. One commenter suggested the FRO value should not be considered when determining the
Frequency Bias Setting. Another commenter suggested gradually lowering the Frequency Bias Setting floor threshold over several years to
assess the associated reliability impacts. The SDT agrees and implemented this approach. Initially the FRM will be computed to 0.8% of
the Balancing Authority’s forecasted peak load or generation. A recommendation was provided to estimate the Frequency Bias Setting
using a linear slope approach with a least square fit method. The SDT will assess this method as part of the field trial. Observations
provided include field testing must validate the methodology and that the methodology should include two measures (AGC and
interchange) for identifying lack of frequency response.
In response to industry comments the SDT has revised FRS Form 1 to allow adjustments for known variables that will impact the measure.
One commenter noted that Requirement R2 states that the ERO will provide the Frequency Bias Setting for each Balancing Authority
whereas FRS Form 1 specifies a calculation to obtain a value which the ERO is not required to review or use. The SDT has modified the
requirement to address this process reporting and implementation concern.
Organization
Bonneville Power Administration
Yes or No
Question 13 Comment
No
BPA thinks that the Form can be used as a tool, but the results shouldn’t be the required Frequency Bias
setting. Each individual BA should be allowed to set their own. Also, this shows no consideration for variable
bias. Variable bias changes greatly during a contingency and this should be considered.Please see
comments to number 12.
Response: The SDT agrees that measurement of individual generator’s performance would produce a more accurate measure of Primary Frequency Control and
that the SDT had not considered losses within a BA’s system due to frequency response of other BA’s frequency response flowing through their system. This
could indeed have some effect on the accuracy of the measure when using Interchange Actual for the measure. The SDT agrees that variable bias, based on real
time conditions (up and down headroom) of on line generators and other frequency responsive devices, will produce the most accurate value for the bias setting
if the BA implements a program that will accurately estimate Primary Frequency Control from each of its generators or other frequency responsive devices and
account for load dampening. Form 1 could still be used as a confirmation of general performance and to consistently measure every BA to the same events for
comparison to the Interconnection’s performance as a whole. If the BA were willing to measure performance of each generator and other frequency responsive
devices to the same list of events as an additional measure, this could be used in the field trial to determine the magnitude of the measurement error of Form 1.
135
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000562
Organization
Yes or No
Question 13 Comment
The SDT would like to move the industry to accept the use of variable bias as the superior method for setting the Bias in the ACE equation as long as the BA
meets its minimum FRO and that the variable bias result matches actual Primary Frequency Control performance within some tolerance. A BA should not be
allowed to use a variable bias just to inflate their L10 values for CPS2 compliance.
SPP Standards Development
No
We do not necessarily agree that it does. Please see our response to Question 1.Given the disclaimers on
page 7 of the FRS Form 1 instructions under Data Values, do the BAs have the discretion to change data in
Form 1 if it doesn't match the data they recorded on their system?
Response: FRS Form 1 has been revised to allow adjustments for known variables that will impact the measure. The field trial will validate the accuracy of the
measure and identify problems using Interchange Actual. The BA can adjust the t (0) event time to align with their frequency data but they should not change
their data. Adjustments should be made in the columns provided in the revised FRS Form 1.
IRC Standards Review
Committee
No
It appears to be one acceptable method, but not all the calculations done through the use of the form are
clearly described. Further, it says that the Frequency Bias Setting will be based upon the FRM, but it doesn’t
say how that will be done.
Response: FRS Form 1 has been revised to be clearer. Initially the FRM will be compared to 0.8 % of the BA’s forecasted peak load or generation. The Bias
setting will be based on the larger value. BA’s will continue to be able to use a variable bias.
ERCOT
No
It appears to be one acceptable method, but not all the calculations done through the use of the form are
clearly described. Further, it says that the Frequency Bias Setting will be based upon the FRM, but it doesn’t
say how that will be done.
Response: FRS Form 1 has been revised to be clearer. Initially the FRM will be compared to 0.8 % of the BA’s forecasted peak load or generation. The Bias
setting will be based on the larger value. BA’s will continue to be able to use a variable bias.
Kansas City Power & Light
No
This method is too simplistic and does not take into account normal statistical variations in metering accuracy
and resolution for generation and tie-lines, does not take into account the natural variations of generation due
to mechanical variations, and does not take into account the impact of load control actions on generation.
Without taking these variations into account, the outcome is the wild calculation results that have been seen
in the current submissions by BA’s that should be an indication that the method needs considerable work to
be considered useful.
Response: When the BA’s bias setting closely matches natural Primary Frequency Control, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE
impact on the Interconnection’s frequency. This may also cause greater difficulty maintaining CPS1 and CPS2 compliance. The sample size of identified events is
intended to address BA performance variability concerns.
FRS Form 1 has been revised to account for known variables that will impact the measure. The SDT believes that when actual BA Primary Frequency Control
136
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000563
Organization
Yes or No
Question 13 Comment
improves, the measure will be more consistent and useful.
Progress Energy
No
The FRO should not be part of the determination of the bias setting unless you are actually going to respond
by the FRO value. BAs should be trying to get their FRC <= FRO, but not biasing by the FRO. The bias has
no effect on the FRC. Progress Energy also think the % of projected peak requirement should be removed
now.
Response: The SDT agrees that the % of projected peak requirement has been contributing to Secondary Frequency Control problems and has determined that
a phased-in approach is the preferred method of eliminating this requirement. The FRO is not intended to be the BA’s bias setting unless the BA’s actual Primary
Frequency Control is equal to the BA’s FRO and meets the minimum of the 0.8% of the BA’s forecasted Peak Load or Generation.
NIPSCO
No
Not sure, It appears that the FR is about 1/2 of the freq bias in the East Int. I think that the bias could be
brought down gradually over several years while monitoring system frequency for reliability.
Response: The SDT agrees and the standard has been modified to reflect your concern.
NorthWestern Energy
No
Page 2 implies that there is currently too much frequency response based on the 1% of peak demand method
of establishing frequency bias. Even though NWE does not use the 1% method, NWE feels that the 1%
minimum has been a tried and true method of providing frequency response in the Western
Interconnection.Without the 1% minimum (and BA’s using a natural response less than the 1%), the total
interconnection frequency response would decrease according to research. This would lead to decreased
interconnection bias, causing other operational issues, such as lower L10 values and possible CPS2
compliance factors. A Balancing Authority’s frequency response is based upon a “median” value calculated
from analyzing multiple events. Frequency response during some of these events is better than others,
depending on the system conditions at the time and the amount system loading and unloaded generation
online at the time of the event. Given these circumstances a BA’s actual response could vary by event (better
or worse than median), thus compliance measurement per event to a frequency response obligation based on
the median response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The drafting team agrees that calculated frequency response varies from event to event. This is because there are multiple Balancing Authorities
interconnected and each BA has a small frequency response contribution compared to the variation in its load and generation experienced at any given moment.
This is why the drafting team is proposing to use the median value of events selected during the year as a measure of “average” response. The median is the
preferred measure to eliminate population statistical outliers which have tendency to skew results.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing testing using a bias setting value of less than 1% for BAs with frequency response that is less than the 1% value currently
calculated in order to better match the natural response. The drafting team agrees there needs to be a floor threshold however the current 1% threshold is
137
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000564
Organization
Yes or No
Question 13 Comment
causing many BAs to over-bias, resulting in ACE and frequency undulations.
Please identify the research indicating control problems would occur using a minimum bias setting that is less than 1%.
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
The SDT fails to see the implication that there is too much frequency response based on the 1% of peak demand method of establishing frequency bias. The bias
setting will not increase or decrease Primary Frequency Control. It will only impact the measure of ACE and the resulting Secondary Control of the BA. The 1%
minimum requirement was appropriate in the past when BA’s Primary Frequency Control was nearly equal to 1% of the forecasted peak load or peak generation.
Form 1 and this revision to BAL-003 would still require that the Bias setting in the ACE equation be equal to or greater than the natural Primary Frequency Control
of the BA with a minimum value of 0.8% of the BA’s forecasted peak load or peak generation. When the BA’s bias setting closely matches natural Primary
Frequency Control, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE impact on the Interconnection’s frequency. This may also cause greater
difficulty maintaining CPS1 and CPS2 compliance. The sample size of identified events is intended to address BA performance variability concerns. The field trial
results should prove if this is a correct assumption.
Energy Mark, Inc.
No
Comment 37: My initial comments associated with calculation of the Frequency Bias Setting are included in
my comments 3, 4, 5, 6, 30, 31, 32, 33, 34 and 36.
Comment 38: The determination of the Frequency Bias Setting using a median or mean value provides an
incorrect weighting of the individual SEFRD measurements to correctly determine the Frequency Bias Setting.
The Frequency Bias Setting as used in the ACE Equation represents a linear function of Frequency
Response to frequency error. The best estimate of the Frequency Bias Setting from this SEFRD data is the
slope of the line through the origin using a least-squares fit. Any other method of determining the Frequency
Bias Setting will improperly weight the individual data points contribution to the error thus providing a poorer
estimate of the true value of Frequency Response.
Response: Comment 37 - Please refer to our response to the comments noted.
Comment 38 - Once events have been identified and data collected the SDT can and will use multiple methods of determining the best selection of a bias setting
for BA’s using a fixed bias. The SDT will include your recommended method as one that is considered.
FMPP
No
It would be better to define significant and let the BA exclude any events that meet this definition, since each
BA will be ramping differently. Since SEFRD is defined as the individual sample of event data from a
Balancing Authority which represents the change in Net Actual Interchange (NIA), divided by the change in
frequency, expressed in MW/0.1Hz, whenever a BA includes an event with a “significant” change in NIA due
138
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000565
Organization
Yes or No
Question 13 Comment
to a large interchange schedule ramp, the FRM is totally skewed, and should not be included. If other events
are available means that if other events are not available then an entity’s compliance is going to be based on
an event or events that has been skewed for the BA by significant interchange schedule ramp.
Response: FRS Form 1 has been revised to account for known variables that will impact the measure. The SDT believes that when actual BA Primary Frequency
Control improves, the measure will be more consistent and useful. Using identified events and measuring every BA’s performance during these events will provide
comparison of all BA’s performance to the Interconnection’s performance as a whole.
American Electric Power
No
There should be two measures to identify lack of frequency response: A calculation and measure for the AGC
part of frequency response based on actual load and generation on line at time of occurrence that is variably
adjusted and measured, while also accounting for interchange imports to balance. Today’s frequency bias
setting does not really address the governor response issue. There also needs to be some form of generator
governor response calculation and measure that starts with a base foundation of droop setting/relative
governor response and is adjusted accordingly. As WECC appears to have shown in its studies, there would
be excessive governor response based on current droop setting if governors responded as they are expected.
This could be an indicator that governor response measure should only be a percentage of this droop, which
protects the generator. Different types of generators and their characteristics must also be factored in.Since
there does not appear to be a performance issue with the Standards involving CPS, we do not believe the
CPS Bounds L10 values should be reduced.
Response: FRS Form 1 has been revised to account for identified variables in measuring Primary Frequency Control. The SDT agrees that measuring generator
governor response and Primary Frequency Control would be beneficial for determining proper delivery of frequency response. The SDT also agrees that generator
governor and droop settings will impact Primary Frequency Control but this concern is outside the scope of this project and a separate SAR will be required to
address governor settings. The SDT is not aware of any WECC studies indicating excessive governor response based on current droop settings if governors
responded as they are expected. The industry nominal droop setting is 5% and this level of performance should limit transmission flows across specific elements
unless the planning process does not account for this flow during contingencies. If Primary Frequency Control is not evenly distributed across the Interconnection
or there is not participation in Primary Frequency Control by all generators with sufficient regulation margin, elements of the transmission system can become
overloaded during a contingency. The SDT believes that when the Bias setting in the BA’s ACE equation closely matches the Primary Frequency Control of the BA,
then the ACE will accurately measure the BA’s impact on Interconnection frequency through the CPS 1 and CPS 2 measures. If a BA has very low Primary
Frequency Control and resulting lower Bias setting, the L10 value will change also.
Duke Energy
No
Other factors need to be considered and incorporated in the calculation. See comments to 1 and 2 above.
Response: FRS Form 1 has been revised to account for known variables.
Patterson Consulting, Inc.
Yes
Requirement 2 states that the ERO will provide the Frequency Bias Setting for each Balancing Authority.
While FRS Form 1 makes a calculation, the requirement does not require the ERO to review or use the FRS
Form 1 value. Otherwise, pending modifications based on results from the field test and subsequent operation
139
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000566
Organization
Yes or No
Question 13 Comment
under the new standard, FRS Form 1 is a good start for calculating a Balancing Authority's Frequency
Response Measurement and Frequency Bias Setting.
Response: The SDT has modified the requirement to address the reporting and implementation process of the bias setting.
South Carolina Electric and Gas
Yes
The form must have clear instructions on its use and meanings of the terms. FRS Form 1 and Instructions
should be included as an attachment to the BAL-003-1 standard.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
Santee Cooper
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
MRO's NERC Standards Review
Subcommittee
Yes
We agree that using Points A and B is correct and the calculations in the spreadsheet are correct.
Response: Thank you for your comment.
LG&E and KU Energy
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
Midwest ISO Standards
Collaborators
Yes
We agree that using Points A and B is correct and the calculations in the spreadsheet are correct.
Response: Thank you for your comment.
FirstEnergy
Yes
Although the method seems acceptable in theory, the results of the field test will be needed to validate the
methodology.
Response: The SDT agrees. The field test will utilize the method to test the measure.
SERC OC Standards Review
Group
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
140
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000567
Organization
EKPC
Yes or No
Yes
Question 13 Comment
The form should include clear instructions for use and clear definitions for terms.
Response: The SDT agrees and has revised Form 1 and included instructions to provide clarity in using the form.
We Energies
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
Independent Electricity System
Operator
Yes
Arizona Public Service Company
Yes
ENBALA Power Networks
Yes
Westar Energy
Yes
Alberta Electric System Operator
The AESO finds it difficult to comment as it is not clear how the FRO is determined.
Response: The revised instructions clarify the method for determining the FRO.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response for Question 17.
141
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000568
14. The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS Form 1 for calculating FRM and Frequency Bias
Setting. Do you agree with the SDT that this document provides a clear understanding of how to use the form? If not, please explain in the
comment area.
Summary Consideration: Several of the commenters did not agree that FRS Form 1 instructions provide a clear understanding of how to
use the form. The majority of commenters indicated that the instructions were incomplete, unclear, required better definitions, lacked
variable bias information, technically incomplete and mainly provided background information. In response to industry comments the SDT
has revised FRS Form 1 instructions and removed the background information.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 14 Comment
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Midwest ISO Standards
Collaborators
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
FirstEnergy
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
We Energies
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
LG&E and KU Energy
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable
142
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000569
Organization
Yes or No
Question 14 Comment
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
SERC OC Standards Review
Group
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. Fiqure 1 in Section B of the FRS Form 1 Instructions document should be
corrected so that it is viewable.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
South Carolina Electric and Gas
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Bonneville Power Administration
No
There is no explanation for variable bias. If the suggesting from tab 2 is that a monthly average should be
used then this grossly misrepresents the amount of variable bias that is used during a contingency. For
example: BPAs monthly average ranges from-150 to -160, but during a contingency it can be in the -400 to 500 range.
Figure 1 does not show up so it cannot be determined if BPA agrees with Points A, B and C. Averaging the
pre and post data with 16 seconds and 34 seconds, respectively, will cause the calculations to be skewed
with some generator response, some tertiary response, etc. We do agree, if Figure 1 appears, that this does
spell out how to use the form, BPA just has issues with the data to be provided.
Response: Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT is aware
of the extraneous influences in Net Actual Interchange values, and intends to select a sampling interval and an aggregation technique to minimize these
influences.
We apologize for the exclusion of Figure 1. The SDT has removed this figure from the revised instructions and has modified the FRS Form 1 and including
instructions within the form to provide clarity in using the spreadsheet.
SPP Standards Development
No
This document provides valuable background information regarding frequency deviations but lacks the
specific line-by-line Form 1 instructions as mentioned at the top of page 7. We need those details, what goes
in each column, how do we determine which values to use, etc. This would tend to minimize any confusion
that currently exists regarding completing the form.One specific item we'd like to see provided in the
instructions, as well as changed in Form 1, is carrying the Frequency Bias Setting value (Cell L32) out to two
decimals. The current limitation of one decimal has caused confusion in past surveys.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
143
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000570
Organization
IRC Standards Review
Committee
Yes or No
No
Question 14 Comment
The document explains much of the FRS Form 1, but not all, as commented previously.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
ERCOT
No
The document explains much of the FRS Form 1, but not all, as commented previously.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Progress Energy
No
The forms clarity can only truly be found by reverse engineering the formulas within each of the cells.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
ENBALA Power Networks
No
The FRS Form 1 Instructions that was downloaded from the supporting website seemed to be missing
information on page 5. We found that the accompanying FRS Form 1 (excel document) was more useful than
the actual instruction document in providing detail on the required calculation for the Bias Setting.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Energy Mark, Inc.
No
Comment 39: The following comments apply to Balancing Authority FRS Form 1 Background and
Instructions.Section A:
Comment 40: The last sentence in the second paragraph should be modified to read, “Therefore, it is better
to analyze response only when significant frequency deviations occur until better measurement methods can
be developed to overcome these difficulties.”Section A, Subsection 1, Frequency Response:
Comment 41: The words “continuous and inverse relationship” should be changed to “bidirectional,
continuous and inverse relationship” in all three bullets. Frequency Response that is not provided bidirectionally will be rapidly depleted by oscillating frequency events.
Comment 42: If a BA has “non-bidirectional step-function Frequency Response” to frequency, it must also
have sufficient continuous frequency response to restore frequency, frequency response, and frequency
responsive reserves (margins) following the use of the “non-bidirectional step-function Frequency Response.”
Therefore, the Frequency Response of primary interest for this standard is a subset of the Frequency
Response defined in the NERC Glossary.
Comment 43: Simulations and actual experience on the interconnections have demonstrated that step
function Frequency Responses can result in frequency instability and oscillations when they are not effectively
coordinated with bidirectional, continuous and inverse Frequency Response. Therefore, it is imperative that
the standard differentiate this bidirectional, continuous and inverse Base Frequency Response from other
144
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000571
Organization
Yes or No
Question 14 Comment
Supplemental Frequency Responses that can be applied under restricted conditions to supplement it.Section
A, Subsection 2, Response to Internal and External Generation/Load Imbalances:
Comment 44: Most AGC Systems use the Frequency Bias Setting in conjunction with the frequency deviation
to determine whether an imbalance in load and generation is internal or external to the BA. This can only be
done effectively when the Frequency Bias Setting matches the internal Frequency Response of the BA.
Unless the minimum Frequency Bias Setting requirements are modified to allow this matching to be
implemented, the most AGC Systems will be unable to perform as indicated in this subsection.Section A,
Subsection 4, Effects of a Disturbance on all Balancing Authorities...:
Comment 45: The description should be modified as follows; “When a loss of generation occurs,
Interconnection frequency declines because machine speed must decrease to supply the energy shortfall
from rotating kinetic energy. Initially, rotating kinetic energy from all rotating machines with direct mechanicalto-electrical coupling addresses the entire shortfall by lowering machine speed, and hence frequency, of the
Interconnection*.* Initially, an amount of kinetic energy equal to the power (generation) lost will be withdrawn
from the stored energy in rotating machines with direct mechanical-to-electrical coupling throughout the
Interconnection. As the mechanical speeds are reduced, Interconnection frequency decreases proportionally.
Comment 46: The term Inadvertent Interchange is not correctly used at the end of the first paragraph. Tie
flow error indicates power. Inadvertent Interchange indicates energy (power integrated over an hour). A
better sentence would be, “The resulting tie flow error (NIA - NIS) will be integrated into Inadvertent
Interchange.”
Comment 47: The first sentence in the fifth paragraph states, “If the Frequency Bias Setting is greater (as an
absolute value) than the Balancing Authority’s actual Frequency Response, then its AGC will ... , which further
helps arrest the frequency decline, but increases Inadvertent Interchange. Frequency decline is arrested
within the first 10 seconds of an imbalance by the Frequency Response of the interconnection. AGC action is
not initiated until many seconds after the frequency decline is arrested. Therefore, a Frequency Bias Setting
greater than the actual Frequency Response will not result in the AGC System having any effect on the
arrested frequency or make any contribution to arrest the frequency decline. The only effect will be to provide
aid during the initial stages of the frequency recovery which is immediately withdrawn during the later stages
of the frequency recovery, while contributing to Inadvertent Interchange. In fact, the effect of a Frequency
Bias Setting greater than the actual Frequency Response is very similar to the effect the a BA receives from a
reserve sharing group with the exception that the reserve sharing group does not withdraw the aid until after
the frequency recovery has been completed. The last sentence in this paragraph is also incorrect for the
same reasons stated previously. If a BA’s Frequency Bias Setting is less than the actual Frequency
Response, the BA will still contribute to arresting the frequency, however, it may withdraw its Frequency
Response before the contingent BA or Reserve Sharing Group is able to initiate recovery contributing to
further frequency decline or a delayed frequency recovery.Section A, Subsection 5, Effects of a Disturbance
on the Contingent Balancing Authority:
Comment 48: In the first sentence, the phrase “as allowed by the Frequency Bias Settings” refers to the
145
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000572
Organization
Yes or No
Question 14 Comment
replacement power provided to the Contingent BA from the interconnection. The initial amount of
replacement power supplied to the Contingent BA is unaffected by the Frequency Bias Settings. The
Frequency Bias Settings will only affect how quickly the replacement power is withdrawn after the frequency
is arrested and stabilizes. The risk is that the replacement power will be withdrawn before the Contingent BA
or RSG can replace it.
Comment 49: The two boxes indicating that the Point A and Point B values are averages should also indicate
that the averaging periods for these calculations vary with the scan rate used to collect the data. The correct
averaging periods were presented in Definitions of Frequency Values for Frequency Response Calculation in
NERC Reference Document - Understand and Calculating Frequency Response.
Response: Comments 39 through 48: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning
language within this document are not incorporated in this version.
Comment 49: The SDT created FRS Form 2 to address your comments. In addition, the SDT has extensively modified the instructions for the use of these forms
to provide additional clarity.
EKPC
No
The form should include clear instructions for use and clear definitions for terms. All figures within the
document should be viewable. More examples for various situations (non-conforming loads) should be
included.
Response: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning figures within this
document are not incorporated in this version.
The SDT has modified the FRS Form 1 and included detailed instructions within the form to provide clarity in using the form.
American Electric Power
No
The FRO value and calculation formula assigned by the ERO is not totally clear. The survey form should
indicate the complete formula used by the ERO. It appears to be missing.
Response: The information you are referencing is now included in Attachment A. The SDT has also modified the FRS Form 1 and included detailed instructions
to provide clarity in using the form.
Duke Energy
No
The form does not recognize the impacts noted in the comment to 1 above. The form does show a column
that appears to allow for exclusion of contingent BA events, but it is not clear how that is accomplished, nor
how doing so matches the definitions currently proposed. Duke Energy agrees with the SERC OC comments
“We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable.”
The form does not provide much in the way of instructions.
146
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000573
Organization
Yes or No
Question 14 Comment
Response: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning figures within this
document are not incorporated in this version.
The SDT has also modified the FRS Form 1 and included detailed instructions within the form to provide clarity in using the form.
Santee Cooper
Yes
The instructions should include how to take into account changes in metered non-conforming loads.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT has modified FRS Form 1 to allow for adjustments such as nonconforming load.
The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
NIPSCO
Yes
We didn't read it but the form looks good.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Patterson Consulting, Inc.
Yes
There are inaccuracies that should be corrected, but the document is useful and valuable. The desired
"averaging" of scan-cycle data included in FRS Form 1 Background and Instructions should be made
mandatory to achieve the standard's purpose of providing consistent measurement methods.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT created FRS Form 2 to address the averaging issue identified in your comment. In addition, the SDT has extensively modified the instructions for the
use of these forms to provide additional clarity. The SDT has also modified the FRS Form 1, correcting errors in the calculations.
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
NorthWestern Energy
Yes
Independent Electricity System
Operator
Yes
147
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000574
Organization
Yes or No
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
Northeast Power Coordinating
Council
Question 14 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
148
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000575
15. The SDT is soliciting comments on methods of obtaining Frequency Response to meet the FERC Order 693 directive. If possible please
provide any thoughts you may have on this subject.
Summary Consideration: Stakeholders provided the suggestions shown below as possible methods of obtaining Frequency Response to
meet the FERC Order 693 directive:
1.
Develop requirements applicable to the Generator Owner.
2.
Address droop, dead band settings and governor operation.
3.
Corroborate with manufacturers to address load demand response.
4.
Use generator output as a primary input for calculating Frequency Response
5.
Define ways Reserve Sharing Groups can assist Balancing Authorities in providing Frequency Response.
6.
Write standard requirements based on performance needs.
7.
Establish demand response as an ancillary service providing frequency response.
8.
Do not apply the standard to entities that do not have generation resources.
9.
Create a primary frequency market.
10.
Keep the 1% method currently in use.
11.
Ensure generators provide appropriate governor response and merchant generation contracts include a Frequency Response
obligation.
12.
Develop a specific continent wide Frequency Response definition.
13.
Provide a customer compensated pre-emptive load shedding program.
In response to industry comments the SDT delivered to NERC staff the recommendation for collaboration between the ERO and
manufacturers regarding load demand response. The SDT has specified in the latest draft standard other methods for a BA to obtain
Frequency Response. The SDT will examine, during the field trial, the possibility of transferring Frequency Response between BAs.
Organization
Santee Cooper
Yes or No
Question 15 Comment
The SDT should consider focusing and directing requirements at root causes. Specifically, the SDT should
develop requirements that apply to GOs and address droop requirements, deadband settings, governor
operation, etc., as well as specific response expectations which are measured and compared to reported
149
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000576
Organization
Yes or No
Question 15 Comment
settings. Such requirements would likely include exemption criteria to address older existing systems as well
as current operating conditions. Newer systems should be developed, however, to meet specific
requirements that will ultimately improve or maintain Frequency Response at acceptable levels. Subsequent
efforts by the ERO should also consider collaboration with manufacturers to address demand responses
associated with loads.
Response: This issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band settings and governor
operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these concerns. The
SDT will pass on your suggestion concerning further collaborations between the ERO and manufacturers.
Bonneville Power Administration
Primarily, frequency response comes from governor control at generators. In order to accurately measure
this, the output of generation should be used as one of the primary inputs to the calculation of frequency
response. Due to losses, as earlier explained, some BAs could be penalized due to losses associated with
other BA frequency response flowing over the BAs’ transmission system. This needs to be taken into account
when calculating the frequency response of the BAs.
Response: The SDT does not have adequate information to address this suggestion. An impact study would be the best option for conducting an analysis.
SPP Standards Development
The SDT has already offered a suggestion that Reserve Sharing Groups could assist Balancing Authorities in
the provision of Frequency Response. We're not familiar with such arrangements within Reserve Sharing
Groups and would need more information regarding the specifics of such sharing arrangements. That being
the case, as written the draft standard does not provide for the provision of Frequency Response by any entity
other than a Balancing Authority. Such arrangements would definitely have to be reflected in modifications to
Form 1.
Response: Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT has revised the standard to
include RSGs. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response. The SDT will examine,
during the field trial, the possibility of transferring Frequency Response between BAs.
IRC Standards Review
Committee
Demand Response performing as an ancillary service in which the resources are paid to reduce load upon
automatic or manual deployment can provide frequency response. Other devices are available, such as
flywheels or storage arrangements, such as battery banks, that can provide fast and sustainable response,
could also provide frequency response. The standard must be written around performance requirements and
results rather than prescriptive requirements that may have the unintended consequence of stifling innovation
and creativity in this area.
Within the ERCOT Interconnection and the ERCOT market construct, an ancillary service titled Load acting
as a Resource (LaaR) may provide up to 50% of the responsive reserve requirement and provides automatic
underfrequency relay activated response to frequency drops. Other market constructs provide for similar
150
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000577
Organization
Yes or No
Question 15 Comment
services.
As indicated in our comments under Q2, there is a missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an
industry discussion on this subject, and determine the entity(ies) responsible for governor actions/setting, the
mechanism to provide such a response, and the place for stipulating the necessary standard requirements to
enforce compliance for governor actions before further developing this BAL-003-1 standard.
Response: Manual deployment is not quick enough for frequency response. Automatic deployment of other devices could be useful to provide the desired
frequency response. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
ERCOT
Demand Response performing as an ancillary service in which the resources are paid to reduce load upon
automatic or manual deployment can provide frequency response. Other devices are available, such as
flywheels or storage arrangements, such as battery banks, that can provide fast and sustainable response,
could also provide frequency response. The standard must be written around performance requirements and
results rather than prescriptive requirements that may have the unintended consequence of stifling innovation
and creativity in this area.
Within the ERCOT Interconnection and the ERCOT market construct, an ancillary service titled Load acting
as a Resource (LaaR) may provide up to 50% of the responsive reserve requirement and provides automatic
underfrequency relay activated response to frequency drops. Other market constructs provide for similar
services.
As indicated in our comments under Q2, there is a missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an
industry discussion on this subject, and determine the entity(ies) responsible for governor actions/setting, the
mechanism to provide such a response, and the place for stipulating the necessary standard requirements to
enforce compliance for governor actions before further developing this BAL-003-1 standard.
Response: Manual deployment is not quick enough for frequency response. Automatic deployment of other devices could be useful to provide the desired
frequency response. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
151
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000578
Organization
Kansas City Power & Light
Yes or No
Question 15 Comment
The determination of sufficient frequency response in the interconnection is complex and varies according to
the ratio of generation online and the load in the interconnection. The calculation of actual frequency
response is also extremely challenging considering metering accuracy & resolution, SCADA sample rates,
statistical variations of load and generation. To accurately assess what is needed and the methods to
implement such a complex subject will take considerable thoughtfulness, time, testing and engineering
ingenuity.
Response: The SDT agrees with your comments and thanks you for your participation.
Progress Energy
We feel this problem exists on the generator level and this standard should only be applied to those entities
and their response. This will impact BAs of vertically integrated companies. Entities without generation
resources should not be held accountable for frequency response. If their energy supplier wants to make
them responsible for purchasing ancillary response service, that will be up to them on how they distribute it.
Based on the fact that schedules respond too slowly to meet the response window of the frequency measure,
schedules should never be used to measure response capabilities, thus making ancillary service
unnecessary.
Response: The SDT agrees that schedules are too slow to be used for Frequency Response. The SDT has also specified in the latest draft standard version
other methods for a BA to obtain Frequency Response.
The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…”
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns. Also, Requirements imposed on generators is outside the scope of the project approved SAR.
ENBALA Power Networks
ENBALA supports the creation of a Primary Frequency Market. This could be achieved in two methods:
Implementation of a new Market for Primary Frequency Response Or
Including in the definition of spinning reserves the requirement for resources to be capable of providing
Primary Frequency Response through autonomous and local control by governor action and inertial
response.
And
We particularly encourage the participation from all resources capable of providing this service in a
coordinated approach, including alternative technologies such as controllable loads, energy storage,
electrically-coupled wind farm controls, and demand response. Furthermore, we stress that this service needs
to be a coordinated, autonomous, and local control and should NOT be integrated in the AGC system.
152
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000579
Organization
Yes or No
Question 15 Comment
Response: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region, ISO,
RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
NIPSCO
We reviewed the related NERC Training Document from 2003 and your proposed method seems like the best
approach.
Response: The SDT thanks you for your support.
NorthWestern Energy
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly. Page 2 implies that there
is currently too much frequency response based on the 1% of peak demand method of establishing frequency
bias. Even though NWE does not use the 1% method, NWE feels that the 1% minimum has been a tried and
true method of providing frequency response in the Western Interconnection.
Without the 1% minimum (and BA’s using a natural response less than the 1%), the total interconnection
frequency response would decrease according to research. This would lead to decreased interconnection
bias, causing other operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The drafting team agrees that there is great variability in calculated frequency response event to event. This is because in a multi-BA
Interconnection, a given BA’s frequency response contribution is small compared to the variations in load and generation within the BA at any given moment.
This is why the drafting team is proposing to use the median value of many events during the year as the measure of “average” response. The median is the
preferred measure of by statisticians when dealing with data populations containing outliers.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing a test allowing all BAs with frequency response less than the 1% of peak to use a Frequency Bias Setting set less than 1% of peak
to better match the Frequency Bias setting to the natural response. The drafting team agrees a floor threshold needs to be maintained however the current 1%
of peak requirement is causing many BAs to over-bias, causing undulations in ACE and frequency.
The SDT would appreciate it if you could identify the research indicating control problems would be realized if the minimum bias setting was set less than 1%.
The SDT also agrees CPS compliance scoring may be affected which is why the drafting team proposes testing using incremental changes to the Frequency Bias
Setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) implies that better matching of the Frequency Bias Setting
to the system Frequency Response Characteristic will improve AGC and frequency performance, and also improve CPS compliance scoring.
The SDT does not agree that there is excessive frequency response because of the 1% of peak demand method for establishing the Frequency Bias Setting. The
153
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000580
Organization
Yes or No
Question 15 Comment
bias setting does not increase or decrease Primary Frequency Control. The bias setting value will only impact the measure of ACE and resulting Secondary
Control. The 1% of peak minimum threshold was appropriate in the past when BA Primary Frequency Control was nearly equal to 1% of the forecasted peak load
or peak generation. Keep in mind FRS Form 1 and the BAL-003 draft standard still require the ACE Frequency Bias Setting be set equal to or greater than the
Frequency Response Characteristic with an initial minimum value of 0.8% of the BA forecasted peak load or peak generation. When the BA Frequency Bias
Setting better matches the Frequency Response Characteristic, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE impact on Interconnection
frequency. This may result in lower CPS1 and CPS2 compliance scoring than currently realized.
The sample size of selected events used for analysis is intended to minimize the concern about variability of performance observed on an event-to-event basis so
that the BA can realize a consistent reference measure when performing analysis.
Energy Mark, Inc.
Comment 50: In those regions of North America where energy is supplied through markets, Frequency
Response should be defined as an additional Ancillary Service and acquired through these Ancillary Service
Markets. Attempts to acquire Frequency Response through methods external to the Ancillary Service
markets will contribute to market inefficiencies since these external methods must affect the capacity
available to the Ancillary Service markets. Use of out-of-market methods would oppose the very reasons that
electric energy markets were created in the first place.
Comment 51: BAs not participating in formal RTOs or ISOs could obtain Frequency Response by insuring
that their owned generation is providing appropriate Governor Response to the BA and that contracts will
merchant generation are modified to include the provision of Frequency Response in the merchant contracts.
It may be appropriate to request guidance from regulatory agencies encouraging the renogiation efforts
required to modify existing merchant generator contracts.
Comment 52: Whether Frequency Response is obtained through Ancillary Service Markets, merchant
generator contracts or owned generation, specific continent wide definitions for Frequency Response should
be developed to provide guidance and consistency in these diverse circumstances. NERC should be taking
the lead on developing the necessary continent wide definitions or policies for Frequency Response.
Response: Comments 50 & 51: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a
region, sub-region, ISO, RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Comment 52: The SDT will forward this comment to NERC staff.
Beacon Power Corporation
Beacon Power is a manufacturer and merchant developer of an innovative advanced energy storage
technology that uses flywheels. Beacon Power’s technology operates by using flywheels to rapidly recycle
energy from the grid in order to follow moment-by-moment changes in frequency nearly instantaneously. The
following characteristics of Beacon’s technology support the use of this technology for frequency response on
the electric grid.
− Responds to local frequency change in less than 1 second; full response in less than 4
seconds
− State of the art electronic control - accurate response. No dead-band required, but could be
incorporated if beneficial
- Inherently modular - Can be distributed around the grid. With distributed local
154
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000581
Organization
Yes or No
Question 15 Comment
response to frequency, less likely to be limited by congestion, and ensures islanded portions of the grid
maintain frequency response. The ability of Beacon Power’s flywheels to quickly and precisely respond to
frequency events on the grid makes this technology an ideal source of frequency response. The fast response
provided can aid in arresting rapid frequency decline on the system, which can assist in preventing the
frequency nadir from encroaching on the first step of Under Frequency Load Shedding. Because of its
modular design, flywheels can be built and positioned throughout the grid to provide a diversified frequency
response, ensuring adequate response during events that cause the grid to separate into islands. Any
standards developed by NERC must allow energy storage and should be inclusive of all technologies able to
provide frequency response. Storage resources that provide frequency response should be allowed to
recover their costs as a wholesale transmission facility subject to FERC’s jurisdiction. Storage facilities do not
generate electricity and operate only to enhance the reliability of transmission service. Given that there is no
open-market for frequency response, there are no concerns of cross-subsidization or competitive concerns.
This will address the FERC Order 693 directive to develop a method of obtaining frequency response, and will
improve the overall reliability of the interconnections. Beacon agrees with the approach of mandating
Balancing Authority response.
However, the SDT should go further to define performance requirements for different tiers of frequency
response, for example full response in 5 seconds maintained until 15 seconds, and full response in 15
seconds maintained until 90 seconds (numbers are for example only, the SDT would determine the
appropriate values), so that Balancing Authorities can be confident when acquiring new sources that
demonstrate those performance characteristics.
The use of Reserve Sharing Groups (as detailed in Attachment A) to provide a means of sharing Frequency
Response seems unnecessary. Since Frequency Response is contributed to the entire interconnection,
ignoring any propagation delays, any Balancing Authorities within an interconnection can share Frequency
Response if a consistent method of measuring and allocating it can be determined. However, since all online
sources of Frequency Response will contribute based on the change in frequency, this sharing of Frequency
Response will not improve interconnection performance. It will only allow Balancing Authorities with too few
sources to meet NERC requirements. Hence, sharing arrangements would only improve frequency
performance if it results in more frequency responsive sources being online during an event. Additionally, due
to the geographical differences of the Balancing Authorities within the Reserve Sharing Groups, their use is
not conducive to a diversified interconnection frequency response.
Response: Frequency Response required by the Standard fully satisfies the reliability needs of each Interconnection.
Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT is just offering this as a suggestion that
needs to be vetted. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Westar Energy
RSG and Spinning Reserve today is SECONDARY response. How does FERC see the RSG (or RTO
markets) providing PRIMARY frequency response? Allowing the RSG option does not "address the 693
155
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000582
Organization
Yes or No
Question 15 Comment
directive", only dumps it on the RSG with no direction. Using frequency responsive loads seems impractical
based on the small frequency deviation levels required. What customer would be ok with dropping load when
frequency drops to 59.964 or 59.92, etc.
Response: Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT is just offering this as a
suggestion that needs to be vetted. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Customers are not required to provide frequency responsive load for reliability however this is an options entities may wish to explore.
ISO New England Inc.
As indicated previously in our comments, there is missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. This standard appears to
incorrectly assume that the BAs have the resources/ability to provide (primary) Frequency Response, and this
is simply not the case. The BAs do not necessarily own facilities which can provide this service.
Response: The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…” The SDT has also specified in the latest draft
standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band
settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address
these concerns.
Independent Electricity System
Operator
As indicated in our comments under Q2, there is missing piece to maintaining system frequency and arresting
frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an industry
discussion on this piece, and determine the entity responsible for governor actions/setting, the mechanism to
provide such a response, and the place for stipulating the necessary standard requirements to enforce
compliance for governor actions before further developing this BAL-003-1 standard.
Response: The NERC Reliability Standards do not dictate how Requirements are satisfied.
The SDT believes each Interconnection possesses sufficient frequency response.
Regarding governor response - this issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band
settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address
these concerns.
Duke Energy
The efforts to develop the MOD-025/026 standards and the associated work to determine actual and
predicted generator response will do much to identify the response available and provide ways to plan for and
validate the response needed and supplied. ERCOT has demonstrated effective use of Load Acting as a
Resource (LAAR - essentially customer compensated pre-emptive load shedding). Exploration of similar
applications of this in other interconnections is warranted.
156
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000583
Organization
Yes or No
Question 15 Comment
Response: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region, ISO,
RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Patterson Consulting, Inc.
The SDT has taken the correct approach in mandating Balancing Authority response. Balancing Authorities
should be able to acquire that response from various sources to create a suitable portfolio to meet the
required performance. The industry may benefit if the SDT defined required performance characteristics for
Frequency Response from a technical perspective, such as initial response in less than 2-8 seconds,
maximum response in less than 2-40 seconds, continuous (or not) response, etc. (These values are
examples and should be determined by the SDT.) Once the market and industry understand expectations,
existing or new technologies with those characteristics become possible sources. Then, it is just a matter of
adjusting tariffs (compensation) to incent implementation. If Frequency Response is allowed to be shared
between Balancing Authorities, the SDT must create requirements to address such issues as deliverability,
measurement, and suitable electrical diversity throughout the interconnection.
Response: The SDT agrees with your comment. However, keep in mind that the SDT is responding to a FERC directive to “…define methods of obtaining
Frequency Response…” The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
The SDT is evaluating several averaging time periods during the field trial. The SDT will select the averaging time period that provides the most accurate results.
Alberta Electric System Operator
Frequency Response has different aspects and time frames (inertia, governor and AGC response), the
method of obtaining Frequency Response should respect these different aspects and time frames.
Response: The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…” The SDT has also specified in the latest draft
standard version other methods for a BA to obtain Frequency Response.
FirstEnergy
See our responses to Question 4.
Response: Please refer to our response to Question 4.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
157
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000584
16. If you are aware of any conflicts between the proposed standard and any regulatory function, rule order, tariff, rate schedule, legislative
requirement, or agreement please identify the conflict here.
Summary Consideration: Most of the commenters responding to this question provided a response but did not identify any conflicts. A
couple of the commenters felt that there may be a conflict with both the FERC Order 693 and the FERC March 18, 2010 order. Another
commenter felt that the requirements could impact CPS performance and that using events from the prior evaluation period could create
the possibility of double jeopardy.
The SDT explained that the comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue
needing to be addressed at this time was not correct. The SDT stated that in the December 16, 2010 FERC Order Accepting NERC’s
Compliance Filing the Commission states in par 12 “…NERC’s proposed action plan demonstrates a commitment to develop requirements
for minimum levels of frequency response needed for Reliable Operation consistent with the Commission’s directives in Order No. 693.”
The SDT believes that this clearly states that the directives from FERC Order 693 are to be addressed.
Concerning the comment that the requirements could impact CPS performance the SDT explained that it believes that the large gap
commonly found between natural frequency response and the frequency bias settings deployed based on 1% of peak load was resulting in
excessive and unnecessary regulation and was related to high frequency following DCS events and in other circumstances as well. The
SDT agreed that the reduction of the 1% of peak load floor for the frequency bias setting can affect the total interconnection frequency
bias setting, L10 values, and possibly CPS 2 compliance as well. The SDT further explained that it put Requirement R5 back in the
proposed standard with a process for reducing the minimum to provide for monitoring the system to ensure reliable operation.
With regards to the comment concerning the possibility for double jeopardy the SDT responded that the SDT expected each year to normally
have enough frequency events to avoid double jeopardy, but there was a need to have a backup plan in case a year does not yield sufficient frequency events.
Organization
FirstEnergy
Yes or No
Question 16 Comment
We are not aware of any conflicts at this time.
Response: The SDT thanks you for your participation.
IRC Standards Review
Committee
This proposed Field Trial and standard MAY conflict with Order 693 and the March 18, 2010 Order that
state:Specifically, the Commission stated: As the Commission noted in the NOPR and in our response to
FirstEnergy, Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall establish
and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing
Authority’s Frequency Response.” The Commission believes that the achievement of this Requirement is
fundamental to the tie line bias control schemes that have been in use to assist in balancing generation and
load in the Interconnections for many years.
158
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000585
Organization
Yes or No
Question 16 Comment
Further, in Order No. 693 the Commission concluded: We understand that the present Reliability Standard
sets the required frequency response of the balancing authorities to be approximately one percent or greater
by requiring that the frequency bias shall not be less than one percent and that the frequency bias be as close
as practical to, or greater than, the actual frequency response. March 18 Order concludesAccordingly, to
assure that NERC proceeds expeditiously, the Commission is setting a compliance deadline of six months
from the date of issuance of this order for the development of modifications to Reliability Standard BAL-003-0
that comply with the Commission’s directives as set forth in Order No. 693 to define the appropriate
periodicity of frequency response surveys necessary to ensure that Requirement R2 and other requirements
of the Reliability Standard are being met and the necessary amount of frequency response needed for reliable
operation. May 13, 2010 Order for a Technical Conference statedThus, we direct that NERC submit, within 30
days after the technical conference, a proposed schedule that includes firm deadlines for completing studies,
analyses needed to develop a frequency response requirement, and for submission of a modified Reliability
Standard that is responsive to the Commission directives in Order No. 693 pertaining to Reliability Standard
BAL-003-0.
In short the Orders only ask for the BAL-003 to be revised to provide a schedule for the Frequency Response
surveys. We may question whether the subjective 25 events per year is the same as a scheduled periodicity,
but the point here is that that is the only mandate that is needed immediately.
The only other requirement is that NERC file a schedule for completing its studies. Note that is not something
that is for a standard it is something for a NERC filing.
Response: The SDT disagrees with your comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue needing to be
addressed at this time. In the December 16, 2010 FERC Order Accepting NERC’s Compliance Filing the Commission states in par 12 “…NERC’s proposed action
plan demonstrates a commitment to develop requirements for minimum levels of frequency response needed for Reliable Operation consistent with the
Commission’s directives in Order No. 693.” This clearly states that the directives from FERC Order 693 are to be addressed.
ERCOT
This proposed Field Trial and standard MAY conflict with Order 693 and the March 18, 2010 Order that
state:Specifically, the Commission stated: As the Commission noted in the NOPR and in our response to
FirstEnergy, Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall establish
and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing
Authority’s Frequency Response.” The Commission believes that the achievement of this Requirement is
fundamental to the tie line bias control schemes that have been in use to assist in balancing generation and
load in the Interconnections for many years. Further, in Order No. 693 the Commission concluded: We
understand that the present Reliability Standard sets the required frequency response of the balancing
authorities to be approximately one percent or greater by requiring that the frequency bias shall not be less
than one percent and that the frequency bias be as close as practical to, or greater than, the actual frequency
response. March 18 Order concludesAccordingly, to assure that NERC proceeds expeditiously, the
Commission is setting a compliance deadline of six months from the date of issuance of this order for the
development of modifications to Reliability Standard BAL-003-0 that comply with the Commission’s directives
159
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000586
Organization
Yes or No
Question 16 Comment
as set forth in Order No. 693 to define the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other requirements of the Reliability Standard are being met and the
necessary amount of frequency response needed for reliable operation. May 13, 2010 Order for a Technical
Conference statedThus, we direct that NERC submit, within 30 days after the technical conference, a
proposed schedule that includes firm deadlines for completing studies, analyses needed to develop a
frequency response requirement, and for submission of a modified Reliability Standard that is responsive to
the Commission directives in Order No. 693 pertaining to Reliability Standard BAL-003-0. In short the Orders
only ask for the BAL-003 to be revised to provide a schedule for the Frequency Response surveys. We may
question whether the subjective 25 events per year is the same as a scheduled periodicity, but the point here
is that that is the only mandate that is needed immediately. The only other requirement is that NERC file a
schedule for completing its studies. Note that is not something that is for a standard it is something for a
NERC filing.
Response: The SDT disagrees with your comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue needing to be
addressed at this time. In the December 16, 2010 FERC Order Accepting NERC’s Compliance Filing the Commission states in par 12 “…NERC’s proposed action
plan demonstrates a commitment to develop requirements for minimum levels of frequency response needed for Reliable Operation consistent with the
Commission’s directives in Order No. 693.” This clearly states that the directives from FERC Order 693 are to be addressed.
Arizona Public Service Company
AZPS would like clarity if Interpretations of BAL-003-0 will be part of BAL-003-1.
Response: This standard will replace all existing BA-003’s and incorporates any approved interpretation.
Energy Mark, Inc.
Comment 53: In Comment 25 I indicated that the suggested allocation method fails to meet the requirement
that “A reliability standard shall neither mandate nor prohibit any specific market structure.” My comments
here support that contention. The allocation method is not influenced by demand for frequency response. As
a consequence, only one side of a fair market is represented. Markets are effective because:
1. Markets are voluntary allowing the demand side of the market to choose to not create the need to acquire
a product or service.
2. Markets select the lowest cost product or service from competing offers to supply the product or service
demanded.When the allocation method is blind to the demand for the product or service it eliminates the most
efficient market designs from consideration, and therefore, mandates a market design that only looks at the
supply side of the market.
Comment 54: Selecting an allocation method for Frequency Response that considers both the supply and
demand sides of the market for Frequency Response would enable the implementation of a much more
efficient market design. Such an allocation method would allow demand side reductions in the need for
Frequency Response to compete with supply side increases in the need for Frequency Response allowing for
160
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000587
Organization
Yes or No
Question 16 Comment
the creation of the most efficient markets in this Ancillary Service.
Response: The SDT acknowledges your concerns but your market-related suggestions are outside the scope of the industry approved SAR.
FMPP
NERC Relablity Standards Conflict - by using events from last year to determine an entity’s compliance with a
Requirement for this year puts the entity in double jeopardy for last year’s events, which were already used
for compliance for last year.
Response: The SDT agrees that a standard should not place an entity in double jeopardy. The SDT expects that each year will normally have enough frequency
events to avoid double jeopardy, but it needs to have a backup plan in case a year does not yield sufficient frequency events.
American Electric Power
This Standard has the potential to affect Standards involving CPS performance with respect to the calculated
CPS Bounds L10 if relative.
Response: The SDT believes that the large gap commonly found between natural frequency response and the frequency bias settings deployed based on 1% of
peak load is resulting in excessive and unnecessary regulation and is related to high frequency following DCS events and in other circumstances as well. You are
correct in asserting that the reduction of the 1% of peak load floor for the frequency bias setting can affect the total interconnection frequency bias setting, L10
values, and possibly CPS 2 compliance as well.
The SDT has put Requirement R5 back in the proposed standard. The SDT has modified the plan for reduction of the minimum Frequency Bias Setting. The plan
is no longer tied to the Field Trial. The SDT has removed the table reflecting the reduction of the minimum bias setting. The SDT is proposing a method of
reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reductions and adjusting them accordingly in an effort to bring the
Frequency Bias Setting closer to natural Frequency Response. Please refer to Attachment B for details of this reduction plan.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
Patterson Consulting, Inc.
None.
Kansas City Power & Light
No other comments.
161
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000588
17. Please provide any other comments (that you have not already provided in response to the questions above) that you
have on the draft standard BAL-003-1.
Summary Consideration: Several commenters indicated that the supplemental compliance information and attachment sections created
additional standard requirements. In response to this concern these documents have been revised. If a requirement states that the entity
must perform in accordnace with Attachment X, then Attachment X is an extension of that requirement and the performance identified in
the attachment is mandatory and enforceable.
Several commenters expressed concern that the Balancing Authority may not have the necessary means to effectively manage Frequency
Response and recommended that the SDT consider establishing a standard for generators to support the Balancing Authorities achieve the
necessary level of Frequency Response. The SDT explained that this standard will provide the metrics for Frequency Response while the
market will define itself.
Commenters also stated that insufficient detail has been provided for evaluating the appropriateness of the methodology used for
determining FRO. They indicated that the standard needed more details on how the FRO is calculated and allocated among the Balancing
Authorities. The SDT made significant modifications to Attachment A – Supporting Document which details the methodology used to
determine the calculations.
Commenters indicated that the plan to annually reduce the floor percentage for the Frequency Bias Settings may adversely impact
reliability. In response to this concern the Implementation Plan no longer outlines the Frequency Bias Setting reduction plan initially
proposed. Attachment B sets forth the procedure for reducing the Frequency Bias Setting floor threshold.
Another commenter stated that emphasis should be placed on the Frequency Excursion Curve Point C value and not other values because
the Point C value is critical for reliability. A request was also received to correlate the frequency response for the Point B value timeframe
window with the timeframe window for the Point C value. The SDT committed to reviewing this relationship during the field trial.
One commenter asked how to attain or schedule Frequency Response from another Balancing Authority if it is a market resource. The SDT
responded that the standard simply provides reliability metrics. Industry determines which markets and independent solutions could be
developed.
A comment was received requesting clarification of the NERC glossary term “native load” mentioned in the Implementation Plan. Instead
of providing clarification, this term has been removed from the Implementation Plan.
Twenty-five additional industry comments have been received regarding the draft BAL-003-1 standard as noted in the following table.
Organization
Northeast Power Coordinating
Council
Question 17 Comment
It is not clear from either Form 1 or its instructions whether the supplied frequency deviation for an event should be used
without modification, or if it should be overwritten with a value computed from the Balancing Authority’s data source (or if
162
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000589
Organization
Question 17 Comment
there is an option, to use the lesser value, for example). Clearly express which frequency deviation value to use.
The load sensitivity calculation is an important Balancing Authority Area value to compute accurately for modeling purposes.
As proposed, it would use the same computational technique as that used for frequency bias sampling calculations. To yield
a useful result, load values would need to have “convergence characteristics” similar to that found in the actual net
interchange values used for frequency bias sampling. While experience has shown that the average or median values of the
frequency bias samples computed for most Balancing Authorities will converge with about 20 samples, a similar outcome for
load sensitivity calculations might not occur. Frequency bias samples rely on the measured actual net interchange values
that are sampled at the AGC scan rate, and the actual net interchange tends to be a rather stable value because AGC and
operator actions usually keep the actual net interchange close to a scheduled value. The total net system load may have
greater volatility and may be trending in a particular direction much more often than actual net interchange. Also, the load
calculation typically relies on adding the sum of the generation within the Balancing Authority to the actual net interchange.
The generation values may have a slower scan rate, longer data latency periods, and smaller generators might not be
telemetered, with hourly scheduled values or manually entered values being used instead. These differences can contribute
to a very different convergence characteristic than that found for actual net interchange. Simply put, the load sensitivity
calculation needs validation.
The Form 1 instructions mention a generation only Balancing Authority form to be filled in. It is not shown on the
spreadsheet provided, and it is not clear what data should be entered, though it seems like it would still be actual net
interchange.Form 1 contains an entry form for a single Balancing Authority Interconnection, however, it is not referenced in
the Form 1 instructions.Section A of the Form 1 instructions contains excellent background material that explains why this
effort is important. However, section B needs a careful review so that the instructions are thorough and unambiguous.The
information on variable bias calculations seems sparse, and the requirements for variable bias should be reviewed
thoroughly with those Balancing Authorities that are familiar with the nuances and challenges of determining an appropriate
variable bias.If BIAS is set equal to response, about 50% of the time, AGC will cancel out the primary response; the BIAS,
therefore, should be slightly higher than the natural response but clearly 1% is too large. The game plan to continually
reduce the floor percentage for frequency bias settings needs to be reconsidered. With .4% peak load being a typical actual
frequency response lately for Balancing Authorities, the 1% of peak load to .8% of peak load transition seems prudent.
Perhaps a further reduction to .6% may be useful as well, but lesser floors may in effect result in AGC too often canceling out
the primary frequency response being provided.While the 16 to 52 second sampling window for point B computations seem
to be a reasonable initial guess for the metric, preliminary studies by the Frequency Responsive Reserve Standard Drafting
Team (FRRSDT) indicate that AGC contributions from fast acting hydro generators will be included in the samples. As those
same studies were not conclusive, perhaps the initial years of this standard could require the provision of scan rate data from
30 seconds before to 60 seconds after the start of the frequency decline for each event. While this significantly increases the
volume of data to be provided, it would allow the FRRSDT to determine the best sampling intervals to be used. Perhaps a
point B sampling interval of 15 to 30 seconds would filter out most of the fast acting AGC, but more data/analysis is needed
to determine the best sampling interval to be sure that the primary response data is not being corrupted by this fast acting
AGC response.To support Balancing Authorities in achieving the targeted level of frequency response, a standard for
generators is needed as well, as they are historically the largest source of discretionary frequency response. The standard
could give a Balancing Authority the right to waive these requirements should they pursue other sources of frequency
163
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000590
Organization
Question 17 Comment
response, such as ERCOT’s “load acting as a resource (LAAR)” efforts.
Point C values are the more important reliability metric. Since point C metrics are challenged with data quality issues on a
Balancing Authority and generator level, an effort should be made to correlate the required frequency response in the point B
time window with that needed in the point C time window (perhaps using rules of thumb, such as 100% of load’s frequency
response and 30% of generator’s frequency response occurs in time for point C).
While Attachment A mentions that N-2 category C events will be used to determine the frequency response obligation on an
interconnection level, there is insufficient detail provided at this time to evaluate the appropriateness of the obligations
selected. Efforts in this area for the frequency model developed by the Reliability-Based Control Standard Drafting Team
(and now the BARCSDT) for HQTE may shed some insight into this process.
Response: The SDT agrees that clearer instructions are needed in Form 1. This has been addressed in the revised form. The SDT also agrees that there may
be limited benefit from measuring the load response of a BA due to data fidelity and resolution. An attempt to measure a BA’s load response was included for the
field trial to determine its value and was not used in the BA’s frequency response measure. It is believed that some BA’s with generation data that is on a similar
scan rate as their Interchange data may find that it accurately measures their load dampening. The field trial will determine if it is useful or not. The SDT agrees
that the 16 to 52 second sampling window may include some fast acting AGC. The field trial will determine if this sampling period should be reduced. Form 1 has
been revised to include a minimum data set that starts 30 seconds before the event and ends not earlier than 60 seconds after the event to help identify the
overall best averaging periods. The SDT also agrees that the use of LaaRs in ERCOT is a great backup to Primary Frequency Control but would also like to point
out that this response only responds in one direction and does not provide bidirectional frequency stability for the moment to moment changes in frequency.
Once utilized, it takes hours to restore the service for the next contingency. During this time, the BA and Interconnection depends on Primary Frequency Control
from other sources that are continuous and bidirectional as long as headroom is available. The SDT agrees that Point C Primary Frequency Control is critical for
preventing UFLS and will use the field trial results to determine if the Point B measure of performance can be correlated to Point C performance. Thank you for
your comments.
Regarding governor response - this issue concerning generators has been discussed by the SDT. The SDT understands your concern. However, governor droop
requirements, dead-band settings, and governor operation is outside of the industry approved SAR. The SDT believes that the Generator Verification standards
will help address these concerns.
The N-2 criteria is being evaluated during the field trial.
ISO New Engand Inc.
It is not clear from either Form 1 or its instructions whether the supplied frequency deviation for an event should be used
without modification, or if it should be overwritten with a value computed from the Balancing Authority’s data source (or if
there is an option, to use the lesser value, for example). Clearly express which frequency deviation value to use.
2. The load sensitivity calculation is an important Balancing Authority Area value to compute accurately for modeling
purposes. As proposed, it would use the same computational technique as that used for frequency bias sampling
calculations. To yield a useful result, load values would need to have “convergence characteristics” similar to that found in
the actual net interchange values used for frequency bias sampling. While experience has shown that the average or
median values of the frequency bias samples computed for most Balancing Authorities will converge with about 20 samples,
a similar outcome for load sensitivity calculations might not occur. Frequency bias samples rely on the measured actual net
164
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000591
Organization
Question 17 Comment
interchange values that are sampled at the AGC scan rate, and the actual net interchange tends to be a rather stable value
because AGC and operator actions usually keep the actual net interchange close to a scheduled value. The total net system
load may have greater volatility and may be trending in a particular direction much more often than actual net interchange.
Also, the load calculation typically relies on adding the sum of the generation within the Balancing Authority to the actual net
interchange. The generation values may have a slower scan rate, longer data latency periods, and smaller generators might
not be telemetered, with hourly scheduled values or manually entered values being used instead. These differences can
contribute to a very different convergence characteristic than that found for actual net interchange. Simply put, the load
sensitivity calculation needs validation.The Form 1 instructions mention a generation only Balancing Authority form to be
filled in. It is not shown on the spreadsheet provided, and it is not clear what data should be entered, though it seems like it
would still be actual net interchange.Form 1 contains an entry form for a single Balancing Authority Interconnection, however,
it is not referenced in the Form 1 instructions.Section A of the Form 1 instructions contains excellent background material
that explains why this effort is important. However, section B needs a careful review so that the instructions are thorough
and unambiguous.The information on variable bias calculations seems sparse, and the requirements for variable bias should
be reviewed thoroughly with those Balancing Authorities that are familiar with the nuances and challenges of determining an
appropriate variable bias.If BIAS is set equal to response, about 50% of the time, AGC will cancel out the primary response;
the BIAS, therefore, should be slightly higher than the natural response but clearly 1% is too large. The game plan to
continually reduce the floor percentage for frequency bias settings needs to be reconsidered. With .4% peak load being a
typical actual frequency response lately for Balancing Authorities, the 1% of peak load to .8% of peak load transition seems
prudent. Perhaps a further reduction to .6% may be useful as well, but lesser floors may in effect result in AGC too often
canceling out the primary frequency response being provided.
While the 16 to 52 second sampling window for point B computations seem to be a reasonable initial guess for the metric,
preliminary studies by the Frequency Responsive Reserve Standard Drafting Team (FRRSDT) indicate that AGC
contributions from fast acting hydro generators will be included in the samples. As those same studies were not conclusive,
perhaps the initial years of this standard could require the provision of scan rate data from 30 seconds before to 60 seconds
after the start of the frequency decline for each event. While this significantly increases the volume of data to be provided, it
would allow the FRRSDT to determine the best sampling intervals to be used. Perhaps a point B sampling interval of 15 to
30 seconds would filter out most of the fast acting AGC, but more data/analysis is needed to determine the best sampling
interval to be sure that the primary response data is not being corrupted by this fast acting AGC response.
To support Balancing Authorities in achieving the targeted level of frequency response, a standard for generators is needed
as well, as they are historically the largest source of discretionary frequency response. The standard could give a Balancing
Authority the right to waive these requirements should they pursue other sources of frequency response, such as ERCOT’s
“load acting as a resource (LAAR)” efforts.
Point C values are the more important reliability metric. Since point C metrics are challenged with data quality issues on a
Balancing Authority and generator level, an effort should be made to correlate the required frequency response in the point B
time window with that needed in the point C time window (perhaps using rules of thumb, such as 100% of load’s frequency
response and 30% of generator’s frequency response occurs in time for point C).While Attachment A mentions that n-2
category C events will be used to determine the frequency response obligation on an interconnection level, there is
insufficient detail provided at this time to evaluate the appropriateness of the obligations selected. Efforts in this area for the
165
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000592
Organization
Question 17 Comment
frequency model developed by the Reliability-Based Control Standard Drafting Team (and now the BARCSDT) for HQTE
may shed some insight into this process.
Response: The SDT agrees that clearer instructions are needed in Form 1. This has been addressed in the revised form. The SDT also agrees that there may
be limited benefit from measuring the load response of a BA due to data fidelity and resolution. An attempt to measure a BA’s load response was included for the
field trial to determine its value and was not used in the BA’s frequency response measure. It is believed that some BA’s with generation data that is on a similar
scan rate as their Interchange data may find that it accurately measures their load dampening. The field trial will determine if it is useful or not. The SDT agrees
that the 16 to 52 second sampling window may include some fast acting AGC. The field trial will determine if this sampling period should be reduced. Form 1 has
been revised to include a minimum data set that starts 30 seconds before the event and ends not earlier than 60 seconds after the event to help identify the
overall best averaging periods. The SDT also agrees that the use of LaaRs in ERCOT is a great backup to Primary Frequency Control but would also like to point
out that this response only responds in one direction and does not provide bidirectional frequency stability for the moment to moment changes in frequency.
Once utilized, it takes hours to restore the service for the next contingency. During this time, the BA and Interconnection depends on Primary Frequency Control
from other sources that are continuous and bidirectional as long as headroom is available. The SDT agrees that Point C Primary Frequency Control is critical for
preventing UFLS and will use the field trial results to determine if the Point B measure of performance can be correlated to Point C performance. Thank you for
your comments.
This issue concerning generators has been discussed by the SDT. The SDT understands your concern. However, governor droop requirements, dead-band
settings, and governor operation is outside of the industry approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
The N-2 criteria is being evaluated during the field trial.
Santee Cooper
Again, we believe that the SDT should consided or prior years’ data. We are concerned with how the total frequency
response obligation of an interconnection will be determined since this will ultimately determine each BA’s FRO. We believe
more detail should be presented on this issue.We appreciate the time and the work performed by the standard drafting team
on this standard that we feel is a necessary component for reliable operation of the Interconnections.
Response: The SDT does not understand the intent of the first sentence in your comment.. The next posting will be more explicit in the method for determining
the FRO.
MRO's NERC Standards Review
Subcommittee
We feel the Reserve Sharing Group should be removed from the applicability section as it’s not included in any requirement.
Response: The SDT has modified the proposed standard to better reflect the RSG responsibility in providing Frequency Response.
Xcel Energy
We feel Reserve Sharing Group should be removed from the applicability section since it is not included in any of the
requirements. Additionally, the documents are not clear as to how there is a field trial included in the proposal.
166
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000593
Organization
Question 17 Comment
Response: The SDT has modified the proposed standard to better reflect the RSG responsibility in providing Frequency Response.
LG&E and KU Energy
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data.We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.Please make
sure enhanced frequency response from load is examined as an economical source of frequency response per FERC
requirements in Order 693 paragraphs 336 and 375.
The SDT has not addressed how the requirements of the proposed standard can be implemented without a market
mechanism.All frequency response available in an RTO/ISO ancillary services market should be offered in a nondiscriminatory way (possibly on an OASIS).
The standard needs more detail (not an attachment) on how the Interconnect FRO is allocated to BAs. We further suggest
the SDT consider providing detail in Attachment A that the Reliability Coordinator will need to be involved in allocation of the
FRO to specific regions or plants within the Reliability Coordinator Area.
There is a good chance that the proper geographic location of frequency responsive reserves will increase Transfer Path
capability when the Transfer Path capability is limited by a loss of generation. This may be the case in the west where loss of
two Palo Verde units establishes the California-Oregon Intertie SOL because frequency responsive reserves are carried in
the Pacific Northwest, not near Palo Verde. The BAL-003-1 standard does not consider this issue.
Please review the (pk gen+pk load)/2 method described in Attachment A, page 3.We appreciate the time and the work
performed by the standard drafting team on this standard that we feel is a necessary component for reliable operation of the
Interconnections.
Response: The FRO is based on the forecasted values. The SDT had extensive discussions concerning the generation/load split for determining the BA FRO and
believes that the proposed methodology is both reasonably equitable and non-discriminatory.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
This standard provides metrics in which markets and independent solutions can be developed.
This standard provides a minimum requirement of a BA but does not prevent an RC from imposing further restrictions.
All of the methodologies proposed in this standard are being tested during the field trial.
SERC OC Standards Review
Group
The Standard Authorization Request Form references that BAL-003-0 originated as part of Project 2007-18, Reliability-based
Control. Actually, it originated in Project 2007-05, Balancing Authority Control.
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
167
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000594
Organization
Question 17 Comment
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data. We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.
We appreciate the time and the work performed by the standard drafting team on this standard which we feel is a necessary
component for reliable operation of the Interconnections.”The comments expressed herein represent a consensus of the
views of the above named members of the SERC OC Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”
Response: Revisions to BAL-003 were originally part of Project 2007-05, but Project 2007-05 was then merged on July 28, 2010 into Project 2007-18.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
The FRO is based on the forecasted values.
The methodologies proposed in this standard have been tested during the field trial.
South Carolina Electric and Gas
The Standard Authorization Request Form references that BAL-003-0 originated as part of Project 2007-18, Reliability-based
Control. Actually, it originated in Project 2007-05, Balancing Authority Control.
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data. We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.We appreciate
the time and the work performed by the standard drafting team on this standard that we feel is a necessary component for
reliable operation of the Interconnections.
Response: Revisions to BAL-003 were originally part of Project 2007-05, but Project 2007-05 was then merged on July 28, 2010 into Project 2007-18.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
The FRO is based on the forecasted values.
The methodologies proposed in this standard have been tested during the field trial.
FirstEnergy
If not already planned, we suggest that the drafting team conduct a webinar on this project to clarify the deliverables and
answer questions that industry may have.
Response: The SDT conducted a Webinar on July 18, 2011 and is planning on holding another webinar in November 2011 to explain the changes made between
168
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000595
Organization
Question 17 Comment
versions.
Bonneville Power Administration
o D1.4 R1 Supplemental Information (first paragraph) - Adds an additional requirement outside of the requirements section.
o D1.4 R2 Supplemental Information (first paragraph) - Adds an additional requirement outside of the requirement section.
o D1.4 R Supplemental Information (Second paragraph) - Adds an additional requirement outside of the requirements
section. This number has nothing to do with frequency response during events. Also, has more to do with R1 than R2.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
SPP Standards Development
The reporting requirement in Attachment A under R1 '...each BA has one month to assemble its data and calculate the FRM.'
is not consistent with the reporting requirements in D. Compliance, 1.4 of the draft Standard.
R4 - We suggest replacing the word 'increase' with 'modify' or 'adjust'.
We also suggest deleting Balancing Authority Area and replacing it with combined areas at the end of the sentence.
Why is R4 in BAL-003-0 being retired?
Response: The SDT has corrected the error in the wording.
The SDT prefers to use the word “increase” to provide clarity that the Frequency Bias Setting should go up when providing this service. Use of the terms you are
suggesting could be interpreted to allow for adjustments up or down.
BAL-003-01.b Requirement R4 is not longer necessary. This Requirement addresses how to calculate Frequency Bias Settings. This is no longer needed since the
Frequency Bias Settings are calculated in FRS Form 1 using Frequency Response associated with the “official” list of events and a couple of “floor or ceiling” limits
(% of peak load/gen and FRO). The entire calculation is built into the FRS Form 1 workbook.
IRC Standards Review
Committee
The sections of “Additional Compliance Information” in the draft standard seem to create requirements as written. For
example, revision of 1.4 for R1 Supplemental Information is suggested to be as follows: Each Balancing Authority or the
Interconnection designated entity shall reports its previous year’s Frequency Response Measure (FRM) to the ERO on Form
1 by January 10 each year. If the ERO posts the official list of events after December 10, Balancing Authorities or the
Interconnection designated entity will be given 45 days from the date the ERO posts the official list of events to submit their
FRS Form 1.
If aA Balancing Authority may elects to fulfill its Frequency Response Obligation by participating as a member of a Reserve
Sharing Group (RSG). If a Balancing Authority elects to report as an RSG, the total of the participating Balancing Authorities’
FRO will be compared to the total of the participating Balancing Authorities’ FRM.
Further, revision of 1.4 for R2 Supplemental Information is suggested to be as follows:
Each Balancing Authority or the Interconnection designated entity shall reports its current year requested Frequency Bias
169
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000596
Organization
Question 17 Comment
Setting and Frequency Bias type (fixed or variable) to the ERO on FRS-Form 1 by January 10 each year. If the ERO posts
the official list of events after December 10, Balancing Authorities will be given 45 days from the date the ERONERC posts
the official list of events to submit their FRS Form 11. Once the FRM and Frequency Bias Settings have been validated by
the ERO, the ERO will disseminate the Frequency Bias Settings Report for all Balancing Authorities in each Interconnection
along with the implementation date.Balancing Authorities with variable Frequency Bias Settings shall calculate monthly
average Frequency Bias Settings. The previous year’s monthly averages will be reported annually on FRS Form 1.
Again, please clarify what qualifies as “variable” Frequency Bias Setting.
Also please clarify how the “monthly average Frequency Bias Settings” are to be calculated. Is it a daily or weekly or hourly
weighted average, or something else?
In Attachment A: What is the “frequency deviation event threshold specified for the Interconnection”? Where is it specified?
Please clarify.In Attachment A, 2.b.: Is this intended to be describing Point B? Please clarify.In Attachment A:
While the ERO is deciding which events to use, does this mean that, throughout the year, the BA must collect and save all
the relevant data for all events so as to have the data ready and available for when the ERO issues the list of events to be
reported?
In Attachment A, 4.: “Any indication or evidence of a secondary event occurrence after Point C should be reviewed for
inclusion based on having sufficient information to perform a full analysis of the event”. What meant by “should be
reviewed”? Who is to be doing the review? What are the criteria for the review?
In the Implementation Plan: “native load” is not defined in the ERCOT Interconnection. Please clarify.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
The Requirement and Measure have been modified to include references to RSGs.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions.
The SDT recognizes the need to convert Attachment A into two documents in order to provide further clarity. The first document will remain part of the standard
as Attachment A and provide greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as
supplemental standard information.
The current Reliability Standard BAL-005 cites the data required to be archived.
As envisioned, the ERO will post the events to be analyzed on a quarterly basis to allow a BA to review its performance throughout the year.
The Implementation Plan no longer references “Native Load”. However, this term is defined in the NERC Glossary of Terms.
ERCOT
The sections of “Additional Compliance Information” in the draft standard seem to create requirements as written. For
example, revision of 1.4 for R1 Supplemental Information is suggested to be as follows: Each Balancing Authority or the
Interconnection designated entity shall reports its previous year’s Frequency Response Measure (FRM) to the ERO on Form
170
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000597
Organization
Question 17 Comment
1 by January 10 each year. If the ERO posts the official list of events after December 10, Balancing Authorities or the
Interconnection designated entity will be given 45 days from the date the ERO posts the official list of events to submit their
FRS Form 1. If aA Balancing Authority may elects to fulfill its Frequency Response Obligation by participating as a member
of a Reserve Sharing Group (RSG). If a Balancing Authority elects to report as an RSG, the total of the participating
Balancing Authorities’ FRO will be compared to the total of the participating Balancing Authorities’ FRM.Further, revision of
1.4 for R2 Supplemental Information is suggested to be as follows:Each Balancing Authority or the Interconnection
designated entity shall reports its current year requested Frequency Bias Setting and Frequency Bias type (fixed or variable)
to the ERO on FRS-Form 1 by January 10 each year. If the ERO posts the official list of events after December 10,
Balancing Authorities will be given 45 days from the date the ERONERC posts the official list of events to submit their FRS
Form 11. Once the FRM and Frequency Bias Settings have been validated by the ERO, the ERO will disseminate the
Frequency Bias Settings Report for all Balancing Authorities in each Interconnection along with the implementation date.
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The
previous year’s monthly averages will be reported annually on FRS Form 1. Again, please clarify what qualifies as “variable”
Frequency Bias Setting. Also please clarify how the “monthly average Frequency Bias Settings” are to be calculated. Is it a
daily or weekly or hourly weighted average, or something else?In Attachment A: What is the “frequency deviation event
threshold specified for the Interconnection”? Where is it specified? Please clarify.In Attachment A, 2.b.: Is this intended to
be describing Point B? Please clarify.In Attachment A: While the ERO is deciding which events to use, does this mean that,
throughout the year, the BA must collect and save all the relevant data for all events so as to have the data ready and
available for when the ERO issues the list of events to be reported?In Attachment A, 4.: “Any indication or evidence of a
secondary event occurrence after Point C should be reviewed for inclusion based on having sufficient information to perform
a full analysis of the event”. What meant by “should be reviewed”? Who is to be doing the review? What are the criteria for
the review?In the Implementation Plan: “native load” is not defined in the ERCOT Interconnection. Please clarify.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
The Requirement and Measure have been modified to include references to RSGs.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions.
The SDT recognizes the need to convert Attachment A into two documents in order to provide further clarity. The first document will remain part of the standard
as Attachment A and provide greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as
supplemental standard information.
The current Reliability Standard BAL-005 cites the data required to be archived.
As envisioned, the ERO will post the events to be analyzed on a quarterly basis to allow a BA to review its performance throughout the year.
The Implementation Plan no longer references “Native Load”. However, this term is defined in the NERC Glossary of Terms.
Progress Energy
We believe this standard insufficiently addresses the true nature of the problem; however it does accuratly address the fact
171
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000598
Organization
Question 17 Comment
that the current BA minimum frequency bias setting is too large.
This standard should also exclude LSE's without generation capacity since this problem both exists and can be solved at the
generator level.
Response: The SDT agrees that the generator level can solve the issues. This standard is addressing directives from FERC Order 693. Any reference to a
generator requirement would be outside of the industry approved SAR.
The LSE is not cited as an applicable entity.
NIPSCO
We reviewed the number of BAs in the Eastern Interconnection and there are many. We're hoping that compliance to R1
would be covered by the RSGs similar to DCS.
Response: The SDT added the RSG as a applicable entity to allow a BA an alternative method for complying with this standard.
Energy Mark, Inc.
Comment 55: In Comment 25 I indicated that the suggested allocation method creates perverse incentives for BAs
attempting to make decisions concerning Frequency Response. My comments here support that contention. Since the
suggested allocation method is blind to changes in the demand for Frequency Response and it allocates the requirement to
supply Frequency Response on a fixed Peak Load / Peak Generation Ratio share, it supports economic decisions at the BA
level that are far from economic at the interconnection level. This perverse influence on economics and reliability are
illustrated with two examples.
Example 1: A BA with a Peak Load / Peak Generation Ratio share of 5% of the interconnection must decide whether
or not to implement a program to expend $1 M to reduce the demand for Frequency Response worth approximately a
comparable $5 M. From an interconnection level this is an obvious decision. The BA should implement the program.
However, when the allocation method is considered, if the BA implements the program, it will expend $1 M, but will
only see a reduction in its Frequency Response requirement of $.25 M. The remainder of the reduction in demand for
Frequency Response will be shared by the other BAs on the interconnection. Therefore, it is in the BAs interest to not
implement the program even though it provides excellent overall economics and results in improved reliability.
Example 2: A BA with a Peak Load / Peak Generation Ratio share of 5% of the interconnection must decide whether
or not to implement a program to save $1 M in annual maintenance expenses at its generation plants that will increase
the need for Frequency Response on the interconnection at an annual cost of $5 M. From an interconnection level
this is an obvious decision. The BA should not implement the program. However, when the allocation method is
considered, if the BA implements the program, it will save $1 M anually, but will only see a increase in its annual
expense for Frequency Response requirement of $.25 M. The remainder of the increase in demand for Frequency
Response will be shared by the other BAs on the interconnection. Therefore, it is in the BAs interest to implement the
program even though it fails to provide good economics and results in a decline in reliability.
These examples demonstrate why a fixed allocation method as suggested in Attachment A would result in perverse results
172
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000599
Organization
Question 17 Comment
with respect to reliability and economics.
Comment 56: A series of four technical papers were written and offered to the Frequency Response Standard Drafting
Team that describe a measurement method for Frequency Response that does not have the detrimental limitations that exist
with the Peak Load / Peak Generation Ratio share method suggested in Attachment A. These four paper are:1. Illian, H. F.,
Frequency Response Risk Measure, Prepared for the Frequency Response Standard Drafting Team, Energy Mark, July 1,
2010 revised September 7, 2010.2. Illian, H. F., Understanding ACE and CPS1, Prepared for the Frequency Response
Standard Drafting Team, Energy Mark, September 8, 2010.3. Illian, H. F., Frequency Response Reliability Measure for the
Balancing Authority, Prepared for the Frequency Response Standard Drafting Team, Energy Mark, October 11, 2010.4.
Illian, H. F., Description of Regressions for Frequency Response Analysis, Prepared for the Frequency Response Standard
Drafting Team, Energy Mark, September 21, 2010.PDFs of these papers have been forwarded to supplement these
comments and should be addended as part of my comments.
Response: Comment 54 – The SDT understands your concerns and has taken them under consideration during the development of this standard. The SDT will
provide technical justification for the methods it proposes within the standard.
Comment 55 – The SDT thanks you for your work in creating the aforementioned papers. The SDT has reviewed these papers and considered them during the
development of this standard. Furthermore, the SDT will forward them on to the appropriate NERC personnel.
Hydro-Quebec TransEnergie
The proposed NERC standard (BAL-003) does not take into account the “point C” issue. The proposed requirements are only
related to “point B”.The proposed NERC standard (BAL-003) validates that the Balancing Authority carries enough
Synchronized Reserve and that this reserve is really Frequency Responsive, on average in the most common situations
(based on the median). It is an “after-the-fact” evaluation of the performance of the Balancing Authority. However, there is
no guaranty that the Balancing Authority will maintain the required Synchronized Reserve either when the load is very low or
during peak load periods Real-time Monitoring of the frequency responsive reserve would be a good way to avoid this issue.
Response: The SDT is proposing a more conservative Point B result in order to protect for Point C UFLS.
We encourage real-time monitoring of Frequency Response as a good practice but mandating it is beyond industry approved SAR. Also, the SDT believes that
this is being addressed in the development of the Balancing Authority Reliability-based Control standards in Project 2010-14.
Westar Energy
Based on a Category C (N-2) event, what is the approximate Interconnection Frequency Response Obligation for each
Interconnection? What is the First Step UFLS for each Interconnection?
Since there is no NERC Standard requirement for what first step UFLS is, what if it changes during the year?
Response: The SDT recognized the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and
provide greater detail for the calculation methodologies, including FRO. The second document will explain the rationale for the requirements as supplemental
standard information. Table 2 in revised Attachment A shows the FRO for each interconnection and the methodology used to determine this value. The UFLS set
point used in the calculation is shown in Table 2 for each Interconnection. These values are intended to protect against frequency reaching the highest UFLS
173
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000600
Organization
Question 17 Comment
setting for credible contingencies.
The utilities have the ability to change the UFLS settings during the year. The entities FRO and Frequency Bias Setting would remain the same until it was
reviewed by the ERO. Your comment does emphasize the need for the ERO to coordinate these changes across standards but this is outside the scope of this
project..
EKPC
EKPC would like to express the importance of considering large non-conforming loads and their effects on smaller BAs.We
appreciate the drafting team’s effort and dedication to this standard.
Response: The SDT has modified FRS form 1 to allow for adjustments, including non-conforming load.
We Energies
The FRO and the standard in general focus on Frequency Response for an intact grid. Inadequate consideration is given to
unexpected events such as separation, islanding and partial or total BES failure. In these cases, the location of the FR
resources is important. For example, if a BA has a contract with an entity that controls load level to satisfy the required FRO,
that load may not be within the island created following a disruption to the BES. A complete BES failure may leave a black
start island with only load frequency response. Load frequency response is the ultimate dispersed source for this commodity,
but may be inadequate as the sole provider under abnormal grid conditions. For better grid security, other dispersed sources
of frequency response are desirable.
Comment on the NERC Resources Subcommittee Position Paper on Frequency Response (Discussion Draft):EOP-005-2
does not contain requirements for the Balancing Authority in a restoration event involving the use of black start resources.
Only Transmission Operators, Generator Operators, Transmission Owners identified in the Transmission Operators
restoration plan, and Distribution Providers identified in the Transmission Operators restoration plan have roles in that
standard. How will the BA “bring more Frequency Responsive resources to bear” during black start if they have no defined
role?
Response: This standard is not meant to be an emergency operations standard. However, this standard could assist an entity in identifying and solving the
problem you have mentioned.
The NERC RS Position Paper on Frequency Response is not a product of this standard. It is an information paper requested by the NERC OC. The RS posted the
document and received industry comments that were incorporated.
American Electric Power
If a balancing authority loses generation, what happen to the neighboring balancing authority’s AGC?
If an overall Reserve Sharing Group’s performance can possibly be used to meet performance measures, why is the RSG
not included in the Standard applicability for such functional entity?
Response: If the Frequency Bias Setting is close to natural Frequency Response, as this standard is proposing, the AGC impacts would be minimal or none.
The RSG is listed in the Applicability Section of this standard. The SDT has further modified Requirement R1 to identify the RSG within the requirement.
174
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000601
Organization
Duke Energy
Question 17 Comment
Below are just some of the points that Duke Energy believes need to be discussed further.
Relationship to other standards under development: Given the significant implications of this standard to the other balancingrelated standards, Duke Energy feels strongly that the Standards Committee should keep the work under Project 2010-14,
Balancing Authority Reliability-based Control, high on the list of standards to be developed. CPS1 and the proposed BAAL
are measures that make sense in the long term, as they provide “support to maintain Interconnection Frequency within
predefined bounds” and aid in “supporting frequency until the frequency is restored to schedule” as desired in the purpose
statement of this standard.
Reserve Sharing Group: Duke Energy understands and supports the concept that Frequency Response could be aggregated
over a Reserve Sharing Group, however the details need to be addressed in the measures, and in the requirements, which in
the current draft only apply to the Balancing Authority.
Field test: Duke Energy found the implementation plan and field test confusing. The information didn’t indicate when the field
test would start and end. The implementation plan proposes starting the gradual adjustment of BAL-003-0 R5 in May 2011 what if the standard hasn’t been approved by FERC by then? Shouldn’t those dates be tied somehow to the effective date of
BAL-003-1 which is in turn tied to regulatory approval where required? Or is that gradual decrease actually part of the field
test?
Frequency responsive resources: What are the attributes needed for a resource, or combination of resources, to be
considered capable of providing “Frequency Response”? The answer is a critical element to the development of market
products in a uniform manner across the Interconnection. Among other attributes, Frequency Response aids in arresting
sudden frequency decline, however frequency responsive resources must respond to positive and negative deviations in
Interconnection frequency. Having loads that drop off the system at certain levels of frequency are valuable tools in arresting
frequency decline, however such resources do nothing within the range of frequency in which the Interconnection operates
perhaps 99% of the time. This would point to perhaps two types of services to address frequency below 60 Hz - provision of
frequency response in normal and emergency operation, and provision of a service specific for arresting a significant drop in
frequency at a specific bound to reduce the possibility of UFLS needing to be utilized. Duke Energy believes these are two
different products and should not be considered interchangeable.
Methods of obtaining Frequency Response:
If frequency response is a market resource, how can it be attained or scheduled from another Balancing Authority? Duke
Energy believes this question needs to be asked of the Interchange Subcommittee.
As the concept of a Reserve Sharing Group providing a “group frequency response” would not in our opinion constitute
“interchange”, Duke Energy believes the measure for calculated response should look at the RSG as if it was a single BA,
rather than attempt to measure the RSG participants individually. On the other hand, outside of an RSG, if resources in one
BA Area were contracted to supplement the response of resources in another BA Area, would such response be provision of
a service between a source and sink BA, or would it be interchange with the Interconnection in some manner?
FRM calculation:
175
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000602
Organization
Question 17 Comment
Under the proposed definition, the FRM calculation would only consider provision of response from resources external to the
BA Area if the “interchange” came in the form of a Pseudo-tie adjustment to Actual Interchange - Dynamic Schedules would
not be accounted for. As the use of Pseudo-ties changes load calculations and other data, even the use of them may not
make sense compared perhaps to just having a mechanism to move the obligation to the area providing the response, and
then determining if the provision of just Frequency Response must absolutely carry into increased secondary control
requirements.
Separating primary response from secondary control:
Is it possible for resources in one BA to provide a measure of Frequency Response for another BA, but not result in a change
to each BA’s Frequency Bias Setting used in the secondary control requirements?
Response: The development of the Balancing Authority Reliability-based Control standards in Project 2010-14 are outside the scope of this SDT, however the
need to coordinate development was raised with the Standards Committee and the standards in Project 2010-14 that address “reserves” have been advanced as
high priority.
The SDT has modified Requirement R1 and the associated measure to identify the RSG.
In reference to your field trial comment the SDT has modified the Implementation Plan to no longer reference the field test or the reduction of the minimum
Frequency Bias Setting. The SDT has developed a process by which the ERO will reduce the minimum Frequency Bias Setting. The procedure used to reduce
the Frequency Bias Setting is detailed in Attachment B and is now tied to regulatory approval of this standard.
This standard will provide the metrics for Frequency Response while the market will define itself. The SDT encourages you to work with NAESB to define a
market.
The SDT encourages you to open a discussion with the Interchange Subcommittee concerning Frequency Response as a market resource.
The SDT has included language that defines how the RSG is to perform and comply with this standard. The SDT agrees that a Reserve Sharing Group providing
a “group frequency response” would not be interchange between the entities within that group. The SDT also agrees that the RSG would be evaluated as if it
were a single BA.
The SDT has incorporated an improved FRS Form 1 with instructions for its use. The SDT thanks you for your comment concerning Pseudo-tie but, based on the
information provided, the SDT is unsure of your question and cannot provide a further response.
With regards to your last comment, the SDT believes that it is possible as long as they are using a dynamic schedule.
Patterson Consulting, Inc.
Requirement 4 is worded incorrectly, although it is taken from the existing standard. Requirement 4 states "Each Balancing
Authority that is performing Overlap Regulation Service shall [increase] its Frequency Bias Setting in its ACE calculation by
combining the Frequency Bias Settings for the entire Baalancing Authority Area being controlled." (Bracketing added for
emphasis.) Considering Frequency Bias Settings are negative numbers, this requirement should have Balancing Authorities
"decrease" rather than "increase" their Frequency Bias Settings. For example, the requirement could state "Each Balancing
Authority that is performing Overlap Regulation Service shall decrease..." or if "decrease" is undesirable then "Each
Balancing Authority that is performing Overlap Regulation Service shall modify..."
176
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000603
Organization
Question 17 Comment
Response: The SDT understands your concern with the use of the term “increase” and has replaced this word with “modify”. The SDT revised Requirement R4
for additional clarity and it now reads:
Each Balancing Authority that is performing Overlap Regulation Service shall modify its Frequency Bias Setting in its ACE calculation to be
equivalent to the sum of the Frequency Bias Settings of the participating Balancing Authorities as validated by the ERO or calculate the
Frequency Bias Setting based on the entire area being combined and thereby represent the Frequency Response for the combined area being
controlled.
Associated Electric Cooperative,
Inc.
BAL-003-1 draft standard:
Apparent Intent and expectations:
1) I agree with this emerging standard’s recognizing that the arbitrary 1% of peak-load should be refined by being lowered to
better reflect each BA’s expected frequency response.
2) This emerging standard apparently attempts to address the divesture of generation from loads by utilizing the “(Load +
Generation)/2” formula, which seems fair.
3) I’m still struggling with the concept of being able to share in the success of an RSG, but not its failures if your BA was
individually successful. Something seems wrong with that approach. However if necessary, AECI will definitely use it to its
advantage.
4) I really would have liked to see the Measures that are currently in draft.
Comment on Definitions:
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is actually an internally
calculated value derived from a set of event sample data, and not really a “sample” value at all. So, I believe the SEFRD
definition needs further work.
2) FRM is defined by undefined terms “FRS” and “FRS Form 1”.
3) FRO – fine
4) FRS - “Frequency Response Survey”
Requirements and Requirements Supplement Information1) R1 and R1 Supplemental Information, pp 2, 4
a) I believe these two sections should be combined into one requirement, specifying the basic BA requirement “or, if
the BA was within an RSG and elects to report from within that RSG’s performance,” that RSG’s performance
requirement.
b) The time-frame for reporting should be another requirement, and with a companion Measurement. (Concerning the
timing, the original response timeframe is 31 days, but the if NERC slips past the “normal” December 10 deadline, the
177
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000604
Organization
Question 17 Comment
response time requirement is increased by 50%, to 45 days? Did somebody make a mistake, or was this intentional?)
c) The problem with this requirement is that it relies on each BA to “read” its own frequency-performance, and does
not provide a clear system of comparison between BAs for the same frequency event. In other words, the drafting
team is trying to impose a nice bright-line objective standard, that is really resting on what is currently a very subjective
calculation of SEFRD. . (See item 3, Rx- below)
2) R2 and R2 Supplemental Information pp 2..4
a) See comment 1.b above, concerning reporting time-frame being another requirement
b) I believe every BA should report its monthly average frequency-bias setting, whether fixed-bias or variable-bias. In
the case of reporting fixed-bias, the first two months will likely be different from the remaining ten months within the
same calendar year.
3) Rx - I believe there is a hidden requirement, that the ERO monitor each interconnection’s frequency for candidate events,
then annually select and provide the top events for FRS Form 1 reporting. That same requirement should dictate that the ERO
provide the corresponding A, B, and C times for each FRS Form 1 reportable event, when the survey goes out. I believe this
requirement should be spelled-out, in order to improve reporting consistency and make the FRS reporting process a bit more
objective.
Response: “Apparent Intent”
Comments 1) & 2) – The SDT thanks you for your comment.
Comment 3) The SDT added the RSG as a applicable entity to allow a BA an alternative method for complying with this standard. The SDT has included
language that defines how the RSG is to perform and comply with this standard.
Comment 4) The SDT purposely left the measures out of the first draft. This was to ensure the focus would be on the requirements themselves. The SDT also
recognized that the requirements would probably need revision after receiving industry feedback.
Definitions:
Comment 1) The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
Comment 2) The term FRS Form 1 is only identifying a form to be used when providing information to the ERO.
Comment 3) The SDT thanks you for your agreement with the definition.
Comment 4) Again, the term FRS is simply pointing to a particular for to be used when providing the information to the ERO.
Requirements:
Comment 1 a) The SDT has revised Requirement R1 to reference an RSG. The Requirement now reads “Each Balancing Authority (BA) or Reserve Sharing Group
(RSG) shall achieve an annual Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative
than its Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each BA or RSG to maintain an adequate level of
178
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
000605
Organization
Question 17 Comment
Frequency Response in the Interconnection.”
Comment 1 b) The Additional Compliance Section has been completely revised and the issues you identified have been removed.
Comment 1 c) The revised standard changes the methodology from subjective to directed.
Comment 2 a) The Additional Compliance Section has been completely revised and the issues you identified have been removed. The SDT has corrected the
timing issue you have referenced.
Comment 2 b) The SDT disagrees and believes that “fixed” should be reported on a annual basis while “variable” should be reported monthly due to the nature of
the calculation.
Comment 3) The SDT believes that Point C is not needed for the methodology being recommended. The revised FRS Form 1 and the new Form 2 provide
clarification concerning Point A and Point B.
Alberta Electric System Operator
Is there any relation or coordination between the work of this standard and the effort on "NERC RS Position Paper on
Frequency Response" ? The AESO believes these two projects should be coordinated.The AESO has also signed on to
comments submitted by the SRC. We see the SRC comments as continent wide and these AESO comments as more
Alberta specific.
Response: The NERC RS Position Paper on Frequency Response is not a product of this standard. It is an information paper requested by the NERC OC. The
RS posted the document and received industry comments that were incorporated. In addition, some of the Frequency Response SDT membership are also
members of the NERC RS.
Please refer to our comments to SRC.
Kansas City Power & Light
No other comments.
179
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000606
Consideration of Comments
Project 2007-12 Frequency Response
The Frequency Response Drafting Team thanks all commenters who submitted comments on the first
formal posting for Project 2007-12 Frequency Response. This standard was posted for a 45-day public
comment period from October 25, 2011 through December 9, 2011. Stakeholders were asked to
provide feedback on the standard and associated documents through a special electronic comment
form. There were 43 sets of comments, including comments from approximately 133 different people
from approximately 86 companies representing all 10 of the Industry Segments as shown in the table
on the following pages.
Based on the comments received and the drafting team’s discussion of those comments, the drafting
team made the following changes to the proposed Standard, definitions, and associated documents:
Modified the definition for Frequency Response Measure (FRM)
Modified the definition of Frequency Bias Setting
Removed the references to Reserve Sharing Groups (RSGs) and replaced them with Frequency
Response Sharing Group
Created a definition for Frequency Response Sharing Group (FRSG)
Modified Requirement R2 to provide clarity and incorporate Requirement R5
Created a new Requirement R3 for entities using variable Frequency Bias
Removed the requirement for operating in Tie Line Bias mode as duplicative of other
requirements in other standards
Removed Requirement R5 and combined it into revised Requirement R2 and new Requirement
R3
Modified Attachment A to provide additional clarity
Created a Procedure to provide instructions for the ERO to follow in supporting the standard
Made conforming changes to Measures, Evidence Retention, and VSLs to align with language in
the revised requirements
Re-wrote the Background Document to incorporate additional language for justification of
requirements and provide additional clarity
The SDT is now using the method detailed in the Frequency Response Initiative Report dated
September 30, 2012 to calculate the Interconnection Frequency Response Obligation.
There were some minority issues that the team was unable to resolve, including the following:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000607
A few stakeholders questioned a Requirement for the BA to provide Frequency Response when
they typically do not own generation. The SDT explained that the NERC Functional Model and
FERC cited the BA as the responsible party for providing Frequency Response and that this was
outside the scope of the industry approved SAR. The SDT also stated that there were several
different methods available to the BA to provide Frequency Response and that the SDT had
included these in the Background Document. The SDT further stated that any entity could
submit a SAR addressing this issue to the SC for consideration and that the SDT supported this
option.
A couple of the commenters felt that the median was not the proper method to use for the
calculation of the FRM and that the RSG was not fully explained. The SDT stated that the
statisticians note that the median is a more accurate measure of central tendency than the
mean when analyzing a sample that is small and or where scores vary widely. This is the case
when estimating a BA’s Frequency Response. The SDT also noted that while the median was
not perfect, the median approaches a BA’s typical performance after 15-20 observations and
that more observations give a higher confidence in the estimate of the BA’s performance.
Some commenters disagreed with proceeding through development of the standard before the
proposed measures have been thoroughly field tested. The SDT stated that it was responding to
FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months.
FERC later granted an extension to provide a standard addressing these issues by the end of
May 2012.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments: Project 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000608
Index to Questions, Comments, and Responses
1.
The SDT has made minor modifications to the proposed definitions to provide additional clarity.
Do you agree that these modifications provide sufficient clarity? If not, please explain in the
comment area. .................................................................................................................................. 10
2.
The SDT has made minor modifications to the Requirements R1 through R4 to provide additional
clarity. Do you agree that these modifications provide sufficient clarity to comply with the
standard? If not, please explain in the comment area. .................................................................... 28
3.
The SDT has developed VRFs for the proposed Requirements within this standard. Do you agree
that these VRFs are appropriately set? If not, please explain in the comment area. ...................... 82
4.
The SDT has developed Measures for the proposed Requirements within this standard. Do you
agree with the proposed Measures in this standard? If not, please explain in the comment area. 86
5.
The SDT has developed VSLs for the proposed Requirements within this standard. Do you agree
with these VSLs? If not, please explain in the comment area. ......................................................... 93
6.
The SDT divided the previously posted “Attachment A – Background Document” into two
documents to provide additional clarity. The first document “Attachment A- Supporting
Document” which details the methods used to develop the events to be analyzed, the FRO, FRM
and Frequency Bias Setting. Do you agree that the revised Attachment A – Supporting Document
provides sufficient clarity on the methodologies to be used? If not, please explain in the comment
area. ................................................................................................................................................. 113
8.
The SDT has developed a new document titled Attachment B – Process for Adjusting Bias Setting
Floor. This document is intended to provide the methodology the ERO will use to reduce the
minimum Frequency Bias Setting to become closer to natural Frequency Response. Do you agree
that this document provides clear and concise instructions for the ERO to follow? If not, please
explain in the comment area. ......................................................................................................... 161
9.
The SDT has provided an additional spreadsheet, FRS Form 2, to assist the Balancing Authority in
providing the data needed to comply with the proposed standard. Do you agree that this
spreadsheet is useful and the instructions are meaningful? If not, please explain in the comment
area. ................................................................................................................................................. 174
10.
Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1................................................. 184
Consideration of Comments: Project 2007-12 Frequency Response
3
000609
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Chris Higgins
Bonneville Power Administration
2
3
X
X
X
X
4
5
6
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. James Murphey
BPA
WECC 1
2. Bart McManus
BPA
WECC 1
3. David Kirsch
BPA
WECC 1
2.
Group
Jesus Sammy Alcaraz
Imperial Irrigation District
Additional Member Additional Organization Region Segment Selection
1. Tino Zaragoza
IID
WECC 1
2. Jesus Sammy Alcaraz IID
WECC 3
3. Diana Torres
IID
WECC 4
4. Marcela Caballero
IID
WECC 5
X
7
8
9
10
000610
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Cathy Bretz
IID
3.
Guy Zito
Group
Additional Member
4
5
6
7
Northeast Power Coordinating Council
Additional Organization
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Chantel Haswell
FPL Group, Inc.
NPCC 5
Nydro One Networks Inc.
NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
Neqw Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
Will Smith
OPPD
2.
CHUCK LAWRENCE ATC
10
X
MRO NSRF
X
Additional Member Additional Organization Region Segment Selection
MAHMOOD SAFI
9
NPCC 10
10. David Kiguel
1.
8
Region Segment Selection
2.
Group
3
WECC 6
1.
4.
2
MRO
1, 3, 5, 6
MRO
1
Consideration of Comments: Project 2007-12 Frequency Response
5
000611
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
NSP (XCEL)
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
1, 3, 5, 6
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 4, 5
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. RICHARD BURT
MPC
MRO
1, 3, 5, 6
5.
Gerald Beckerle
Group
SERC OC Standards Review Group
2
X
3
4
5
6
7
X
Additional Member Additional Organization Region Segment Selection
1.
Andy Burch
EEI
SERC
5
2.
Bob Dalrymple
TVA
SERC
1, 3, 5, 6
3.
Brad Gordon
PJM
SERC
2
4.
Vicky Budreau
SCPSA
SERC
1, 3, 5, 6
5.
Sam Holeman
Duke
SERC
6, 1, 3, 5
6.
Cindy Martin
Southern Co
SERC
1, 5
7.
Scott Brame
NCEMC
SERC
1, 3, 4, 5
8.
Wayne Van Liere
LGE-KU
SERC
3
9.
Larry Akens
TVA
SERC
1, 3, 5, 6
10. John Troha
SERC Reliability Corp.
SERC
10
6.
Robert Rhodes
Group
Additional Member
Additional Organization
SPP Standards Review Group
X
Region Segment Selection
1. John Allen
City Utilities of Springfield
SPP
2. David Dockery
Assocoated Electric Cooperative SERC
1, 3, 5
1, 3, 5
Consideration of Comments: Project 2007-12 Frequency Response
6
8
9
10
000612
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Lisa Duffey
Cleco Power
SPP
1, 3, 5
4. Jonathan Hayes
SPP
SPP
2
5. Steve Haun
Lincoln Electric System
MRO
1, 3, 5
6. Tony McMurtry
Lafayette Utilities System
SPP
NA
7. Dave Milliam
Kansas City Power & Light
SPP
1, 3, 5, 6
8. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
9. Katie Shea
Westar Energy
SPP
1, 3, 5, 6
7.
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
8.
Florida Municipal Power Agency
Group
Frank Gaffney
2
3
4
5
6
7
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
9.
Group
FRCC
Thomas McElhinney
JEA Electric Compliance
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. John Babik
JEA Electric Compliance FRCC
5
2. Ted Hobson
JEA Electric Compliance FRCC
1
3. Garry Baker
JEA System Operations
FRCC
10.
Group
3
ISO/RTO Council Standards Review
Committee
Al DiCaprio
X
Additional Member Additional Organization Region Segment Selection
1. Charles Yeung
SPP
2
2. Kathleen Goodman ISO-NE
SPP
NPCC
2
3. Gary DeShazo
CAISO
WECC 2
4. Greg Campoli
NYISO
NPCC
5. Steve Myers
ERCOT
ERCOT 2
2
Consideration of Comments: Project 2007-12 Frequency Response
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
8
7
000613
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Don Weaver
NBSO
NPCC
7. Mark Thompson
AESO
WECC 2
8. Ben Li
IESO
NPCC
11.
Group
Region
RFC
2. James Jones
WECC 1, 5, 6
3. Erin Woods
East Kentucky Power Cooperative
SERC
Joe Tarantino
Sacramento Municipal Utility District
(SMUD)
Additional Organization
X
X
X
X
X
Balancing Authority of Northern California (BANC) WECC 1
Southwest Power Pool Regional Entity
14.
Individual
Cindy Oder
Salt River Project
X
X
X
X
15.
Individual
Progress Energy
X
X
X
X
X
X
X
X
Individual
Jim Eckelkamp
Janet Smith, Regulatory
Affairs Supervisor
17.
Individual
Antonio Grayson
Southern Company
X
X
X
X
18.
Individual
Howard F. Illian
Energy Mark, Inc.
19.
Individual
Don McInnis
Florida Power & Light Company
X
X
X
20.
Individual
Carlos J. Macias
X
X
X
X
X
X
X
X
X
Arizona Public Service Company
X
Individual
Mauricio Guardado
FPL
Los Angeles Department of Water and
Power
Individual
Thomas Washburn
FMPP
Individual
24. Individual
Alice Ireland
Kathleen Goodman
Xcel Energy
ISO New England Inc
X
25.
John Tolo
Tucson Electric Power
X
21.
Individual
10
Region Segment Selection
Emily Pennel
23.
9
1, 3, 5, 6
Individual
22.
8
3, 5, 6
13.
16.
7
Segment
Selection
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative
12.
6
X
Old Dominion Electric Cooperative
1. Kevin Smith
5
2
1. Mark Ringhausen
Group
4
2
Additional Organization
Additional Member
3
ACES Power Marketing Standards
Collaborators
Jason L. Marshall
Additional
Member
2
Consideration of Comments: Project 2007-12 Frequency Response
X
X
X
X
X
8
000614
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
26.
Individual
Dennis Sismaet
Seattle City Light
27.
Individual
Michael Falvo
Independent Electricity System Operator
28.
Individual
John Bussman
Associated Electric Cooperative Inc
X
29.
Individual
Rich Salgo
NV Energy
30.
Individual
Thad Ness
31.
Individual
32.
2
X
4
X
5
6
X
X
X
X
X
American Electric Power
X
X
X
X
X
X
X
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
Individual
Louis C. Guidry
Cleco Corporation
X
X
X
X
33.
Individual
H. Steven Myers
ERCOT
34.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
35.
Individual
Curtis Crews
Texas Reliability Entity
36.
Individual
Mark B Thompson
Alberta Electric System Operator
37.
Individual
Anthony Jablonski
ReliabilityFirst
38.
Individual
Brenda Powell
Constellation Energy Commodities Group
39.
Individual
Kirit Shah
Ameren
X
X
X
X
40.
Individual
Michael Brytowski
Great River Energy
X
X
X
X
41.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
X
42.
Individual
Greg Rowland
Duke Energy
X
X
X
X
43.
Individual
Robert Blohm
Keen Resources Asia Ltd.
Consideration of Comments: Project 2007-12 Frequency Response
X
3
7
8
9
10
X
X
X
X
X
X
X
X
9
000615
1.
The SDT has made minor modifications to the proposed definitions to provide additional clarity. Do you agree that these
modifications provide sufficient clarity? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters felt that the SDT should use the term “prevent” instead of “discourage” in
the definition of FRM. The SDT explained that it did not want to use the word “prevent” since the SDT believes that the word would
imply that you could stop withdrawal. The SDT does not believe that you can totally stop the withdrawal but you can discourage it.
Many of the commenters did not agree with requiring the BA to provide Frequency Response. The NERC Functional Model and FERC
cite the BA as the responsible party for providing Frequency Response. There are several different methods available to the BA to
provide Frequency Response and these are included in the Background Document.
A couple of the commenters felt that the median was not the proper method to use for the calculation of the FRM and that the RSG
was not fully explained. Statisticians note that the median is a more accurate measure of central tendency than the mean when
analyzing a sample that is small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response. While
the median is not perfect, the median approaches a BA’s typical performance after 15-20 observations and more observations give a
higher confidence in the estimate of the BA’s performance.
Some commenters had concerns about the use of the RSG as a means to provide Frequency Response, and in response the SDT
modified the Background Document to further explain how an RSG (now FRSG) could be used to supply Frequency Response. The
SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term
“Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Organization
Yes or No
Question 1 Comment
Seattle City Light
Negative
Answer: No. Comments: LADWP and SCL recommend the following change
to the definition of Frequency Bias Setting. LADWP believes that this change
increases the clarity of the definition:
Original A number, either fixed or variable, usually expressed in MW/0.1 Hz,
included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s Frequency Response contribution to the
Consideration of Comments: Project 2007-12 Frequency Response
10
000616
Organization
Yes or No
Question 1 Comment
Interconnection, and discourage response withdrawal through secondary
control systems.
Proposed Change A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution
to the Interconnection, and prevent response withdrawal through
secondary control systems
Response: The SDT disagrees with your definition. The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does not
believe that you can totally stop the withdrawal but you can discourage withdrawal.
Alliant Energy Corp. Services, Inc.
Negative
The definition of Frequency Bias Setting should focus on what it is. balancing
Authorities do not supply energy. seggest rivising it to "A number, either
fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority's Area Control Error equation to approximate the expected
natural response provided by the assets within the respective Balancing
Authority's area."
Response: The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model
Technical Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA
controls the amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar
to the relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the
TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
Consideration of Comments: Project 2007-12 Frequency Response
11
000617
Organization
Yes or No
Question 1 Comment
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
chosen to use.
Potomac Electric Power Co.
Negative
The proposed new Definitions do not stand alone and are also linked to
Attachments.
Response: The SDT has modified the definitions to no longer reference any other documents.
ISO/RTO Council Standards Review
Committee
No
(1) In our previous comments, we suggested to drop the definitions for the
terms FRM and FRO in favor of providing the needed wording in the
standard itself to take care of the specific details. The SDT did not adopt
our suggestion with the reason that these definitions will be used by
other standards in the future. That’s fair enough. However, the FRM
definition: “The median of all the Frequency Response observations
reported annually on FRS Form 1” is problematic.
It references an FRS Form 1 which is not included in the definition itself
but is in fact an Attachment to a standard. In the current NERC Glossary
of Terms, there is no such precedence that a definition must rely on the
requirements or details in a standard for completeness. Also, it is very
cumbersome that when changes are made to FRS Form 1, the definition
must be posted for industry comment and balloting, and vice versa.
When other standards begin using the term, there will be cross
references between standards. This further complicates the
update/approval process without any appreciable value.Once again, we
strongly urge the SDT to consider dropping these definitions, and have
the details fully specified in the standard body itself. This will eliminate
that cross reference issue. After all, the definition for FRM is a simple
Consideration of Comments: Project 2007-12 Frequency Response
12
000618
Organization
Yes or No
Question 1 Comment
sentence and does not provide any clarity or specific details that cannot
be presented by using appropriate wording in a requirement.
(2) The definition of Frequency Bias Setting, if retained, should focus on
what it is. Balancing Authorities do not supply energy. We suggest to
revise it to: Frequency Bias Setting A number, either fixed or variable,
usually expressed in MW/0.1 Hz, included in a Balancing Authority’s
(BA’s) Area Control Error (ACE) equation to approximate the expected
natural response provided by the assets within the respective Balancing
Authority’s area.
Response: The SDT believes that these terms will be used in later version of the BAL Standards. The term FRO is presently being
used in the development of a new standard (BAL-012-1 Planning Reserves). The SDT has modified the definitions to no longer
reference any other documents.
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
Consideration of Comments: Project 2007-12 Frequency Response
13
000619
Organization
Yes or No
Question 1 Comment
No
Duke Energy would suggest removing “usually” from the Frequency Bias
Setting definition, as the value in the ACE equation must be in terms of
MW/0.1Hz in order for ACE to be correctly calculated. We apologize for
missing this point in the last round of comments. Though some would argue
that the last phrase of the definition is more of an explanation of a function
rather than a definition, we support keeping the phrase inserted, as it
should be recognized that the intent is to account for the frequency
response contribution AND keep the FBS slightly larger (in magnitude) than
the average estimated response, to better discourage withdrawal, which
was also recognized by Nathan Cohn.
chosen to use.
Duke Energy
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: It is the understanding of the SDT that EMS systems could use different methods implementing the ACE calculation.
The SDT therefore believes that the term “usually” is more appropriate.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median of
all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO.
This will be calculated as MW/0.1Hz.”
Independent Electricity System
Operator
No
In our previous comments, we suggested to drop the definitions for the
terms FRM and FRO in favor of providing the needed wording in the
standard itself to take care of the specific details. The SDT did not adopt our
suggestion with the reason that these definitions will be used by other
standards in the future. That’s fair enough. However, the FRM definition:
“The median of all the Frequency Response observations reported annually
on FRS Form 1” is problematic. It references an FRS Form 1 which is not
included in the definition itself but is in fact an attachment to a standard. In
the current NERC Glossary of Terms, there is no such precedence that a
Consideration of Comments: Project 2007-12 Frequency Response
14
000620
Organization
Yes or No
Question 1 Comment
definition must rely on the requirements or details in a standard for
completeness. Also, it is very cumbersome that when changes are made to
FRS Form 1, the definition must be posted for industry comment and
balloting, and vice versa. When other standards begin using the term, there
will be cross references between standards. This further complicates the
update/maintenance problem without any appreciable value.
Once again, we strongly urge the SDT to consider dropping these definitions,
and have the details fully specified in the standard body. This will eliminate
the cross reference issues. After all, the definition for FRM is a simple
sentence and does not provide any clarity or specific details that cannot be
addressed by providing the appropriate wording in a requirement.
With this cross-reference issue, combined with the issues associated with
Attachments A and B (see our comments under Q6, below), we are unable
to support this standard at this time.
Response: The SDT believes that these terms will be used in later version of the BAL Standards. The term FRO is presently being
used in the development of a new standard (BAL-012-1 Planning Reserves). The SDT has modified the definitions to no longer
reference any other documents.
Keen Resources Asia Ltd.
No
In the Standard, the definition of Frequency Response Measure (FRM) is
statistically wrong. The median is an improper statistical measure of
Frequency Response because--it truncates large excursions which are the
specific subject of Frequency Response control, not normal operating
frequency errors which are self-correcting and are the subject of CPM
control;--it is non-linear; and therefore--it is non-summable over the
interconnection; in other words, the individual BA medians don't add up to
the interconnection median, in complete incompatibility with CPM control
which requires summability of BA performances into the interconnection's
performance. Moreover, it is mathematically impossible to sum the
medians of the BAs in a Reserve Sharing Group (RSG) into the RSG's median:
Consideration of Comments: Project 2007-12 Frequency Response
15
000621
Organization
Yes or No
Question 1 Comment
in other words, the RSG's median cannot represent the sum of the medians
of its members.The last paragraph on page 5 of the Background Document
is patently wrong, invented, and supported in no probability & statistics
literature whatsoever. As a practicing statistician, I hereby give testimony to
the utter falsehood of the statement that "In general, statisticians use the
median as the best measure of central tendency when a population has
outliers." (See http://www.robertblohm.com/BestStatistic.doc for an
explanation of "best statistic" which is a highly technical and central topic in
modern probability theory and statistics.) Also, "outliers" are falsely and
rhetorically claimed to be "noise" when in fact they are the "events" that
are the specific subject of Frequency Response. It is well known that they
do not "fit" a normal distribution. They are distinct from the normal
operating errors that are the subject of CPM control. The paragraph does
correctly conclude that the linear regression more accurately incorporates
outliers than the median does, although the paragraph uses rhetoric by
calling this improvement "skew" as if it is distortionary when, in fact, the
median distorts the reality.
Response: The word “average” is a generic term to represent central tendency. The term is often used synonymously with the
arithmetic “mean”.
The issue with measuring frequency response is that a BA’s calculated performance (as opposed to actual performance) is highly
variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the East typically is only called to
contribute about 10-15 MW for the loss of a large unit. Its minute to minute load changes can easily wash this contribution out.
An arithmetic mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Consideration of Comments: Project 2007-12 Frequency Response
16
000622
Organization
Yes or No
Question 1 Comment
interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
confidence in the estimate of the BA’s performance.
Manitoba Hydro
No
It is not clear why the term “Single Event Frequency Response Data (SEFRD)”
has been removed from the standard but is still used and defined in the
Background Document and Attachment A.
Response: The SDT removed the term because it was not being used within the standard itself. It was only being used in the
calculation of the FRM. There is no need to create a NERC Glossary defined term if it is not being used in the standard.
Seattle City Light
No
LADWP and SCL recommend the following change (in red) to the definition
of Frequency Bias Setting. LADWP believes that this change increases the
clarity of the definition:OriginalA number, either fixed or variable, usually
expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control
Error equation to account for the Balancing Authority’s Frequency Response
contribution to the Interconnection, and discourage response withdrawal
through secondary control systems.Proposed ChangeA number, either fixed
or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing
Authority’s Frequency Response contribution to the Interconnection, and
discourage prevent response withdrawal through secondary control systems
Response: The SDT disagrees with your definition The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does not
believe that you can totally stop the withdrawal but you can discourage withdrawal.
Los Angeles Department of Water
and Power
No
LADWP recommends the following change to the definition of Frequency
Bias Setting (replace the word "discourage" with the word "prevent").
LADWP believes that this change increases the clarity of the
definition:OriginalA number, either fixed or variable, usually expressed in
Consideration of Comments: Project 2007-12 Frequency Response
17
000623
Organization
Yes or No
Question 1 Comment
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution
to the Interconnection, and discourage response withdrawal through
secondary control systems.Proposed ChangeA number, either fixed or
variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing
Authority’s Frequency Response contribution to the Interconnection, and
prevent response withdrawal through secondary control systems
Response: The SDT disagrees with your definition. The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does
not believe that you can totally stop the withdrawal but you can discourage withdrawal.
Progress Energy
No
PGN supports the collective comments of SERC members.We feel that the
last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. While the SERC OC
Standards Review Group understands the statement, we do not feel it
belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that it is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
ERCOT
No
RE: Frequency Response Obligation (FRO) definition: ERCOT suggests
changing “Balancing Authority’s” to “Balancing Authority Area’s” as follows:
Consideration of Comments: Project 2007-12 Frequency Response
18
000624
Organization
Yes or No
Question 1 Comment
The Balancing Authority Area’s share of the required Frequency Response
needed for the reliable operation of an Interconnection.
A BA that does not own generation resources cannot provide Frequency
Response, it can only schedule and dispatch available resources capable of
such; . The BA should be responsible for taking action to schedule resources
that are capable of frequency response, and monitoring to assure frequency
response performance. The GOP (possibly the LSE when demand side
performance is involved) must be accountable for performing.However,
there is nothing in this requirement to encourage the owner of a resource
who chooses not to provide frequency response to come to the table.
There is nothing in this standard that uniformly requires all frequency
response providers to perform. This is likely to be detrimental to the
performance of a BAA and unfairly sanctions those willing to perform to to
assure reliability while others are not required to perform.
Response: The SDT believes that the BA is the responsible entity not the BA Area.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own
generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
Consideration of Comments: Project 2007-12 Frequency Response
19
000625
Organization
Yes or No
Question 1 Comment
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Ameren
No
The Frequency Response Measure (FRM) definition should include which
Entity(ies) it applies to, similar to the definition of the FRO.
Response: The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read
“The median of all the Frequency Response observations reported annually by Balancing Authorities for frequency events
specified by the ERO. This will be calculated as MW/0.1Hz.”
Constellation Energy Commodities
Group
No
The Frequency Response Obligation has two components based on
Attachment 1 - an Interconnection FRO and a BA FRO. The proposed
definition captures only the BA FRO.
Response: The definition is referencing the responsible entity, the BA. The interconnection’s FRO is only calculated as the
beginning point for the determination of the BA’s FRO.
Hydro-Quebec TransEnergie
No
The FRM and FRO definitions should precise that it is expressed in
MW/0.1Hz.
As for the Frequency Bias Setting definition, as written, would apply only to
a multiple BA Interconnection. In a single BA Interconnection, the
Frequency Bias translates the frequency error into a MW value that must be
dispatched to bring back Frequency to desired value. Since Tie Lines are not
controlled through AGC, there is no response withdrawal issue
Response: The FRM and FRO definitions have been modified to state MW/0.1Hz.
The SDT disagrees. There can be withdrawal on any interconnection that uses a Frequency Bias estimate if that estimate is
lower than Frequency Response and other factors are used to determine dispatch, i.e., future load estimate.
Northeast Power Coordinating
Council/ISO New England Inc.
No
The FRM definition should not refer to FORM 1.
Also, suggest the following wording for frequency bias setting: “A number,
Consideration of Comments: Project 2007-12 Frequency Response
20
000626
Organization
Yes or No
Question 1 Comment
either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to approximate the
frequency response provided by the assets within the respective Balancing
Authority’s area.”
Response: The SDT has modified the definitions to no longer reference any other documents.
The definition now read “The median of all the Frequency Response observations reported annually by Balancing Authorities for
frequency events specified by the ERO. This will be calculated as MW/0.1Hz.”
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
chosen to use.
MRO NSRF
No
The FRM definition: “The median of all the Frequency Response
observations reported annually on FRS Form 1” is problematic. It references
an FRS Form 1 which is not included in the definition itself but is in fact an
Consideration of Comments: Project 2007-12 Frequency Response
21
000627
Organization
Yes or No
Question 1 Comment
attachment to a standard. In the current NERC Glossary of Terms, there is
no such precedence that a definition must rely on the requirements or
details in a standard for completeness.
Additionally, the definition of Frequency Bias Setting should focus on what it
is. Balancing Authorities do not supply energy. Suggest revising it
to:Frequency Bias Setting A number, either fixed or variable, usually
expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control
Error equation to approximate the expected natural response provided by
the assets within the respective Balancing Authority’s area.
Response: The SDT has modified the definitions to no longer reference any other documents.
The definition now read “The median of all the Frequency Response observations reported annually by Balancing Authorities for
frequency events specified by the ERO. This will be calculated as MW/0.1Hz.”
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
Consideration of Comments: Project 2007-12 Frequency Response
22
000628
Organization
Yes or No
Question 1 Comment
chosen to use.
Alberta Electric System Operator
No
The FRO definition is specific to BAs. The Appendix 1, which is incorporated
in the standard, uses this definition in relation to requirements of the
Interconnection. The SDT should consider a revision of this definition that
accounts for the requirements of the Interconnection versus the BA
obligation to the Interconnection.
Response: The definition is referencing the responsible entity, the BA. The Interconnection’s FRO is only calculated as the
beginning point for the determination of the BA’s FRO.
South Carolina Electric and Gas
No
The last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. Therefore, we do not feel
it belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
SERC OC Standards Review Group
No
We feel that the last phrase of the definition of Frequency Bias Setting is
more of an explanation of a function rather than a definition. While the
SERC OC Standards Review Group understands the statement, we do not
feel it belongs in the definition of the Frequency Bias Setting and a period
should be inserted after the word “Interconnection”. Should the definition
for Frequency Response Measure (FRM) be specific to the BA, similar to the
Consideration of Comments: Project 2007-12 Frequency Response
23
000629
Organization
Yes or No
Question 1 Comment
definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
Southern Company
No
We suggest adding BA to the definition of Frequency Response Measure
(FRM), similar to the definition for Frequency Response Obligation (FRO).
Response: The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read
“The median of all the Frequency Response observations reported annually by Balancing Authorities for frequency events
specified by the ERO. This will be calculated as MW/0.1Hz.”
Associated Electric Cooperative Inc
Yes
The FRO definition incorrectly applies the historically narrow Balancing
Authority scope of responsibility, while the FRM definition does not address
applicability at all. But the BAL-003-1 Standard itself identifies RSGs (where
applicable) and BAs as the Responsible Entities within scope of this
standard. For consistency, AECI recommends using “Responsible Entities
(e.g. Reserve Sharing Groups - where applicable, and Balancing Authorities)”
in both the FRO and FRM definitions. Rationale: This change should help
future-proof the definition, should more specific “frequency response” or
“spinning reserve” sharing groups later surface within our industry.
AECI agrees with the Frequency Bias Setting definition’s inclusion of a bit
more functionality than typical. We however recommend replacing “to
account for the Balancing Authority’s Frequency Response contribution to
the Interconnection, and discourage response withdrawal through
secondary control systems”, with “to support their Frequency Response
contribution to the Interconnection”. Rationale: Readability, and clarity on
Consideration of Comments: Project 2007-12 Frequency Response
24
000630
Organization
Yes or No
Question 1 Comment
the “discouraging withdrawal...” phrase, which should reside in the
Background document.
Response: The SDT believes that using the term “Responsible Entities” would cause confusion since different standards could
define a Responsible Entity differently. However, the SDT has defined a new term “Frequency Response Sharing Group”
because it believes that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition
reads “A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of its members.” The SDT has decided not to
add the term FRSG to the definition for Frequency Response Obligation (FRO). The SDT believes that the FRO is assigned to a BA
not the FRSG. The FRSG FRO is a summation of the BA FRO’s.
The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has decided to not
further modify the definition based on your comments.
SCE&G
Affirmative
The last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. Therefore, we do not feel
it belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
o The utilization of the term, “Reserve Sharing Group”, is not consistent
with the definition in the NERC Glossary of Terms, and should be deleted,
applicability should be clarified or replaced with a new term, such as
“Frequency Response Sharing
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
Consideration of Comments: Project 2007-12 Frequency Response
25
000631
Organization
Yes or No
Question 1 Comment
The SDT agrees that using the phrase Reserve Sharing Group could cause confusion. The SDT has defined a new term
“Frequency Response Sharing Group”. The definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.” The SDT has decided not to add the term FRSG to the definition for Frequency Response Obligation
(FRO). The SDT believes that the FRO is assigned to a BA not the FRSG. The FRSG FRO is a summation of the BA FRO’s.
Bonneville Power Administration
Yes
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
Western Electricity Coordinating
Council
Yes
ACES Power Marketing Standards
Collaborators
Yes
Southwest Power Pool Regional
Entity
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
Florida Power & Light Company
Yes
FPL
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
26
000632
Organization
Yes or No
Xcel Energy
Yes
Tucson Electric Power
Yes
NV Energy
Yes
Cleco Corporation
Yes
Great River Energy
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 1 Comment
27
000633
2.
The SDT has made minor modifications to the Requirements R1 through R4 to provide additional clarity. Do you agree that
these modifications provide sufficient clarity to comply with the standard? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters felt that the use of an RSG as a method for supplying Frequency Response
was not fully explained. The SDT modified the Background Document to further explain how an RSG (now FRSG) could be used to
supply Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that
using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Many of the commenters were concerned with the language in Requirement R3 stating that an entity had to be operating in Tie Line
Bias mode unless there were adverse affects on the BES. The SDT removed this requirement from the proposed standard since it is
duplicative of Requirement R6 and R7 in BAL-005-0.1b.
Many of the commenters did not agree with assigning the BA to provide Frequency Response. The NERC Functional Model and FERC
cited the BA as the responsible party for providing Frequency Response. There are several different methods available to the BA to
provide Frequency Response included in the Background Document.
A few of the commenters did not agree with lowering the minimum Frequency Bias Setting. Early research by Nathan Cohn on
interconnected power system operations found that control is optimum if a BA’s Bias Setting is equal to its natural Frequency
Response. If there were to be a difference between the two values, it is preferable to be slightly over-biased. The drafting team has
proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is outlined in a Procedure
developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to making this happen and
includes checks to confirm there are not unexpected influences injected into the CPS-related calculations. Based on concerns raised
by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting 0.9% of peak and has
included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The evaluation will look at
both frequency performance and impact on CPS-related compliance calculations.
A couple of commenters were concerned that the BA could be responsible to supply an infinite amount of Frequency Response. They
felt that a BA could not prepare for this in its planning process. The proposed standard was not clear on this subject and the SDT has
added language in the “Event Selection Criteria” section of Attachment A to limit the amount of Frequency Response a BA would be
required to provide to be compliant with the standard.
Consideration of Comments: Project 2007-12 Frequency Response
28
000634
Organization
Yes or No
Question 2 Comment
Seattle City Light
Negative
The language in Requirement 4 needs to be clarified and recommends the following
change:
R4. Each Balancing Authority that is performing Overlap Regulation Service shall
modify its Frequency Bias Setting in its ACE calculation to be equivalent to either
(i)
(ii)
the sum of the Frequency Bias Settings of the participating Balancing
Authorities as validated by the ERO, or
(ii) the Frequency Bias Setting as calculated based on the entire area being
combined and thereby represent the Frequency Response for the combined
area being controlled. [Risk Factor: Medium][Time Horizon: Operations
Planning]
Response: The SDT has modified Requirement R4 to use bullets in support of your suggestion.
Public Utility District No. 1 of
Douglas County
Negative
1. Recommend clarifying the language in R1 to include background information as to
how RSGs fit into the FRM performance.
2. Recommend R3 language be modified to permit operation in other than tie-line
bias mode with the requirement to notify the RC.
3. We have concern about the affect R3 will have on the WECC time error correction
standard (BAL-004-WECC-1).
4. Clarification is needed between Attachment A and the Background Document for
projected peak and historical peak.
5. We have a concern about the affect of lowering the minimum frequency bias
obligation from 1% to .8% and its probable affect on reliability.
6. We have a concern about he upper limit to the amount of frequency response
expected from BAs.
Response: Comment 1 – The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used
to supply Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes
Consideration of Comments: Project 2007-12 Frequency Response
29
000635
Organization
Yes or No
Question 2 Comment
that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
Comment 2 & 3– The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was
based on industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Comment 4 – The SDT has corrected the error between Attachment A and the Background Document.
Comment 5 – Early research by Nathan Cohn2 on interconnected power system operations found that control is optimum if a BA’s
Bias Setting is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to
be slightly over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Comment 6 – The SDT understands your concern and agrees that this could cause problems with compliance. The SDT has
modified Attachment A to include language which puts an upper limit on the amount of Frequency Response required from an
entity.
Potomac Electric Power Co.
Negative
1)The proposed Requirements do not meet all the FERC directives.
2)The proposed Requirements fail to recognize the fact that not all BAs can provide
primary frequency response.
3)The proposed Requirements are not all in the standard. Some are in the
Attachments.
2
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
30
000636
Organization
Yes or No
Question 2 Comment
Response: Comment 1 – The SDT disagrees with you about their meeting all of the FERC directives. Unfortunately your comment
does not provide specific information as to what you believe is not being addressed. The SDT has included a section within the
Background Document which details how this standard is meeting the FERC directives.
Comment 2 – The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Comment 3 – Unfortunately your comment does not provide enough information as to what parts of the attachments you believe
should be in the requirements. However, the SDT has made significant modifications to both Attachment A and Attachment B
now a Procedure for the ERO to follow in support of the proposed standard. The SDT believes that the requirements should be
succinct and the methodologies to be used should be part of an attachment.
Seattle City Light
No
o LADWP and SCL have a concern with Requirement 3. The requirement should
provide allowance for legitimate circumstances when an entity cannot run on Tie
Line Bias mode and not have an Adverse Reliability Impact on the Balancing
Authority’s Area. An entity should not be penalized when these legitimate
circumstances occur. LADWP believes that the Frequency Response Standard
Background Document, on Page 8, lists examples of legitimate circumstances:Telemetry problems that lead the operator to believe ACE is significantly in error.-
Consideration of Comments: Project 2007-12 Frequency Response
31
000637
Organization
Yes or No
Question 2 Comment
The frequency input to AGC is not reflective of the BA’s true frequency (such as if the
control center were operating a local generator and disconnected from the
Interconnection).- During restoration (where one BA might be controlling frequency
while another to which it is connected is managing interchange between them).- For
training purposes.- Many AGC systems will automatically switch to an alternate
mode if the EMS determines Tie Line Bias control could lead to problems.
o LADWP and SCL believe that the language in Requirement 4 needs to be clarified
and recommends the following change (in red):R4. Each Balancing Authority that is
performing Overlap Regulation Service shall modify its Frequency Bias Setting in its
ACE calculation to be equivalent to either (i) the sum of the Frequency Bias Settings
of the participating Balancing Authorities as validated by the ERO, or (ii) calculate the
Frequency Bias Setting as calculated based on the entire area being combined and
thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium][Time Horizon: Operations Planning]
o LADWP and SCL believes the language in Requirement 5 needs to be modified to be
consistent with that of the second paragraph of Attachment B. SCL recommends the
addition of “natural frequency response” as a third bullet item to Requirement 5 (in
red). The revised requirement would read:
R5. In order to ensure adequate control response, each Balancing Authority
shall use a monthly average Frequency Bias Setting whose absolute value is at
least equal to one of the following: [Risk Factor: Medium ][Time Horizon:
Operations Planning]
o The minimum percentage of the Balancing Authority Area’s estimated
yearly Peak Demand within its metered boundary per 0.1 Hz change as
specified by the ERO in accordance with Attachment B.
o The minimum percentage of the Balancing Authority Area’s estimated
yearly peak generation for a generation-only Balancing Authority, per
0.1 Hz change as specified by the ERO in accordance with Attachment
Consideration of Comments: Project 2007-12 Frequency Response
32
000638
Organization
Yes or No
Question 2 Comment
B.
o The natural frequency response
Response: The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow an entity to
circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into Requirement
R2 and a new Requirement R3.
FMPP
No
o R1. Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an
annual Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each BA or RSG to maintain an adequate level of Frequency Response in the
Interconnection. [Risk Factor: Medium ][Time Horizon: Operations Assessment] The
BA does not have control over the frequency responsive generation. There needs to
be a requirement that the GOP shall set frequency response for the generators as
directed by the BA.
o R5. In order to ensure adequate control response, each Balancing Authority shall
use a monthly average Frequency Bias Setting whose absolute value is {greater than
or (<= add these words)} {at least (<= delete these words)} equal to one of the
following: [Risk Factor: Medium ][Time Horizon: Operations Planning] o The
minimum percentage of the Balancing Authority Area’s estimated yearly Peak
Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B. o The minimum percentage of the Balancing
Authority Area’s estimated yearly peak generation for a generation-only Balancing
Authority, per 0.1 Hz change as specified by the ERO in accordance with Attachment
B.
Consideration of Comments: Project 2007-12 Frequency Response
33
000639
Organization
Yes or No
Question 2 Comment
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
With regards to your comment concerning Requirement R5, you have not provided enough information for the SDT to respond.
However, the SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Western Electricity
Coordinating Council
No
Agree with the changes made to this latest version of BAL-003-1. However,
additional clarity could be added by addressing the following:
R1- It is not clear what is intended by "Reserve Sharing Group". As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and
appears to apply more towards 'secondary response'. Recommend clarifiying this
concept and possibly include an example in the background document to help
explain how this would work.
R3 - There may be occasions in which an entity has a legitimate reason or a need to
operate in a mode other than Tie Line Bias but that does not qualify as an Adverse
Reliability Impact. Recommend including language that would permit limited
operation in a mode other than Tie Line Bias mode provided the Reliability
Coordinator was notified. R3 - Has the drafting team considered whether or not the
Consideration of Comments: Project 2007-12 Frequency Response
34
000640
Organization
Yes or No
Question 2 Comment
language of Requirement R3 will have any conflict or coordination issue with the
FERC-approved regional reliability standards BAL-004-WECC-1 - Automatic Time Error
Correction?
R5 - Suggest changing the language “at least equal to” to “greater than or equal to”
for clarity.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
Seattle City Light
Negative
Answer: No Comments: o LADWP and SCL have a concern with Requirement 3. The
requirement should provide allowance for legitimate circumstances when an entity
cannot run on Tie Line Bias mode and not have an Adverse Reliability Impact on the
Balancing Authority’s Area. An entity should not be penalized when these legitimate
circumstances occur. LADWP believes that the Frequency Response Standard
Background Document, on Page 8, lists examples of legitimate circumstances: Telemetry problems that lead the operator to believe ACE is significantly in error. The frequency input to AGC is not reflective of the BA’s true frequency (such as if the
control center were operating a local generator and disconnected from the
Interconnection). - During restoration (where one BA might be controlling frequency
while another to which it is connected is managing interchange between them). - For
training purposes. - Many AGC systems will automatically switch to an alternate
mode if the EMS determines Tie Line Bias control could lead to problems.
Consideration of Comments: Project 2007-12 Frequency Response
35
000641
Organization
Yes or No
Question 2 Comment
o LADWP and SCL believe that the language in Requirement 4 needs to be clarified
and recommends the following change: R4. Each Balancing Authority that is
performing Overlap Regulation Service shall modify its Frequency Bias Setting in its
ACE calculation to be equivalent to either (i) the sum of the Frequency Bias Settings
of the participating Balancing Authorities as validated by the ERO, or (ii) the
Frequency Bias Setting as calculated based on the entire area being combined and
thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium][Time Horizon: Operations Planning]
o LADWP and SCL believes the language in Requirement 5 needs to be modified to
be consistent with that of the second paragraph of Attachment B. SCL recommends
the addition of “natural frequency response” as a third bullet item to Requirement 5.
The revised requirement would read:
R5. In order to ensure adequate control response, each Balancing Authority shall use
a monthly average Frequency Bias Setting whose absolute value is at least equal to
one of the following: [Risk Factor: Medium ][Time Horizon: Operations Planning]
o The minimum percentage of the Balancing Authority Area’s estimated yearly Peak
Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
o The minimum percentage of the Balancing Authority Area’s estimated yearly peak
generation for a generation-only Balancing Authority, per 0.1 Hz change as specified
by the ERO in accordance with Attachment B.
o The natural frequency response
Response: The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow an entity to
circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into Requirement
Consideration of Comments: Project 2007-12 Frequency Response
36
000642
Organization
Yes or No
Question 2 Comment
R2 and a new Requirement R3.
Avista Corp.
Negative
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly including an example in the background
document to help explain how this would work.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Early research by Nathan Cohn3 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
3
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
37
000643
Organization
Yes or No
Question 2 Comment
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
City of Redding, Oregon Public
Utility Commission,
BrightSource Energy, Inc.,
Clark Public Utilities, Avista,
Tri-State G & T Association,
Inc.; Deseret Power
Negative
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifying this concept and possibly including an example in the background
document to help explain how this would work.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Sacramento Municipal Utility
District (SMUD)
No
As drafted, requirement R1 requires Balancing Authorities or Reserve Sharing Groups
(RSGs) to achieve an annual Frequency Response Measure (FRM) that is equal to or
more negative than its Frequency Response Obligation (FRO). As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and
appears to apply more towards 'secondary response'. Recommend clarifying this
concept and possibly including an example in the background document to help
explain how this would work.
As drafted, in requirement R3, each Balancing Authority not receiving Overlap
Regulation Service to operate its AGC in Tie Line Bias mode... unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area. There
may be occasions in which an entity needs to perform testing or other instances
where it is necessary or desirable to operate in a mode other than Tie Line Bias that
does not qualify as an Adverse Reliability Impact, but never the less is necessary or
Consideration of Comments: Project 2007-12 Frequency Response
38
000644
Organization
Yes or No
Question 2 Comment
desired. Recommend including language that would permit operation other than Tie
Line Bias mode provided the Reliability Coordinator was notified.We seek
clarification from the drafting team as to whether or not there will be any conflicts
between proposed Requirement R3 and the requirements of FERC-approved regional
reliability standard BAL-004-WECC-1 - Automatic Time Error Correction.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Energy Mark, Inc.
No
Comment 1: The timing requirements for implementing the Frequency Bias Setting
are not specified for BAs participating in Overlap Regulation Service. The
requirements indicate the value that should be used for the Frequency Bias Setting,
but they do not indicate when those settings should be implemented.
Comment 2: The term "Tie Line Bias mode" in Requirement R3 is not sufficiently
defined to make this requirement enforceable. Any operating mode labeled as "Tie
Line Bias mode" on an EMS that uses interchange scheduled and frequency error as
inputs will meet the standard requirement as stated. This loop-hole exists because
the NERC definition of "Tie Line Bias" fails to define the term in enough detail to
actually limit AGC operation to the specified mode of operation. One way to
improve this requirement would be to redefine Tie Line Bias in the NERC Glossary as
a mode that uses the NERC ACE Equation as defined in BAL-001 as the basis for AGC
action when the EMS is in Tie Line Bias mode.
Comment 3: The standard is silent on how a BA receiving Overlap Regulation Service
should set its Frequency Bias Setting. Unless this is explicitly stated, it will be up to
Consideration of Comments: Project 2007-12 Frequency Response
39
000645
Organization
Yes or No
Question 2 Comment
the auditors to determine the value of the Frequency Bias Setting for BAs receiving
Overlap Regulation Service.
Comment 4: In general, the requirements indicate what the responsible BAs should
do and when. The requirements do not indicate what the BAs that are not
responsible should do and when, ie. how they are relieved from responsibility. This
may create problems when the auditors are required to interpret the standards for
BAs that have appropriately shifted responsibilites to others.
Response: Comment 1 – The SDT believes that Requirement R2 states the timing for implementation of the Frequency Bias
Setting. The Requirement R4 is simply to provide the BA with the method for combining the Frequency Bias Settings for providers
of Overlap Regulation Service. The Background Document and Attachment A have also been modified to provide further clarity.
Comment 2 – The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Comment 3 & 4 – The SDT does not believe that there is an issue for entities receiving Overlap Regulation Service. However, the
SDT has modified the Background document to further clarify this issue.
Duke Energy
No
Duke Energy supports the concept of a group of BAs forming a group to share in
Frequency Response however it should be clear that it is an option. We feel that the
utilization of the term, “Reserve Sharing Group”, is not consistent with the definition
in the NERC Glossary of Terms which is specific to sharing of contingency reserves,
and should be replaced with a new term, such as “Frequency Response Sharing
Group”.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Though comments are provided below on the Attachments, Duke Energy believes
that all NERC Reliability Standards’ requirements must reside within the standard
itself (which is vetted by the Industry and subject to FERC approval), and not within
Attachments that may be revised without Industry review and approval. As noted
below and in prior comments, given the secondary control implications of changing
Consideration of Comments: Project 2007-12 Frequency Response
40
000646
Organization
Yes or No
Question 2 Comment
the minimum Frequency Bias Setting (FBS), Duke Energy believes that subsequent
revisions to the minimum FBS should be vetted through the Standards process.
Duke Energy would suggest moving the details of the minimum FBS for each
Interconnection into the Standard, and having the implementation plan include
annual submittal of a revised minimum FBS based upon the methodology presented
in Attachment B for ballot approval by the Industry.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it also believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Attachments that are referenced within a Requirement are mandatory and enforceable.
Early research by Nathan Cohn4 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
ISO/RTO Council Standards
Review Committee
4
No
General CommentsThe SRC offers the following general comment with regard to the
SDT’s proposed revisions: Gerry Cauley’s Results based initiative calls for
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
41
000647
Organization
Yes or No
Question 2 Comment
requirements that focus on performance (i.e. WHAT must be accomplished NOT on
WHY it is required or HOW it should be accomplished). The SRC has found that such
explanatory statements as the SDT is proposing lead to ambiguities and confusion in
the compliance application. Compliance Enforcement agents must consider not just
the results but must decide if the action was taken for the given reason. To avoid
such confusion, the Results based approach uses reference documents to address
such background material while leaving the requirement as a direct mandate.The
SRC notes:
o All NERC Reliability Standards’ requirements must reside within the standard itself
(which is vetted by the Industry and subject to FERC approval).
o Data requirements are better handled through NERC’s Rules of Procedure Section
1600 than by mandating that ad hoc Forms be submitted.
o Definitions should be generic, and should be self-contained (i.e. should not
reference an external document).
o The decisions regarding alternative methodologies should be decided by the
Industry not by the SDT. The SDT should make its case and ask the Industry for its
approval.
Regarding Order 693 directives, the SRC notes that there are three directives as
follows:
(1) To include Levels of Non-Compliance;
(2) To determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other requirements of the Reliability
Standard are being met, and to modify Measure M1 based on that determination
and
(3) To define the necessary amount of Frequency Response needed for Reliable
Operation for each balancing authority with methods of obtaining and measuring
that the frequency response is achieved.
Consideration of Comments: Project 2007-12 Frequency Response
42
000648
Organization
Yes or No
Question 2 Comment
The SRC suggests that Directive 2 be handled directly as a mandate that the ERO
conduct a fixed number of Frequency Response Surveys for randomly selected
events. Discussion of the number and the methodology can be explained in a
reference document and leave the specifics to the requirement.
Directive 3 is critical to the Industry as it relates to who is the Applicable Entity. The
SDT addresses Directive 3 by mandating Balancing Authorities meet an objective. The
directive is to define that Objective, but there is no requirement associated with that
Objective. There is an attachment and there are discussions of what “may” be done,
but there is no requirement in the Standard itself. The reference to the BA as the
provider of Frequency Response (i.e. Primary Control response) runs counter to
other FERC directives that mandate obligated entities be able to self-serve or to
interchange provision of services. In this case the BA per se has no assets and cannot
self-serve, moreover the primary response service providers have no obligations to
provide the service, thus the BA potentially could face a situation where there is no
physical service to be purchased but there is a federally mandated standard to
comply with. The idea of creating a Primary Response Market as some have
proposed does not work without an obligation on some entity to physically provide
that service.
One final note, the SRC points out that the ACE is an error signal used to drive
secondary response; it is not a signal to drive primary response. Thus the use of the
Frequency Bias setting is not for control, it is for “adjusting” the error measure that is
analyzed after the fact.This standard needs:
o a requirement on the ERO to compute the Obligation on each Interconnection
o a requirement on the ERO to conduct Frequency Response surveys (note the SRC
does not support this requirement but believes that it is needed to meet the FERC
directive)
o a requirement on energy supply assets (both generation and load) to provide
primary response (as a function of the Interconnection obligation in the first bullet)
Consideration of Comments: Project 2007-12 Frequency Response
43
000649
Organization
Yes or No
Question 2 Comment
The above will allow NERC to comply with the FERC directives in a fashion consistent
with the processes and procedures approved by FERC.
Specific recommendations: The SRC proposes that R1 be deleted based on the facts
that:
o It imposes an obligation on an entity that has no capability to comply
o There is an internal conflict with imposing penalties on a deterministic basis
(compliance with a fixed set of events) for a statistical service (primary
response is a function of the assets operating state and not a fixed service of
the asset).In any case, all of the words after FRO should be deleted. The words
are not needed for the requirement and if left in can become a source of
contention between auditors and registered entities.
R3 - delete the added phrase “mode to effectively coordinate control”.The
phrase “would have an Adverse Impact on the BA’s area” needs further
discussion. Who makes the decision that operating on AGC will have adverse
impact must be defined.
R5 - delete the phrase “In order to ensure control response”. Such phrases can
be needless causes of debate. If a BA uses one of the bulleted methods but
does not get “adequate response” then is the BA non-compliant? What is
“adequate response”? Who decides if the response is adequate?
Response: Unfortunately your comment does not provide enough information as to what parts of the attachments you believe
should be in the requirements. However, the SDT has made significant modifications to both Attachment A and Attachment B,
now a Procedure for the ERO to follow in supporting the standard. The SDT believes that the requirements should be succinct and
the methodologies to be used should be part of an attachment.
The SDT is using defined forms to ensure that everyone calculates their Frequency Bias Setting and Frequency Response Measure
in a consistent manner. The SDT also believes that this provides entities a relatively non-time consuming method to provide the
necessary information to evaluate compliance.
Consideration of Comments: Project 2007-12 Frequency Response
44
000650
Organization
Yes or No
Question 2 Comment
The SDT has modified the definitions to no longer reference any other documents.
The SDT is recommending a certain approach to calculating the FRM. The reference to other methods being evaluated is simply a
statement that the SDT believes that further analysis would be beneficial. Any modification to the calculation methodology would
require industry approval.
The SDT believes that it is meeting Directive #2 by requiring at least 20 events to be analyzed each year.
The SDT believes that it is meeting the directive to define the “objective” by creating the BA Frequency Response Obligation (FRO).
With regards to the BA being the responsible entity to provide Frequency Response the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
The ERO is not defined as an applicable entity in the industry approved SAR and therefore it would be inappropriate to include
them as an applicable entity.
Los Angeles Department of
Water and Power
No
LADWP has a concern with Requirement 3. The requirement should provide
allowance for legitimate circumstances when an entity cannot run on Tie Line Bias
Consideration of Comments: Project 2007-12 Frequency Response
45
000651
Organization
Yes or No
Question 2 Comment
mode and not have an Adverse Reliability Impact on the Balancing Authority’s Area.
An entity should not be penalized when these legitimate circumstances occur.
LADWP believes that the Frequency Response Standard Background Document, on
Page 8, lists examples of legitimate circumstances:- Telemetry problems that lead
the operator to believe ACE is significantly in error.- The frequency input to AGC is
not reflective of the BA’s true frequency (such as if the control center were operating
a local generator and disconnected from the Interconnection).- During restoration
(where one BA might be controlling frequency while another to which it is connected
is managing interchange between them).- For training purposes.- Many AGC systems
will automatically switch to an alternate mode if the EMS determines Tie Line Bias
control could lead to problems.
LADWP believes that the language in Requirement 4 needs to be clarified and
recommends the following change:- R4. Each Balancing Authority that is performing
Overlap Regulation Service shall modify its Frequency Bias Setting in its ACE
calculation to be equivalent to either (i) the sum of the Frequency Bias Settings of
the participating Balancing Authorities as validated by the ERO, or (ii) the Frequency
Bias Setting as calculated based on the entire area being combined and thereby
represent the Frequency Response for the combined area being controlled. [Risk
Factor: Medium][Time Horizon: Operations Planning]
LADWP believes the language in Requirement 5 needs to be modified to be
consistent with that of the second paragraph of Attachment B. LADWP recommends
the addition of “natural frequency response” as a third bullet item to Requirement 5.
The revised requirement would read:- R5. In order to ensure adequate control
response, each Balancing Authority shall use a monthly average Frequency Bias
Setting whose absolute value is at least equal to one of the following: [Risk Factor:
Medium ][Time Horizon: Operations Planning] o The minimum percentage of the
Balancing Authority Area’s estimated yearly Peak Demand within its metered
boundary per 0.1 Hz change as specified by the ERO in accordance with Attachment
B. o The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation-only Balancing Authority, per 0.1 Hz change as
Consideration of Comments: Project 2007-12 Frequency Response
46
000652
Organization
Yes or No
Question 2 Comment
specified by the ERO in accordance with Attachment B. o The natural frequency
response
Response: The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow for an entity
to circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into
Requirement R2 and a new Requirement R3.
MidAmerican Energy Co.
Negative
MidAmerican supports the comments provided by the NSRF.
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard.
It is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.5).
Without a statement that the BA is expected to keep its allocated portion of
generation reserves only up to the largest event identified in Table 2, a BA could be
expected to provide limitless amounts of frequency response. Balancing Authorities
cannot know what is expected of them and therefore cannot plan appropriately.
Response: The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency
Response that a BA will be required to provide.
East Kentucky Power Coop.;
ACES Power Marketing;
Hoosier Energy Rural Electric
Cooperative, Inc.; Southwest
Transmission Cooperative,
Inc.
Negative
Overall, [we] believes the drafting team has done an excellent job to address the
FERC directives from Order 693. However, we believe there is still room for
improving the standard and that there is a significant technical error. The technical
error was introduced by applying Requirement 1 to the RSG and is discussed below.
Requirement 1 should not apply to a Reserve Sharing Group. Reserve Sharing Groups
(RSG) are designed to share Contingency Reserves and/or Operating Reserves not
Consideration of Comments: Project 2007-12 Frequency Response
47
000653
Organization
Yes or No
Question 2 Comment
Frequency Response. While these reserves may be frequency responsive, they are
not being shared for the purpose of expanding frequency response. Furthermore,
while reserve sharing groups may calculate a joint ACE by summing its individual BA
ACE values, RSGs do not have a Frequency Bias Setting which is necessary to assess a
Frequency Response Obligation.
Under item 3 of the Event Selection Criteria section, the delta F and Point C should
be described either in this attachment or the “Frequency Response Standard
Background Document”. While many in industry may understand what these terms
mean, history has a way of getting lost with personnel turnover. Furthermore, this
would help ensure that the auditors and industry have a duplicate understanding.
In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency
Protection Criteria should be provided and which N-2 event was selected so that
industry can help validate if the correct MW value was selected.
Furthermore, the document should clarify if the Contingency Protection Criteria
contains the “safety margin”. There is a statement in the paragraph before the table
that states it does, but then the table lists out a separate 25% “Safety Margin”. Thus,
it is not clear if the “Safety Margin” is included in the Contingency Protection Criteria
value listed in the table or not. “Safety margin” should be changed to “reliability
margin”. Safety has a specific meaning in the electric industry and its use here is not
appropriate. The Base Obligation should be explained. The explanation should
include its purpose and origin.
The Data Retention section requires the BA to retain data or evidence for up to four
years. No data that exceeds the audit cycle should be required to be retained. The
audit cycle is three years for BAs.
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Consideration of Comments: Project 2007-12 Frequency Response
48
000654
Organization
Yes or No
Question 2 Comment
Response Obligations of its members.”
The SDT agrees with your comment concerning further clarification on certain terms and has made significant modifications to the
Background Document and Attachments A and B.
The Data Retention is stated as “the current year plus three calendar years” since it is highly unlikely that an entity will be audited
exactly three years after its previous audit. The SDT recognizes that most audits will occur within the year following the third
year.
PPL Electric Utilities Corp.;
PPL Generation LLC
Negative
The PPL Companies do not support proposed Reliability Standard BAL-003-1
(Frequency Response and Frequency Bias Setting) primarily because PPL believes it
inappropriately subjects Reserve Sharing Groups (RSGs) to the proposed
requirements. The proposed Applicability provision states that the mandatory
reliability requirements would be applicable to (1) Balancing Authorities and (2)
Reserve Sharing Groups (where applicable). However, it is unclear how the proposed
requirements would be applicable to an RSG. RSGs typically do not provide a
mechanism for sharing automatic Frequency Response. The BA Frequency Response
Obligation (FRO) is a formula based on BAs and the Interconnection and has nothing
to do with RSGs. Rather, RSGs collectively respond to requests for activation of
contingency reserves generally after the request is made by a member Balancing
Authority. The Standard Drafting Team should therefore remove RSGs from the
Applicability section and should remove all other references to RSGs in the proposed
standard.
Response: The SDT disagrees that an RSG is not an appropriate mechanism for providing Frequency Response. However the SDT
does believe that using the term “Reserve Sharing Group” could cause confusion and has defined a new term “Frequency
Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
Consideration of Comments: Project 2007-12 Frequency Response
49
000655
Organization
Yes or No
Question 2 Comment
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Progress Energy
No
PGN supports the collective comments of SERC members.We feel that the utilization
of the term, “Reserve Sharing Group”, is not consistent with the definition in the
NERC Glossary of Terms, and should be deleted, applicability should be clarified or
replaced with a new term, such as “Frequency Response Sharing”.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
MRO NSRF
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As
RSGs exist today, FRM performance by an RSG is not contemplated in the definition
of FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly include an example in the background document
to help explain how this would work.
R2 - Please add the word “range” in-between the words “date” and “specified”. The
background document specifies that there is a 72-hour period to implement the FBS
setting (See Background document Page 7). R2, as written, does not reflect the
Consideration of Comments: Project 2007-12 Frequency Response
50
000656
Organization
Yes or No
Question 2 Comment
period for which an entity may implement the ERO validated Bias into ACE. Also see
our comment on #7 as to the length of the comment period. Question 7 comment is
provided to assist the SDT; Note from question 7: (Page 7 (3rd paragraph) of the
Background document states “Given the fact that BA’s can encounter staffing or EMS
change issues coincident with the date the ERO sets for new Frequency Bias Setting
implementation, the standard provides a 24 hour window on each side of the target
date.
1. The Standard itself does not state this provision (24 hour window on each side of
target date) as indicated.
2. The SDT accurately addresses the fact that BA’s could have EMS or staffing issues
during implementation of the ERO validated FBS. The current stated 72-hour window
is not long enough for implementation of the FBS as there may be a host of issues
that could impact implementation. We suggest that a seven day window be used for
implementation of the FBS.)
R3 - Recommend the term “Adverse Reliability Impact” be removed from
Requirement
3. Based on the NERC definition of the term, a smaller entity could never operate its
AGC outside of TLB mode due to their impact on the BES not likely to result in
“instability or Cascading”. To ensure a more consistent and equitable approach when
applying this Requirement, recommend the drafting team incorporate the reliability
reasons listed within the Background Document into the actual Requirement.
Additionally, the phrase “effectively coordinated control” should be removed as this
is not essential to the Requirement and introduces ambiguity in its application. To
this end, the following revisions are proposed:
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate
its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively
coordinated control, unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area meets one or more of the following conditions.
Consideration of Comments: Project 2007-12 Frequency Response
51
000657
Organization
Yes or No
Question 2 Comment
o Telemetry problems that lead the operator to believe ACE is significantly in error.
o The frequency input to AGC is not reflective of the BA’s true frequency (such as if
the control center were operating a local generator and disconnected from the
Interconnection).
o During restoration (where one BA might be controlling frequency while another to
which it is connected is managing interchange between them).
o For training purposes.
o Many AGC systems will automatically switch to an alternative mode if the EMS
determines Tie Line Bias control could lead to problems.
o For single BA Interconnections, Flat Frequency and Tie Line Bias are equivalent.
o The Reliability Coordinator has been informed and the duration is [insert time
constraint language here].
R5 - Recommend to delete the phrase “In order to ensure control response”. Such
phrases can be needless causes of debate. If a BA uses one of the bulleted methods
but does not get “adequate response” then is the BA non-compliant? What is
“adequate response”? Who decides if the response is adequate? Please clarify.
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG). The new definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Consideration of Comments: Project 2007-12 Frequency Response
52
000658
Organization
Yes or No
Question 2 Comment
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Xcel Energy
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As
RSGs exist today, FRM performance by an RSG is not contemplated in the definition
of FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly include an example in the background document
to help explain how this would work.
R3 - recommend modifying the language to permit AGC out of TLB mode if the RC is
notified; also remove the "to ensure coordinated control" as this is not essential for
the requirement. Our reasoning behind the suggested change to notification of the
RC is that there are occassions where an entity would need to perform testing, etc
and it could be argued that testing would not be sufficient justification for meeting
the Adverse Reliability Impact definition. Here is proposed revised language:Each
Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode, unless the Balancing
Authority's Reliability Coordinator has been informed and the duration is [insert time
constraint language here].
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Consideration of Comments: Project 2007-12 Frequency Response
53
000659
Organization
Yes or No
Question 2 Comment
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Constellation Energy
Commodities Group
No
R1 should accommodate agreements between multiple BAs and RSGs in achieving
the annual Frequency Response Measure. See proposed modification below:
R1. Each Balancing Authority shall achieve an annual Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or
more negative than its Frequency Response Obligations (FRO) to ensure that
sufficient Frequency Response is provided by each BA. Either the Balancing
Authority individual FRM, multiple Balancing Authority’s FRM per written agreement,
or the FRM of the Reserve Sharing Group must be equal to or more negative than the
applicable Frequency Response Obligations (FRO) for a single Balancing Authority or
the aggregate of multiple Balancing Authorities or RSGs.In R2, “Each Balancing Authority not participating in Overlap Regulation Service”
should state “Each Balancing Authority, not receiving Overlap Regulation, shall
implement the appropriate Frequency Bias Setting (fixed or variable,) validated by
the ERO, into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effectively coordinated Tie Line Bias control”. –
In R3, the explanatory language about why to operate in Tie Line Bias mode should
be deleted. See proposed modification below:
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate
its Automatic Generation Control (AGC) in Tie Line Bias mode, unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area.R5 should be modified to state only that the FBS is specified by the ERO in
accordance with Attachment B. As drafted the Requirement is in conflict with
Attachment B because the Requirement mandates a minimum and does not allow
for a reduction to the minimum but it references Attachment B which is titled
Consideration of Comments: Project 2007-12 Frequency Response
54
000660
Organization
Yes or No
Question 2 Comment
“Process for Adjusting Minimum Frequency Bias Setting”. See proposed modification
below:
R5. In order to ensure adequate control response, each Balancing Authority shall use
a monthly average Frequency Bias Setting whose absolute value is as specified by the
ERO in accordance with Attachment B.There should be a Requirement specifically stating there is an obligation to complete
and submit FRS Form 1 by January 10th each year for clarity.The requirements should be re-ordered to reflect the chronology of the process for
frequency calculation, implementation and performance measurement. The
recommended order is as follows:
R5 which defines the minimum Frequency Bias Setting (FBS) for a Balancing
Authority
R4 which describes how the minimum FBS may be altered through Overlap
Regulation Service
R2 which identifies the coordination required around implementationR3 which
requires operation in Tie Line Bias mode
R1 which establishes the performance obligation
Response: The SDT does not see anything within the Requirement that would restrict any agreements between multiple BAs and
RSGs. However, the SDT has modified the language in Requirement R1 to provide additional clarity. The requirement now reads
“Each Balancing Authority or Frequency Response Sharing Group (FRSG) shall achieve an annual Frequency Response Measure
(FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each Balancing Authority or FRSG to
maintain Interconnection Frequency Response equal to or more negative than the Interconnection Frequency Response
Obligation.” The SDT has also defined a new term “Frequency Response Sharing Group (FRSG)” because it also believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
Consideration of Comments: Project 2007-12 Frequency Response
55
000661
Organization
Yes or No
Question 2 Comment
jointly meet the Frequency Response Obligations of its members.”
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT also believes
that Attachment B, now a Procedure for the ERO to follow in supporting the standard, only details the process the ERO is to use
when evaluating and making modifications to the minimum Frequency Bias Setting.
The SDT disagrees with your comment concerning an additional requirement for timing of reporting. The SDT believes that this is
an administrative issue and is better handled within an attachment. The SDT would also like to note that an attachment when
referenced in a requirement becomes mandatory and enforceable.
The SDT thanks you for your suggested ordering for the requirements but believes that the revised proposed standard reflects the
proper order in that it sets the goal at beginning of year, calculates performance, reports performance and calculates bias at the
end of the year.
Constellation Energy
Negative
-R1 should accommodate agreements between multiple BAs and RSGs in achieving
the annual Frequency Response Measure. See proposed modification below: R1.
Each Balancing Authority shall achieve an annual Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or
more negative than its Frequency Response Obligations (FRO) to ensure that
sufficient Frequency Response is provided by each BA. Either the Balancing Authority
individual FRM, multiple Balancing Authority’s FRM per written agreement, or the
FRM of the Reserve Sharing Group must be equal to or more negative than the
applicable Frequency Response Obligations (FRO) for a single Balancing Authority or
the aggregate of multiple Balancing Authorities or RSGs.
-In R2, “Each Balancing Authority not participating in Overlap Regulation Service”
Consideration of Comments: Project 2007-12 Frequency Response
56
000662
Organization
Yes or No
Question 2 Comment
should state “Each Balancing Authority, not receiving Overlap Regulation, shall
implement the appropriate Frequency Bias Setting (fixed or variable,) validated by
the ERO, into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effectively coordinated Tie Line Bias control”.
-In R3, the explanatory language about why to operate in Tie Line Bias mode should
be deleted. See proposed modification below: R3. Each Balancing Authority not
receiving Overlap Regulation Service shall operate its Automatic Generation Control
(AGC) in Tie Line Bias mode, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.
-R5 should be modified to state only that the FBS is specified by the ERO in
accordance with Attachment B. As drafted the Requirement is in conflict with
Attachment B because the Requirement mandates a minimum and does not allow
for a reduction to the minimum but it references Attachment B which is titled
“Process for Adjusting Minimum Frequency Bias Setting”. See proposed modification
below: R5. In order to ensure adequate control response, each Balancing Authority
shall use a monthly average Frequency Bias Setting whose absolute value is as
specified by the ERO in accordance with Attachment B.
-There should be a Requirement specifically stating there is an obligation to
complete and submit FRS Form 1 by January 10th each year for clarity. -The
requirements should be re-ordered to reflect the chronology of the process for
frequency calculation, implementation and performance measurement. The
recommended order is as follows: R5 which defines the minimum Frequency Bias
Setting (FBS) for a Balancing Authority R4 which describes how the minimum FBS
may be altered through Overlap Regulation Service R2 which identifies the
coordination required around implementation R3 which requires operation in Tie
Line Bias mode R1 which establishes the performance obligation
Response: The SDT does not see anything within the Requirement that would restrict any agreements between multiple BAs and
RSGs. However, the SDT has modified the language in Requirement R1 to provide additional clarity. The requirement now reads
Consideration of Comments: Project 2007-12 Frequency Response
57
000663
Organization
Yes or No
Question 2 Comment
“Each Balancing Authority or Frequency Response Sharing Group (FRSG) shall achieve an annual Frequency Response Measure
(FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each Balancing Authority or FRSG to
maintain Interconnection Frequency Response equal to or more negative than the Interconnection Frequency Response
Obligation.” The SDT has also defined a new term “Frequency Response Sharing Group (FRSG)” because they also believed that
using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT also believes
that Attachment A only details the process the ERO is to use when evaluating and making modifications to the minimum
Frequency Bias Setting.
The SDT disagrees with your comment concerning an additional requirement for timing of reporting. The SDT believes that this is
an administrative issue and is better handled within an attachment. The SDT would also like to note that an attachment when
referenced in a requirement becomes mandatory and enforceable.
The SDT thanks you for your suggested ordering for the requirements but believes that the revised proposed standard reflects the
proper order in that it sets the goal at beginning of year, calculates performance, reports performance and calculates bias at the
end of the year.
Ameren
No
R1.While we agree with the concept of the entire requirement and the
determination of the Interconnection Frequency Response Obligation, we believe
that the accurate measurement of individual BA's FRM has not yet been
demonstrated. This requirement should not be part of the standard (even with the
additional 12 months in the effective date) until the field trial demonstrates that
Consideration of Comments: Project 2007-12 Frequency Response
58
000664
Organization
Yes or No
Question 2 Comment
each BA's FRM can be consistently calculated to a level that will not create false noncompliance to this requirement. While the calculation methodology in FRS Form 1
looks promising, with the A-value and B-value average periods, we believe successful
completion of the field trial is prudent.
R5. We were not sure if it was intended for this comment question to include
Requirement R5, but have decided to include our comments here. While we agree
with the requirement of R5, it should not be at the expense of changing the value of
L10 in BAL-001, R2, which has been accepted by FERC in Order 693. An
accommodation should be made so that any changes to the Frequency Bias Setting
according to BAL-003, R5, should not affect the value of L10 used in BAL-001, R2.
Response: The SDT agrees that validation of the methodology needs to occur. However, the SDT is working under a FERC
approved deadline for completion of this project. The SDT is recommending that continued analysis should occur during the filing
period and implementation period of the standard. The STD has also added considerable language to the Background Document
on why it has chosen the methodology it is recommending for this standard.
The SDT understands your concern with the reduction of the minimum Frequency Bias Setting affecting other performance
standards. The process to do this is outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure
manages a “go slow” approach to making this happen and includes checks to confirm there are not unexpected influences injected
into the CPS-related calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to
make the initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a
change in minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
American Electric Power
No
R1: Clarification is needed regarding the responsibility of a BA that is a member of a
Reserve Sharing Group.
R2 and R3: What does “coordinated control” mean?
There no leverage for the BA to require the generator to carry their burden of
addressing governor settings or droop settings, yet the BA is obligated to meet some
performance measures.
Consideration of Comments: Project 2007-12 Frequency Response
59
000665
Organization
Yes or No
Question 2 Comment
This revision adds new performance measure responsibilities on the BA who likely
has no direct control over every resource affecting their performance within their
footprint. We are not necessarily challenging the performance measures themselves,
nor their underlying objectives, however AEP views this as a gap in responsibilities
which potentially effects reliability.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” to eliminate any confusion with the
present d3efined term “Reserve Sharing Group”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has been instructed to include a “reliability outcome” within the requirements and therefore included the language
“…coordinated control…”. The SDT understands that this does not provide any additional clarity for complying with the
requirement and could be removed. The SDT will forward your concerns about the wording to the Standards Committee Quality
Review group for consideration.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
60
000666
Organization
Yes or No
Question 2 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Great River Energy
No
R1: Including the Reserve Sharing Group (RSG) in the Frequency Response Obligation
is outside of the boundaries of a RSG. Where or how would a Frequency Bias be
determined for an RSG to determine their Frequency Response Obligation? Although
it is apparent that frequency responds during the implementation of reserves, the
intention of a RSG is not to share frequency response, but rather to share Reserves.
Additionally, if the Frequency Response Obligation is not met by the RSG how are
penalties assessed? Should they be assessed to the group as a whole or strictly to
the generators that did not meet their individual obligation?
R3: Needs to include verbiage for those circumstances when it would be necessary to
run AGC out of TLB such as during necessary testing. The BA should have the option
to operate out of TLB for a predetermined amount of time if needed when
notification and coordination with the RC has been established.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
Consideration of Comments: Project 2007-12 Frequency Response
61
000667
Organization
Yes or No
Question 2 Comment
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Tucson Electric Power
No
R1: TEP feels that the FRO should be able to be calculated by the BA and that Form 1
changes should be treated via the Standard drafting process.
R2: TEP feels that use Form 1 should be required by the Standard. Further, BAs
should calculate its own frequency bias setting without ERO intervention.
R3: Operating outside Tie Line Bias mode should be allowed during a year to allow
for the testing of other modes.
R4: Agree with the concept, but without ERO intervention.
R5: Should read "greater than or equal to".
Response: The FRO can be estimated by the BA but the actual BA FRO for compliance is based on the BA’s footprint and is a
function of the Interconnection FRO. Modifications to the FRS Form 1 would go through the Standard Drafting Process.
R3 - The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
R2 and R4 - The Frequency Bias Setting is calculated on FRS Form 1. The ERO is only validating the data used in the calculation.
This is a practice that exists today. History has shown that there typically are errors in the data.
R5 - The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has
Consideration of Comments: Project 2007-12 Frequency Response
62
000668
Organization
Yes or No
Question 2 Comment
modified the requirement and believes we have implemented the intent of your suggestion.
SCE&G
Affirmative
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
o We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1 o
Response: The requirement to operate AGC in Tie Line Bias mode has been removed from the standard since it was duplicative of
Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to address your concern.
The new title is, “Frequency Bias Setting Minimums”.
Bonneville Power
Administration
No
Regarding R1, BPA believes that adding additional requirements in R1 by referencing
Attachment A does not add clarity. FRO should be a calculation that the BA’s can do
themselves and included within the standard.
Can Form 1 be changed outside of the standard drafting process? BPA doesn’t
believe that Form 1 should be allowed to be changed outside of the standard
drafting process. As drafted, Requirement R1 requires Balancing Authorities or
Reserve Sharing Groups (RSGs) to achieve an annual Frequency Response
Measure (FRM) that is equal to or more negative than its Frequency Response
Obligation (FRO).
As RSGs exist today, FRM performance by an RSG is not contemplated in the
definition of FRM and appears to apply more towards 'secondary response'.
BPA recommends clarifying this concept and possibly including an example in
the background document to help explain how this would work.
Regarding R2, BPA believes each BA should be able to calculate its own frequency
bias setting without ERO validation. The standard can require the BA to use Form 1,
if the BA doesn’t use Form 1 correctly, then the BA would be in violation of the
Consideration of Comments: Project 2007-12 Frequency Response
63
000669
Organization
Yes or No
Question 2 Comment
standard.
BPA believes that R3 should include a minimal amount of time (suggesting a couple
of hours per year) to allow for testing other modes. Requirement R3 requires each
Balancing Authority not receiving Overlap Regulation Service to operate its AGC in
Tie Line Bias mode... unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area. There may be occasions in which an entity needs
to perform testing or other instances where it is necessary or desirable to operate in
a mode other than Tie Line Bias that does not qualify as an Adverse Reliability
Impact, but never the less is necessary or desired. BPA recommends including
language that would permit operation other than Tie Line Bias mode provided the
Reliability Coordinator was notified.BPA seeks clarification from the drafting team as
to whether or not there will be any conflicts between proposed Requirement R3 and
the requirements of FERC-approved regional reliability standard BAL-004-WECC-1 Automatic Time Error Correction.
BPA agrees with the concept of R4, however, BPA again disagrees with the ERO
validation of the frequency bias setting.
BPA believes that reducing frequency bias obligation is detrimental to reliability. It
seems that lowering the Minimum Frequency Bias Setting from 1% to .8% will result
in a lower response, which in turn will lower the natural frequency response. BPA
believes that over time, it would seem that this pattern would lead to poorer
response.
BPA believes that R5 should read “greater than or equal to one of the following” not
“ at least equal to”. The requirement should be a part of Form 1 or included in R2.
For variable bias, the minimum percentage should be based on the forecasted month
peak.
Response: R1 – The FRO can be estimated by the BA but the actual BA FRO for compliance is based on the BA’s footprint and is a
function of the Interconnection FRO.
Consideration of Comments: Project 2007-12 Frequency Response
64
000670
Organization
Yes or No
Question 2 Comment
Modifications the FRS Form 1 would go through the Standard Drafting Process.
The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined
term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
R2 – The SDT is interested in the use of good data for the calculations but does not believe that a BA should be penalized for minor
data errors. This is why the SDT proposes that the ERO validate the data. In addition, this process is used today.
R3 - The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
R4 – Again, this is a process that is in use today. The SDT is not proposing that the ERO modify anything, just proposing that the
ERO validate the data being supplied.
R5 - The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. However, the SDT
understands your concern with the reduction of the minimum Frequency Bias Setting affecting other performance requirements.
The process to do this is outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a
“go slow” approach to making this happen and includes checks to confirm there are not unexpected influences injected into the
CPS-related calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to make the
initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change
Consideration of Comments: Project 2007-12 Frequency Response
65
000671
Organization
Yes or No
Question 2 Comment
in minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
Manitoba Hydro
No
Regarding R1:
1. Neither R1 nor the referenced Attachment A clarifies the FRM requirements for an
RSG to comply versus a BA. In particular
(i) At p.3, Attachment A states that the ERO is responsible for “annually
assigning an FRO and Frequency Bias Setting to each BA.” No mention is made
of RSGs.
(ii) Attachment A only references RSGs in the context of reporting obligations
for Form 1 (at p.4) and
(iii) Compared to BAL-002-0 R1.1, which clearly states that the BA may elect to
fulfill its obligation through an RSG and that in such cases the RSG has the
same responsibilities as each BA (that is a participant in the RSG).
2. It should be clarified that this requirement applies to a BA, where the BA doesn’t
belong to an RSG, OR to an RSG. As it is currently drafted, the standard applies to
each BA and each RSG. It is redundant in that each BA would need to comply,
whether or not they are a member of an RSG that would also be required to comply.
Further, the NERC Glossary definition of an RSG is a group of BAs that collectively
maintain, allocate and supply operating reserves. No mention is made of the
agreement including the sharing or delegation of responsibility related to FRM.
Accordingly, the standard should only reference a BA being able to delegate
responsibility to an RSG if the RSG Agreement allows for such delegation.
3. R1 does not specify where or how the FRO is determined. Presumably this would
be determined by the ERO pursuant to Attachment A.
4. The phrase “to ensure that sufficient Frequency Response ...” should be separated
from the requirement as it is
Consideration of Comments: Project 2007-12 Frequency Response
66
000672
Organization
Yes or No
Question 2 Comment
(i) not descriptive of the required actions;
(ii) redundant with the stated purpose at the beginning of the standard. In
general, such a drafting technique should be avoided as it may allow
Responsible Entities to argue that a violation has not occurred where the
specific action that is described has not been taken, but the purpose
referenced in the requirement has been met.
Regarding R2:
1. It is not clear from R2 who determines the Frequency Bias Setting for “validation”
by the ERO and how the FBS is determined. (Presumably done by the BA in
accordance with Attachment B). Based on Background document, should refer to
those “published” by ERO. The BA’s FBS may not be validated, and may be modified
before posting.
2. Attachment B does not refer to the ERO “validating” FBS.
3. Attachment B refers to an RSG calculating FBS, but the standard does not.
Response: R1 – Comment 1 & 2 – The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes
that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
Consideration of Comments: Project 2007-12 Frequency Response
67
000673
Organization
Yes or No
Question 2 Comment
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
Comment 3 – The process for determining the FRO is detailed in Attachment A.
Comment 4 – The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your
concerns about the wording to the Standards Committee Quality Review group for consideration.
R2 – Comment 1 – The Frequency Bias Setting is calculated on FRS Form 1. The ERO is only validating the data not calculating the
setting. The ERO will be working with the BA to correct any data errors discovered during the validation process. This is a process
that is in use today
Comment 2 & 3 – The SDT has made significant modifications to the Background Document and Attachment A to provide
additional clarity. The SDT has added language to Attachment A regarding validation of the BA data. The SDT has removed all
references to a FRSG for Frequency Bias Setting. Attachment B has been removed and the information from Attachment B has
been incorporated in a Procedure developed by the SDT for the ERO to follow to support this standard.
NV Energy
No
Requirement 1 seems to be the only one that has any applicability to an RSG;
however, it is unclear under what circumstances this requirement applies to an RSG.
Suggest changing the R1 to be addressed solely to BA's or alternatively, explain
under Applicability section 1.2 what "where applicable" means.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
Consideration of Comments: Project 2007-12 Frequency Response
68
000674
Organization
Yes or No
Question 2 Comment
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
ACES Power Marketing
Standards Collaborators
No
Requirement 1 should not apply to a Reserve Sharing Group. Reserve Sharing
Groups (RSG) are designed to share Contingency Reserves and/or Operating
Reserves not Frequency Response. While these reserves may be frequency
responsive, they are not being shared for the purpose of expanding frequency
response. Furthermore, while reserve sharing groups may calculate a joint ACE by
summing its individual BA ACE values, RSGs do not have a Frequency Bias Setting
which is necessary to assess a Frequency Response Obligation.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Consideration of Comments: Project 2007-12 Frequency Response
69
000675
Organization
Yes or No
Question 2 Comment
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
City of Redding, Oregon Public
Utility Commission,
BrightSource Energy, Inc.,
Clark Public Utilities, Avista,
Tri-State G & T Association,
Inc.; Deseret Power
Negative
Requirement R3 requires each Balancing Authority not receiving Overlap Regulation
Service to operate its AGC in Tie Line Bias mode... unless such operation would have
an Adverse Reliability Impact on the Balancing Authority’s Area. There may be
occasions in which an entity needs to perform testing or other instances where it is
necessary or desirable to operate in a mode other than Tie Line Bias that does not
qualify as an Adverse Reliability Impact, but never the less is necessary or desired.
Recommend including language that would permit operation other than Tie Line Bias
mode provided the Reliability Coordinator was notified.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Alberta Electric System
Operator
No
The language used in the requirements is superfluous. This could result in confusion
and incorrect assumptions being made.
In R1, the comment within brackets “(as detailed in Attachment A and calculated on
FRS Form 1)”, is not necessary as it is already part of the FRM definition. We suggest
removing this bracketed text from the requirement.
Also in R1, the phrase “to ensure that sufficient Frequency Response is provided by
each BA or RSG to maintain an adequate level of Frequency response in the
Interconnection” is a high level objective that does not add clarity to this
requirement. We suggest removing this from the requirement.
R2, R3 and R5 use similar language e.g. “to ensure effectively coordinated Tie Line
Bias control”, “to ensure adequate control response” etc. Although it provides
background information, this does not add clarity to the requirement. We suggest
removing these from the requirements.
Response: Based on industry comments the SDT has modified the definition for FRM such that it no longer references any other
documents. Therefore, the SDT believes that leaving the reference to Attachment in the standard is prudent, based on advice
Consideration of Comments: Project 2007-12 Frequency Response
70
000676
Organization
Yes or No
Question 2 Comment
from the standards staff – without a reference to the specific Attachment, the responsible entity can’t be held to compliance with
the performance identified in that attachment.
The SDT has been instructed to include a “reliability outcome” within the requirements and therefore included the language you
are referencing. The SDT understands that this does not provide any additional clarity for complying with the requirement and
could be removed. The SDT will forward your concerns about the wording to the Standards Committee Quality Review group for
consideration.
Hydro-Quebec TransEnergie
No
The objective of R2 is that all BA’s implement their new Bias Setting at the same
time, based on the previous year’s data, so that control stays the most effective
throughout the Interconnection (Tie-Line Bias). In addition, the new Bias will be in
effect all year long. The process is quite simple and straightforward for a fixed Bias
Setting. As for Variable Bias Setting, this process is not applicable before the fact
since the Bias equation can depend on real-time values that are not known in
advance. In addition, the simultaneous Bias implementation is not an issue for a
single BA Interconnection. Therefore, we suggest that Requirement 2 applies only to
Fixed Bias Setting.
Response: The SDT agrees with your comment and has modified Requirement R2 to reflect your concern. The SDT has also added
an addition Requirement R3 to address entities using a variable Frequency Bias Setting.
Northeast Power Coordinating
Council
No
The requirements should not be directed at Balancing Authorities, as generators are
the main supplier of “discretionary” frequency response. Requirement R1 refers to
an attached form, which is not part of the standard and therefore not enforceable.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
Consideration of Comments: Project 2007-12 Frequency Response
71
000677
Organization
Yes or No
Question 2 Comment
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
If an attachment is referenced in a requirement that attachment becomes part of the requirement. The requirement has been
modified to no longer reference an attached form.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
The standard is silent on the “methods to obtain Frequency Response”. For instance,
the BA does not have authority over governor and other generator settings. There
should be a requirement for GOPs to incorporate setting changes directed by the BA,
otherwise the standard establishes requirements that BAs may not have the
authority to achieve. R1 includes the Reserve Sharing Group in its applicability, but
none of the other requirements do.
There is no consideration of "footprint" changes of the BA resulting in different
allocation from the ERO during a year. The standard and Attachments seem to
specify an annual process with due dates in December and January with no
allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance?
If the ERO does not meet its obligations, can an entity still be found non-compliant,
especially on a schedule basis? Wasn’t there an issue of assigning standards to RROs,
e.g., the fill-in-the-blank standards? Are there similar issues with assigning
requirements to the ERO? Is the ERO a “user, owner or operator” of the BPS under
Section 215, e.g., at (b)(1)”... All users, owners and operators of the bulk-power
system shall comply with the reliability standards that take effect under this section.”
I question how this would work from a compliance perspective.
On R5, the wording should be changed from “absolute value is at least equal to” to
Consideration of Comments: Project 2007-12 Frequency Response
72
000678
Organization
Yes or No
Question 2 Comment
“absolute value is greater than or equal to”
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has also included other methods that a BA can use to provide Frequency Response in the Background Document.
The SDT has added language to Attachment A to address changes in a BAs footprint.
The proposed standard is not putting a requirement on the ERO. There is language in the Attachments to provide additional time
for a BA to become compliant if the ERO is late in providing the necessary information. If the ERO does not provide the necessary
information then the BA would not be required to modify anything and therefore the last information provided would be that
which would be used for compliance purposes.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
South Carolina Electric and
Gas
No
The utilization of the term, “Reserve Sharing Group”, is not consistent with the
definition in the NERC Glossary of Terms, and should be deleted, applicability should
be clarified or replaced with a new term, such as “Frequency Response Sharing”.
Consideration of Comments: Project 2007-12 Frequency Response
73
000679
Organization
Yes or No
Question 2 Comment
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
Tri-State G & T Association,
Inc.; Tucson Electric Power
Co.; U.S. Army Corps of
Engineers; South California
Edison ; Platte River Power
Authority; Pacific Gas and
Electric Company; Colorado
Springs Utilities; Idaho Power
Negative
We believe that there are several modifications that, if implemented to the existing
requirements, would result in an improved, clarified standard.
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly including an example in the background
Consideration of Comments: Project 2007-12 Frequency Response
74
000680
Organization
Yes or No
Company; California Energy
Commission; California ISO;
Deseret Power
Question 2 Comment
document to help explain how this would work.
Requirement R3 requires each Balancing Authority not receiving Overlap Regulation
Service to operate its AGC in Tie Line Bias mode... unless such operation would have
an Adverse Reliability Impact on the Balancing Authority’s Area. There may be
occasions in which an entity needs to perform testing or other instances where it is
necessary or desirable to operate in a mode other than Tie Line Bias that does not
qualify as an Adverse Reliability Impact, but never the less is necessary or desired.
Recommend including language that would permit operation other than Tie Line Bias
mode provided the Reliability Coordinator was notified. We seek clarification from
the drafting team as to whether or not there will be any conflicts between proposed
Requirement R3 and the requirements of FERC-approved regional reliability standard
BAL-004-WECC-1 - Automatic Time Error Correction.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
Consideration of Comments: Project 2007-12 Frequency Response
75
000681
Organization
Yes or No
Question 2 Comment
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
ISO New England Inc
No
We do not agree with placing a requirement on Balancing Authorities, as generators
are the main supplier of “discretionary” frequency response. Also, the requirement
refers to an attached form, which is not part of the standard and therefore not
enforceable.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
If an attachment is referenced in a requirement that attachment becomes part of the requirement. However the requirement has
been modified to no longer reference an attached form.
SERC OC Standards Review
Group
No
We feel that the utilization of the term, “Reserve Sharing Group”, is not consistent
with the definition in the NERC Glossary of Terms, and should be deleted,
applicability should be clarified or replaced with a new term, such as “Frequency
Response Sharing”.
R2 exempts BAs participating in Overlap Regulation Service from implementing the
Frequency Bias Setting on the date specified by the ERO, and R4 states how the BA
Consideration of Comments: Project 2007-12 Frequency Response
76
000682
Organization
Yes or No
Question 2 Comment
performing Overlap Regulation Service will modify its Frequency Bias Setting but
does not state when the setting will be implemented. The exemption for BAs
participating in Overlap Regulation Service should either be deleted from R2 or
language stating the implementation date of the frequency bias setting needs to be
included in R4.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has modified the language in Requirement R2. The term “not participating in” has be replace with “not receiving”. This
now encompasses entities that are providing Overlap Regulation Service.
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
Consideration of Comments: Project 2007-12 Frequency Response
77
000683
Organization
Yes or No
Florida Municipal Power
Agency/JEA Electric
Compliance
No
Question 2 Comment
We thank the SDT for their hard work and diligence in moving this Project forward.
However, we have some concerns that cause us to not support the standard in its
current form.
In general, we believe that there has not been sufficient prudency review for the
standard, especially R1, to justify a performance based standard around a Frequency
Response Measure.
We also believe that the proposed standard does not meet all of the conditions of
the Final SAR and Supplemental SAR.The “Final SAR” was to develop methods by
which a performance based standard would eventually be developed. The Final SAR
states:”The proposed standard’s intent is to collect data needed to accurately model
existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed
reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be modeled,
and the reasons for the decline in Frequency Response can be identified. Once
thereasons for the decline in Frequency Response are confirmed, requirements can
be written to control Frequency Response to within defined reliability
parameters.”BAL-003-1 does not seem to complete the scope of this “Final SAR”. For
instance, “the reasons for the decline in Frequency Response” were not confirmed to
our knowledge; and the field trial is not completed to our knowledge.The
Supplemental SAR adds to the scope of the Final SAR:”To provide a minimum
Frequency Response Obligation for the Balancing Authority to achieve, methods to
obtain Frequency Response and provide a consistent method for calculating the
Frequency Bias Setting for a Balancing Authority. In addition, the standard will
specify the optimal periodicity of Frequency Response surveys.”The Supplemental
SAR does not eliminate the pre-requisite contained in the Final SAR to determine the
reasons for the decline in frequency response and confirm them before establishing
“defined reliability parameters”.
In addition, the standard does not complete the requirement of the Supplemental
Consideration of Comments: Project 2007-12 Frequency Response
78
000684
Organization
Yes or No
Question 2 Comment
SAR to identify “methods to obtain Frequency Response”. For instance, neither the
BA nor the RSG have authority over governor and other generator settings. There
should be a requirement for GOPs to incorporate setting changes directed by the BA,
otherwise the standard establishes requirements that BAs and RSGs may not have
the authority to achieve.
There is no consideration of "footprint" changes of the BA resulting in different
allocation from the ERO during a year. The standard and Attachments seem to
specify an annual process with due dates in December and January with no
allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance?
If the ERO does not meet its obligations, can an entity still be found non-compliant,
especially on a schedule basis? Wasn’t there an issue of assigning standards to RROs,
e.g., the fill-in-the-blank standards? Are there similar issues with assigning
requirements to the ERO? Is the ERO a “user, owner or operator” of the BPS under
Section 215, e.g., at (b)(1)”... All users, owners and operators of the bulk-power
system shall comply with the reliability standards that take effect under this section.”
We question how this would work from a compliance perspective.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
The SDT agrees that the original SAR was strictly for data collection. However, a supplemental SAR was developed to address the
FERC March 18, 2010 Order and was subsequently approved by the industry. The Standards Committee has determined that a
proposed standard must be within the scope of the approved SAR but the proposed standard is not required to address the full
scope of the SAR if stakeholders support a reduced scope.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
79
000685
Organization
Yes or No
Question 2 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has also included other methods that a BA can use to provide Frequency Response in the Background Document.
The SDT has added language to Attachment A to address changes in a BA’s footprint.
The proposed standard is not putting a requirement on the ERO. There is language in the Attachments to provide additional time
for a BA to become compliant if the ERO is late in providing the necessary information. If the ERO does not provide the necessary
information then the BA would not be required to modify anything and therefore the last information provided would be that
which would be used for compliance purposes.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Florida Power & Light
Company
Yes
Independent Electricity
Yes
Consideration of Comments: Project 2007-12 Frequency Response
80
000686
Organization
Yes or No
Question 2 Comment
System Operator
Associated Electric
Cooperative Inc
Yes
Cleco Corporation
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
81
000687
3.
The SDT has developed VRFs for the proposed Requirements within this standard. Do you agree that these VRFs are
appropriately set? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters agreed with the VRFs that the SDT has proposed for the requirements within
the standard.
One commenter felt the VRFs were too high and that they should have a “lower” VRF. The SDT developed the VRFs using the NERC
Violation Risk Factor guidelines approved by FERC. A lower VRF is an administrative type of requirement that, if violated would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor and control
the bulk electric system; or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect
the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. Violation of any of the requirements in the proposed standard could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Another commenter stated that they could not fine the “Risk Severity Levels” in the standard. The SDT is not sure as to the meaning of
this comment. The SDT believes that the commenter may have been mixing two different terms, Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs). The question asked by the SDT was concerning the VRFs. These are located within the body of the
Requirement. The VSLs are located towards the end of the proposed standard.
Organization
Yes or No
Seattle City Light
Negative
Question 3 Comment
Answer: Yes. Comments: LADWP and SCL agree with the following VRFs: - R1 Medium - R2 - Medium - R3 - Medium - R4 - Medium - R5 - Medium
Response: The SDT thanks you for your clarifying comment.
Energy Mark, Inc.
No
Comment 5: See comments in the non-binding poll.
Response: Please see our response to your comments from the non-binding poll.
Florida Power & Light
Company
No
Could not find the Risk Severity Levels in the documents.
Consideration of Comments: Project 2007-12 Frequency Response
82
000688
Organization
Yes or No
Question 3 Comment
Response: The SDT is not sure as to the meaning of your comment. The SDT believes that you may be mixing two different terms,
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs). The question asked by the SDT was concerning the VRFs. These
are located within the body of the Requirement. The VSLs are located towards the end of the proposed standard.
Cleco Corporation
No
Please note Cleco does not use the VRFs therefore we feel too much energy and time
is spent on the VRFs. The SDT needs to concentrate on the requirements and
measurements.
Response: The SDT thanks you for your clarifying comment.
Ameren
No
This is problematic since for a single BA interconnection these could be argued to be
appropriate VRFs, but is different for a multiple BA interconnection, where the risk
that a single BA would pose to the interconnection would be Lower.
Response: The SDT developed the VRFs using the NERC Violation Risk Factor guidelines approved by FERC. This document can be
found at http://www.nerc.com/files/Violation_Risk_Factors.pdf. IA lower VRF is an administrative type of requirement that, if
violated not be expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system; or, a requirement that is administrative in nature and a requirement in a planning time
frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control,
or restore the bulk electric system. Violation of any of the requirements in the proposed standard could directly affect the electrical
state or the capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Seattle City Light/Los Angeles
Department of Water and
Power
Yes
LADWP and SCL agree with the following VRFs:- R1 - Medium- R2 - Medium- R3 Medium- R4 - Medium- R5 - Medium
Response: The SDT thanks you for your affirmative response and clarifying comment.
NV Energy
Yes
Medium appears to be reasonable and appropriate.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Consideration of Comments: Project 2007-12 Frequency Response
83
000689
Organization
Yes or No
Bonneville Power
Administration
Yes
Imperial Irrigation District
Yes
Northeast Power Coordinating
Council
Yes
MRO NSRF
Yes
SERC OC Standards Review
Group
Yes
SPP Standards Review Group
Yes
ISO/RTO Council Standards
Review Committee
Yes
ACES Power Marketing
Standards Collaborators
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Southern Company
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 3 Comment
84
000690
Organization
Yes or No
ISO New England Inc
Yes
Tucson Electric Power
Yes
Independent Electricity
System Operator
Yes
Associated Electric
Cooperative Inc
Yes
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
Manitoba Hydro
Yes
Constellation Energy
Commodities Group
Yes
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Duke Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 3 Comment
85
000691
4.
The SDT has developed Measures for the proposed Requirements within this standard. Do you agree with the proposed
Measures in this standard? If not, please explain in the comment area.
Summary Consideration: Many of the commenters were concerned with the language in Requirement R3 stating that an entity had to
be operating in Tie Line Bias mode unless there were adverse affects on the BES and that if the requirement was modified that the
measure should be modified. The SDT explained that it had removed this requirement from the proposed standard since they felt it was
duplicative of Requirement R6 and R7 in BAL-005-0.1b.
Some commenters objected to the definition for FRM and the Measure referencing another document (FRS Form 1). The SDT explained
that it modified the definition for FRM to no longer reference another document. The revised definition reads “The median of all the
Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO. This will be
calculated as MW/0.1Hz.”
A couple of the commenters had concerns with Requirement R5 in that it should reference “natural Frequency Response” as a third
bullet. The SDT has explained that it removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The
SDT did not include the term “natural Frequency Response” within the standard itself but included it in the Background Document and
Attachment A. The SDT felt that this provided additional clarity within the requirement and allowed for further explanation of the term
in the Background Document and Attachment A.
Some commenters indicated that the use of an RSG as a method for supplying Frequency Response was not fully explained. The SDT
modified the Background Document to further explain how an RSG (now FRSG) could be used to supply Frequency Response. The SDT
has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve
Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities
that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response Obligations of its
members.”
A couple commenters wanted the sampling interval to be tuned on a per Interconnection basis to support HQTE’s characteristics. The
SDT agreed and explained that it adjusted the event selection criteria to address concerns related to response driving frequency back to
pre-event level during the B value measurement period and this adjustment should address their concern.
Organization
Yes or No
Consideration of Comments: Project 2007-12 Frequency Response
Question 4 Comment
86
000692
Organization
Yes or No
Seattle City Light
Negative
Question 4 Comment
Answer: No. Comments: LADWP and SCL recommend that the Measures for
Requirement 3 and Requirement 5 reflect their comments to Question 2.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Constellation Energy
Commodities Group
No
Based on language modifications proposed to the Requirements, the measures
should be revisited.
Response: The SDT has revised the Measures to align with modifications made to the Requirements.
Xcel Energy
No
Based on our suggested changes to R3 in response to Question 2, the drafting team
should modify M3 to be consistent with the proposed language.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
MRO NSRF
No
Based on suggested changes to R3 in response to Question 2, the drafting team
should modify M3 to be consistent with the proposed language.
Additionally, M1 should be revised to not reference a specific Form. The Form may
be the format of choice but it should not be an implied requirement.
Measures 3 and 4 identify the use of “operating logs” as evidence. Measure 2
identifies hard copy and electronic evidence, “or other evidence”. We suggest calling
out specifically “operator logs” for M2 also, in case there are system problems in
capturing hard copy or electronic evidence during the short time window for
implementation.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has modified Measure M1 which no longer references a form but does reference Attachment A to align with the
requirement.
Consideration of Comments: Project 2007-12 Frequency Response
87
000693
Organization
Yes or No
Question 4 Comment
The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be used as long
as it reflects compliance with the standard.
Bonneville Power
Administration
No
BPA believes that historian data should be able to be used for evidence.
Response: The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be
used as long as it reflects compliance with the standard. The SDT believes that the data from the software program “Historian”
could be used to demonstrate compliance..
Manitoba Hydro
No
It should be clarified that R1 requirement applies to a BA, where the BA doesn’t
belong to an RSG, or to an RSG. As it is currently drafted, the standard applies to
each BA and each RSG. It is redundant in that each BA would need to comply,
whether or not they are a member of an RSG that would also be required to comply.
Further, the NERC Glossary definition of an RSG is a group of BAs that collectively
maintain, allocate and supply operating reserves. No mention is made of the
agreement including the sharing or delegation of responsibility related to FRM.
Accordingly, the standard should only reference a BA being able to delegate
responsibility to an RSG if the RSG Agreement allows for such delegation.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has modified the Applicability Section to clarify when a BA or FRSG is accountable for compliance.
The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined
term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Tucson Electric Power
No
It should be clear that historical data may be used to show compliance.
Response: The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be
used as long as it reflects compliance with the standard. The SDT believes that the data used to reflect compliance would have to
Consideration of Comments: Project 2007-12 Frequency Response
88
000694
Organization
Yes or No
Question 4 Comment
be historical data.
Seattle City Light/ Los Angeles
Department of Water and
Power
No
LADWP and SCL recommend that the Measures for Requirement 3 and Requirement
5 reflect their comments to Question 2.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
ISO/RTO Council Standards
Review Committee
No
M1: The measure should not be tied to a specific Form. If a BA has the evidence but
does not provide it on a given Form, how is the reliability of the Power System
impacted? The Form may be the format of choice but it should not be an implied
requirement.
M4: This measure does not read quite right. Something seems to be missing in the
part that says: “...showing when Overlap Regulation Service is provided including
Frequency Bias Setting calculation to demonstrate compliance with Requirement R4.”
This part might have read something like: “...showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation or it
calculated the Frequency Bias Setting meeting the conditions specified in
Requirement R4.”
Response: The SDT has modified Measure M1 which no longer references a form, however it does reference Attachment A to align
with the associated requirement.
The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be used as
long as it reflects compliance with the standard.
The SDT has modified the Measure M4 to incorporate your suggested wording.
Independent Electricity
No
M4: This measure does not read quite right. Something seems to be missing in the
Consideration of Comments: Project 2007-12 Frequency Response
89
000695
Organization
Yes or No
System Operator
Question 4 Comment
part that says: “...showing when Overlap Regulation Service is provided including
Frequency Bias Setting calculation to demonstrate compliance with Requirement R4.”
This part might have read something like: “...showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation or it
calculated the Frequency Bias Setting meeting the conditions specified in
Requirement R4.”
Response: The SDT has modified the Measure M4 to incorporate your suggested wording.
ERCOT
No
Measure should be modified to align with revised Requirements per ERCOT’s
comments on #1.
Response: The SDT has modified the Measures to align with the modifications to the Requirements.
SERC OC Standards Review
Group/ Progress Energy/
South Carolina Electric and
Gas/ Duke Energy
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
Response: Please see our response to your comments on Question 2 regarding “Reserve Sharing Group”.
Northeast Power Coordinating
Council/ISO New England Inc.
No
The sampling interval needs to be tuned on a per Interconnection basis to support
HQTE’s characteristics.
Response: The SDT adjusted the event selection criteria to address concerns related to response driving frequency back to preevent level during the B value measurement period. We believe that this adjustment addresses your concern.
Florida Power & Light
Company
No
What is meant by documented formulae for M5? Is a one time snapshoot of the AGC
formual sufficien? The concept is ok but this needs clarification of proof.
Response: The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Consideration of Comments: Project 2007-12 Frequency Response
90
000696
Organization
Yes or No
Southwest Power Pool
Regional Entity
Yes
Question 4 Comment
Measures are more specific and measurable than seen in the past. This is a positive
improvement.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Ameren
Yes
With the understanding that any suggested changes to the proposed requirements
would come with corresponding changes to their measure.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT agrees that any modification to a
Requirement would necessitate a re-evaluation of the corresponding Measure.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
Associated Electric
Cooperative Inc
Yes
NV Energy
Yes
Cleco Corporation
Yes
Consideration of Comments: Project 2007-12 Frequency Response
91
000697
Organization
Yes or No
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 4 Comment
92
000698
5.
The SDT has developed VSLs for the proposed Requirements within this standard. Do you agree with these VSLs? If not, please
explain in the comment area.
Summary Consideration: Most of the commenters indicated that VSLs for Requirement R1 should not include language tied to whether
or not a BA is in a single BA Interconnection or a multi-BA Interconnection. Frequency Response is an Interconnection-wide resource.
The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections. Consider a small BA
whose performance is 70% of its’ FRO. If all other BAs in the Interconnection are compliant, the small BA’s performance has negligible
impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not
rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would
treat multi-BA Interconnections tens of times more harshly than single BA Interconnections. However, the SDT has added language to
the requirement to reference the Interconnection Frequency Response Obligation.
Several commenters did not agree with the VSLs for Requirement R3. The SDT removed Requirement R3 from the revised standard
since the requirement was duplicative of Requirement R6 & R7 in BAL-005-0.1b.
With concerns about the use of the RSG as a means to provide Frequency Response, the SDT modified the Background Document to
further explain how an RSG (now FRSG) could be used to supply Frequency Response. The SDT has defined a new term “Frequency
Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve Sharing Group” could cause
confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities that collectively maintain,
allocate, and supply operating resources required to jointly meet the Frequency Response Obligations of its members.”
Organization
Yes or No
Seattle City Light
Negative
Question 5 Comment
Answer: No. Comments: LADWP and SCL recommend that either the VSL for
Requirement 3 reflects its comments to Question 2, or that these comments be
addressed as an exception in the Measure for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
Consideration of Comments: Project 2007-12 Frequency Response
93
000699
Organization
Yes or No
Question 5 Comment
with R6 and R7 in BAL-005-0.1b.
Public Utility District No. 1 of
Douglas County
Negative
1. The BA and interconnection meet the FRO differently. Suggest removing the
interconnection performance from the VSL and develop additional levels of BA
failure to meet its FRO.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
BrightSource Energy, Inc.
Negative
The negative vote from BrightSource is related to the proposed VSL only. The
proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO. Conforming changes
to the VSLs would need to be made for any changes to the Requirements as
suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
Consideration of Comments: Project 2007-12 Frequency Response
94
000700
Organization
Yes or No
Question 5 Comment
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of its FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
U.S. Army Corps of Engineers;
Platte River Power Authority;
Pacific Gas and Electric
Company; Idaho Power
Company; Colorado Springs
Utilities; California Energy
Commission; California ISO;
Clark Public Utilities; Tucson
Electric Power Co.; Tri-State G
& T Association, Inc.
Negative
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO. Conforming changes
to the VSLs would need to be made for any changes to the Requirements as
suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Consideration of Comments: Project 2007-12 Frequency Response
95
000701
Organization
Yes or No
Question 5 Comment
Negative
The VSL for Requirement 3 does not sufficiently reflect a thoughtful range of
violation severity of duration or number of instances by which AGC is not in Tie-Line
Bias mode.
Obligation.
Kansas City Power & Light Co.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 and R7 in BAL-005-0.1b.
ACES Power Marketing; East
Kentucky Power Coop.;
Hoosier Energy Rural Electric
Cooperative, Inc.
Negative
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
performance.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
Southwest Transmission
Cooperative, Inc.
Negative
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
Consideration of Comments: Project 2007-12 Frequency Response
96
000702
Organization
Yes or No
Question 5 Comment
performance. The proposed VSLs for Requirement R1 treats a BA that did not meet
the FRO requirement differently depending on whether or not the Interconnection
met the FRO requirement. The obligation of the BA to meet its allocated FRO
should be consistent regardless of what the other entities within the
interconnection are doing. Suggest removing the interconnection performance
from the VSLs and developing four increasing levels of BA failure to meet its FRO.
Conforming changes to the VSLs would need to be made for any changes to the
Requirements as suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of its FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Western Area Power
Administration
Negative
Under compliance for R1, there is a difference between VSL levels whether the
interconnection met is FRO or not. If the interconnection meets it’s FRO but a single
BA doesn't’t meet its share of FRO the violation is considered low VSL, but, if the
interconnection dosen't’t meet it’s FRO the same BA will have a High VSL.
Obligation of the individual BA to meet its allocated FRO should always be
applicable regardless of what other BAs are doing in the interconnection. This
provision creates a disparity amongst BAs and creates a disparate treatment
between the BAs who perform compared to those who don’t.
Response: The drafting team does not agree, but believes an explanation would be helpful.
Consideration of Comments: Project 2007-12 Frequency Response
97
000703
Organization
Yes or No
Question 5 Comment
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Ameren Services; Ameren
Energy Marketing
Co./Ameren
Negative/No
It is not clear how the VSL for R1 uses the "Summation of the BA's FRM", when the
requirement is BA or RSG specific.
Response: Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing
Group (FRSG). FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Manitoba Hydro
Negative/No
The Violation Severity Levels for R1 penalize entities more severely depending on
how the interconnection as a whole has performed. MH believes that BAs should
only be held accountable for issues within their control and that the VSLs for R1
should be revised accordingly.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
98
000704
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small
BA’s performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for
its entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
Constellation Energy
Commodities Group
No
The language in the VSLs for R1 should be revisited based on the proposed
language modifications above and should also clearly look to the FRM of a BA,
group of BAs or RSG against the BA FRO not an Interconnection FRO.
Response: The drafting team has made conforming changes to VSLs based on wording changes to the Requirements.
Regarding the evaluation of the Interconnection, the drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing Group (FRSG).
FRSG performance may be calculated on one of two ways:
Consideration of Comments: Project 2007-12 Frequency Response
99
000705
Organization
Yes or No
Question 5 Comment
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Bonneville Power
Administration
No
BPA believes that R1 needs to be more clear and concise as to what is being
conveyed in the requirement. It is difficult to understand. The proposed VSLs for
Requirement R1 treats a BA that did not meet the FRO requirement differently
depending on whether or not the Interconnection met the FRO requirement. The
obligation of the BA to meet its allocated FRO should be consistent regardless of
what the other entities within the interconnection are doing. Suggest removing the
interconnection performance from the VSLs and developing four increasing levels
of BA failure to meet its FRO.BPA believes that conforming changes to the VSLs
would need to be made for any changes to the Requirements as suggested in the
comments to the standard.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. We would welcome suggested
wording changes that relay this concept more clearly.
With regard to removing a view of Interconnection performance, the drafting team does not agree, but believes an explanation
would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Consideration of Comments: Project 2007-12 Frequency Response
10
0
000706
Organization
Yes or No
Question 5 Comment
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Florida Power & Light
Company
No
For R1 the low and high level descriptions appear to be identical and the high level
is less than the medium risk level.
For R3 there should be low, medium, and high levels. One BA not operating to TLB
does not jepordize the Interconnection. Additionally, computer failures, database
loads etc may require some period where TLB is not in service. Suggestion would
be Lower VSL operation off of TLB for more than 5 but < 8 continuous hours or
accumlative during the year of more than 8 < 16 hours. Medium VSL would be
operation off of TLB for more than 8 but <16 continuous hours or accumlative
during the year of more than 16 <24 hours. High VSL would be operation off of TLB
for more than 16 <24 continuous hours or accumlative during the year of more
than 36 <48 hours. Severe VLS would be >24 continuous hours off of TLB or
accumlative of > 48.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added
language to the requirement to reference the Interconnection Frequency Response Obligation.
Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative with R6 and
R7 in BAL-005-0.1b.
NV Energy
No
For R1, suggest that the VSL's not be dependent upon the aggregate performance
of the BA's within an interconnection.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
1
000707
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
American Electric Power
No
It is not clear for R1 what the exact delineations are among Lower, Medium, High,
and Severe VSL’s.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added
language to the requirement to reference the Interconnection Frequency Response Obligation.
Seattle City Light
No
LADWP and SCL recommend that either the VSL for Requirement 3 reflects its
comments to Question 2, or that these comments be addressed as an exception in
the Measure for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 andR7 in BAL-005-0.1b.
Los Angeles Department of
Water and Power
No
LADWP recommends that either the VSL for Requirement 3 reflects its comments to
Question 2, or that these comments be addressed as an exception in the Measure
for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 and R7 in BAL-005-0.1b.
ReliabilityFirst
No
ReliabilityFirst thanks the SDT for their effort on this project. ReliabilityFirst has a
number of concerns/questions related to the draft BAL-003-1 VSLs which include
Consideration of Comments: Project 2007-12 Frequency Response
10
2
000708
Organization
Yes or No
Question 5 Comment
the following:
1. General VSL Comment - For consistency with other standards, each VSL should
begin with the phrase “The Responsible Entity...” or “The Balancing Authority”. This
is consistent with the language of the requirement and correctly pinpoints the
appropriate responsible entity.
2. VSL R1 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:a. Lower VSL - The Responsible
Entity achieved an annual FRM within an Interconnection that was equal to or more
negative than the Interconnection’s FRO and the Responsible Entity’s FRM was less
negative than its FRO by more than 1% but by at most 30% or 15 MW/0.1 Hz,
whichever one is the greater deviation from its FROb. Medium VSL - The
Responsible Entity achieved an annual FRM within an Interconnection that was
equal to or more negative than the Interconnection’s FRO and the Responsible
Entity’s FRM was less negative than its FRO by more than 30% or by more than 15
MW/0.1 Hz, whichever one is the greater deviation from its FROc. High VSL - The
responsible entity failed to achieve an annual FRM that is equal to or more negative
than its FRO and the Responsible Entity’s, FRM was less negative than its FRO by
more than 1% but by at most 30% or 15 MW/0.1 Hz, whichever one is the greater
deviation from its FROd. Severe VSL - The responsible entity failed to achieve an
annual FRM that is equal to or more negative than its FRO and the Responsible
Entity’s FRM was less negative than its FRO by more than 30% or by more than 15
MW/0.1 Hz, whichever one is the greater deviation from its FRO3.
VSL R4 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:
a. Example for Lower VSL which should be carried throughout all four VSLs - The
Balancing Authority incorrectly modified the Frequency Bias Setting value used in
its ACE calculation when providing Overlap Regulation Services with combined
Consideration of Comments: Project 2007-12 Frequency Response
10
3
000709
Organization
Yes or No
Question 5 Comment
footprint setting-error less than 5% of the validated or calculated value4.
VSL R5 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:
a. Example for Lower VSL which should be carried throughout all four VSLs - The
Balancing Authority used a monthly average Frequency Bias Setting whose absolute
value was less than or equal to 5% below the minimum specified by the ERO.
Response: While there may be a better way to lay out the VSL, the VSL for R1 is consistent with R1 in that performance can be
reported either as a single BA or as an RSG. The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection
does not meet the FRO and assesses sanctions based on whether the BA is deficient by a small or larger amount respectively.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
The drafting team has modified the VSLs for R4 based on your comments. The SDT removed Requirement R5 and combined it into
revised Requirement R2 and new Requirement R3.
Progress Energy / South
Carolina Electric and
Gas/Duke Energy
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
Response: Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing
Group (FRSG).
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine how
to allocate sanctions among its members. This standard does not mandate the formation of FRFSGs, but allows them as a means to
meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Consideration of Comments: Project 2007-12 Frequency Response
10
4
000710
Organization
Yes or No
Question 5 Comment
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
SERC OC Standards Review
Group
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
VSL for R1:The draft VSLs for R1 uses the summation of FRM for all BAs within an
Interconnection as a factor in determining the applicable VSL. This does not seem
consistent with R1. R1 is about a single BA and the individual BA’s frequency
response performance as measured by the FRM for that specific BA. Including the
FRM summation of the Interconnection expands R1. It appears that a BA that is
non-compliant with R1 could end up with either a Low/Medium or High/Severe VSL
based upon the FRO performance of the Interconnection. The FRM performance of
the Interconnection is beyond the knowledge and control of a single BA and should
not be a determinate of the applicable VSL.Is there a technical basis for selection of
the 1%, 30% and 15MW/.1 Hz VSL breakpoints? Does the Lower VSL give a 1% dead
band to a BA’s FRO? If so, will this be acceptable to NERC/FERC?
VSL for R2:The VSL should reflect the language used in the requirement. R2 says a
BA “not participating in Overlap Regulation service shall ....”, while the VSL says a
BA “not receiving Overlap Regulation Service.....” The VSL language is not
consistent with the requirement.
VSLs for R5:Since Frequency Bias Setting is expressed as a negative value, the terms
“absolute value” and “less than” must be used carefully. Wouldn’t the “absolute
value” of a BA’s Frequency Bias Setting always be positive and thus it could never
be less than the minimum specified by the ERO (a negative value)?
Response: With regard to R1, VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended
to measure a violation’s impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide
resource. The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
5
000711
Organization
Yes or No
Question 5 Comment
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Regarding the 1%, 30% and 15MW breakpoints, the 1% value accommodates rounding error. The 30% or 15MW/0.1Hz is intended to
comparably address both large and small BAs. The drafting team used its judgment in selecting these values and cannot predict what
the FERC might accept.
The SDT has modified the VSLs for Requirement R2 to correctly match the requirement.
The SDT has removed Requirement R5 from the proposed standard and combined it into Requirements R2 and R3. Requirement R2
no longer references “absolute value” and Requirement R3 references “absolute value” only as a comparison to another “absolute
value”.
Western Electricity
Coordinating Council
No
The proposed VSLs for Requirement R1 treat a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
Consideration of Comments: Project 2007-12 Frequency Response
10
6
000712
Organization
Yes or No
Question 5 Comment
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response.
To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
JEA Electric Compliance/ MRO
NSRF
No
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
7
000713
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response.
To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Northeast Power
Coordinating Council
No
The violation severity levels for R1 are reasonable. The technical writing needs to
be enhanced for clarity.
Response: Thank you for the comment. The drafting team will look at ways to clarify the wording or provide an explanation in
the Background Document.
ISO New England Inc
No
The violation severity levels for R1 seem to be reasonable. However, the technical
writing needs to be enhanced for clarity
Response: Thank you for the comment. The drafting team will look at ways to clarify the wording or provide an explanation in the
Background Document.
SPP Standards Review
Group/Cleco Corporation
No
The VSLs for R2 are based on 5, 15 and 25 days. What was the justification for these
values? Could we just as well use 10, 20 and 30 or some other set of values?
In R3, we understand that brief periods of operation outside of TLB control are
allowable providing 1) continued operation in TLB control would create ARI on the
Interconnection or 2) that justification is provided for the periods when TLB is not
used. For example, if something happens within our EMS that disables TLB control
Consideration of Comments: Project 2007-12 Frequency Response
10
8
000714
Organization
Yes or No
Question 5 Comment
are we compliant if we document the period as an EMS malfunction?
Response: Regarding R2, the time windows were based on judgment of the drafting team. Similar to the commenters’ question,
the team could have chosen 1, 7, 14 and 28 days or 1, 2, 3 or 4 days to frame the four levels of VSLs. The SDT has modified
Attachment A to allow an implementation window of 3 days for implementation of the Frequency Bias Setting.
With regard to R3, the drafting team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL-005-0.1b.
ACES Power Marketing
Standards
Collaborators/Great River
Energy
No
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
performance.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Southern Company
No
VSL for R2:We suggest the language in the VSL be consistent with the language
Consideration of Comments: Project 2007-12 Frequency Response
10
9
000715
Organization
Yes or No
Question 5 Comment
used in the Requirement. The VSL for R2 says a BA ‘not receiving Overlap
Regulation Service.......’ R2 says a BA ‘not participating in Overlap Regulation service
shall .......’
VSLs for R5:Since Frequency Bias Setting is expressed as a negative value, the terms
“absolute value” and “less than” must be used carefully. This VSL uses “absolute
value” when referring to the BA’s Frequency Bias Setting, but does not use
“absolute value” when referring to the Frequency Response Obligation, or
minimum value specified by the ERO. Consider revising this VSL so that a true
comparison can be made.
Response: We agree with your suggested change for the VSL for R2 and corrected the mismatch between the requirement and
the VSLs.
The SDT has removed Requirement R5 from the proposed standard and combined it into Requirements R2 and R3. Requirement R2
no longer references “absolute value” and Requirement R3 references “absolute value” only as a comparison to another “absolute
value”.
Tucson Electric Power
No
VSL's could be clearer and simpler. Allowance for the testing of other AGC modes
should be considered.
Response: The drafting team has made changes to VSLs based on specific suggestions. Regarding AGC operation, the drafting
team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL-005-0.1b.
Southwest Power Pool
Regional Entity
Yes
Hard to follow the language for the VSL for R1. Suggest using formulas for ease of
interpretation or provide an example in the Supporting Documentation.
Response: The drafting team will provide an explanation in the Background Document.
Associated Electric
Cooperative Inc
Yes
The VSLs appear reasonable for the risk and particularly where they assess higher
severity when the BA or RSG Interconnection's performance was sub-standard as
well.
Consideration of Comments: Project 2007-12 Frequency Response
11
0
000716
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment.
ISO/RTO Council Standards
Review Committee
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should
have been “...Reserve Sharing Group’s...”. Alternatively, the wording after
“interconnection’s FRO” could be revised to: “...and the Balancing Authority’s or the
Reserve Sharing Group’s FRM was...”
Response: The drafting team agrees and has made this change.
Independent Electricity
System Operator
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should
have been “...Reserve Sharing Group’s...”. Alternatively, the wording after
“interconnection’s FRO” could be revised to: “...and the Balancing Authority’s or the
Reserve Sharing Group’s FRM was...”
Response: The drafting team agrees and has made this change.
Texas Reliability Entity
Yes
We suggest that the Severe VSL for R3 is confusing and should be clarified as
follows: “A Balancing Authority not receiving Overlap Regulation service failed to
operate AGC in Tie Line Bias mode, when operation in Tie Line Bias mode would not
have had an Adverse Reliability Impact on the Balancing Authority’s Area.”
Response: Regarding AGC operation, the drafting team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL005-0.1b.
Imperial Irrigation District
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
11
1
000717
Organization
Yes or No
Xcel Energy
Yes
Hydro-Quebec TransEnergie
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 5 Comment
11
2
000718
6.
The SDT divided the previously posted “Attachment A – Background Document” into two documents to provide additional
clarity. The first document “Attachment A- Supporting Document” which details the methods used to develop the events to be
analyzed, the FRO, FRM and Frequency Bias Setting. Do you agree that the revised Attachment A – Supporting Document
provides sufficient clarity on the methodologies to be used? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters pointed out that there was a discrepancy between Attachment A and
the Background Document concerning the methodology used to calculate FRO. The SDT addressed the discrepancy between the
two documents to ensure that historical data is used for the allocation of an Interconnection Frequency Response Obligation to
the BAs within that Interconnection.
Several of the commenters indicated that the proposed standard did not provide a limit on the amount of Frequency Response
that a BA was supposed to provide. The SDT added Paragraph #8 in Attachment A under the Event Selection Criteria to clarify
that events greater than the limit in the criteria would be capped at a certain limit. This translates to a maximum expectation of
Frequency Response equal to a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Some commenters were confused about the intent of Attachment A. They indicated that Attachment A was describing both a
methodology to select events and providing a background for the process (not a process/methodology). The intent of
Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain date and to have the
BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that provides at least the
response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the process. The
drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
As to the use of the term “may” in the attachment, at this time the drafting team is unable to further restrict the language due to
the issues surrounding an individual event. As an example, frequency is scheduled at 60 Hz most of the time. However, when
viewed on a graph or an EMS screen, it rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005.
The drafting team is unable to say at this time that an event that starts with frequency at 60.005 is materially different than an
event that starts at 59.995. Therefore, the drafting team has attempted to put guidance into the document as to what is pertinent
without attempting to be overly restrictive in the selection criteria since there is no support for a restriction at this time. As more
experience is gained, the process should be refined. If the refinement is significant enough to require a change to the Attachment
A language, the process required to do so would be open to participation of industry and not done without public exposure.
Consideration of Comments: Project 2007-12 Frequency Response
11
3
000719
A couple of commenters said that using older data for compliance could cause an entity to be in “double jeopardy”. The SDT
discussed the concern of double jeopardy several times. At this time, the drafting team believes the issue of noise in individual
events and the convergence of measurement of multiple events outweighs the double jeopardy concerns. The drafting team has,
however, reduced the minimum number of events in a 12 month period to 20 from 25 but is still recommending that events from
a previous year be used for the calculation if this number of events cannot be found in that period.
A few o commenters indicated that the allocation of the FRO to the BAs was a “top down” approach. The SDT agrees with some
of the comments made, but not in the conclusion drawn from the individual points. There is not currently an obligation to provide
any amount of frequency response to a sudden change in interconnection frequency. The proposed standard addresses this
shortcoming in the proposed standard.
The drafting team has also reduced the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction can
be studied closely to ensure no detrimental impact on the reliable operation of the Bulk Electric System.
Finally, there is ongoing disagreement in the industry as to whether it is desired to have a minimum Frequency Bias Setting that is
significantly greater than the Frequency Response Characteristic.
A couple of commenters questioned whether point B was 18 seconds after the start of the disturbance. The SDT revised the
language in the document to provide clarity on the 18 seconds. To the extent that the language is related to a specific definition
of steady frequency, this has been worded intentionally to allow the process being developed by the ERO (specifically the
Resources Subcommittee and the Frequency Working Group) to be adjusted based on experience that will only be gained through
evaluation of actual events over the course of the next few years. Until that experience is gained, there will need to be some
leeway in the process. The drafting team believes that the level of guidance provided in Attachment A is appropriate based on the
information currently available.
Organization
Yes or No
Question 6 Comment
Western Area Power
Administration, Western Area
Power Administration - UGP
Marketing
Negative
4. The allocation of FRO among BAs is a top-down approach instead of bottom up
approach currently used. Currently, BAs calculate their FRC and set their Bias based
on the greater of 1% peak load (1% generation for gen only BAs), or the average of
frequency response characteristic of their BA over a year (FRC). These calculated
individual biases get summed up and it becomes the Interconnection Bias value. The
proposed standard has identified a set MW (for Western Interconnection 685 MW for
Consideration of Comments: Project 2007-12 Frequency Response
11
4
000720
Organization
Yes or No
Question 6 Comment
0.1 of HZ) and is allocating it among all BAs. The individual BA’s allocated FRO is much
lower than what BAs obligations’ presently are since the proposed standard lowers
the bar for the BAs. The current approach is definitely superior to what is proposed
since it more closely matches with the characteristic of the system and it protect the
interconnection by requiring larger contribution than proposed standard.
5. The allocation of FRO among the BAs in the interconnection favors the BAs with
more load than more installed capacity
Response: 4. The drafting team agrees with some of the comments made here but not in the conclusion you draw from the
individual points. There is not currently an obligation to provide any amount of frequency response to a sudden change in the
interconnection frequency. The proposed standard addresses this shortcoming in the current standard. The drafting team has also
reduced the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction can be studied closely to ensure
no detrimental impact on the reliable operation of the Bulk Electric System. Finally, there is ongoing disagreement in the industry
as to whether it is desired to have a minimum Frequency Bias Setting that is significantly greater than the Frequency Response
Characteristic. Please refer to Order 693 P371 for further information on this issue.
5) After further discussion, the drafting team believes that the proposed allocation methodology does not favor any specific type
of entity. To the extent that the commenter believes that the allocation favors any specific type of entity, the commenter should
provide detailed reasoning of its position, not just an unsupported statement. The drafting team was unable to find any basis for
this position during our discussions of the proposed allocation methodology. The drafting team will also point out that installed
capacity is not a part of the calculation. The proposed allocation methodology, which has been clarified in the revised documents,
utilizes monthly average peak generation and average peak load.
Seattle City Light
Negative
Answer: No. Comments:
o LADWP and SCL consider the increase in number of events to analyze (now 25) to
be excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. SCL suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Consideration of Comments: Project 2007-12 Frequency Response
11
5
000721
Organization
Yes or No
Question 6 Comment
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not be used consistently across the industry.
Alliant Energy Corp. Services,
Inc.
Negative
Confusion exists around the "peak load" in that Attachment A states the allocastion is
based on Projected Peak Loads and Generation but the Background Document states
it will use historical Peak and Generation to make the allocation. - There appears to
be a difference in how FRO is calculated in Attachment A and what is described in the
Background Document. These differences should be reconciled such that both
documents address the same approach. If installed capacity is used in the equation in
Attachment A, how are variable/intermittent resources (e.g. wind, solar) accounted
for? At full capacity of something less - please clarify. –
It is not clear if there is an upper limit to the amount of frequcncy response expected
of the BA's under this standard. Except for Table 2 in Attachment A, there is no
discussion of an amount of FR expected on a total basis. BA's need to know for how
many tenths of a hertz they are to respond so they can determine how to plan to
meet the requirements.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
BrightSource Energy, Inc.;
Clark Public Utilities; Tri-State
Negative
Confusion exists between Attachment A and the Background Document. Attachment
A states peak load allocation is based on “Projected” Peak Loads and Generation, but
Consideration of Comments: Project 2007-12 Frequency Response
11
6
000722
Organization
Yes or No
G & T Association, Inc.; Tucson
Electric Power Co.; U.S. Army
Corps of Engineers; South
California Edison ; Platte River
Power Authority; Pacific Gas
and Electric Company;
Colorado Springs Utilities;
Idaho Power Company;
California Energy Commission;
California ISO; Deseret Power
Question 6 Comment
the Background Document states it will use “historical” Peak Load and Generation.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it seems
this pattern would lead to poorer response.
The standard is unclear as to if there is an upper limit to the amount of frequency
response expected of the Balancing Authorities under this standard. Except for Table
2 in Attachment A, there is no discussion of an amount of Frequency Response
expected on a total basis. Balancing Authorities need to know for how many tenths of
a hertz they are to respond so they can determine how to plan to meet this
requirement. The documents do not appear to provide any boundary on the
maximum amount of Frequency Response that a BA will provide, i.e. it is not clear
what will happen if an event occurs in the Eastern Interconnection that causes the
frequency to drop to less than 59.6 Hz or in the Western Interconnection that causes
the frequency to drop to less than 59.5 Hz, or if that event is excluded from the list
used to calculate the Balancing Authorities’ response or is it included with an
expectation that it counts the same as any other event. Without a clear statement of
what is expected, including whether there is a limit on that expectation or not, it is
unclear what is expected of the Balancing Authorities.
Finally, why are there no requirements on governor installation, settings, and
operation for a frequency response standard?
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
A reduction in the Frequency Bias Setting (FBS) may reduce the amount of AGC responses to a change in frequency. However, the
drafting team has ensured that the FBS does not dip below the actual frequency response to ensure that the Frequency Response
Consideration of Comments: Project 2007-12 Frequency Response
11
7
000723
Organization
Yes or No
Question 6 Comment
is not withdrawn due to AGC action. With that said, there is currently not an obligation to provide any amount of frequency
response to a sudden change in the interconnection’s frequency. The proposed standard addresses this shortcoming in the current
standard. The drafting team has modified the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction
can be studied closely to ensure no detrimental impact on the reliable operation of the Bulk Electric System. Finally, there is
ongoing disagreement in the industry as to whether it is desired to have a minimum Frequency Bias Setting that is significantly
greater than the Frequency Response Characteristic. Please refer to Order 693 P371 for further information on this issue.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
The drafting team is operating under the Standard Authorization Requests (SARs) as approved. This drafting team believes that
proposing a generator requirement is beyond the scope of the SARs. To the extent that the commenter believes there is a need to
have a reliability standard related to generators, the drafting team would suggest that the commenter submit a SAR to begin the
development process.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO
can go back in time to the previous year. This creates a double jeopardy to R1 of the
standard. It also may include irrelevant data if there have been changes from one
year to the next in FRO or Bias settings assigned by the ERO.
On Frequency Response Obligation, first paragraph states that "Each Interconnection
will establish target contingency protection criteria"; however, the Interconnection is
not a decision-making body. Does this really mean the ERO will establish FRO for each
Interconnection?
The single asterisk note for the table on page 2 states: "It is extremely unlikely that an
event elsewhere in the Eastern Interconnection would cause the Florida UFLS special
protection scheme to “false trip”.", "Special protection scheme" should be stricken
from this sentence, Florida has just a regional difference in its UFLS program.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
Consideration of Comments: Project 2007-12 Frequency Response
11
8
000724
Organization
Yes or No
Question 6 Comment
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Salmon River Electric
Cooperative
Negative
We feel that the drafting team has done an excellent job of providing clarify and
reasonable reporting requirements to the right functional entity. We support the
modifications but would like to have two additional minor modification in order to
provide additional clarification to the Attachment I Event Table. We suggest the
following clarifications: For the Event: BES Emergency resulting in automatic firm load
shedding Modify the Entity with Reporting Responsibility to: Each DP or TOP that
experiences the automatic load shedding within their respective distribution serving
or Transmission Operating area. For the Event: Loss of Firm load for = 15 Minutes
Modify the Entity with Reporting Responsibility to: Each BA, TOP, DP that experiences
the loss of firm load within their respective balancing, Transmission operating, or
distribution serving area. With these modifications or similar modifications we fully
support the proposed Standard.
Response: The drafting team understands that this comment was submitted under the wrong project.
FMPP
No
o Item 2 should be changed as follows: The ERO will identify at least 25 frequency
excursion events in each Interconnection for calculating the Frequency Bias Setting
and the FRM. If the ERO cannot identify in a given evaluation period 25 frequency
excursion events satisfying the limits specified in criteria 3 below, then similar
acceptable events from the previous evaluation period also satisfying listed criteria
will be included with the data set by the ERO for determining FRS compliance. (as
written this item could cause double jeopardy for event from the previous period)
o Under FRO for the Interconnection the first sentence should be changed as follows:
“The ERO {Each Interconnection (delete these words)} will establish target
Consideration of Comments: Project 2007-12 Frequency Response
11
9
000725
Organization
Yes or No
Question 6 Comment
contingency protection criteria for each Interconnection.” (each Interconnection is
not a governing entity)
o The footnote under Table 2 of Attachment A should be changed as follows: The
Eastern Interconnection set point listed is a compromise value for the highest UFLS
step setting of 59.5Hz used in the east and the {special protection scheme’s (delete
these words)} highest UFLS step setting of 59.7Hz used in Florida. It is extremely
unlikely that an event elsewhere in the Eastern Interconnection would cause the
Florida UFLS {special protection scheme (delete these words)} to “false trip”. (this is
not a special protection system; it is just an UFLS)
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Seattle City Light
No
o LADWP and SCL consider the increase in number of events to analyze (now 25) to
be excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. SCL suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
Consideration of Comments: Project 2007-12 Frequency Response
12
0
000726
Organization
Yes or No
Question 6 Comment
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not used consistently across the industry.
Manitoba Hydro
No
1. p.2 refers to each “Interconnection” establishing target contingency protection
criteria. However, an “Interconnection” as defined in the NERC Glossary is an
electrical system, not a Responsible Entity. This should be revised to clarify which
Responsible Entities must establish the protection criteria.
2. Table 2, although entitled “Interconnection Frequency Response Obligations” does
not use the term FRO in the Table itself. This terminology should be consistent.
3. There is no clear statement in Attachment A identifying the significance of Table 2.
The previous paragraph identifies Table 2 as listing “default targets”, but how does
this relate to the FRO referenced in R1?
4. The “Note” on p.2 regarding the ERO being able to use additional events that don’t
satisfy the criteria is unreasonable as drafted. Since these events are used to
calculate the Frequency Bias Setting and FRM (as per p.1, s.2), the selection of events
should not be at the unfettered discretion of the ERO. As drafted, no grounds or
criteria must be satisfied.
Response:1. The drafting team modified the language to clarify that the ERO will set the IFRO.
2. The drafting team modified the table to ensure consistent terminology is used.
3. The drafting team modified Attachment A to clarify the importance and explain the calculations made to get to the
Interconnection FRO.
4. The drafting team revised the note to clarify that the ERO may use any event, regardless of size or other condition, in its
evaluation of Interconnection Frequency Response. However, these additional events will not be used for evaluation of BA
response compliance.
FPL
No
3. - How many seconds of observation for “Delta F”? Does “Point C” in a. refer to
“Figure 1 - Classic Frequency Excursion and Recovery” from NERC’s Survey
Consideration of Comments: Project 2007-12 Frequency Response
12
1
000727
Organization
Yes or No
Question 6 Comment
Instructions document dated September 1, 2010? If so it should be included in this
document along with the added 8 and 18 second time lines being shown. What is a
“narrow range” in item b.?
4. - Better define “relatively steady” (i.e. within a specific range and state it?) Also,
“near 60.000 Hz” is not precise enough (i.e. if the event begins below 60.000 Hz, what
range or time error correction is to be considered acceptable?) Is the “A” value also
part of the figure cited in 3?
5. - Is the “B” value also part of the figure cited in 3?
6. - Change “should be excluded” to “will be excluded”.
7. - Better explain “the cleanest 2 or 3 frequency excursion events” or remove the
word “cleanest”.
Page 2 paragraph 5: Provide specific dates for the “quarterly postings” and where
these will be posted (i.e. Internet address or other). Clarify the December 15 ERO
annual post date with the dates stated for same posting on Page 3 paragraph 5 and
the BA’s January 10 deadline. The BA posts 30 days from which date? This is
confusing.
Page 2 Table 2: What of starting event frequencies that are < 60 Hz? Why is the
“Highest UFLS” 59.6 when the Florida setting for its load is 59.7?
Page 3 FRO equation: Page 4 of the “Frequency Response Standard Background
Document, October 2011” also shows this equation but uses different terms. Make
the same on both documents. In the Background Document each component of the
numerator is explained and reference is made to FERC Form 714 to obtain these
values. There is no reference to this form for the denominator values. All of this
needs to be made clear with reference to FERC Form 714 on Attachment A.
Response: 3. The SDT has modified the titles of the columns in Table 1 of the Procedure document to clarify what was intended by
the table. The Point C value is defined in section 3a.
Consideration of Comments: Project 2007-12 Frequency Response
12
2
000728
Organization
Yes or No
Question 6 Comment
4 - Due to the complicated nature of event evaluation and selection, the drafting team has retained the words “relatively steady”
and “near 60” in the document without providing further clarification or definition. The drafting team believes that the process
being developed by NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some
leeway. As more experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
5 – No, the B value is a calculated value not shown in the chart referenced in number 3 above. Additional language has been
added in Attachment A to clarify both the A value and the B value. The A and B values are shown on Figure 2 of the Background
document as green and red lines, respectively.
6 – The drafting team modified this language.
7 – Due to the complicated nature of event evaluation and selection, the drafting team has retained the word “cleanest” in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
NERC is developing this part of the process and an area to post this information. The drafting team has put clear language in the
attachment requiring at least quarterly posting of events. It is currently the drafting team’s expectation that a list of potential
events would be posted shortly after they actually occur and a refined list will be made available quarterly.
Modifications to Table 2 have been made to clarify what is being used.
Attachment A and the Background Document have been modified so that the FRO Allocation equation is the same and the terms
are fully explained.
Tucson Electric Power
No
Attachment A creates additional requirements to the BAL-003-1 Standard. The
arrested value of frequency observed within 8 seconds may not be long enough in
some instances.
The delta F in the West should be greater than 0.05 Hz to ensure a measurable
frequency response.
West Under Frequency should be set at 59.95 Hz. There is no reliability concern for
Over Frequency.
Does 18 seconds after the start of the disturbance set point B?
Consideration of Comments: Project 2007-12 Frequency Response
12
3
000729
Organization
Yes or No
Question 6 Comment
Pre-disturbance frequency should be relatively steady and near 60.000 Hz is vague.
TEP feels that the ERO should not need to validate a BAs frequency bias setting.
Response: The drafting team has modified the standard to put the requirements there and use Attachment A to clarify the
process.
After further discussion and review of the events in the Western Interconnection Form 1 for 2011, the drafting team has modified
the Delta C and Under Frequency values in Table 1.
Based on language in Order 693 P355, the drafting team believes that frequency response is needed in both directions, not just
one.
The drafting team has revised the language in the document to provide clarity on the 18 seconds. To the extent that the language
related to a specific definition of steady frequency, this has been worded intentionally to allow the process being developed by
the ERO (specifically the Resources Subcommittee and the Frequency Working Group) to be adjusted based on experience that
will only be gained through evaluation of actual events over the course of the next few years. Until that experience is gained,
there will need to be some leeway in the process. The drafting team believes that the level of guidance provided in Attachment A
is appropriate based on the information currently available.
Due to level of detail being used to determine the FBS and FRM as well as the interactions between this standard and others, the
drafting team disagrees with the commenter and continues to recommend the ERO validate the FBS of each BA.
Bonneville Power
Administration
No
BPA believes that Attachment A adds additional requirements to the standard.
Confusion exists between Attachment A and the Background Document. Attachment
A states peak load allocation is based on “Projected” Peak Loads and Generation, but
the Background Document states it will use “historical” Peak Load and Generation.
3a: it may take longer than 8 seconds in some disturbances. This should be 10
seconds. .05 Hz Delta F is not low enough for the Western Interconnection, it should
be .075Hz to ensure there is measurable frequency response for the interconnection.
Also, under frequency should be set at 59.95 Hz. BPA does not believe there is a
reliability need to include over frequency events.
Consideration of Comments: Project 2007-12 Frequency Response
12
4
000730
Organization
Yes or No
Question 6 Comment
3b: It is unclear if the 18 seconds is setting the B point. If this is the B point, BPA
believes it should be changed to 25 seconds for the Western Interconnection.
4. Please define relatively steady and near 60 Hz.
6: For the Western Interconnection, BPA believes this needs to be 10 minutes at the
top of the hour. As mid hour scheduling becomes more prevalent, the ramping at the
bottom of the hour will have to be taken into account.
FRO for the interconnection: Starting frequency should be the FTL limit. With RBC in
place, the frequency is seldom at 60 Hz.
BPA understands the theory behind setting the base obligation to the values listed in
table 2. BPA would like to know if there were any studies performed to validate
setting the FRO for the interconnection to such a low level?
BA FRO and frequency bias setting: BPA does not agree with ERO assigning a
Frequency Bias setting to each BA. This calculation is indicated as the initial FRO
allocation, what is the process for changing it? BPA believes this should go through
the standard drafting process for any changes. The calculation should use Peak
online capacity, not the installed capacity. This would lead to the denominator being
2 X Peak projected load for the interconnection. BPA has approximately 35,000 MW
of installed generation, and has never seen the actual coincidental generation go over
21,000 MW.
Again, BPA doesn’t believe the ERO should be validating the frequency bias setting. It
is unclear to BPA how variable bias is being addressed in the standard.
Response: The drafting team has modified the requirements to address comments. The drafting team believes as modified the
requirements are stated in the standard and the process to be used is in the Attachment.
The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for the
allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
The drafting team has revised the language in the document to provide clarity on the 18 seconds. The drafting team has also
Consideration of Comments: Project 2007-12 Frequency Response
12
5
000731
Organization
Yes or No
Question 6 Comment
attempted to clarify that the B Value is the average of the scan rate data for the period from 20 to 52 seconds following the start
of the event. The event selection criteria will use the frequency approximately 18 seconds (prior to the start of the B Value period)
to as frequency level to determine if the change in frequency qualifies as an event for the purposes of this standard. Based on
event information for the 12 month period beginning December 2010, the drafting team has modified the frequency levels used
for event qualification but did not modify the 18 second frequency point.
To the extent that the language related to a specific definition of steady frequency, this has been worded intentionally to allow
the process being developed by the ERO (specifically the Resources Subcommittee and the Frequency Working Group) to be
adjusted based on experience that will only be gained through evaluation of actual events over the course of the next few years.
Until that experience is gained, there will need to be some leeway in the process. The drafting team believes that the level of
guidance provided in Attachment A is appropriate based on the information currently available.
Both the NERC Resources Subcommittee (RS) and the NERC Transmission Issues Subcommittee (TIS) evaluated the level of
response needed. The drafting team decided to use the limits determined by the RS over that determined by the TIS after
evaluation of both. The documents developed by both of these subcommittees are available on the NERC website under this
project (http://www.nerc.com/filez/standards/Frequency_Response-RF.html).
The drafting team clarifies that the ERO is not assigning the Frequency Bias Setting. The ERO will review the data to determine
that the Frequency Response Measure is correctly determined by the BA and that the Frequency Bias Setting is therefore correct.
The expected process is that a subcommittee under NERC will review the Form 1 and Form 2 for each entity to ensure that the BA
correctly filled out the form. Assuming the BA has correctly filled out these forms, there is no ERO interaction with the number
provided by the BA.
The FRO calculation is being included in the Attachment A to ensure that the process to modify the calculation would need to be
open to industry input. It is not appropriate to put it in a requirement since it would not make sense to make a requirement that
the FRO be allocated in a certain manner. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
The drafting team revised the requirements to separate the variable bias requirement from the fixed bias setting requirement and
provide clarity related to what is expected in a variable bias setting.
Energy Mark, Inc.
No
Comment 6: “If the ERO cannot identify in a given evaluation period 25 frequency
excursion events satisfying the limits specified in criteria 3 below, then similar
acceptable events from the previous evaluation period also satisfying listed criteria
Consideration of Comments: Project 2007-12 Frequency Response
12
6
000732
Organization
Yes or No
Question 6 Comment
will be included with the data set by the ERO for determining FRS compliance." I
believe that the better alternative in this case would be to use the lesser number of
events. This is partly based on the consideration that if there are fewer events, the
risk to the interconnection for that year was less that expected, and as a result,
evaluation of fewer events will not compromise interconnection reliability. If fewer
than 25 events are available in any year, the selection criteria should be adjusted to
select more events.
Comment 7: There are a number of problems with the use of "median" Frequency
Response of the measured events. These problems make a choice other than median
preferable. The following comments list some of those problems.
Comment 8: The current standard uses average Frequency Response of selected
events. This makes the current standard incompatible with the use of median.
Comment 9: If a BA reconfigures during a measurement year, that reconfiguration
will create a bi-modal distribution of the Frequency Response events. Median is
incapable of representing a bi-modal distribution. The use of median will result in a
standard that is incapable of measuring compliance effectively for an BA that is
reconfigured during a measurement year (Dec 1 thru Nov 30).
Comment 10: Any attempt to purchase additional Frequency Response from another
BA for a portion of a measurement year will also cause a bi-modal distribution
making the purchase of Frequency Response only effective for entire measurement
years.
Comment 11: Median is a non-linear measurement method. Because it is a nonlinear measurement method, there is no valid way to manage partial year
measurements.
Comment 12: I will offer an alternative to median to the SDT before the end of the
development of responses to these comments.
Comment 13: The Minimum Frequency Bias Setting and the Frequency Response
Obligation are both based on a method that assigns responsibility based on a Peak
Consideration of Comments: Project 2007-12 Frequency Response
12
7
000733
Organization
Yes or No
Question 6 Comment
Load / Peak Generation share of the interconnection. However, the method used to
set the Minimum Frequency Bias Setting is different than the method used to
determine the Frequency Response Obligation. Using these two different methods
could result in the Minimum Frequency Bias Setting being less that the FRO for a BA.
The best way to correct this problem is to use that same allocation methodology for
determining the FRO and the Minimum Frequency Bias Setting. This can be easily
accomplished by modifying R5 to use the FRO allocation method to determine the
Minimum Frequency Bias Setting. This calculation would divide the numerator from
the FRO allocation equation, divide it by two and multiply it by the percentage
specified in Attachment B. In fact, the current FRS Form 1 uses this equation with
projected rather than historic data. The best alternative would be to modify the R5 in
the standard to match the FRO allocation method and modify FRS Form 1 to use
historic data instead of projected data. This would result in only one set of Peak Load
and Peak Generation data throughout the standard, rather than three different sets
of data as currently written. When multiple sets of the same or similar data are used
within a single standard, it only creates confusion and errors in the result.
Response: Comment 6: The studies from the field trial show a convergence of the measurement after approximately 20 to 25
events. Based on the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to
fail inappropriately due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure
that the events picked are not weighted in such a way to cause the measurements to be increased over actual response. The
drafting team has attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate
the FRM. Finally, the calculation process is being used for more than the previous process, not to mention that the previous
process is not clearly defined and therefore not used consistently across the industry.
Comment 7-12: The drafting team is recommending use of the median for the purposes of determining a BA FRM over multiple
events. This decision is based on the determination that, while it may not be perfect, it is better than the other alternatives
available at this time. The drafting team recognizes that in the future a better methodology might be found; based on the data
available at this time the median allows us to move forward to implement a response requirement.
Comment 13: The drafting team understands your concern of using the historical numbers for the FRO allocation and the
projected number as the basis for the minimum Frequency Bias Setting. However, after discussions, the drafting team believes
Consideration of Comments: Project 2007-12 Frequency Response
12
8
000734
Organization
Yes or No
Question 6 Comment
that at this time, minimizing the changes to the current Frequency Bias Setting process provides better comparability for the
purpose of evaluating the impacts of reducing the minimum setting requirement. In the alternative, the drafting team feels that
allocating the FRM based on historical data provides less room to game the process since the numbers used for allocation can be
verified independently.
MRO NSRF
No
Confusion exists around the “peak load” in that Attachment A states the allocation is
based on Projected Peak Loads and Generation but the Background Document states
it will use a historical Peak and Generation to make the allocation. Also, for the BA
installed capacity, where is that value derived from and does NERC obtain that from
FERC form data or does the BA provide that information somewhere specific to this
effort? Additionally, there appears to be a difference in how FRO is calculated in
Attachment A and what is described in the Background Document. These differences
should be reconciled such that both documents address the same approach.If
installed capacity is used in the equation, how are variable/intermittent resources
(e.g. wind, solar) accounted for? At full capacity? Please clarify.We suggest the SDT
clarify if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or “Technical Background”, or “requirements
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
Xcel Energy
No
Confusion exists around the “peak load” in that the Attachment A states the
allocation is based on Projected Peak Loads and Generation but the Background
Document states it will use a historical Peak and Generation to make the allocation.
Also, for the BA installed capacity, where does that value come from and does NERC
obtain that from FERC form data or does the BA provide that information somewhere
specific to this effort? Additionally, there appears to be a difference in how FRO is
calculated in Attachment A and what is described in the Background Document.
These differences should be reconciled such that both documents address the same
Consideration of Comments: Project 2007-12 Frequency Response
12
9
000735
Organization
Yes or No
Question 6 Comment
approach.If installed capacity is used in the equation, how are variable/intermittent
resources (e.g. wind, solar) accounted for? At full capacity?
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and monthly peak generation (monthly peak) and does not use installed capacity.
ISO/RTO Council Standards
Review Committee
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two
separate documents (Attachments A and B), the modified Attachment A is
problematic. As many commenters indicated, the previous Attachment A, other than
the section providing guidance on event selection, appears to be explanatory,
contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment
A should include only the event selection process and calculations associated with
the requirements, including an explanation of what is necessary if variable Frequency
Bias Settings are implemented. If other "requirements" need to be specified, such as
the reporting time frame stipulated on P. 3 of Attachment A, they should be moved
to the standard itself but not imbedded in an attachment. We suggest that the SDT
first determine if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as-written Attachment A is a mix bag as it on the one hand describes the ERO’s
process for supporting the Frequency Response Standard (FRS), in other words, the
method and criteria it uses to calculate the frequency bias settings and the FRM, and
on the other hand the BA’s obligations to support this process. We strongly disagree
that the latter requirements be imbedded in an attachment, especially one that is
supposed to provide the technical background and guideline for another entity which
is not held responsible for complying with the proposed method. Further, there are
no measures provided for the requirements stipulated/imbedded in Attachment A so
how can the Responsible Entity (BA, in this case) be assessed for compliance?We
Consideration of Comments: Project 2007-12 Frequency Response
13
0
000736
Organization
Yes or No
Question 6 Comment
suggest the SDT move those requirements on the BA to the main standard, and turn
Attachment A into an appendix describing the calculation process. An appendix is not
regarded as a mandatory requirement. Similar comments apply to Attachment B.
Moreover, if the Attachments are to be integral to the standards, the terminology
“may” must be replaced with “shall”.
Finally, the two Attachments are listed in Section F - Associated Documents. This
Section is generally used to list reference documents that are NOT standard
requirements. We suggest the SDT review and revise this listing depending on its final
determination of the status of the two Attachments (or their revisions, where
appropriate).
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry. As to the use of the term “may” in the
attachment, at this time the drafting team is unable to further restrict the language due to the issues surrounding an individual
event. As an example, frequency is scheduled at 60 Hz most of the time. However, when viewed on a graph or an EMS screen, it
rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005. The drafting team is unable to say at this
time that an event that starts with frequency at 60.005 is materially different that an event that starts at 59.995. Therefore, the
drafting team has attempted to put guidance into the document as to what is pertinent without attempting to be overly
restrictive in the selection criteria since there is no support for a restriction at this time. As more experience is gained, the process
should be refined. It the refinement is significant enough to require a change to the Attachment A language, the process required
to do so would be open to participation of industry and not done without public exposure.
The SDT agrees with your comment about removing the documents from Section F of the proposed standard has made this
modification to the standard.
Independent Electricity
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two
separate documents (Attachments A and B), the modified Attachment A is
Consideration of Comments: Project 2007-12 Frequency Response
13
1
000737
Organization
Yes or No
System Operator
Question 6 Comment
problematic. As many commenters indicated, the previous Attachment A, other than
the section providing guidance on event selection, appears to be explanatory,
contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment
A should include only the event selection process and calculations associated with
the requirements, including an explanation of what is necessary if variable Frequency
Bias Settings are implemented. If other "requirements" need to be specified, such as
the reporting time frame stipulated on page 3 of Attachment A, they should be
moved to the standard itself but not imbedded in an attachment. We suggest the SDT
to first determine if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or “Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as-written Attachment A is a mix bag as it on the one hand describes the ERO’s
process for supporting the Frequency Response Standard (FRS) (in other words, the
method and criteria it uses to calculate the frequency bias settings and the FRM), and
on the other hand the BA’s obligations to support this process. We strongly disagree
that the latter requirements be imbedded in an attachment, especially one that is
supposed to provide the technical background and guideline for another entity
which, by the way, is not held responsible for complying with the proposed method.
Further, there are no measures developed for the requirements stipulated/imbedded
in Attachment A so how can the Responsible Entity (BA, in this case) be assessed for
compliance?
We suggest the SDT to move those requirements on the BA to the main standard,
and turn Attachment A into an appendix describing the calculation process. An
appendix is not regarded as a mandatory requirement. Similar comments apply to
Attachment B.
Finally, the two Attachments are listed in Section F - Associated Documents. This
Section is generally used to list reference documents that are NOT standard
requirements. We suggest the SDT review and revise this listing depending on its final
determination of the status of the two Attachments (or their revisions, where
Consideration of Comments: Project 2007-12 Frequency Response
13
2
000738
Organization
Yes or No
Question 6 Comment
appropriate).
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments and modified them to address the concerns raised by
the comments that requirements were in the Attachments. In order to explain the process, the drafting team believes the
information needs to be attached to the standard such that it cannot be changed without input from the industry. As to the use of
the term “may” in the attachment, at this time the drafting team is unable to further restrict the language due to the issues
surrounding an individual event. As an example, frequency is scheduled at 60 Hz most of the time. However, when viewed on a
graph or an EMS screen, it rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005. The drafting
team is unable to say at this time that an event that starts with frequency at 60.005 is materially different that an event that starts
at 59.995. Therefore, the drafting team has attempted to put guidance into the document as to what is pertinent without
attempting to be overly restrictive in the selection criteria since there is no support for a restriction at this time. As more
experience is gained, the process should be refined. It the refinement is significant enough to require a change to the Attachment
A language, the process required to do so would be open to participation of industry and not done without public exposure.
The SDT agrees with your comment about removing the documents from Section F of the proposed standard has made this
modification to the standard.
Florida Power & Light
Company
No
In the table on page2 the asterick references a statement that the 59.7Hz used in
Florida is a special protection scheme. This is incorrect. The special protection
scheme setting was 59.82Hz and was done away with in 2005 or earlier. The 59.7Hz
setting used within the FRCC is based on FRCC TWG studies that require this level of
setting to protect the state in the event of a separation and to protect nuclear
equipment. FPL supports the use of the C(N-2) critiera. Additionally, the reference to
the FERC714 report that is currently in the background data should be made part of
attachment A not separated. FPL fully agrees with Table 1The formula used to derive
the FRO is inconsistant with the definition used for requirement R5. R5 states that
the load is " within the BA's metered boundary". The load used in the formulae is
taken from FERC714. The yearly peak demand used in R5 should be the peak
Consideration of Comments: Project 2007-12 Frequency Response
13
3
000739
Organization
Yes or No
Question 6 Comment
monthly load from June, July or August as reported on FERC714 to be compatible
with the FRO formula.
Response: The drafting team has removed the reference to the special protection scheme. The drafting team has modified the FRO
allocation formula to better explain what is desired. However, the drafting team did not adjust the formula to what is suggested
by the commenter.
NV Energy
No
It is not clear whether the calculation of FRO is to utilize projections of BA load as in
Att A, or past data reported in FERC Form 1 as per the Background Document.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
Los Angeles Department of
Water and Power
No
LADWP considers the increase in number of events to analyze (now 25) to be
excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. LADWP suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not used consistently across the industry.
JEA Electric
No
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO
Consideration of Comments: Project 2007-12 Frequency Response
13
4
000740
Organization
Yes or No
Compliance/Florida Municipal
Power Agency
Question 6 Comment
can go back in time to the previous year. This creates a double jeopardy to R1 of the
standard. It also may include irrelevant data if there have been changes from one
year to the next in FRO or Bias settings assigned by the ERO.
On Frequency Response Obligation, first paragraph states that "Each Interconnection
will establish target contingency protection criteria"; however, the Interconnection is
not a decision-making body. Does this really mean the ERO will establish FRO for each
Interconnection?
The single asterisk note for the table on page 2 states: "It is extremely unlikely that an
event elsewhere in the Eastern Interconnection would cause the Florida UFLS special
protection scheme to “false trip”.", "Special protection scheme" should be stricken
from this sentence, Florida has just a regional difference in its UFLS program.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Duke Energy
No
On page 3 of the document it states “For a multiple Balancing Authority
Interconnection, the Interconnection Frequency Response Obligation is allocated
based upon either the Balancing Authority Peak Demand or peak generation”,
however, the initial FRO allocation equation shows that the BA allocation is based
upon the sum of the Projected BA Peak Load plus installed capacity, times the
Interconnection FRO, and divided by the sum of the Projected Interconnection Peak
Load plus Interconnection installed capacity. Is the statement in quotes correct, or is
the allocation equation correct? In addition, the equation in Attachment A
referencing “installed capacity” conflicts with the equation in the BAL-003-1
Consideration of Comments: Project 2007-12 Frequency Response
13
5
000741
Organization
Yes or No
Question 6 Comment
Background Document entitled “Frequency Response Standard Background
Document” where “Peak Gen” is used. In summary, is the FRO allocation based upon
an equation which a) sums the Projected BA Peak Load plus peak generation, b) sums
the Projected BA Peak Load plus installed capacity, or c) uses either Projected BA
Peak Load OR peak generation? All three options are currently represented in the
documentation.
Calculation of the FRO for the Eastern Interconnection: Duke Energy agrees with the
criteria suggested for the event to be protected (4500 MW), and at this time also
agrees with the “compromise” low limit of 59.6 Hz. However, knowing that another
Standard is under development which may require hourly assessment of available
“frequency responsive reserves”, we are trying to determine what impact the choice
of this methodology will have on the amount of frequency responsive reserves the
industry will have to maintain - enough to cover frequency swings that only
occasionally reach down to perhaps 59.9 Hz as we see on the Interconnection today
(essentially the allocated FRO for a 0.1Hz deviation), enough to cover a 4500 MW
loss, or whatever we deem appropriate as long as we are compliant to the FRM? We
recognize that the Standard Drafting Team cannot answer this question, as the
Standard under development is not within the scope of this team, however our
comment is meant to illustrate the point that similar to our response to question 8, it
should be recognized that elements of this Standard are tightly coupled to other
current and potential Standards, and the impacts must be considered by the Industry.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Consideration of Comments: Project 2007-12 Frequency Response
13
6
000742
Organization
SERC OC Standards Review
Group
Yes or No
Question 6 Comment
No
The definition of Single Event Frequency Response Data (SEFRD) was struck from the
draft standard but still appears in Attachment A. Since R1 of the standard references
Attachment A, would the definition of SEFRD still be applicable? If the definition is to
be totally struck, we don’t think the term should be used in Attachment A.
Response: The SEFRD definition was moved to Attachment A. The SEFRD is used on individual events. The median of a BA’s SEFRDs
will be used to determine its FRM. Therefore, the drafting team believes it is appropriate to use the definition in the Attachment.
Since it is not likely to be used outside of the context of this standard, the drafting team is not proposing to place the definition in
the NERC Glossary.
Hydro-Quebec TransEnergie
No
The Event Selection Criteria should be modified for the Quebec Interconnection. In
Table 1, the change in frequency (Delta f) used for Quebec’s Event Selection Criteria
should be 0,3Hz (from point “A” to point “C”) and must last for at least 7 seconds so
that we don’t measure AGC action. In addition, a criterion should be added by saying
that events that recovered within the 20-52 second average period for point “B”
should be excluded from analysis.
Response: The drafting team has modified Attachment A to address these comments.
Keen Resources Asia Ltd.
No
The sample pre-selection described in Attachment A, Event Selection, Criteria 2 & 7,
violates the fundamental statistical procedure of unbiased sampling. A population is
governed by a single "process" which, when stationary, is represented by a fixed
probability distribution. In this case the population is several years of events (which
are the subject of Frequency Response), not of normal operating control errors which
are the subject of CPM control. A sample is governed by a single process that
approximates the process governing the population as the sample gets larger, in this
case if it includes several years of data. Samples are measured "as they come", no
triage/filtering allowed, and they are called "stratified" when their distribution
approximates the population distribution. Unlike normal operating errors, samples of
events are not evenly distributed over a year. The attempt in criteria 2 & 7 to preselect only certain events, and not others, in such a way that the selected events
Consideration of Comments: Project 2007-12 Frequency Response
13
7
000743
Organization
Yes or No
Question 6 Comment
occur evenly throughout the year, is papently wrong because it is trying to "fit"
events into a process (even distribution over time) that does not govern events, but
that instead governs normal operating errors that are the subject of CPM control, not
of this Frequency Response standard. In other words, criteria 2 & 7 confuse
Frequency Response with CPM, and events with normal operating errors. The result
is a false, biased sample which destroys the integrity of this standard. Paragraph 4 on
page 5 of the Background Document, on the other hand, provides a statistically
correct description of event selection without sample pre-selection and should
followed instead of the erroneous criteria 2 & 7 in Attachment A.
Response: The drafting team has discussed this issue several times and believes that issues related to measurement caused by
noise in individual events and the need to ensure adequate representation of events throughout the year outweigh the concern to
have a “pure” statistical sample. For these reasons the drafting team has not modified the event selection criteria.
Northeast Power Coordinating
Council
No
The SDT has to first determine if the materials in the revised Attachment A & B are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as written Attachment A is confusing as it describes the ERO’s process for
supporting the Frequency Response Standard (FRS) (the method and criteria it uses
to calculate the frequency bias settings and the FRM), and at the same time the BA’s
obligations to support this process. The latter requirements should not be imbedded
in an attachment, especially one that is supposed to provide the technical
background and guideline for another entity which is not held responsible for
complying with the proposed method. An appendix is not regarded as a mandatory
requirement.
Additionally, regarding BAL-003-1- Attachment A 1. Criterion 5 needs to be re-written
for clarity.
2. Criterion 7 refers to “cleanest events”. A statement of what constitutes a “clean
event” is needed to avoid possible controversy in the future.
Consideration of Comments: Project 2007-12 Frequency Response
13
8
000744
Organization
Yes or No
Question 6 Comment
3. The use of 59.6 Hz as the highest UFLS setting is flawed. It should either be 59.7 Hz
as a deliberate choice to protect Florida interests, or it should be 59.5 Hz without
concern for Florida’s unique settings.
4. In the last 2 sentences at the end of the section on Frequency Response Obligation,
it refers to an Interconnection being able to offer “alternate FRO protection criteria”.
The Interconnection should have been an integral part of establishing its obligation.
It is stated that the “ERO will confirm” the “alternate FRO protection criteria”. Does
this mean the ERO unconditionally approves it, or evaluates with a right of rejection?
Please clarify.
5. In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Does the industry have a clear and consistent definition for installed
capacity? Also, with greater wind energy development, the delivered capacity over
longer time horizons will be substantially less than nameplate machine ratings. The
background document refers to the use of peak generation instead of installed
capacity. Which shall be used? Please clarify.
6. Recent studies have shown that the 18-52 second sampling interval does not work
well for the Quebec Interconnection, in part due to the excellent and high level of
response found in that Interconnection. The standard needs to be modified such that
the sampling interval is that which works the best for each individual interconnection.
7. Attachment A needs to define the point A sampling interval.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The drafting team believes that Criterion 5 is clear as written. The comment does not provide any guidance as to what needs
Consideration of Comments: Project 2007-12 Frequency Response
13
9
000745
Organization
Yes or No
Question 6 Comment
clarification so no change was made.
2. Due to the complicated nature of event evaluation and selection, the drafting team has retained the word “cleanest” in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
3. The drafting team has revised the terminology used to explain the frequency levels proposed. There was not a change to the
Eastern Interconnection numbers.
4. An interconnection can recommend a change to the table. As the standards process currently works, that interconnection
would need to support its alternative level with data. If the interconnection has a single Regional Reliability Organization, the ERO
would typically agree to the alternative assuming it would be more restrictive (in this case a larger response requirement) than
the ERO has recommended.
5. The drafting team has addressed the concerns raised by clarifying that historical data is used for the allocation of an
Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is not used in the
allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak) and peak
generation (monthly peak) and does not use installed capacity.
6. The drafting team has modified Attachment A to address concerns with selection of an event where frequency returns to the A
Value level during the measurement period. These events will be excluded from the measurement process for all
interconnections.
7. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
Sacramento Municipal Utility
District (SMUD)
No
The standard is unclear as to if there is an upper limit to the amount of frequency
response expected of the Balancing Authorities under this standard. Except for Table
2 in Attachment A, there is no discussion of an amount of Frequency Response
expected on a total basis. Balancing Authorities need to know for how many tenths of
a hertz they are to respond so they can determine how to plan to meet this
requirement. The documents do not appear to provide any boundary on the
maximum amount of Frequency Response that a BA will provide, i.e. it is not clear
what will happen if an event occurs in the Eastern Interconnection that causes the
Consideration of Comments: Project 2007-12 Frequency Response
14
0
000746
Organization
Yes or No
Question 6 Comment
frequency to drop to less than 59.6 Hz or in the Western Interconnection that causes
the frequency to drop to less than 59.5 Hz, or if that event is excluded from the list
used to calculate the Balancing Authorities’ response or is it included with an
expectation that it counts the same as any other event. Without a clear statement of
what is expected, including whether there is a limit on that expectation or not, it is
unclear what is expected of the Balancing Authorities.
Response: The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency
Response for which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency
Response equal to a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Western Electricity
Coordinating Council
No
There is disagreement between Attachment A and the Background Document.
Attachment A states peak load allocation is based on “Projected” Peak Loads and
Generation, but the Background Document states it will use “historical” Peak Load
and Generation.
The allocation methodology of FRO among the BAs in the equation on page 3 of
Attachment A favors BAs with more load than more installed capacity. Peak load is
served but not all installed capacity is always dispatched.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
Alberta Electric System
Operator
No
These documents not only provide additional clarity but also specify additional
requirements, such as FRS Form 1 annual reporting by January 10. All the enforceable
requirements should be included in the body of the standard.
1. Attachment A uses the terms "delta F (change in frequency)", "arresting frequency
(Point C)", "B Value", "A Value". These terms are not properly defined or described in
this document as drafted. The AESO suggests adding a description or definitions for
Consideration of Comments: Project 2007-12 Frequency Response
14
1
000747
Organization
Yes or No
Question 6 Comment
clarity in this document.
2. The standard gives 2 sets of values for Interconnection Frequency Response
Obligation in Table 2, (1) Base Obligation and (2) the obligation including 25% Safety
Margin (which seems to be implied by the "contingency protection criterion"). The
Attachment A does not specifiy whether the Base Obligation or the 25% Safety
Margin value will be used to allocate the Interconnection FRO to the BAs. Please
clarify which value will be used to calculate the BA Frequency Response Obligation
(FRO) in the Interconnection FRO allocation formula in Attachment A.
3. The "initial FRO allocation" formula in Attachment A uses Peak Load. The term
Peak Load is not used in the standard nor is it a defined term in the NERC Glossary.
The standard uses Peak Demand, which is defined in the Glossary Is "Peak Load"
synonymous with "Peak Demand"? If so, Peak Demand should be used in the formula
instead. Otherwise Peak Load should be clearly defined in this document.
4. Is "Projected" in the FRO allocation formula synonymous with "Forecasted"? If so,
Forecasted should be used for consistency. Otherwise "Projected" or the context in
which it appears must be defined.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
2. The drafting team has modified Table 2 to clarify that the bottom number in each column is the Interconnection FRO. The
Interconnection FRO will be allocated to the BAs within that interconnection.
3 and 4. The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
Consideration of Comments: Project 2007-12 Frequency Response
14
2
000748
Organization
Yes or No
Question 6 Comment
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
Great River Energy/ACES
Power Marketing Standards
Collaborators
No
Under item 3 of the Event Selection Criteria section, the delta F and Point C should be
described either in this attachment or the “Frequency Response Standard
Background Document”. While many in industry may understand what these terms
mean, history has a way of getting lost with personnel turnover. Furthermore, this
would help ensure that the auditors and industry have a duplicate understanding.
In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency
Protection Criteria should be provided and which N-2 event was selected so that
industry can help validate if the correct MW value was selected.
Furthermore, the document should clarify if the Contingency Protection Criteria
contains the “safety margin”. There is a statement in the paragraph before the table
that states it does but then the table lists out a separate 25% “Safety Margin”. Thus,
it is not clear if the “Safety Margin” is included in the Contingency Protection Criteria
value listed in the table or not. “Safety margin” should be changed to “reliability
margin”. Safety has a specific meaning in the electric industry and its use here is not
appropriate. The Base Obligation should be explained. The explanation should
include its purpose and origin.
Response: 1. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
The drafting team has clarified Table 2 by modifying the titles for each line.
Texas Reliability Entity
No
We have a number of concerns regarding Attachment A which are set forth below:
1. Regarding the formula for “Initial FRO Allocation” on page 3 of Attachment A, the
terms for “BA installed capacity” and “Interconnection installed capacity” are
undefined and could be subject to manipulation and dispute. We suggest that this
formula be revised to mirror the calculation based on well-established FERC Form 714
data that is discussed in the Background document, which is based on actual
Consideration of Comments: Project 2007-12 Frequency Response
14
3
000749
Organization
Yes or No
Question 6 Comment
generation output.
2. In Attachment A, all references to “Texas” should be changed to “ERCOT” as a
reference to the Interconnection or the Region (including tables).
3. Regarding the Event Selection Criteria in Attachment A: in item 2, consider
whether certain events, such as DCS events, should be required to be included in the
FRM analysis.
4. Regarding the Event Selection Criteria in Attachment A: item 7 provides that the
selected frequency excursion events are to be selected so that they are evenly
distributed seasonally. Consider adding the seasonal distribution concept to item 2,
particularly if it becomes necessary to include events from the previous evaluation
period.
5. In Attachment A, page 1 says the ERO is to post the final list of frequency
excursion events by December 15, but on page 3 it suggests that the list will be
posted by December 10. These references should be made consistent.
6. Attachment A states, on page 3, “the ERO will use FRS Form 1 data to post the
following information for each Balancing Authority for the upcoming year: Frequency
Bias Setting and Frequency Response Obligation (FRO).” What is meant by “the
upcoming year”? Is the BA supposed to implement the new FBS immediately, or wait
until the beginning of the next evaluation period on December 1? Note that if the
new FRO and FBS are implemented immediately (e.g. in March), then the FRO will
change in the middle of an evaluation period. This will complicate the comparison of
FRM and FRO as required by R1.
Response: 1. The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used
for the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
2. This change was made.
Consideration of Comments: Project 2007-12 Frequency Response
14
4
000750
Organization
Yes or No
Question 6 Comment
3. The drafting team recommends all events with a frequency deviation that meets the selection criteria should be evaluated. For
the entity that lost generation (or load) to initiate the event, the calculation methodology proposed allows adjustments to be
made for that event.
4. This modification was made to the Attachment B (now a Procedure). The suggested modifications are shown in Criteria 2 and 7.
5. These two documents have been conformed.
6. The ERO will notify the BAs as to the date the Frequency Bias Setting is to be implemented if they are utilizing a fixed Frequency
Bias Setting.
Southern Company
No
We suggest increasing the delta f for the East to be the same value as the West or
larger. The reason for this is that the 0.04Hz suggested is too close to the governor
deadbands of .036Hz. This would potentially omit frequency response that some
units may provide for a larger excursion but not for those close to the deadband.
Response: The delta f values have been selected to balance the need to have a sufficient number of events for evaluation and the
need to have sufficient frequency movement to actually measure response. At this time the drafting team is not modifying the
eastern interconnection values based on the event selection process for the period December 2010 through November 2011.
ISO New England Inc
No
We suggest the SDT to first determine if the materials in the revised Attachment A &
B are “Guideline” or Technical Background”, or are they “requirements”. If it is the
former, then Requirement R1 should not mention Attachment A at all. If it is the
latter, then the as-written Attachment A is a mix bag as it on the one hand describes
the ERO’s process for supporting the Frequency Response Standard (FRS), in other
words, the method and criteria it uses to calculate the frequency bias settings and
the FRM, and on the other hand the BA’s obligations to support this process. We
strongly disagree that the latter requirements be imbedded in an attachment,
especially one that is supposed to provide the technical background and guideline for
another entity which, by the way, is not held responsible for complying with the
proposed method. An appendix is not regarded as a mandatory requirement.
Additionally, BAL-003-1- Attachment A
Consideration of Comments: Project 2007-12 Frequency Response
14
5
000751
Organization
Yes or No
Question 6 Comment
1. Criterion 5 needs to be re-written for clarity.
2. Criterion 7 refers to the “cleanest events”. Perhaps a statement of what
constitutes a “clean event” is needed to avoid possible controversy in the future.
3. The use of 59.6 Hz as the highest UFLS setting seems flawed. It should either be
59.7 Hz as a deliberate choice to protect Florida interests, or, it should be 59.5 Hz
without concern for Florida’s unique settings.
4. In the last 2 sentences at the end of the section on Frequency Response Obligation,
it refers to an Interconnection being able to offer “alternate FRO protection criteria”.
It seems that the Interconnection should have been an integral part of establishing its
obligation. Also, it states that the “ERO will confirm” the “alternate FRO protection
criteria”. Does this mean the ERO unconditionally approves it, or evaluates with a
right of rejection? Please clarify.
5. In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Does the industry have a clear and consistent definition for installed
capacity? Also, with greater wind energy development, the delivered capacity over
longer time horizons will be substantially less than nameplate machine ratings. Also,
the background document refers to the use of peak generation instead of installed
capacity. Which shall be used? Please clarify.
6. Very recent studies have shown that the 18-52 second sampling interval does not
work well for the Quebec Interconnection, in part due to the excellent and high level
of response found in that Interconnection. The standard needs to be modified such
that the sampling interval is that which works the best for each individual
interconnection.
7. Attachment A needs to define the point A sampling interval.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
Consideration of Comments: Project 2007-12 Frequency Response
14
6
000752
Organization
Yes or No
Question 6 Comment
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The drafting team believes that Criterion 5 is clear as written. The comment does not provide any guidance as to what needs
clarification so no change was made.
2. Due to the complicated nature of event evaluation and selection, the drafting team has retained the word cleanest in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
3. The drafting team has revised the terminology used to explain the frequency levels proposed. There was not a change to the
Eastern Interconnection numbers.
4. An interconnection can recommend a change to the table. As the standards process currently works, that interconnection
would need to support its alternative level with data. If the interconnection has a single Regional Reliability Organization, the ERO
would typically agree to the alternative assuming it would be more restrictive (in this case a larger response requirement) than
the ERO has recommended.
5. The drafting team has addressed the concerns raised by clarifying that historical data is used for the allocation of an
Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is not used in the
allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak) and peak
generation (monthly peak) and does not use installed capacity.
6. The drafting team has modified Attachment A to address concerns with selection of an event where frequency returns to the A
Value level during the measurement period. These events will be excluded from the measurement process for all
interconnections.
7. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
Constellation Energy
Commodities Group
Yes
Additional information relating to defining the FRO for the Interconnection would be
helpful as would an example for calculating the BA FRO.
Response: The drafting team has revised Attachment A to provide better explanation and to clarify the allocation methodology to
Consideration of Comments: Project 2007-12 Frequency Response
14
7
000753
Organization
Yes or No
Question 6 Comment
the BA.
American Electric Power
Yes
A frequency response observation should not be used spanning multiple years, or if
there does, there should at least be a reset period.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
Cleco Corporation/ SPP
Standards Review Group
Yes
We appreciate the effort of the SDT in developing Attachment A. It was very helpful
in weeding through BAL-003.
Response: Thank you for your comments.
Imperial Irrigation District
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Associated Electric
Cooperative Inc
Yes
South Carolina Electric and
Gas
Yes
Consideration of Comments: Project 2007-12 Frequency Response
14
8
000754
Organization
Ameren
Yes or No
Question 6 Comment
Yes
Consideration of Comments: Project 2007-12 Frequency Response
14
9
000755
7.
The second document “BAL-003-1 Background Document” provides information behind the development of the
standard. Do you agree that this new document provides sufficient clarity as to the development of the standard? If
not, please explain in the comment area.
Summary Consideration: The majority of the commenters referenced other questions in the comments. The SDT asked them to review
the response to those earlier questions.
Several of the commenters pointed out that there was a discrepancy between the Background Document and Attachment A regarding
the calculation of the BA FRO. The SDT has corrected the reference so both documents agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Some commenters indicated that Supplemental Regulation Service is not an appropriate method to provide Frequency Response. It is
inappropriate to expect supplementary regulation to transfer frequency response successfully. However the SDT does not want to
prevent any innovative solution that will transfer frequency response through the use of a pseudo-tie among Balancing Authorities.
Also, the SDT believes that Balancing Authorities exchanging supplementary regulation via a pseudo-tie have to be consistent in the
removal or inclusion of it in their actual net interchange measurement as well as in all events across the measurement period.
Organization
Yes or No
Seattle City Light
Negative
Question 7 Comment
Answer: Yes Comments: o LADWP and SCL note that the document “BAL-003-1
Background Document” seems to be reasonable.
Response: Thank you for your comment.
Energy Mark, Inc.
No
Comment 14: Some of the information in this document concerning the Frequency
Bias Setting for BAs participating in Overlap Regulation should be moved to the
Supporting Document. This change would help in addressing Comments 3 & 4 under
Question 2.
Response: The SDT has added language to Attachment A to address your concern.
Consideration of Comments: Project 2007-12 Frequency Response
15
0
000756
Organization
Yes or No
Duke Energy
No
Question 7 Comment
Please see our comments to Question 6. In addition, Duke Energy disagrees with the
statement on page 9 that Attachment B will “ensure there is no negative impact on
other Standards” - please see our response to Question 8 for additional information.
Response: Thank you for your comments. Please see the responses to Questions #6 and #8.
SERC OC Standards Review
Group
No
Portions of the Background Document do not appear to be complete or finished. The
Background Document should be edited to be consistent with changes made to the
standard or other related documents (eg. elimination of the definition of SEFRD and
any revisions to the draft BAL-003-1).
Response: The SDT has made significant modifications to the Background Document to support the proposed standard. The SDT is
proposing that this document be posted on the NERC web site in order for it to be easily obtained by stakeholders once the
standard is approved.
ERCOT
No
Refer to comments in #1.
Response: Refer to the response in Question #1.
Northeast Power Coordinating
Council
No
Refer to the first comment in Question 6.For the Frequency Response Standard
Background Document –
1. Cite Attachment B in addition to Attachment A in the discussion of requirement R1.
2. The Balancing Authority allocation method specified in this document does not
agree with that in Attachment A.
3. Drop the speculation on page 4 that most Balancing Authorities will be compliant.
While it may be a commonly held belief by many that there is adequate frequency
response right now, that assessment should be made after a targeted level of
reliability has been defined and approved. The same comment applies on page 12.
4. On page 6, drop the inappropriate recommendation of getting frequency response
Consideration of Comments: Project 2007-12 Frequency Response
15
1
000757
Organization
Yes or No
Question 7 Comment
through supplemental regulation. It is inappropriate to try to substitute a “minute
plus” product that is deployed centrally by the Balancing Authority for a “sub-minute”
product that is deployed automatically without any Balancing Authority action.
When a pseudo-tie is used, changes in the ACE values due to supplemental regulation
are unrelated to and not coordinated with the need to deploy frequency response.
Not only should this approach not be offered as an alternative, but the FRSDT should
actively conduct research to determine if supplemental regulation via a pseudo-tie
should be deliberately REMOVED from any actual net interchange calculation that
may include it. This comment also applies to the mentioning of supplemental
regulation on page 11 as well.
5. On page 7, the reference to a 24 hour window on each side of the frequency bias
setting implementation date is inconsistent with the wording of the standard. The
standard states that any time within the designated date is acceptable.
6. On page 8, the inclusion of “for training purposes” as a reason to not operate in tie
line bias control should be dropped. This training can be done in a training simulator.
If it is determined that it should be supported, then the requirement needs to be
reworded to allow it explicitly.
7. On page 14, the sentence: “This approach would only provide feedback for
performance during that specific event and would not provide insight into the depth
of response or other limitations” is difficult to understand. The paragraph would
read better by simply deleting the sentence.
Response: Please refer to our response to Question #6.
Comment 1 – The SDT has modified the Background Document to incorporate your suggested change.
Comment 2 – The SDT has corrected the reference so both documents agree. The drafting team is proposing to use historical
information rather than forecasted information for the allocation of the Frequency Response Obligation.
Comment 3 – The SDT has removed the speculative language and replaced it with more appropriate language.
Comment 4 - While the SDT agrees that it is inappropriate to expect supplementary regulation to transfer frequency response
Consideration of Comments: Project 2007-12 Frequency Response
15
2
000758
Organization
Yes or No
Question 7 Comment
successfully, we do not want to prevent any innovative solution that will transfer frequency response through the use of a
pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging supplementary regulation
via a pseudo-tie have to be consistent in the removal or inclusion of it in their actual net interchange measurement as well as all
events across the measurement period.
Comment 5 – The SDT has corrected the background document to accurately reflect the language proposed in the standard.
Comment 6 – The SDT has modified the background document to remove the training language.
Comment 7 – The SDT has revised the paragraph to provide additional clarity.
Xcel Energy
No
Same comment here as the one in question 6.
Response: Please refer to our response to Question #6.
ISO New England Inc
No
See first comment in 6 above. Also, Frequency Response Standard Background
Document –
1. Cite Attachment B in addition to Attachment A in the discussion of requirement 1.
2. The Balancing Authority allocation method specified in this document does not
agree with that in Attachment A.
3. Drop the speculation on page 4 that most Balancing Authorities will be compliant.
While it may be a commonly held belief by many that there is adequate frequency
response right now, that assessment should be made after a targeted level of
reliability has been defined and approved. The same comment applies on page 12.
4. On page 6, drop the inappropriate recommendation of getting frequency response
through supplemental regulation. It is inappropriate to try to substitute a “minute
plus” product that is deployed centrally by the Balancing Authority for a “sub-minute”
product that is deployed automatically without any Balancing Authority action.
When a pseudo-tie is used, changes in the ACE values due to supplemental regulation
are unrelated to and not coordinated with the need to deploy frequency response.
Not only should this approach not be offered as an alternative, but the FRSDT should
Consideration of Comments: Project 2007-12 Frequency Response
15
3
000759
Organization
Yes or No
Question 7 Comment
actively conduct research to determine if supplemental regulation via a pseudo-tie
should be deliberately REMOVED from any actual net interchange calculation that
may include it! This comment also applies to the mentioning of supplemental
regulation on page 11 as well.
5. On page 7, the reference to a 24 hour window on each side of the frequency bias
setting implementation date is inconsistent with the wording of the requirement.
The requirement says that any time within the designated date is acceptable.
6. On page 8, the inclusion of “for training purposes” as a reason to not operate in tie
line bias control should be dropped. This sort of training can be done in a training
simulator. Alternatively, if it is determined that it should be supported, then the
requirement needs to be reworded to allow it explicitly.
7. On page 14, the sentence: “This approach would only provide feedback for
performance during that specific event and would not provide insight into the depth
of response or other limitations” is difficult to understand. The paragraph would
read better by simply dropping it.
Response: Please refer to our response to Question #6.
Comment 1 – The SDT has modified the Background Document to incorporate your suggested change.
Comment 2 – The SDT has corrected the reference so both documents agree. The drafting team is proposing to use historical
information rather than forecasted information for the allocation of the Frequency Response Obligation.
Comment 3 – The SDT has removed the speculative language and replaced it with more appropriate language.
Comment 4 - While the SDT agrees that it is inappropriate to expect supplementary regulation to transfer frequency response
successfully, we do not want to prevent any innovative solution that will transfer frequency response through the use of a
pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging supplementary regulation
via a pseudo-tie have to be consistent in the removal or inclusion of it in their actual net interchange measurement as well as all
events across the measurement period.
Comment 5 – The SDT has corrected the background document to accurately reflect the language proposed in the standard.
Consideration of Comments: Project 2007-12 Frequency Response
15
4
000760
Organization
Yes or No
Question 7 Comment
Comment 6 – The SDT has modified the background document to remove the training language.
Comment 7 – The SDT has revised the paragraph to provide additional clarity.
Western Electricity
Coordinating Council
No
See response to question 6.
Response: Please refer to our response to Question #6.
Alberta Electric System
Operator
No
The Background Document uses BA Peak Generation in the BA FRO allocation
formula. Attachment A uses BA Installed Capacity. The AESO suggests making the two
formulae consistent.
Response: The drafting team has corrected the reference so both documents agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Florida Municipal Power
Agency
No
The document does not discuss how the new reliability parameter will affect BAs
Response: The new standard will require that Balancing Authorities meet a level of response to frequency events equal to or more
negative than their Frequency Response Obligation. The SDT has made significant modifications to the Background Document
which should address your concern.
JEA Electric Compliance
No
The document does not discuss how the new reliability parameter will affect BAs
Response: The new standard will require that Balancing Authorities meet a level of response to frequency events equal to or more
negative than their Frequency Response Obligation. The SDT has made significant modifications to the Background Document
which should address your concern.
MRO NSRF
No
The MRO NSRF has restated the same answer as in question 6 on purpose. Confusion
exists around the “peak load” in that Attachment A states the allocation is based on
Projected Peak Loads and Generation but the Background Document states it will use
Consideration of Comments: Project 2007-12 Frequency Response
15
5
000761
Organization
Yes or No
Question 7 Comment
a historical Peak and Generation to make the allocation. Also, for the BA installed
capacity, where is that value derived from and does NERC obtain that from FERC form
data or does the BA provide that information somewhere specific to this effort?
Additionally, there appears to be a difference in how FRO is calculated in Attachment
A and what is described in the Background Document. These differences should be
reconciled such that both documents address the same approach. If installed capacity
is used in the equation, how are variable/intermittent resources (e.g. wind, solar)
accounted for? At full capacity? Please clarify.
Page 7 (3rd paragraph) of the Background document states “Given the fact that BA’s
can encounter staffing or EMS change issues coincident with the date the ERO sets
for new Frequency Bias Setting implementation, the standard provides a 24 hour
window on each side of the target date.
1) The Standard itself does not state this provision (24 hour window on each side of
target date) as indicated.
2) The SDT accurately addresses the fact that BA’s could have EMS or staffing issues
during implementation of the ERO validated FBS. The current stated 72-hour window
is not long enough for implementation of the FBS as there may be a host of issues
that could impact implementation. We suggest that a seven day window be used for
implementation of the FBS.
Response: The drafting team has corrected the proposed standard to accurately reflect the language in the Background Document.
Texas Reliability Entity
No
There is an inconsistency between the Background Document and Attachment A.
Attachment A only proposes event criteria based on “the largest category C (N-2)
event identified,” but the Background Document says: “Attachment A proposes the
following Interconnection event criteria as a basis to determine an Interconnection’s
Frequency Response Obligation: - Largest category C loss-of-resource (N-2) event; Largest total generating plant with common voltage switchyard; - Largest loss of
generation in the interconnection in the last 10 years.”
Consideration of Comments: Project 2007-12 Frequency Response
15
6
000762
Organization
Yes or No
Question 7 Comment
Response: The drafting team has corrected the reference so both documents agree.
Great River Energy/ACES
Power Marketing Standards
Collaborators
No
We can find no document titled “BAL-003-1 Background Document”. We assume this
question is referring to the “Frequency Response Standard Background Document”
dated October 2011. We do not believe the document provides sufficient clarity. No
explanation is provided for why RSG was added to Requirement R1.There are typos
contained in the document. On page 6 in NIA, the A should be in subscript. On page
7 in bullet 4 in the first sentence, “The” should be in lowercase
Response: Your assumption was correct. The drafting team has corrected these typos.
Southern Company
No
We suggest the Background Document should be edited to be consistent with
changes made to the standard or other related documents (eg. Any revisions to draft
BAL-003-1 and removal of the definition of SEFRD).
Response: Thank you for your comments. The drafting team revised the background document based upon modifications to the
standard as well as modifications to other documents related to the standard.
Seattle City Light
Yes
o LADWP and SCL note that the document “BAL-003-1 Background Document”
seems to be reasonable.
Response: Thank you for your comments.
Constellation Energy
Commodities Group
Yes
Should be revisited based on the propposed modifications to the requirements.
Response: Thank you for your comments. The drafting team revised the background document based upon modifications to the
standard as well as modifications to other documents related to the standard.
Los Angeles Department of
Water and Power
Yes
LADWP notes that the document “BAL-003-1 Background Document” seems to be
reasonable.
Consideration of Comments: Project 2007-12 Frequency Response
15
7
000763
Organization
Yes or No
Question 7 Comment
Response: Thank you for your comments.
Keen Resources Asia Ltd.
Yes
Paragraph 4 on page 5 of the Background Document provides a statistically correct
description of event selection without sample pre-selection and should followed
instead of the erroneous criteria 2 & 7 in Attachment A. The risk-based approach to
determining FRM, that the Background Document mentions in paragraph 4 of page 4
is being evaluated by the drafting team for application in this standard, should be
considered for deployment as soon as possible to replace the administered method
currently proposed in this standard, because the administered method lacks any
technical justification. No such justification was ever attempted in the development
of this standard. The administrative method of determining FRM is therefore but a
highly dubious "quick fix" until the risk-based method is evaluated and implemented.
The administrative method is in fact perverse because it discourages BAs from
reducing their contribution to frequency error by refusing to reduce the BA's FRO
accordingly, and because it encourages BAs to contribute to frequency error without
increasing their FRO.
Response: The standard has to be written with what will be used day one. Due to the timeline that NERC has filed with FERC, there
is not enough time to adequately evaluate a second methodology.
Manitoba Hydro
Yes
Please see MH’s response to Question 1 regarding the term Single Event Frequency
Response Data.
Additionally, the discussion in this document is useful in clarifying the intent of the
drafting team, but some of this clarification would best be incorporated into the
Standard itself. Ex. RSG requirement on page 6. Also on page 7 Attachment A does
not specify what validation is and how it is done. Attachment A refers to BA providing
FBS data to ERO which then validates and publishes. This should be reflected in R2.
Response: Please refer to our response to Question 1.
The “validation” process is nothing new. The ERO presently validates the information sent in by BAs today. The ERO will not be
Consideration of Comments: Project 2007-12 Frequency Response
15
8
000764
Organization
Yes or No
Question 7 Comment
performing this process in a vacuum, but will be working with the BAs in the same manner as they presently do.
NV Energy
Yes
This is a good reference; however see response to Question 6 in that there appears to
be a discprepancy between Att A and the Background Document with regard to FRO
calculation.
Response: The drafting team has corrected the discrepancy so both documents now agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Cleco Corporation/SPP
Standards Review Group
Yes
We appreciate the effort of the SDT in developing the Background Document. It
provided insight on how the SDT got the proposed standard to where it is with this
posting.
Response: Thank you for your comment.
Imperial Irrigation District
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Florida Power & Light
Company
Yes
FPL
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
15
9
000765
Organization
Yes or No
Tucson Electric Power
Yes
Associated Electric
Cooperative Inc
Yes
South Carolina Electric and
Gas
Yes
Ameren
Yes
Hydro-Quebec TransEnergie
Yes
ISO/RTO Council Standards
Review Committee/
Independent Electricity
System Operator
Question 7 Comment
We do not have an opinion on whether or not the Background Document provides
sufficient clarity to the development of the standard. We do, however, suggest that
the SDT consider our comments in Q6, above, and move some of the information
from Attachments A and B to or combine with the Background Document, to the
Background Document to provide all the technical basis and background behind the
elements stipulated in the requirements.
Response: Please refer to our response to Question #6.
Consideration of Comments: Project 2007-12 Frequency Response
16
0
000766
8.
The SDT has developed a new document titled Attachment B – Process for Adjusting Bias Setting Floor. This document is
intended to provide the methodology the ERO will use to reduce the minimum Frequency Bias Setting to become closer to
natural Frequency Response. Do you agree that this document provides clear and concise instructions for the ERO to follow? If
not, please explain in the comment area.
Summary Consideration: The majority of commenters did not like the word “initially” that was used in the proposed standard. They
felt that it caused confusion. The SDT modified the attachment to remove the reference to the word “initially” and added
other clarifying language to the document.
Some commenters were concerned with how the calculation of FRO for BAs that have load and generation. The intent was that
generation-only BAs would base their settings on generation. Traditional BAs would use load. The SDT revised the table
to agree with the proposed standard.
One commenter indicated that the standard was measuring AGC. The SDT disagrees.. There may be some AGC influence in the
measurement however the SDT believes that this impact is minor. Based on the data received from the Field Trial, the
SDT did not see this phenomenon.
A couple of commenters indicated that the methodology used for calculation of the minimum Frequency Bias Setting could be adverse
for a single BA interconnection. The SDT explained that to ensure comparable treatment between BAs with fixed Bias
Settings, BAs with a variable Bias Setting report their monthly average Bias for the reporting year. This average will be
calculated when frequency is greater than 60.036 Hz or less than 59.964 Hz. The average of the 12 months’ Bias values
must be equal to or more negative than the Interconnection’s minimum Bias Setting.
Organization
Yes or No
Seattle City Light
Negative
Question 8 Comment
Answer: Yes Comments: o LADWP and SCL note that Attachment B seems to be
reasonable.
Response: Thank you for your comment.
Constellation Energy
Commodities Group
No
Should be revisited based on the proposed modifications to the requirements.
Consideration of Comments: Project 2007-12 Frequency Response
16
1
000767
Organization
Yes or No
Question 8 Comment
Response: The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to reflect
modifications to the requirements and suggested changes from the industry.
MRO NSRF
No
: There could be some confusion caused by the Attachment B due to the use of the
word “initially” when the reference is made to the current standard. The drafting
team should change the word “initially” to “currently” or strike it to avoid the
potential confusion.
The second paragraph of Attachment B (which contains the two bullets):The words
“initially 1%” in the second bullet contradict with the Table 1 on Attachment B, which
states “Initial” and “0.8%”. Suggest deleting the parenthetical in the second bullet as
when BAL-003-1 is effective it would be referencing an old Standard version. If the
initial minimum is intended to be 1% say so in the Table 1.
Response: The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to reflect your
suggested changes.
Texas Reliability Entity
No
1. In Attachment B, we suggest removing the paragraph beginning “The BA
calculates . . .” because it appears to be background information that conflicts
with the methods provided in this version of the standard for determining
minimum bias settings.2.
2. Attachment B, Table 1, refers to “0.8% of peak load or generation.” If a BA has
both load and generation, will its minimum Frequency Bias Setting be based on its
load, its generation, or can it pick the value that it prefers to use?
Response: The SDT agrees and has removed it from the Attachment B, now a Procedure.
The SDT intended that generation-only BAs would base their settings on generation. Traditional BAs would use load. We have
revised the table to agree with the proposed standard.
Bonneville Power
No
BPA understands the concept and we disagree with it. As the ERO continues to lower
the required minimum frequency bias setting for an interconnection, the BA’s that
Consideration of Comments: Project 2007-12 Frequency Response
16
2
000768
Organization
Yes or No
Administration
Question 8 Comment
have frequency response higher than the 1% will have a higher percentage of the
frequency response of the interconnection.
Also, this standard is primarily measuring AGC response, not natural frequency
response; therefore not lowering the limit is appropriate.
Response: The SDT believes that you may be mixing the Frequency Bias Setting and Frequency Response Measure. As proposed
the FRO will be assigned based upon load and generation as defined in Attachment A. Therefore actual Frequency Response will
be required to come from the interconnection on that basis. To the extent an entity has a FRM greater than its Interconnection’s
minimum Frequency Bias Setting, its Frequency Bias Setting may grow as a percent of the Interconnections total Frequency Bias
Setting. However, that is not Frequency Response.
The SDT disagrees with your comment concerning AGC. There may be some AGC influence in the measurement however the SDT
believes that this impact is minor. Based on the data received from the Field Trial, the SDT did not see this phenomenon.
Duke Energy
No
Duke Energy suggests that the SDT consider a term other than “Initial’ in the title for
Table 1. We suggest “Proposed Frequency Bias Setting” for Table 1. Notwithstanding
our suggestion that the criteria/requirements of the minimum FBS in the Attachment
be incorporated into the Standard, Duke Energy has the following concerns with what
is proposed:
As cited in our comments to Question 8 in the last posting (extensive, so not repeated
here), the secondary control measures of CPS1, CPS2 and the draft Balancing
Authority ACE Limit (BAAL) are tightly coupled to the Frequency Bias Setting (FBS),
and a reduction of the FBS will impact the secondary control requirements placed
upon the BA. Noted in our response to Question 7 above, the statement on page 9 in
the “BAL-003-1 Background Document”is not correct in stating that Attachment B will
“ensure there is no negative impact on other Standards”.The gradual reduction of the
FBS will proportionally tighten the secondary control limits for each Balancing
Authority. Even if the “natural” Frequency Response in the Eastern Interconnection
remains unchanged for the next several years, under the process described allowing
the ERO to annually adjust the minimum FBS for the Interconnection, the FBS will
Consideration of Comments: Project 2007-12 Frequency Response
16
3
000769
Organization
Yes or No
Question 8 Comment
eventually be reduced to a value approximately 10% above the calculated response in
magnitude, cutting the current CPS1, CPS2 and BAAL limits in the Eastern
Interconnection on average by more than half. The current FBS for the Eastern
Interconnection is approximately minus 6500 MW/0.1Hz, estimated “natural”
Frequency Response is perhaps around minus 2400 MW/0.1Hz. Unlike CPS1 and
BAAL where the measures are based upon the FBS of the BA only, CPS2 (dependent
upon the FBS of the BA and the Interconnection) will be significantly limiting to the
degree that no change in a BA’s own Frequency Response could significantly change
its CPS2 limit if the Interconnection FBS drops over time as indicated. At least under
CPS1 and the draft BAAL, the BA would have an option of improving its Frequency
Response, allowing it to increase its FBS and proportionally the CPS1 and BAAL
bounds using the FBS.
Conclusion from our last comments submitted: Duke Energy does not believe there is
a reliability need pushing the industry to tighten secondary control to the degree
discussed above simply as a result of reducing the Frequency Bias Setting. If the
calculated Frequency Response of the Interconnection stayed at its current level,
what would be the justification for tightening the secondary control requirements of
CPS1, CPS2 and the proposed BAAL? Duke Energy supports taking more of the error
out of the ACE equation by having the FBS closer to the estimated Frequency
Response of the Balancing Authority, however, Duke Energy does not believe the
result should be a significant increase in secondary control costs to meet the CPS1,
CPS2, or draft BAAL requirements. Duke Energy understands the position placed
upon this Standard Drafting Team- the secondary control and reserve requirements
are not under the scope of the team, however, proper consideration has not been
given in Attachment B to the impact lowering the FBS will have on the industry in
terms of the requirements placed upon the BA for secondary control and reserve
requirements - especially for meeting CPS2. The research discussed in our comments
to the last posting support that reducing the FBS while under CPS1 and the draft
BAAL may be achievable, however a CPS2 bound cut potentially in half or lower will
place unreasonable bounds on a BA, requiring control actions even when the BA may
Consideration of Comments: Project 2007-12 Frequency Response
16
4
000770
Organization
Yes or No
Question 8 Comment
be operating in support of the Interconnection frequency. Given the significant
impacts discussed, Duke Energy believes that additional provisions must be in place
for the Industry to approve each subsequent revision to the calculation of the
minimum Frequency Bias Setting, rather than leave it as a decision made only by the
ERO.
Response: We agree with your comment about the word "initial" in Attachment B, now a Procedure for the ERO to follow in
supporting the standard, and have removed the word “initial” from the title to remove the confusion.
We believe that your assessments about the effects on CPS2, BAAL and CPS1 are uncertain because there are complex interactions
between the Frequency Bias Setting and the ACE values in these measures that use a Frequency Bias Setting.
We agree that the words in Attachment B, now a Procedure for the ERO to follow in supporting the standard, stating "ensure there is
no negative impact on other standards" is an overstatement at this point. We have added language to allow for analysis prior to
implementing changes to the minimum Frequency Bias Setting. This is also why we have chosen to go slow with the concept of
allowing the frequency bias setting to be reduced below 1% of Peak Load.
We agree with your support of taking more of the error out of the ACE equation by making the FBS closer to the estimated Frequency
Response of the Balancing Authority; however, we do not agree that the effects of secondary control can be ignored when we make
these changes. Therefore we are proposing a “go slow approach” to making this happen and included checks to confirm there are
not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Attachment B, now a Procedure for the ERO to follow
in supporting the standard, to make the initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will
evaluate the impact caused by a change in minimum Bias Setting. The evaluation will look at both frequency performance and
impact on CPS-related compliance calculations.
We support your comment related to the ERO working with the Industry to approve each subsequent revision to the minimum FBS.
However, it is this drafting team’s understanding that the language in the standard is limited to referencing the ERO and the ERO will
develop a process to address the needs of the standard. Therefore, no modification has been made to require any specific
coordination between the ERO and the Industry.
Consideration of Comments: Project 2007-12 Frequency Response
16
5
000771
Organization
Yes or No
Sacramento Municipal Utility
District (SMUD)
No
Question 8 Comment
In addition to the requirements, reducing frequency bias obligation results in
generation tripping closer to the set point.
It seems that Lowering the Minimum Frequency Bias Setting from 1% to .8% will
result in a lower response, which in turn will lower the natural frequency response.
Over time it seems this pattern would lead to poorer response.
Response: The SDT is unsure of what your first comment is attempting to say. Therefore the SDT cannot provide a response to
your comment without further clarification.
The SDT believes that you may be mixing the Frequency Bias Setting and Frequency Response Measure. As proposed the FRO will
be assigned based upon load and generation as defined in Attachment A. Therefore actual Frequency Response will be required
to come from the Interconnection on that basis. To the extent an entity has an FRM greater than its Interconnection’s minimum
Frequency Bias Setting, its Frequency Bias Setting may grow as a percent of the Interconnection’s total Frequency Bias Setting.
However, that is not Frequency Response.
NV Energy
No
In Attachment B, it seems unclear whether the initial FB setting is supposed to be 1%
of BA peak load or 0.8% as shown in the table. In general, I was extremely confused
about what the required FB setting should be. R5 indicates a percentage of load
found in Att B, but Att B indicates the greater of Natural Frequency Response or 1%
of peak, and then the table that follows indicates 0.8%. At this point, I have no idea
what is being stated for the requirement.
Response: The SDT agrees and has modified the attachment.
The SDT intended that generation-only BAs would base their settings on generation. Traditional BAs would use load. We have
revised the table to agree with the proposed standard.
Progress Energy
No
PGN supports the collective comments of SERC members. We suggest the SDT
consider a term other than “Initial’ in the title for Table 1. We suggest “Proposed
Frequency Bias Setting” for Table 1
Consideration of Comments: Project 2007-12 Frequency Response
16
6
000772
Organization
Yes or No
Question 8 Comment
Response: The SDT agrees with your comments and has made corresponding modifications to the attachment by removing the
word, “initial”.
Independent Electricity
System Operator
No
Please see our comments under Q6. In brief, we do not agree with including a
process description type of document as part of the standard requirement.
Response: Please refer to our response to Question #6.
ISO/RTO Council Standards
Review Committee
No
Please see our comments under Q6. In brief, we do not agree with including a
process description type of document as part of the standard requirement. Process
description should be regarded guideline document and not a part of the standard
requirement.
Response: Please refer to our response to Question #6.
Tucson Electric Power
No
Reducing a BAs frequency bias setting may have an adverse impact on recovering
from a frequency event once you get past the first 8-10 seconds. A larger bias will
allow for actual and sustained AGC generator responses. Industry focus should be on
generator governor response within the first 8-10 seconds.
Response: The Standard Drafting Team disagrees with your comment. Full recovery is dependent upon the contingent BA
recovering from its loss. However, we do agree that secondary frequency support from the non-contingent BAs may not be as
robust.
Northeast Power Coordinating
Council
No
Refer to the first comment in Question 6.
Response: Please refer to our response to Question #6.
Hydro-Quebec TransEnergie
No
The methodology proposed to compute the Minimum Frequency Bias Setting (in
MW/0,1Hz) could be adverse for the Quebec Interconnection. Hydro-Quebec uses a
Consideration of Comments: Project 2007-12 Frequency Response
16
7
000773
Organization
Yes or No
Question 8 Comment
variable Bias that is calculated based upon which generator is online and it’s droop
setting. Under light load condition, we might have a Bias setting that would be under
(in absolute value) than the FRM which is the median value, even though the Bias
setting would reflect the grid’s frequency response. This method, as proposed, would
mandate us to have a larger Bias that what is really needed. Unlike Eastern
Interconnection, we are not over biased. By implementing this new methodology, it
would make us over biased. Having a too large Bias could lead to system instability,
based on the results of studies from our control specialists. The Minimum Frequency
Bias Setting should take into account the wide load span that we can face.
For the variable bias, we could express the Minimum Frequency Bias Setting as a
function of monthly peak loads, and remove the Natural Frequency Response term.
In addition, there is a gap between Attachment B and the text in R5. See comment
10 for explanation.
Response: To ensure comparable treatment between BAs with fixed Bias Settings, BAs with a variable Bias Setting report their
monthly average Bias for the reporting year. This average will be calculated when frequency is greater than 60.036 Hz or less than
59.964 Hz. The average of the 12 months’ Bias values must be equal to or more negative than the Interconnection’s minimum Bias
Setting.
Xcel Energy
No
There could be some confusion caused by the Attachment B due to the use of the
word “initially” when the reference is made to the current standard. The drafting
team should change the word “initially” to “currently” or strike it to avoid the
potential confusion.
Response: The SDT agrees with your comment and has modified the attachment to remove the word, “initially”.
Florida Power & Light
Company
No
There is no technical justification provided either in the attachment or background
data for the initial starting value of 0.8%. This is acceptable but is arbitary.
Additionally, the last sentense on page 1 of Attachment B should be changed to read
" the ERO must reduce ( in absolute value) the minimum Frequency Bias Settings for
BA's within that Interconnection, by 0.1 percentage point from its previous annual
Consideration of Comments: Project 2007-12 Frequency Response
16
8
000774
Organization
Yes or No
Question 8 Comment
value, to better match the Frequency Bias Setting to the natural Frequency Response
or provide technical justification for not implementing the reduction
Response: You are correct, the starting value is arbitrary. The SDT did not want to make a one step change to immediately reduce
the minimum Frequency Bias Setting to natural Frequency Response. The SDT believes that a multi-year multi-step process would
be better and allows for monitoring the effects on other performance standards.
The SDT believes that the end result would be the same. The present wording allows for collaboration between the ERO and
other entities/groups. The SDT is also concerned with putting a requirement on the ERO within an Attachment when there is not
a reliability problem if it were not to happen.
SERC OC Standards Review
Group
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
South Carolina Electric and
Gas
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
ISO New England Inc
No
We suggest the SDT to first determine if the materials in the revised Attachment A &
B are “Guideline” or Technical Background”, or are they “requirements”. If it is the
former, then Requirement R1 should not mention Attachment A at all. If it is the
latter, then the as-written Attachment A is a mix bag as it on the one hand describes
the ERO’s process for supporting the Frequency Response Standard (FRS), in other
words, the method and criteria it uses to calculate the frequency bias settings and
the FRM, and on the other hand the BA’s obligations to support this process. We
strongly disagree that the latter requirements be imbedded in an attachment,
especially one that is supposed to provide the technical background and guideline for
another entity which, by the way, is not held responsible for complying with the
Consideration of Comments: Project 2007-12 Frequency Response
16
9
000775
Organization
Yes or No
Question 8 Comment
proposed method. An appendix is not regarded as a mandatory requirement.
Response: The process is still being developed at NERC but an Attachment would document processes to be utilized without a
measurement saying that you failed the standard.
Southern Company
No
We suggest using the words, ‘Proposed Frequency Bias Setting’ in the Title of Table 1
instead of the word, ‘Initial’.
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
ERCOT
No
While there is no problem with the calculation involved, it is unclear why the SDT
elected to assign a grid performance element in this standard to the ERO, who has no
functional (registered) role in grid performance. Since this is a cook-book calculation
and transfer of data on frequency performance, why not assign it to the BA?
Response: The Attachment B, now a Procedure for the ERO to follow in supporting the standard, only outlines a process that the
ERO is to use when adjusting the minimum Frequency Bias Setting. The Procedure does not place any grid performance
requirement on the ERO. The SDT also believes that some authority should have oversight over the minimum setting to prevent
abuses and assure fairness.
Seattle City Light
Yes
o LADWP and SCL note that Attachment B seems to be reasonable.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Energy Mark, Inc.
Yes
Comment 15: This Yes answer assumes that the SDT addresses Comment 13 under
Question 6 in these comments.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT addressed your Comment #13
under Question #6.
Ameren
Yes
Considering the comments made regarding R5, in question 2, above, which are:
Consideration of Comments: Project 2007-12 Frequency Response
17
0
000776
Organization
Yes or No
Question 8 Comment
R5. While we agree with the requirement of R5, it should not be at the expense of
changing the value of L10 in BAL-001, R2, which has been accepted by FERC in Order
693. An accommodation should be made so that any changes to the Frequency Bias
Setting according to BAL-003, R5, should not affect the value of L10 used in BAL-001,
R2.
Response: The SDT thanks you for your affirmative response and clarifying comment. However, the SDT disagrees with your
comment. Since L10 is the function of individual Frequency Bias Settings to the sum of all BA Frequency Bias Settings within an
Interconnection and establishes operating boundaries, it would be inappropriate to leave L10 as is when a Frequency Bias Setting
changes.
Los Angeles Department of
Water and Power
Yes
LADWP notes that Attachment B seems to be reasonable
Response: The SDT thanks you for your affirmative response and clarifying comment.
FPL
Yes
Last paragraph: As stated, would that make the Minimum Frequency Bias Setting
0.7% of peak load or generation? A numerical example shown would help clarify this
paragraph.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT has added an example to the
Background Document.
Southwest Power Pool
Regional Entity
Yes
Need to clarify that 2012 Bias setting will be based on 1% of peak load or generation
until approval of BAL-003-1 by FERC establishing the .08% of peak load or generation
minimum threshold.
Response: We agree and we have endeavored to do so. The SDT does point out that the proposed minimum for the first year
once approved by FERC is 0.9% not 0.08%.
Associated Electric
Yes
This is a very important document, providing bounds and rationale for and future
Consideration of Comments: Project 2007-12 Frequency Response
17
1
000777
Organization
Yes or No
Cooperative Inc
Question 8 Comment
changes, as well as initial settings going into ballot. As such, it is AECI's understanding
that, upon going into effect, this BAL-003-1 will utilize these initial settings.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
Salt River Project
Yes
FMPP
Yes
American Electric Power
Yes
Cleco Corporation
Yes
Manitoba Hydro
Yes
Great River Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
17
2
000778
Consideration of Comments: Project 2007-12 Frequency Response
17
3
000779
9.
The SDT has provided an additional spreadsheet, FRS Form 2, to assist the Balancing Authority in providing the data needed to
comply with the proposed standard. Do you agree that this spreadsheet is useful and the instructions are meaningful? If not,
please explain in the comment area.
Summary Consideration: Many of the commenters expressed concern with the fact that the Excel Spreadsheets that were required to
be used were in a newer version of Excel than their company was presently using. In response, the SDT developed Excel Spreadsheets
that are compatible with earlier versions of Excel.
A couple of commenters expressed concern that the Excel Spreadsheets did not contain all of the information necessary to comply with
the analysis required (timing of the event (hour, minute, second). Form 1 contains the time of the event including the hour, minute and
second for t(0) and a graph of frequency data for each event in the list. The time for each BA’s t(0) may vary from this time due to
different sample rates of data and physical proximity to the contingency. Since this standard does not identify an “A Point” or “B Point”
but calculates an “A Value” and “B Value”, providing an exact time for these provides little value. T(0) is the focus of the measurement
process and is the first observed change in frequency of the event. Also added to Form 1, the BA can enter the time zone of its data and
the time of t(0) will be converted to the correct time in that zone. We agree that the proper selection of t(0) is important. This can be
viewed on the “Graph 20 to 52s” worksheet. When set correctly, the first change in frequency of the event will be exactly in the center
of the graph on the vertical grid line.
Some commenters felt that it would be useful if the SDT could develop a completed form as an example to help entities better
understand the methodologies used in the form. Form 2 contains actual data for frequency and NAI of an event. Sample data was
added for each of the adjustments to demonstrate their use and impact on the analysis.
A couple of commenters question the meaning of “master event list” in FRS Form 2. The “Master event list” refers to the event list
contained in each Interconnection’s Form 1.
Organization
Yes or No
Question 9 Comment
Seattle City Light
Negative
Answer: No Comments: o LADWP and SCL note that Form 2 is not compatible with
prior versions of Excel-it won’t even open in Excel 2003 (which is still widely used)and requests that all spreadsheets and calculation tools developed under 2007-12 be
revised to support common software of the past 10 years.
Consideration of Comments: Project 2007-12 Frequency Response
17
4
000780
Organization
Yes or No
Question 9 Comment
Response: Excel 2003 versions of all forms have been developed.
Seattle City Light
No
o LADWP and SCL note that Form 2 is not compatible with prior versions of Excel-it
won’t even open in Excel 2003 (which is still widely used)-and requests that all
spreadsheets and calculation tools developed under 2007-12 be revised to support
common software of the past 10 years.
Response: Excel 2003 versions of all forms have been developed.
Associated Electric
Cooperative Inc
No
AECI believes the SDT could spare our industry both confusion and inconsistency, by
specifying that identified Interconnection Disturbances include both Point A and
Point B to the hour, minute, and second. While this introduces some risk of Entities
over-automating their data-reports, the benefits for Eastern Interconnection
respondents would be tremendous. Cautions and disclaimers should be placed on
both Form 1 and Form 2, to assure respondents manually inspect their frequency
data and pinpoint the specific inflection-point samples.
Response: Form 1 contains the time of the event including the hour, minute and second for t(0) and a graph of frequency data for
each event in the list. The time for each BA’s t(0) may vary from this time due to different sample rates of data and physical
proximity to the contingency. Since this standard does not identify an “A Point” or “B Point” but calculates an “A Value” and “B
Value”, providing an exact time for these provides little value. T(0) is the focus of the measurement process and is the first
observed change in frequency of the event. Also added to Form 1, the BA can enter the time zone of its data and the time of t(0)
will be converted to the correct time in that zone. We agree that the proper selection of t(0) is important. This can be viewed on
the “Graph 20 to 52s” worksheet. When set correctly, the first change in frequency of the event will be exactly in the center of the
graph on the vertical grid line.
Bonneville Power
Administration
No
BPA believes the form is not easily understood and is overly complicated for what it is
trying to accomplish. BPA believes the form might work for an internal evaluation,
just not for an external audit. Compliance is based on this form. BPA believes the
standard needs to be simplified and possibly returned to a data gathering standard.
Consideration of Comments: Project 2007-12 Frequency Response
17
5
000781
Organization
Yes or No
Question 9 Comment
Response: The addition of “Adjustments” to the analysis did add complexity to the Form. These were added based on comments
received from the industry on previous postings. Some of these “Adjustments” may be removed as the field trial progresses if
they are not utilized. In the latest Form 2, version 6, the multiple time period averages were removed since the final average
period was selected based on the results of the first round of the field trial evaluated last fall. However, Form 2 is important to
the standard in that it achieves the requirement of measuring frequency response in the same manner for all Interconnections.
Returning Form 2 with Form 1 allows validation of the selection of t(0) which is critical for this requirement.
The SDT does not believe that it can revert back to a “data gathering” standard. The SDT is responding to FERC Directives from
Order 693 as well as the FERC Order dated March 18, 2010 which mandated development of a standard addressing the Order 693
directives within six months. FERC later granted an extension to provide a standard addressing these issues by the end of May
2012.
FPL
No
FRS Form 2 - Two-second Sample DataInstructions tab/worksheet: What is referred
to as or meant by the ‘master event list’?
4. - Regarding 2 second sample rate for 25 minutes starting 2 minutes before event
begins and 15 minutes after it begins, does this add up to 25 minutes or are
additional minutes being required for collection? Also, FPL can report frequency at
this rate, but can only report load in MW every four seconds. Move to 4 second
sample rate.6-8. - Possible to add button to auto-populate cells C8 and C11 in ‘Entry
Data’ tab from the new column C and cell identifying the desired frequency change
time and simplify these steps?
10. - Clarify where the “Copy” button is. Is it the one in the ‘Data’ tab or worksheet?
Entry Data tab/worksheet:Step 6 should also be or be moved to the “Instructions”
worksheet.Are the values in column C in the “Data” worksheet labeled “Total Lost
Generation” the same as those in column AQ in the “Evaluation” worksheet? If so,
why are they not both labeled “Net Actual Interchange”?
What is the definition of “Non Conforming Load” in column E?
Response: “Master event list” refers to the event list contained in each Interconnection’s Form 1.
Consideration of Comments: Project 2007-12 Frequency Response
17
6
000782
Organization
Yes or No
Question 9 Comment
The inconsistency in the data sample totals has been corrected. The absolute minimum amount of data required for the full
analysis is two minutes before the beginning of the event to 15 minutes after the beginning of the event. The calculation rate of
“Load” can be at a different rate than the AGC scan rate. The Load data is not used in measuring performance. The variability of
Load can impact measured performance and can be observed on the “BA Load Dampening” worksheet graph. On some
Interconnections, load dampening can be observed in the data. Using the historian “data sample” collection option, it will fill the
spreadsheet with the same value of Load, changing at the calculation rate.
The “auto populate” of cells C8 and C11 is a good idea. A couple BAs did this during the first phase of the field trail. The problem
is that the event time of t(0) in column C was set using 2 second scan data in one part of the Interconnection and the beginning of
the event may be shifted one or two scans when frequency is scanned less often. This would make this automation difficult for
the value in C8. It is critical for the measure for t(0) be set correctly. The value of C11 is less critical and is not used in the initial
primary Frequency Response Measure. It is only used to demonstrate delivery of primary frequency response during the
frequency recovery period.
The location of the “Copy” button has been clarified.
Step 6 on the “Data Entry” worksheet was added to the “Instructions” worksheet. The value in column C in the “Data” worksheet
labeled “Total Lost Generation” is for single BA Interconnections only. It takes the place of “Net Actual Interchange” for multiple
BA Interconnections. Column “AO” on the “Evaluation” worksheet is not the same as the “Contingent BA Lost Generation” data
on the “Evaluation” worksheet. The “Contingent BA Lost Generation” data is only used by multiple BA Interconnection BAs not
Single BA Interconnections. The “Data” worksheet for the “Single BA Interconnection” Forms has an n/a in columns G, H and I and
should not be used by BAs in these Interconnections. This is noted on their “Instructions” worksheet. This should explain why
they are not labeled the same.
Non-conforming Load is Load that changes abnormally different than the conventional diurnal load pattern of a Balancing
Authority Area. Non-conforming Load becomes significant when the net change within a few minutes is greater than a BA’s L 10
limit. The importance here is that this Load change can be ten times larger than some BAs’ FRO and makes measuring the SEFRD
inaccurate. An example of non-conforming load would be an arc furnace of a significant size.
Thank you for your comments and the effort to find each of these items.
ISO/RTO Council Standards
Review Committee
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet
file. Apart from that, however, there are other sheets added to the previous Form 1.
But this Comment form makes no mention of the changes, nor is there a question in
Consideration of Comments: Project 2007-12 Frequency Response
17
7
000783
Organization
Yes or No
Question 9 Comment
the Comment Form asking whether the additional information should be requested.
We believe this is a significant change to the standard and many commenters may
have missed the opportunity to comment on it. Compared to the previous version,
Form 1 has been significantly expanded to include not only additional sheets but
much more comprehensive data requirements even on the Data Entry sheet itself.
This makes data submission a very time-consuming task but the justification for
requiring detailed data entry has not been provided.
We question the need for such expansion on data entry requirements. We have yet
to see the reason for expanding Form 1 in assisting a BA to provide the data needed
to comply with the standard, hence we do not see how adding a Form 2 can help in
that regard. We suggest the SDT to keep data requirements to only what is minimally
needed to support the FRS reporting process. Where the SDT deems additional data
entry sheets to be necessary, it should provide the rationale for expanding from a 2
sheet form into a multiple sheet form for additional data collection. Where the SDT
deems the additional data sheet or information not necessary to support FRS
reporting, then we suggest the SDT to hide those pages not required for the standard
so as to avoid confusion, and/or to remove those analytical pages not directly used in
the standard.
Response: The SDT points out that there are no additional data requirements. It is possible that you are seeing more
spreadsheets due to them being unhidden.
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the ability of the BA to enter the time zone of its data and the
spreadsheet will calculate the local time of the event from the UTC time. This was added for the convenience of the BA in
collecting the correct data for each event and does not require additional data from the BA. The second worksheet added was a
worksheet that displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data
collection and the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This
graph worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this
worksheet will greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous
Consideration of Comments: Project 2007-12 Frequency Response
17
8
000784
Organization
Yes or No
Question 9 Comment
versions. The absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the
“Data” worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in
the ACE equation and is important to BAs that utilize variable Bias. Column K, BA Load, was added by the drafting team in the
beginning to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I
of the “Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
Independent Electricity
System Operator
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet
file. Apart from that, however, there are other sheets added to the previous Form 1.
But this Comment form makes no mention of the changes, nor is there a question on
the additional information requested. We have a concern over this omission of
attention or oversight. Compared to the previous version, Form 1 has been
significantly expanded to include not only additional sheets but much more
comprehensive data requirements even on the Data Entry sheet itself. This makes
data submission a very time-consuming task but the justification for requiring
detailed data entry has not been provided. We question the need for such expansion
on data entry requirements. We have yet to see the reason for expanding Form 1 in
assisting a BA to provide the data needed to comply with the standard, hence we do
not see how adding a Form 2 can help in that regard. We suggest the SDT to look at
the basic need for data submission that would suffice to support the FRS reporting
process. Where the SDT deems additional data entry sheets to be necessary, it should
provide the rationale for expanding from a 2 sheet form into a multiple sheet form
for additional data collection.
Response: The SDT points out that there are no additional data requirements. It is possible that you are seeing more
spreadsheets due to them being unhidden.
Consideration of Comments: Project 2007-12 Frequency Response
17
9
000785
Organization
Yes or No
Question 9 Comment
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the ability of the BA to enter the time zone of its data and the
spreadsheet will calculate the local time of the event from the UTC time. This was added for the convenience of the BA in
collecting the correct data for each event and does not require additional data from the BA. The second worksheet added was a
worksheet that displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data
collection and the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This
graph worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this
worksheet will greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous
versions. The absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the
“Data” worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in
the ACE equation and is important to BA’s that utilize variable Bias. Column K, BA Load, was added by the drafting team in the
beginning to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I
of the “Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
Los Angeles Department of
Water and Power
No
LADWP notes that Form 2 is not compatible with prior versions of Excel-it won’t even
open in Excel 2003 (which is still widely used)-and requests that all spreadsheets and
calculation tools developed under 2007-12 be revised to support common software
of the past 10 years.
Response: Excel 2003 versions of all forms have been developed.
Tucson Electric Power
No
TEP feels that Form 2 is a useful tool for internal BA use and should not be used for
compliance purposes.
Response: Form 2 is not intended to be used to reflect compliance but rather for consistency in reporting.
Consideration of Comments: Project 2007-12 Frequency Response
18
0
000786
Organization
Yes or No
Question 9 Comment
Form 2 was developed so consistent analysis of each event could be validated. During the first round of the field trial, many BAs
selected the incorrect t(0), some provided data that was filtered or utilized data compression techniques that caused the analysis
to be incorrect. With Form 2, the selection of t(0) can be quickly evaluated and data quality reviewed. The proper selection of t(0)
can be made and Form 1 corrected providing validated consistent results.
MRO NSRF
Yes
: It would be useful if the drafting team could develop a completed form as an
example to help entities better understand the methodologies used in the form
Response: All versions of Form 2 contain actual data for frequency and NAI of an event. Sample data was added for each of the
adjustments to demonstrate their use and impact on the analysis.
Xcel Energy
Yes
It would be useful if the drafting team could develop a completed form as an example
to help entities better understand the methodologies used in the form.
Response: All versions of Form 2 contain actual data for frequency and NAI of an event. Sample data was added for each of the
adjustments to demonstrate their use and impact on the analysis.
Ameren
Yes
We agree that the spreadsheet is meaningful, but still needs to be vetted through the
field trial process, with improvements made based on experience in its use.
Response: We completely agree.
Imperial Irrigation District
Yes
Northeast Power Coordinating
Council
Yes
SERC OC Standards Review
Group
Yes
SPP Standards Review Group
Yes
Consideration of Comments: Project 2007-12 Frequency Response
18
1
000787
Organization
Yes or No
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Southern Company
Yes
Energy Mark, Inc.
Yes
Florida Power & Light
Company
Yes
FMPP
Yes
ISO New England Inc
Yes
NV Energy
Yes
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
Cleco Corporation
Yes
Manitoba Hydro
Yes
Constellation Energy
Commodities Group
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 9 Comment
18
2
000788
Organization
Yes or No
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Duke Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 9 Comment
18
3
000789
10.
Please provide any other comments (that you have not already provided in response to the questions above) that you have on
the draft standard BAL-003-1.
Summary Consideration: Many of the commenters referenced other questions in the comments. The SDT asked them to review
the response to those earlier questions rather than repeating the responses here.
Several commenters pointed out that there was a discrepancy between the Background Document and Attachment A regarding
the calculation of the BA FRO. The SDT has corrected the reference so both documents agree. The drafting team is proposing to
use historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Several other commenters indicated that Supplemental Regulation Service was not an appropriate method to provide Frequency
Response. The SDT agrees that it is inappropriate to expect supplementary regulation to transfer Frequency Response
successfully, however the SDT did not want to prevent any innovative solution that will transfer Frequency Response through the
use of a pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging Supplementary
Regulation via a pseudo-tie have to be consistent in the removal or inclusion of Supplementary Regulation in their actual net
interchange measurement as well as in all events across the measurement period.
Many commenters were concerned that the BA could be responsible for supplying an infinite amount of Frequency Response.
They indicated that a BA could not prepare for this in its planning process. The SDT agrees that the proposed standard was not
clear on this subject and added language in the “Criteria for Selection of Events” section of the revised Attachment A to limit the
amount of Frequency Response a BA would be required to provide in order to be compliant with the standard.
Some commenters were concerned with the wording in Requirement R5. They indicated that the wording needed to say “greater
than or” instead of “at least”. The SDT removed the requirement and combined it with the revised Requirement R2 and the new
Requirement R3. The SDT has modified the requirement and believes we have implemented the intent of your suggestion.
Many commenters did not agree with requiring the BA to provide Frequency Response. The NERC Functional Model and FERC
both cited the BA as the responsible entity for providing Frequency Response. T There are several different methods available to
the BA to provide Frequency Response and the SDT has included these in the Background Document.
Some commenters were concerned with the threshold that the SDT recommended for the Eastern Interconnection. Florida sees a
greater change in frequency for a given contingency than for a comparable event elsewhere in the East. This is the reason for
the higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry extra frequency responsive
reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a contingency inside
Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW of frequency
Consideration of Comments: Project 2007-12 Frequency Response
18
4
000790
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
A few commented did not agree with lowering the minimum Frequency Bias Setting. Early research by Nathan Cohn on
interconnected power system operations found that control is optimum if a BA’s Bias Setting is equal to its natural Frequency
Response. If there were to be a difference between the two values, it is preferable to be slightly over-biased. The drafting team
has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is outlined in a
Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to making this
happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations. Based on
concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting 0.9% of
peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Some commenters had concerns about the use of the RSG as a means to provide Frequency Response, and the SDT modified the
Background Document to further explain how an RSG (now FRSG) could supply Frequency Response. The SDT has defined a new
term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve Sharing
Group” could cause confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities
that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response Obligations
of its members.”
A couple of commenters indicated that the median was not the proper method to use for the calculation of the FRM. Statisticians
note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is small and
or where scores vary widely. This is the case when estimating a BA’s Frequency Response. While the median is not perfect, the
median approaches a BA’s typical performance after 15-20 observations and more observations give a higher confidence in the
estimate of the BA’s performance.
Organization
Yes or No
Question 10 Comment
MRO NSRF
Negative
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard. Except for Table 2 in Attachment A,
there is no discussion of an amount of FR expected on a total basis. Balancing
Authorities need to know for how many tenths of a hertz they are to respond so they
Consideration of Comments: Project 2007-12 Frequency Response
18
5
000791
Organization
Yes or No
Question 10 Comment
can determine how to plan to meet this requirement. The documents do not appear
to provide any boundary on the maximum amount of FR that a BA will provide, i.e. it
is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is
the BA expected to provide a limitless amount of frequency response?).
Also, is that event excluded from the list used to calculate the Balancing Authorities’
response or is it included with an expectation that it counts the same as any other
event. Without a clear statement of what is expected, including whether there is a
limit on that expectation or not, the Balancing Authorities cannot know what is
expected of them and therefore cannot plan appropriately.
In the first paragraph of R5 delete “at least” and replace with “greater than or”. This
phrase would now read “…absolute value is greater than or equal to one of the
following:” “Equal to or greater than” accurately identifies the expectation, the
current phrasing will lead to confusion and mis-interpretation.
Bullet #1 of R5: The minimum % is based upon the “estimated yearly Peak Demand”.
During the NERC webinar it was mentioned that this minimum would move to being
based on historical reporting of Peak Demand. Where does the SDT stand on this
item? Please provide clarification.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Consideration of Comments: Project 2007-12 Frequency Response
18
6
000792
Organization
Yes or No
Muscatine Power & Water
Negative
Question 10 Comment
"MPW agrees with the comments submitted by the MRO-NSRF."
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
JDRJC Associates
Negative
Support Midwest ISO Comments
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Lincoln Electric System
Negative
Please see comments submitted by the MRO NSRF. (See comments for Question 5
submitted by the MRO NSRF.)
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
Consideration of Comments: Project 2007-12 Frequency Response
18
7
000793
Organization
Yes or No
Question 10 Comment
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Madison Gas and Electric Co.
Negative
Please see the MRO NSRF comments
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Midwest Reliability
Organization
Negative
Please see the comments submitted by MRO NSRF. As MRO Sector 10 we agree with
MRO NSRF position and recommendation to vote negative for this ballot.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Muscatine Power & Water
Negative
"MPW agrees with the comments submitted by the MRO-NSRF."
Consideration of Comments: Project 2007-12 Frequency Response
18
8
000794
Organization
Yes or No
Question 10 Comment
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Nebraska Public Power
District
Negative
NPPD joins it’s comments with comments submitted by the Midwest Reliability
Organization - NERC Standards Review Forum (MRO NSRF) submitted on December
8, 2011.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Omaha Public Power District
Negative
Please see MRO's comments submitted via Comment Form.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
Consideration of Comments: Project 2007-12 Frequency Response
18
9
000795
Organization
Yes or No
Question 10 Comment
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
FirstEnergy Corp.; FirstEnergy
Energy Delivery; FirstEnergy
Solutions;Ohio Edison
Company
Abstain
FirstEnergy appreciates the hard work of the drafting team but needs more time to
review the standard with internal business units and with our RTO. Therefore at this
time we must abstain.
Response: The SDT thanks you for your clarifying comment.
Abstain
As a qualified professional statistician I abstain from voting "affirmative" or
"negative" on this standard because it violates two fundamental statistical best
practices.
1. In the Standard, the definition of Frequency Response Measure (FRM) is
statistically wrong. The median is an improper statistical measure of Frequency
Response because --it truncates large excursions which are the specific subject of
Frequency Response control, not normal operating frequency errors which are selfcorrecting and are the subject of CPM control; --it is non-linear; --it is non-summable
over the interconnection; in other words, the individual BA medians don't add up to
the interconnection median, in complete incompatibility with CPM control which
requires summability of BA performances into the interconnection's performance.
Moreover, it is mathematically impossible to sum the medians of the BAs in a
Reserve Sharing Group (RSG) into the RSG's median: in other words, the RSG's
median cannot represent the sum of the medians of its members. The last paragraph
on page 5 of the Background Document is patently wrong, invented, and supported
in no probability & statistics literature whatsoever. As a practicing statistician, I
hereby give testimony to the utter falsehood of the statement that "In general,
statisticisns use the median as the best measure of central tendency when a
Consideration of Comments: Project 2007-12 Frequency Response
19
0
000796
Organization
Yes or No
Question 10 Comment
population has outliers." (See http://www.robertblohm.com/BestStatistic.doc for an
explanation of "best statistic" which is a highly technical and central topic in modern
probability theory and statistics.) Also, "outliers" are falsely and rhetorically claimed
to be "noise" when in fact they are the "events" that are the specific subject of
Frequency Response. It is well known that they do not "fit" a normal distribution.
They are distinct from the normal operating errors that are the subject of CPM
control. The paragraph does correctly conclude that the linear regression more
accurately incorporates outliers than the median does, although the paragraph uses
rhetoric by calling this improvement "skew" as if it is distortionary when, in fact, the
median distorts the reality.
2. The sample pre-selection described in Attachment A, Event Selection, Criteria 2 &
7, violates the fundamental statistical procedure of unbiased sampling. A population
is governed by a single "process" which, when stationary, is represented by a fixed
probability distribution. In this case the population is several years of events (which
are the subject of Frequency Response), not of normal operating control errors
which are the subject of CPM control. A sample is governed by a single process that
approximates the process governing the population as the sample gets larger, in this
case if it includes several years of data. Samples are measured "as they come", no
triage/filtering allowed, and they are called "stratified" when their distribution
approximates the population distribution. Unlike normal operating errors, samples of
events are not evenly distributed over a year. The attempt in criteria 2 & 7 to preselect only certain events, and not others, in such a way that the selected events
occur evenly throughout the year, is papently wrong because it is trying to "fit"
events into a process (even distribution over time) that does not govern events, but
that instead governs normal operating errors that are the subject of CPM control,
not of this Frequency Response standard. In other words, criteria 2 & 7 confuse
Frequency Response with CPM, and events with normal operating errors. The result
is a false, biased sample which destroys the integrity of this standard. Paragraph 4 on
page 5 of the Background Document, on the other hand, provides a statistically
correct description of event selection without sample pre-selection and should
Consideration of Comments: Project 2007-12 Frequency Response
19
1
000797
Organization
Yes or No
Question 10 Comment
followed instead of the erroneous criteria 2 & 7 in Attachment A. The reason I do not
vote "negative": the risk-based approach to determining FRM, that the Background
Document mentions in paragraph 4 of page 4 is being evaluated by the drafting team
for application in this standard, should be considered for deployment as soon as
possible to replace the administered method currently proposed in this standard,
because the administered method lacks any technical justification. No such
justification was ever attempted in the development of this standard. The
administrative method of determining FRM is therefore but a highly dubious "quick
fix" until the risk-based method is evaluated and implemented. The administrative
method is in fact perverse because it discourages BAs from reducing their
contribution to frequency error by refusing to reduce the BA's FRO accordingly, and
because it encourages BAs to contribute to frequency error without increasing their
FRO.
Response: The word “average” is a generic term to represent central tendency. The term is often used synonymously with the
arithmetic “mean”.
The issue with measuring Frequency Response is that a BA’s calculated performance (as opposed to actual performance) is highly
variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the East typically is only called to contribute
about 10-15 MW for the loss of a large unit. Its minute to minute Load changes can easily wash this contribution out. An arithmetic
mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
Consideration of Comments: Project 2007-12 Frequency Response
19
2
000798
Organization
Yes or No
Question 10 Comment
confidence in the estimate of the BA’s performance.
Associated Electric
Cooperative, Inc.
Affirmative
Please see comments submitted by John Bussman of AECI. Thanks, Chris Bolick
Response: Please refer to our earlier question responses to Mr. Bussman’s comments.
Southwest Power Pool, Inc.
Negative
Please refer to the IRC Standards Review Committee comments which SPP is a party
to for our concerns and recommendations for this standard.
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
City Utilities of Springfield,
Missouri
Affirmative
SPRM supports the comments from SPP.
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
Oklahoma Gas and Electric Co.
Affirmative
See comments submitted by the Southwest Power Pool
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
Electric Reliability Council of
Texas, Inc.
Affirmative The Applicability of BAL-003-1 should be clarified. Specifically, Section 1.2 should be
changed from “Reserve Sharing Groups (where applicable)” to “Reserve Sharing Group
whose intent includes meeting Frequency Response Obligations”.
Regarding Data Retention:
1. As the standard is currently drafted, both the BA and the RSG would be
required to retain data or evidence to show compliance with requirements R1
and M1. It is unclear whether this is the intention, or whether it would be
acceptable that just one or the other would maintain such records.
2. In the first and second paragraph, the reference to ‘three calendar years’
should be specified to be the ‘previous three calendar years’.
3. In the third paragraph, it should be clarified who is required to keep
Consideration of Comments: Project 2007-12 Frequency Response
19
3
000799
Organization
Yes or No
Question 10 Comment
information related to non compliance if the BA belongs to an RSG – the BA or
the RSG or both.
4. In the fourth paragraph, it should be clarified for what length of time the last
audit records must be retained.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.” The SDT has modified the Background Document to further
explain how an RSG (now FRSG) can be used to supply Frequency Response.
1 & 3 - The SDT believes that the reporting entity would be the responsible entity to maintain records. The SDT also believes that
once a BA has declared itself as part of an FRSG then the FRSG would be the responsible entity with the obligation to maintain
records.
2 - The SDT agrees with your second comment and has made this modification.
4 – The last audit record should be kept until the next audit.
Midwest ISO, Inc.
Affirmative
We would like to thank the drafting team for developing a standard responsive to
the FERC Orders.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SCE&G
Affirmative
We feel that frequency response is a function of a contingency event and the
Purpose Statement should recognize this relationship. We suggest the following
insertion in the Purpose Statement. Purpose: To require sufficient Frequency
Response from the Balancing Authority to maintain Interconnection Frequency
within predefined bounds by arresting frequency deviations (due to a contingency
event) and supporting frequency until the frequency is restored. To provide
consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Consideration of Comments: Project 2007-12 Frequency Response
19
4
000800
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT believes that the Purpose
Statement you are recommending is basically the same as what the SDT is proposing. For this reason the SDT has decided to
propose their Purpose Statement for use in the proposed standard.
SERC Reliability Corporation
Affirmative
Please see comments submitted by the SERC Operating Committee standards
subgroup for technical suggestions to improve the standard.
Response: Please refer to the earlier question for the SDTs responses.
Tennessee Valley Authority
Affirmative
Comments submitted by SERC OC Standards Review Group. TVA votes affirmative
with comments previously submitted by SERC.
Response: Please refer to the earlier questions for the SDTs responses.
Louisville Gas and Electric Co.
Negative
We support the comments in the SERC OC Standards Review Group Comments.
Response: Please refer to the earlier questions for the SDTs responses.
AEP, AEP Marketing, AEP
Service Corp.
Negative
AEP's negative ballot is primarily due to our concerns regarding R1. Comments are
being submitted via electronic form by Thad Ness on behalf of American Electric
Power.
Response: Please refer to our response for Question #1.
Alberta Electric System
Operator
Negative
Besides the standard, the posting has two attachments, supporting material and two
forms. It is not clear how enforcement will be applied given the array of explicit and
implicit requirements throughout this package, and the use of undefined
terminology, which will be subject to interpretations.
In the SDT response to our comments to the first draft of this standard it was stated
that “The expectation is events will be selected by the Balancing Authorities. The
Balancing Authority may exclude events from consideration for specific conditions
Consideration of Comments: Project 2007-12 Frequency Response
19
5
000801
Organization
Yes or No
Question 10 Comment
such as data quality issues. “ Based on the SDT’s response, it is our understanding
that, for the purpose of the FRM calculation, BAs could exclude or include events
based on specific conditions consideration, such as data quality or event suitability
(e.g. BA separation from the Interconnection). However, the standard as currently
drafted, does not have any provisions to this effect. Please include such provisions in
the body of the standard.
Response: The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments
that requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to
be attached to the standard such that it cannot be changed without input from the industry.
The SDT recognizes that data may not be available for specific events and therefore has provided in FRS Form 1 a means to
exclude an event. Additionally if an entity has separated from an Interconnection this could be reason for excluding that event
from its FRM calculation since the frequency it would be responding to would not be the Interconnection wide frequency. The risk
caused by excluding events is that the measurement process has shown that a limited number of events does not provide suitable
calculation.
Ameren Energy Marketing
Co.; Ameren Services
Negative
We believe that this is good start to a worthwhile standard, but the following issues
need to be addressed in this standard:
(1) The FRM methodology has not been fully vetted through the field trial process.
(2)Adjusting the minimum of the Frequency Bias Setting, while an appropriate
adjustment for AGC control in the ACE equation, should not be at the expense of L10
as used in BAL-001, R2.
(3) The absence of any resource specific frequency response requirement in NERC
standards is an issue that must be address somewhere. As the resource portfolio of
our industry changes(expedited by recent EPA rulemaking), the resources used for
traditional primary frequency response are becoming a lower percentage of the mix.
New resources and existing resources that have not provided primary frequency
response need to be incorporated into the available frequency response discussion.
(4) BAL-003 is only applicable for an interconnected system, conditions that are
Consideration of Comments: Project 2007-12 Frequency Response
19
6
000802
Organization
Yes or No
Question 10 Comment
created by islanding and other emergences are not address here(nor should they),
but need to be address within the EOP family of standards, so that adequate primary
frequency response is available during emergency situations.
Response: (1) – The issue with measuring Frequency Response is that a BA’s calculated performance (as opposed to actual
performance) is highly variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the Eastern Interconnection typically is only
called to contribute about 10-15 MW for the loss of a large unit. Its minute to minute Load changes can easily wash this contribution
out. An arithmetic mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
confidence in the estimate of the BA’s performance.
- The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related
calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial
minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in
minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
(2) - The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
19
7
000803
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
Frequency Response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
(3) – The SDT agrees that the issue you cite should not be covered in this standard. The SDT will forward this comment on to the
appropriate entity at NERC.
PJM Interconnection, L.L.C.
Negative
PJM does not believe that the BA should be the entity responsible for the frequency
response obligation, moreover the SDT has not sufficiently vetted the issue of
applying the response requirements on an entity that cannot provide that service.
PJM is concerned that the proposed draft does not explicitly cover the FERC Order
693 directives in the proposed requirements and rather addresses the directives
indirectly in the attachments. This matter of mandatory vs. informational
attachments must be formally clarified before approval can be given for this
approach.
PJM does not agree with the additional clarifying phrases being incorporated into the
requirements. Explanatory phases should be included as text boxes as proposed in
NERC’s Risk Based Methodology.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
19
8
000804
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Potomac Electric Power Co.
Negative
The proposed standard is not reliability centered and will not improve reliability. 5)
Potomac Electric Power Company supports the comments provided by PJM.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
Consideration of Comments: Project 2007-12 Frequency Response
19
9
000805
Organization
Yes or No
Question 10 Comment
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Atlantic City Electric Company
Negative
See comments submitted by David Thorne in Segment 1, Potomac Electric Power
Company
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Avista Corp.
Negative
This standard should be designed for each interconnection explicitly rather than one
size fits all. Frequency is an interconnection issue and response is driven by the
interconnection's topology. One size does not fit all for interconnections. This
Consideration of Comments: Project 2007-12 Frequency Response
20
0
000806
Organization
Yes or No
Question 10 Comment
standard should be designed around the explicit needs of each interconnection.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
Response: The SDT believes that an Interconnection has the capability to request a variance (especially one that is more restrictive),
however the SDT has tried to prevent the need for variances by respecting the individuality of each of the Interconnections in
setting Interconnection Frequency Excursion Threshold Values, Interconnection Frequency Response Obligations and the Frequency
Bias Setting Minimums as noted in Attachment A.
Early research by Nathan Cohn5 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
We thank the SDT for their hard work and diligence in moving this Project forward.
However, I have some concerns that cause me to not support the standard in its
current form. In general, I believe that there has not been sufficient prudency review
for the standard, especially R1, to justify a performance based standard around a
Frequency Response Measure.
I also believe that the proposed standard does not meet the intent of the Final SAR
5
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
20
1
000807
Organization
Yes or No
Question 10 Comment
or Supplemental SAR. The “Final SAR” was to develop methods by which a
performance based standard would eventually be developed. The Final SAR states:
“The proposed standard’s intent is to collect data needed to accurately model
existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed
reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be modeled,
and the reasons for the decline in Frequency Response can be identified. Once the
reasons for the decline in Frequency Response are confirmed, requirements can be
written to control Frequency Response to within defined reliability parameters.”
BAL-003-1 is beyond the scope of this “Final SAR”. For instance, “the reasons for the
decline in Frequency Response” were not confirmed to our knowledge; and the field
trial is not completed to our knowledge. The Supplemental SAR adds to the scope of
the Final SAR: “To provide a minimum Frequency Response Obligation for the
Balancing Authority to achieve, methods to obtain Frequency Response and provide
a consistent method for calculating the Frequency Bias Setting for a Balancing
Authority. In addition, the standard will specify the optimal periodicity of Frequency
Response surveys.” Please note that the Standards Development Roadmap does not
confirm whether this Supplemental SAR was ever approved; hence, I question
whether this is actually part of the scope of the SDT. Be that as it may, the
Supplemental SAR does not eliminate the pre-requisite contained in the Final SAR to
determine the reasons for the decline in frequency response and confirm them
before establishing “defined reliability parameters”. In addition, the standard does
not meet the scope requirements of the Supplemental SAR.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
The SDT agrees that the original SAR was strictly for data collection. However, a supplemental SAR was developed to address the
FERC March 18, 2010 Order and was subsequently approved by the industry.
Consideration of Comments: Project 2007-12 Frequency Response
20
2
000808
Organization
Yes or No
Constellation Energy
Commodities Group
Negative
Question 10 Comment
Please see submitted comments for additional detail behind the negative vote.
Response: Please see the SDT responses to your comments to the earlier questions.
Energy Mark, Inc.
Negative
The issue of Median, Mean, Regression needs to be resolved using Field Trial data.
This should be able to be completed before the end of January 2012.
The FRO and Minimum Bias Setting allocations should be determined using a single
allocation method and a single data set.
Wording changes are needed in the Requirements to indicate compliance in all cases
for all BAs.
In general, although this standard has many weaknesses, its implementation with
small modifications will be better than failure to implement it.
Response: The drafting team is recommending use of the median for the purposes of determining a BA FRM over multiple events.
This decision is based on the determination that, while it may not be perfect, it is better than the other alternatives available at
this time. The drafting team recognizes that in the future a better methodology might be found; based on the data available at
this time the median allows us to move forward to implement a response requirement.
The drafting team understands your concern of using the historical numbers for the FRO allocation and the projected number as
the basis for the minimum Frequency Bias Setting. However, after discussions, the drafting team believes that at this time,
minimizing the changes to the current Frequency Bias Setting process provides better comparability for the purpose of evaluating
the impacts of reducing the minimum setting requirement. In the alternative, the drafting team feels that allocating the FRM
based on historical data provides less room to game the process since the numbers used for allocation can be verified
independently.
The SDT has modified the requirements and believes that your concern has now been addressed.
The SDT thanks you for your comment.
Energy Mark, Inc.
Negative
The Time Horizon for R1 is Operations Assesment. It should be Real Time. Frequency
Consideration of Comments: Project 2007-12 Frequency Response
20
3
000809
Organization
Yes or No
Question 10 Comment
Response is a service that is automatic. It does not require operator action to
activate the service. It requires that the operator set-up the system to provide the
automatic response before an event requiring Frequency Response occurs. Unlike
other Real Time services, if the operator fails to set-up the system to provide this
service before Real Time, there is no action that the operator can take to provide the
service in response to an event. Many other actions in the standards required by the
system operator are considered to be Real Time because the operator can take
action after an event occurs. It does not make sense to consider an action that must
be taken before Real Time as Operations Assessment.
Response: The requirement does not fall into a single category. The operator is constantly taking actions some of which were set
in a “longer term” horizon, some in a “real-time” horizon and this is an after-the-fact measure.
Fort Pierce Utilities Authority
Negative
FPUA supports the comments submitted by Florida Municpal Power Agency (FMPA)
through the formal comment process.
Response: Please refer to the SDT response to the comments received from FMPA in the earlier questions.
Hydro One Networks, Inc.
Negative
Hydro One is casting a negative vote for this project. We support and subscribe to
the comments submitted by NPCC on behalf of its members.
In summary, the comments are:
1 o Use of 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz.
2 o Use of installed capacity in determining the Frequency Response Obligation.
3 o The sampling interval should be tuned on a per Interconnection basis to support
HQTE’s characteristics.
4 o NPCC does not advocate the use of supplemental regulation as a method of
procuring frequency response.
5 o BAL-003-1 is applicable only to Balancing Authorities and Reserve Sharing
Consideration of Comments: Project 2007-12 Frequency Response
20
4
000810
Organization
Yes or No
Question 10 Comment
Groups. A common concern that has been expressed in the industry is that the
burden of compliance is being placed solely on Balancing Authorities while the main
sources of discretional frequency response are generators.
6 o Balancing Authorities must be able to provide sufficient frequency response and
be able to and the proper frequency bias settings applied in their AGC systems are
necessary.
7 o In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Is there a clear and consistent definition for installed capacity?
Considering the growth of wind energy development, the delivered energy from
wind generation over longer time horizons will be substantially less than the machine
nameplate ratings.
8 o The background document refers to the use of peak generation instead of
installed capacity. Which shall be used?
o Additional minor issues for the SDT consideration that should be addressed:
? A link should be provided in the standard to FRS Form 1, or instructions
provided for how entities may find the form.
? In the definitions, FRS should be spelled out before using the acronym.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for its higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2, 7 & 8 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses
“historical data” to circumvent the problem you have described.
Consideration of Comments: Project 2007-12 Frequency Response
20
5
000811
Organization
Yes or No
Question 10 Comment
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
5 – The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
Consideration of Comments: Project 2007-12 Frequency Response
20
6
000812
Organization
Yes or No
Question 10 Comment
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
6 – The SDT agrees with you comment.
Additional minor issues
The Forms will be put on a NERC website and announced once the standard is approved.
The definition no longer reference FRS Form 1.
Independent Electricity
System Operator
Negative
The complete IESO’s comments on the revised standard are provided through the
electronic comment form. The summary below highlights IESO's major concerns with
the revised standard:
1)The definition for Frequency Response Measure (FRM): The proposed FRM
definition: “The median of all the Frequency Response observations reported
annually on FRS Form 1” is problematic. It references an FRS Form 1 which is not
included in the definition itself but is in fact an attachment to the standard. In the
current NERC Glossary of Terms, there is no such precedence that a definition must
rely on the requirements or details in a standard for completeness. Also, it is very
cumbersome that when changes are made to FRS Form 1, the definition must be
posted for industry comment and balloting, and vice versa. When other standards
begin using the term, there will be cross references between standards. This further
complicates the update/maintenance problem without any appreciable value. (See
complete comment in Section Q1 in the electronic comment form)
2)Attachment A: Attachment A should include only the event selection process and
calculations associated with the requirements, including an explanation of what is
necessary if variable Frequency Bias Settings are implemented. If other
"requirements" need to be specified, such as the reporting time frame stipulated on
page 3 of Attachment A, they should be moved to the standard itself but not
imbedded in an attachment. (See complete comment in Section Q6 in the electronic
Consideration of Comments: Project 2007-12 Frequency Response
20
7
000813
Organization
Yes or No
Question 10 Comment
comment form)
3)The expanded FRS Form 1 and the addition of a Form 2 ask for data entry that is
excessive and whose value has not been demonstrated. (See complete comment in
Section Q9 in the electronic comment form)
Response: 1) The SDT has modified the definition to no longer reference FRS Form 1. The definition now reads “The median of all
the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO. This
will be calculated as MW/0.1Hz.”
2) The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain date
and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
indicated requirements were in the Attachments. In order to explain the process, the drafting team believes the information
needs to be attached to the standard such that it cannot be changed without input from the industry.
3) The SDT points out that there are no additional data requirements. It is possible that you are seeing more spreadsheets due to
them being unhidden.
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the BA to enter the time zone of its data and have the spreadsheet
calculate the local time of the event from the UTC time. This was added for the convenience of the BA in collecting the correct
data for each event and does not require additional data from the BA. The second worksheet added was a worksheet that
displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data collection and
the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This graph
worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this worksheet will
greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous versions. The
absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the “Data”
worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in the ACE
equation and is important to BA’s that utilize Variable Bias. Column K, BA Load, was added by the drafting team in the beginning
to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I of the
Consideration of Comments: Project 2007-12 Frequency Response
20
8
000814
Organization
Yes or No
Question 10 Comment
“Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
ISO New England, Inc.
Negative
ISO New England will not vote to approve the standard because it fails to place
requirements on generators to provide frequency response. There are four
substantive problems:
1 • Using 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz
2 • Using installed capacity in determining the Frequency Response Obligation
3 • The sampling interval needs to be tuned on a per Interconnection basis to
support HQTE’s characteristics
4 • Do not advocate the use of supplemental regulation as a method of procuring
frequency response
Additionally, the SDT must decide on what the purpose of this standard is. If it is to
respond to Order 693 then the standard misses the point of defining how often to
run Frequency Response Surveys; it does not crisply define the “Interconnection”
obligations. If the SDT does want to focus on performance then the issue of who is
the default provider must be addressed. As the IRC has noted previously, all BAs do
not own the service providers. To create standards that apply to entities that are
dependent on other function entities to comply with a standard requirement is of
great concern.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
Consideration of Comments: Project 2007-12 Frequency Response
20
9
000815
Organization
Yes or No
Question 10 Comment
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
21
0
000816
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
6 – The SDT agrees with you comment.
Additional minor issues
The Forms will be put on a NERC website and announced once the standard is approved.
The definition no longer reference FRS Form 1.
JEA
Negative
JEA is not comfortable with a performance based standard as written without more
field testing to ensure that net interchange is not skewed by load and generation
changes that are not a function of frequency. Since frequency response has
components from load and generation resources, and load is not controllable for the
most part, seems this standard should be directed at specific generator response
methods from the GO/GOP's.
This is a wide reaching standard. And, this is a performance standard (if it doesn't
perform as designed, it is a violation). Because of this, more testing needs to be
completed so we know the model is correct. We are not sure we know how to
ensure compliance.
Don't agree the standard needs to be performance based.
Response: Based on the studies performed by the SDT, the drafting team believes that a calculation of the median of multiple
Consideration of Comments: Project 2007-12 Frequency Response
21
1
000817
Organization
Yes or No
Question 10 Comment
events addresses the concerns raised by the noise being inside a single event. The studies from the field trial show a convergence
of the measurement after approximately 20 to 25 events.
The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which mandated
development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to provide a
standard addressing these issues by the end of May 2012.
Kansas City Power & Light Co.
Negative
The proposed Standard BAL-003-1 does not consider the real time operating
conditions under which this standard should apply. There are no considerations for
the complexities introduced by capacity energy agreements between BA's nor
consideration of the differing level of Interconnection Frequency Response needed
at times of minimum interconnection load conditions and interconnection peak load
conditions.
Response: The method for determining the FRO is based upon the determination of the largest contingency that could occur at any
time and does not vary based upon time of day or system conditions. Since the largest contingency could occur at any time, the
minimum Frequency Response Obligation necessary to manage the contingency will not be dependent upon the differing conditions
that can occur during different times of the day like those referred to in the question.
Lakeland Electric
Negative
In general; here has not been sufficient prudency review for the standard, especially
R1, to justify a performance based standard around a Frequency Response Measure.
Refer to comments submitted by FMPA on LAK behalf.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
Please refer to the SDT response to the comments received from FMPA in the earlier questions.
Liberty Electric Power LLC
Negative
Voting no due to SDT addressing FERC directives with attachments instead of in the
standard requirements.
Response: The SDT disagrees with your concern about addressing FERC directives within an attachment. If a requirement
Consideration of Comments: Project 2007-12 Frequency Response
21
2
000818
Organization
Yes or No
Question 10 Comment
references specific performance in an Attachment, then the performance described in the Attachment is mandatory and
enforceable.
Manitoba Hydro
Negative
The Applicability of BAL-003-1 should be clarified. Specifically, Section 1.2 should be
changed from “Reserve Sharing Groups (where applicable)” to “Reserve Sharing Group
whose intent includes meeting Frequency Response Obligations”.
Regarding Data Retention:
1. As the standard is currently drafted, both the BA and the RSG would be
required to retain data or evidence to show compliance with requirements R1
and M1. It is unclear whether this is the intention, or whether it would be
acceptable that just one or the other would maintain such records.
2. In the first and second paragraph, the reference to ‘three calendar years’
should be specified to be the ‘previous three calendar years’.
3. In the third paragraph, it should be clarified who is required to keep
information related to non compliance if the BA belongs to an RSG – the BA or
the RSG or both.
4. In the fourth paragraph, it should be clarified for what length of time the last
audit records must be retained.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.” The SDT has modified the Background Document to further
explain how an RSG (now FRSG) can be used to supply Frequency Response.
1 & 3 - The SDT believes that the reporting entity would be the responsible entity to maintain records. The SDT also believes that
once a BA has declared themselves as part of a FRSG then the FRSG would be the responsible entity to maintain records.
2 - The SDT agrees with your second comment and has made this modification.
4 – The last audit record should be kept until the next audit.
Consideration of Comments: Project 2007-12 Frequency Response
21
3
000819
Organization
Yes or No
Question 10 Comment
New Brunswick Power
Transmission Corporation
Negative
The compliance burden should not fall on the BA as the provider of Frequency
Response (i.e. Primary Control response). In this case the BA per se has no assets,
moreover the primary response service providers have no obligations to provide the
service, thus the BA potentially could face a situation where there is no physical
service to be purchased but there is a mandated standard to comply with. The idea
of creating a Primary Response Market as some have proposed does not work
without an obligation on some entity to physically provide that service.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
New York State Department
of Public Service, National
Association of Regulatory
Utility Commissioners
Negative
After review of the standard and draft comments to be submitted by industry
participants, it appears that there are many areas of the proposed standard that
require clarification.
Response: The SDT thanks you for your participation. Please be more specific about what needs clarification so the SDT can
address your specific concerns.
Consideration of Comments: Project 2007-12 Frequency Response
21
4
000820
Organization
Yes or No
Northeast Power Coordinating
Council
Negative
Question 10 Comment
This standard as written does not place requirements on generators to provide
frequency response. There are four substantive problems:
1 • Using 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz.
2 • Using installed capacity in determining the Frequency Response Obligation.
3 • The sampling interval needs to be tuned on a per Interconnection basis to
support HQTE’s characteristics.
4 • Do not advocate the use of supplemental regulation as a method of procuring
frequency response.
It must be decided as to what the purpose of this standard is. If it is to respond to
Order 693 then the standard misses the target of defining how often to run
Frequency Response Surveys; it does not crisply define the “Interconnection”
obligations. If performance is the focus, then the issue of who is the default provider
must be addressed. All BAs do not own the service providers. To create standards
that apply to entities that are dependent on other functional entities to comply with
a standard requirement is of great concern.
FRS Form 1 is listed as being an Associated Document. Will it be attached to the
standard?
The acronym FRS is used in the standard. FRS should be spelled out before its
acronym is used.
If FRS Form 1 will not be an appendix or an attachment to the document, then a link
should be provided to it, or instructions given on how to find it.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4000 MW
Consideration of Comments: Project 2007-12 Frequency Response
21
5
000821
Organization
Yes or No
Question 10 Comment
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
Consideration of Comments: Project 2007-12 Frequency Response
21
6
000822
Organization
Yes or No
Question 10 Comment
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
New Brunswick System
Operator
Negative
Please see comments submitted by the NPCC Reliability Standards Committee and
the IRC Standards Review Committee
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
Consideration of Comments: Project 2007-12 Frequency Response
21
7
000823
Organization
Yes or No
Question 10 Comment
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
Consideration of Comments: Project 2007-12 Frequency Response
21
8
000824
Organization
Yes or No
Question 10 Comment
approved.
The definition no longer reference FRS Form 1.
New York Independent
System Operator
Negative
The NYISO's comments are included with both the Joint IRC/SRC and Joint NPCC RSC
comments.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Consideration of Comments: Project 2007-12 Frequency Response
21
9
000825
Organization
Yes or No
Question 10 Comment
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
Rochester Gas and Electric
Corp.
Negative
RG&E supports comments to be submitted to NPCC.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
Consideration of Comments: Project 2007-12 Frequency Response
22
0
000826
Organization
Yes or No
Question 10 Comment
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
Consideration of Comments: Project 2007-12 Frequency Response
22
1
000827
Organization
Yes or No
Question 10 Comment
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
Orlando Utilities Commission
Negative
Per LPPC comments
Response: The SDT is not sure of the entity you are referencing (LPPC). Therefore, the SDT cannot respond to your comment
without further clarification.
Portland General Electric Co.
Negative
PGE agrees with the WECC whitepaper including the comments and concerns.
Negative
The PPL Companies do not support proposed Reliability Standard BAL-003-1
(Frequency Response and Frequency Bias Setting) primarily because PPL believes it
inappropriately subjects Reserve Sharing Groups (RSGs) to the proposed
requirements. The proposed Applicability provision states that the mandatory
reliability requirements would be applicable to (1) Balancing Authorities and (2)
Reserve Sharing Groups (where applicable). However, it is unclear how the proposed
requirements would be applicable to an RSG. RSGs typically do not provide a
mechanism for sharing automatic Frequency Response. The BA Frequency Response
Response: see WECC comments.
PPL Electric Utilities Corp.; PPL
Generation LLC
Consideration of Comments: Project 2007-12 Frequency Response
22
2
000828
Organization
Yes or No
Question 10 Comment
Obligation (FRO) is a formula based on BAs and the Interconnection and has nothing
to do with RSGs. Rather, RSGs collectively respond to requests for activation of
contingency reserves generally after the request is made by a member Balancing
Authority. The Standard Drafting Team should therefore remove RSGs from the
Applicability section and should remove all other references to RSGs in the proposed
standard.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
PPL EnergyPlus LLC
Negative
Please refer to PPL's corporate comments.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Seattle City Light
Negative
LADWP and SCL support project 2007-12’s general approach to frequency response,
and is prepared to support the ballot once several problematic details are corrected.
o LADWP and SCL note that the time allowed to analyze the final “official” set of 25
events for each year, from Dec 15 to Jan 10, is relatively short and coincides with the
holiday vacation season
Response: The ERO will be posting preliminary events throughout the year. The criteria contained in Attachment A should allow
an entity to evaluate events as they occur. This coupled with the Forms 1 & 2 should allow an entity to be looking forward
throughout the year. In addition the standard allows 30-days for providing information.
Consideration of Comments: Project 2007-12 Frequency Response
22
3
000829
Organization
Yes or No
Question 10 Comment
Seattle City Light
Negative
SCL would like to see addressed in the Standard how the case is to be addressed
where a BA simply has no frequency response information to provide, as could
happen for a small 1-2 generator BA which has its generators out of service for an
extended period for maintenance or upgrades. Assuming the BA purchases
frequency response services from another entity during this period, is the BA out of
compliance with the proposed Standard simply because it has no data report? And
how is its next-year obligation to be computed? These issues should be addressed in
the Measures or Additional Compliance information. If these are issues for “lawyers”
as the Standards Drafting Team indicated during the November 14, 2011, webinar
then the team should engage a NERC lawyer to resolve them prior to releasing the
Standard for ballot.
o Finally, SCL points out that the proposed Standard introduces a new obligation on
applicable entities to maintain frequency responsive reserves. Although this
obligation does not appear to be unreasonable or problematic in general,
compliance may prove difficult for some entities and in some localized areas.
Response: The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Consideration of Comments: Project 2007-12 Frequency Response
22
4
000830
Organization
Yes or No
Question 10 Comment
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
Public Utility District No. 1 of
Snohomish
County/Snohomish County
PUD No. 1
Negative
Public Utility District No. 1 of Snohomish County supports the comments filed by
Seattle City Light.
Response: The ERO will be posting preliminary events throughout the year. The criteria contained in attachment A should allow
an entity to evaluate events as they occur. This coupled with the Forms 1 & 2 should allow an entity to be looking forward
throughout the year. In addition the standard allows 30-days for providing information.
The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
South California Edison
Negative
SCE's "No" vote, like the WECC position, regarding Project 2007-12 is based on the
Consideration of Comments: Project 2007-12 Frequency Response
22
5
000831
Organization
Yes or No
Company
Question 10 Comment
following five points:
1) Clarification is needed whether there will/ will not be conflicts between proposed
Requirement R3 and the requirements of FERC-approved regional reliability standard
BAL-004-WECC-1 - Automatic Time Error Correction
2) Confusion exists between Attachment A and the Background Document:
2a) Attachment A states peak load allocation is based on “Projected” Peak
Loads and Generation, versus
2b) The Background Document which states it will use “historical” Peak Load
and Generation.
3) Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
4) There is no clear statement of what is expected from the Balancing Authorities
and whether or not there is a limit on that expectation.
5) Why are there no requirements on governor installation, settings, and operation
for a frequency response standard?
Response: 1) The SDT has removed Requirement R3. The SDT believes that this requirement is duplicative of BAL-005-0.1b
Requirements R6 & R7.
2) The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3) Early research by Nathan Cohn6 on interconnected power system operations found that control is optimum if a BA’s Bias Setting
is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
6
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
22
6
000832
Organization
Yes or No
Question 10 Comment
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
4) The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency Response that
a BA will be required to provide
5) The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Western Area Power
Administration
Negative
1. Reducing frequency bias obligation is a detriment to reliability of interconnection
and the proposed standard aims to reduce the bias obligation from the current
minimum level of 1% load to 0.8% and subsequently to a lower percentage.
2. The proposed standard is very confusing and complex in regard to data collection
Consideration of Comments: Project 2007-12 Frequency Response
22
7
000833
Organization
Yes or No
Question 10 Comment
and compliance.
3. The proposed standard is encompassing reserve sharing group (where applicable),
why? What reserve sharing group operates AGC?
It is not clear whether the compliance period is monthly or yearly for R1 & R5.
The issue of non-binding standard and whether it serves a purpose to go through
complicated data submission and found in compliance or out of compliance without
any consequences.
Response: 1. Early research by Nathan Cohn7 on interconnected power system operations found that control is optimum if a BA’s
Bias Setting is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to
be slightly over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
3. The SDT has modified the Background Document to provide additional information and clarity.
4. The SDT modified R1 so that it no longer applies to an RSG _ the SDT defined new term, “Frequency Response Sharing Group”
to address stakeholder concerns that the RSG is not the correct entity. The definition of Frequency Response Sharing Group is:
A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of its members.
3. Requirement R1 is calculated on an annual basis. The SDT has removed Requirement R5 and combined it into Requirement R2
7
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
22
8
000834
Organization
Yes or No
Question 10 Comment
and new Requirement R3.
The SDT made modifications to Attachment A to try to distinguish mandatory performance assigned to the BA from process steps
performed by the ERO.
Xcel Energy, Inc.
Negative
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard. Except for Table 2 in Attachment A,
there is no discussion of an amount of FR expected on a total basis. Balancing
Authorities need to know for how many tenths of a hertz they are to respond so they
can determine how to plan to meet this requirement. The documents do not appear
to provide any boundary on the maximum amount of FR that a BA will provide, i.e. it
is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is
the BA expected to provide a limitless amount of frequency response?). Also, is that
event excluded from the list used to calculate the Balancing Authorities’ response or
is it included with an expectation that it counts the same as any other event. Without
a clear statement of what is expected, including whether there is a limit on that
expectation or not, the Balancing Authorities cannot know what is expected of them
and therefore cannot plan appropriately.
Response: The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency
Response that a BA will be required to provide.
Negative
59.6 Hz should be used as the Eastern Interconnection URLS.
Installed capacity should always be used determining an area's frequency response
obligation.
I question the use of supplemnetal regulation as a method of procuring frequency
response. Is this an acceptable practice throughout all NERC Regions?
Each Balancing Authority must be able to provide the required or calculated
frequency response and be able to incorporate the proper frequency bias settings in
Consideration of Comments: Project 2007-12 Frequency Response
22
9
000835
Organization
Yes or No
Question 10 Comment
the Balancing Authority's AGC system.
A link should be provided in the proposed standard to FRS Form 1.
Response: Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the East.
This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry extra
frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical data”
to circumvent the problem you have described.
The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
Consideration of Comments: Project 2007-12 Frequency Response
23
0
000836
Organization
Yes or No
Question 10 Comment
The SDT agrees with you comment.
The Forms will be put on a NERC website and announced once the standard is approved.
END OF REPORT
Consideration of Comments: Project 2007-12 Frequency Response
23
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000837
Consideration of Comments
Project 2007-12 Frequency Response
(BAL-003-1)
The Project 2007-12 Drafting Team thanks all commenters who submitted comments on the proposed
standard, BAL-003-1 which was posted for a 30-day formal comment period from October 5, 2012
through November 6, 2012. Stakeholders were asked to provide feedback on the standard and
associated documents through a special electronic comment form. There were 50 sets of comments,
including comments from approximately 144 different people from approximately 100 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
Based on industry comments the drafting team made the following clarifying modifications to the
proposed standard and associated documents.
•
•
•
•
Made clarifying changes to the proposed standard including replacing the term “…subject to…: with
“…in accordance with…” in Requirement R2.
Clarified the description of the calculation for the Interconnection IFRO in Attachment A.
Modified Attachment A and the Procedure to provide consistency with the use of the term
“resource contingency criteria”.
Corrected typographical errors in all documents.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000838
Index to Questions, Comments, and Responses
1.
The SDT has made minor modifications to the proposed definition for Frequency Response Measure
based on industry comments. Do you agree that these modifications provide sufficient clarity? If not,
please explain in the comment area. ....................................................................................................... 11
2.
The SDT has created a definition for Frequency Response Sharing Group. The definition is as follows: A
group whose members consist of two or more Balancing Authorities that collectively maintain,
allocate, and supply operating resources required to jointly meet the Frequency Response Obligations
of its members. Do you agree with this definition? If not, please explain in the comment area. .......... 16
3.
The SDT has added Requirement R3 for entities using variable Frequency Bias. R3. Each Balancing
Authority that is a member of a multiple Balancing Authority Interconnection, is not receiving Overlap
Regulation Service and utilizing a variable Frequency Bias Setting shall maintain a Frequency Bias
Setting that is: 3.1 Less than zero at all times, and 3.3 Equal to or more negative than its Frequency
Response Obligation when Frequency varies from 60 Hz by more than +/-0.036 Hz. ............................ 22
4.
Based on Industry comments the SDT has modified ”Attachment A- Supporting Document” to provide
additional clarity. Do you agree with the modifications? If not, what modifications do you disagree
with? ......................................................................................................................................................... 29
5.
The SDT has moved a portion of the material located in Attachment A and all of the material located in
”Attachment B- Process for Adjusting Bias Setting Floor” into a new document “Procedure for ERO
Support of Frequency Response and Frequency Bias Setting Standard”. The SDT created this document
to assign tasks to the ERO and provide instructions for the ERO to follow when carrying them out
under the BAL-003-1 standard. Do you agree that the ERO should perform these tasks and that this
document provides sufficient detail for the ERO to do it under the BAL-003-1 standard? If not, what
needs to be added to the document?”. ................................................................................................... 49
6.
The SDT is now using the method detailed in the Frequency Response Initiative Report dated
September 30, 2012 to calculate the Interconnection Frequency Response Obligation. Do you agree
that this method provides for the proper amount of Frequency Response? If not, what specifically
needs to be changed? .............................................................................................................................. 59
7.
Based on Industry comments received the SDT made significant clarifying modifications to the
Background Document. Do you agree that this document provides sufficient information to justify the
rationale used by the SDT in developing the draft standard an provides the industry with sufficient
understanding of the issues being addressed by the standard? ............................................................. 66
8.
If you are not in support of this draft standard, what modifications do you believe need to be made in
order for you to support the standard? Please list the issues and your proposed solution to the issue.
.................................................................................................................................................................. 72
9.
Please provide any other comments (that you have not already provided in response to the questions
above) that you have on the draft standard BAL-003-1. ......................................................................... 92
Consideration of Comments: Project 2007-12
2
000839
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
9.
Michael Jones
National Grid
NPCC 1
2
3
4
5
6
7
8
9
10
X
000840
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. David Kiguel
Hydro One Networks Inc.
NPCC 1
11. Michael Lombardi
Northeast Utilities
NPCC 1
12. Randy Macdonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
15. Lee Pedowcz
Northeast Power Coordinating Council
NPCC 10
16. Wayne Sipperly
New York Power Authority
NPCC 5
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
20. Brian Robinson
Utility Services
NPCC 8
21. Brian Shanahan
National Grid
NPCC 1
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Christina Koncz
PSEG Power LLC
2.
Group
Erik Ela
Additional Member Additional Organization
Region
5
6
7
Segment Selection
NA - Not Applicable NA
2. Brendan Kirby
Consultant
NA - Not Applicable NA
3. Yingchen Zhang
NREL
NA - Not Applicable
4. Mohit Singh
NREL
NA - Not Applicable
WILL SMITH
4
NPCC 5
NREL
Group
3
NREL Transmission and Grid Integration
Group
1. Vahan Gevorgian
3.
2
MRO NSRF
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM BREENE
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
Consideration of Comments: Project 2007-12
4
8
9
10
000841
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 5
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. DAN INMAN
MPC
4.
Group
Bonneville Power Administration
Additional Organization
Technical Operations
WECC 1
2. Kristy Humphrey
Technical Operations
WECC 1
3. Ayodele Idowu
Technical Operations
WECC 1
4. Rebecca Berdahl
Policy Development & Analysis WECC 3
Group
4
5
6
7
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Bart McManus
5.
3
1, 3, 5, 6
Chris Higgins
Additional Member
2
Scott Miller
MEAG Power
Additional Member Additional Organization Region Segment Selection
1. Steve Jackson
MEAG Power
SERC
3
2. Danny Dees
MEAG Power
SERC
1
3. Steve Grego
MEAG Power
SERC
5
6.
Group
Brent Ingebrigtson
Additional
Member
PPL NERC Registered Affiliates
Additional Organization
Region
Segment
Selection
1.
Brenda L. Truhe
PPL Electric Utilities Corporation`
RFC
1
2.
Annette M. Bannon
PPL Generation, LLC on behalf of Supply NERC Registered
Affiliates
RFC
5
Elizabeth A. Davis
PPL EnergyPlus, LLC
3.
4.
X
WECC 5
Consideration of Comments: Project 2007-12
MRO
6
5
8
9
10
000842
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
NPCC 6
6.
SERC
6
7.
SPP
6
8.
RFC
6
9.
WECC 6
10. Brent Ingebrigtson
LG&E and KU Services
7.
Greg Rowland
Group
SERC
2
3
4
5
6
7
3
Duke Energy
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Lee Schuster
Duke Energy
FRCC
3
3. Dale Goodwine
Duke Energy
SERC
5
4. Greg Cecil
Duke Energy
RFC
6
8.
Group
Jason Marshall
Additional
Member
ACES Power Marketing Standards
Collaborators
Additional Organization
X
Region
Segment
Selection
1. John Shaver
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.
WECC 1, 4, 5
2. Bill Hutchison
Southern Illinois Power Cooperative
SERC
1
3. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
9.
Group
Gerry Beckerle
SERC OC Standards Review Group
X
X
Additional Member Additional Organization Region Segment Selection
1.
Jeff Harrison
2.
Robert Thomasson Big Rivers Electric Corp. SERC
AECI
SERC
1, 3, 5, 6
1
3.
Dan Roethemeyer
Dynegy
SERC
5
4.
Adam Guinn
Duke Energy
SERC
1, 3, 5, 6
5.
Brad Young
LGE-KU
SERC
1, 3, 5, 6
6.
Wayne Van Liere
LGE-KU
SERC
1, 3, 5, 6
7.
Marie Knox
MISO
SERC
2
8.
Terry Bilke
MISO
SERC
2
Consideration of Comments: Project 2007-12
6
8
9
10
000843
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Troy Blalock
SCE&G
SERC
1, 3, 5, 6
10. Cindy Martin
Southern Co. Services
SERC
1, 5
11. Todd Lucas
Southern Co. Services
SERC
1, 5
12. Kelly Casteel
TVA
SERC
6, 1, 3, 5
13. Joel Wise
TVA
SERC
1, 3, 5, 6
14. Stuart Goza
TVA
SERC
1, 3, 5, 6
15. Steve Corbin
SERC Reliability Corp
SERC
10
10.
David Dockery, NERC
Reliability Compliance
Coordinator
Group
Additional Member
Associated Electric Cooperative, Inc. JRO00088
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
Group
3
4
5
X
X
X
X
X
X
6
7
X
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
11.
2
Scott Kinney
Avista
Additional Member Additional Organization Region Segment Selection
1. Scott
Kinney
WECC 1
2. Bob
Lafferty
WECC 3
3. Ed
Groce
WECC 5
12.
Group
Robert Rhodes
Additional Member
Additional Organization
SPP Standards REview Group
X
Region Segment Selection
1.
John Allen
City Utililties of Springfield
SPP
1, 4
2.
Lisa Duffey
Cleco Power
SPP
1, 3, 5
3.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
4.
Greg McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
5.
Stephen McGie
City of Coffeyville
SPP
NA
Consideration of Comments: Project 2007-12
7
8
9
10
000844
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6.
Terry Petzoldt
Kansas City Board of Public Utilities SPP
3
7.
Valerie Pinamonti
American Electric Power
SPP
1, 3, 5
8.
Randy Root
Grand River Dam Authority
SPP
1, 3, 5
9.
Katie Shea
Westar Energy
SPP
1, 3, 5, 6
10. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
13.
Thomas McElhinney
Group
JEA
2
3
4
5
X
X
X
6
7
8
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
FRCC
1
2. Garry Baker
FRCC
3
3. John Babik
FRCC
5
14.
Mark Gray
Janet Smith, Regulatory
Affairs Supervisor
Edison Electric Institute
X
X
X
X
Arizona Public Service Company
Individual
17. Individual
ryan millard
Stephanie Monzon
pacificorp
PJM Interconnection, LLC
X
X
X
X
X
X
X
X
18.
Individual
Richard Vine
California Independent System Operator
19.
Individual
Howard F. Illian
Energy Mark, Inc.
20.
Individual
Thad Ness
American Electric Power
X
21.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
22.
Individual
Travis Metcalfe
Tacoma Power
X
X
23.
Individual
Nazra Gladu
Manitoba Hydro
X
24.
Individual
Alice Ireland
Xcel Energy
25.
Individual
Shammara Hasty
26.
Individual
27.
15.
Individual
Individual
16.
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Southern Company
X
X
X
X
Greg Travis
Idaho Power Company
X
X
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
28.
Individual
Michael Falvo
Independent Electricity System Operator
29.
Individual
Brian J Murphy
NextEra Energy
X
X
X
Consideration of Comments: Project 2007-12
X
X
X
X
8
9
10
000845
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
30.
Individual
2
3
4
5
6
Texas Reliability Entity
Individual
32. Individual
Don Schmit
Brett Holland
Nebraska Public Power District
Kansas City Power & Light
X
X
X
X
X
X
X
33.
Individual
Angela P Gaines
Portland General Electric Company
X
X
X
X
34.
Individual
Kathleen Goodman
ISO New England Inc.
35.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
36.
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
X
37.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
X
X
X
X
38.
Individual
David Jendras
Ameren
X
X
X
X
39.
Individual
Maggy Powell
X
X
X
X
X
X
X
X
X
Individual
Janelle Marriott Gill
Exelon Corporation and its affiliates
Tri-State Generation and Transmission
Assn., Inc.
41.
Individual
Denise M Lietz
Puget Sound Energy
X
X
X
42.
Individual
Rich Salgo
NV Energy
X
X
X
43.
Individual
John Tolo
Tucson Electric Power
X
44.
Individual
Ken Gardner
AESO
45.
Individual
Patricia Robertson
BC Hydro
X
X
46.
Individual
Grergory Campoli
New York Independent System Operator
47.
Individual
Robert Blohm
Keen Resources Asia Ltd.
48.
Individual
Marie Knox
MISO
49.
Individual
Tony Kroskey
Individual
Mauricio Guardado
Brazos Electric Power Cooperative, Inc.
Los Angeles Department of Water and
Power
40.
50.
Consideration of Comments: Project 2007-12
8
9
10
X
Don Jones
31.
7
X
X
X
X
X
X
X
X
X
X
X
9
000846
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration:
Organization
Supporting Comments of “Entity Name”
MEAG Power
Southern Company Services, Inc - Gen
Associated Electric Cooperative, Inc. JRO00088
SERC OC Standards Review Group
Avista
Bonneville Power Administration
Nebraska Public Power District
MRO NSRF [Midwest Reliability Organization - NERC Standards Review Forum]
ISO New England Inc.
Last submitted comments of ISO-NE which have not been addressed and, for
efficiency sake, do not believe we should be requested to re-submit.
South Carolina Electric and Gas
SERC OC Standards Review Group
Entergy Services, Inc. (Transmission)
Entergy is in agreement with comments submitted by SERC on 11/5/0212.
Brazos Electric Power Cooperative, Inc.
ACES Power Marketing
Consideration of Comments: Project 2007-12
10
000847
1.
The SDT has made minor modifications to the proposed definition for Frequency Response Measure based on industry
comments. Do you agree that these modifications provide sufficient clarity? If not, please explain in the comment area.
Summary Consideration: A few of the commenters felt that the definition applied to all of the observations for both the BA and the
FRSG. The drafting team stated that although they understood their concern they did not agree with them. They felt
that the present definition provided sufficient clarity and decided to not make any modifications.
One commenter felt that the definition should state that it is a negative value. The drafting team explained that while the desired
value would be negative it is mathematically feasible for the actual value to be positive but that value would by
definition mean that the entity failed the measurement for Requirement R1.
Another commenter did not believe that there was sufficient clarity as to the number of observations that would be used to calculate
FRM. The drafting team stated that the number of observations would vary from year to year. The basis for
determining events is outlined in the Procedure attached to this standard.
Organization
Yes or No
Duke Energy
No
Question 1 Comment
The definition reads as if the FRM is the median of all of the observations reported by the
Balancing Authorities and Frequency Response Sharing Groups. Duke Energy would suggest
that the definition read, “The median of all of the Frequency Response observations
reported annually by a Frequency Response Sharing Group, or Balancing Authority if not a
participant in a Frequency Response Sharing Group, for frequency events specified by the
ERO. The Frequency Response Measure is calculated as MW/0.1Hz.”
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
SERC OC Standards
Review Group
No
The definition reads as if the FRM is the median of all of the observations reported by the
Balancing Authorities and Frequency Response Sharing Groups. We agree with the Duke
Energy suggestion that the definition read, “The median of all of the Frequency Response
observations reported annually by a Frequency Response Sharing Group, or Balancing
Consideration of Comments: Project 2007-12
11
000848
Organization
Yes or No
Question 1 Comment
Authority if not a participant in a Frequency Response Sharing Group, for frequency events
specified by the ERO. The Frequency Response Measure is calculated as MW/0.1Hz.”
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
PPL NERC Registered
Affiliates
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on this
question.
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
BC Hydro
Yes
Additionally, there should be language to clarify that this is a negative value (the same
should apply to the definitions of FRO and Frequency Bias). It is fairly obvious that these
values should be negative when reading elsewhere in the proposed Standard and its related
document but not in their definitions.
Response: While the desired value would be negative it is mathematically feasible for the actual value to be positive but that
value would by definition mean that the entity failed the measurement for Requirement R1.
Tucson Electric Power
Yes
however, the number of observations to be used in calculating an entity's FRM is not clear.
Response: Thank you for your affirmative response and clarifying comment. The number of observations will vary from year to
year. The basis for determining events is outlined in the Procedure attached to this standard.
Exelon Corporation and
its affiliates
Yes
Please see response to question 8. The FRM definition is acceptable within the context of
the attachment description; however, without clarifying the terms under which the ERO
specifies which events are to be measured, the FRM definition is too variable.
Response: Thank you for your affirmative response and clarifying comment. The criteria used to determine the events to be used
are outlined in the Procedure attached to this standard. Please refer to our response to Question #8.
Consideration of Comments: Project 2007-12
12
000849
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
Yes
Question 1 Comment
We believe that refinements to the definition were needed.
Response: Thank you for your affirmative response and clarifying comment.
Manitoba Hydro
Yes
Northeast Power
Coordinating Council
Yes
NREL Transmission and
Grid Integration Group
Yes
MRO NSRF
Yes
Bonneville Power
Administration
Yes
SPP Standards REview
Group
Yes
Edison Electric Institute
Yes
Arizona Public Service
Company
Yes
pacificorp
Yes
No comment.
PJM Interconnection, LLC Yes
California Independent
Yes
Consideration of Comments: Project 2007-12
13
000850
Organization
Yes or No
Question 1 Comment
System Operator
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Xcel Energy
Yes
Southern Company
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
Texas Reliability Entity
Yes
Kansas City Power &
Light
Yes
Consolidated Edison Co.
of NY, Inc.
Yes
Ameren
Yes
NV Energy
Yes
New York Independent
System Operator
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12
14
000851
Organization
Yes or No
MISO
Yes
American Electric Power
Question 1 Comment
As provided in question 2 below, AEP does not agree with the definition containing the
Frequency Response Sharing Group as this function does not exist at this point in time.
Response: Thank you for your comments. The term Frequency Response Sharing Group is defined at the beginning of the
standard. Once this standard is approved by the industry, NERC BOT and FERC the definition will be removed from the standard
and added to the NERC Glossary of Terms.
Consideration of Comments: Project 2007-12
15
000852
2.
The SDT has created a definition for Frequency Response Sharing Group. The definition is as follows: A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members. Do you agree with this definition? If not, please explain in the
comment area.
Summary Consideration: Almost all of the commenters wanted to modify the definition. The drafting team explained that they
believed that the proposed definition should remain unchanged. The drafting team developed the definition to be
essentially the same as that currently used for contingency Reserve Sharing Groups. This will help ensure that the
different types of reserve groups are comparable as we move forward with this new type of group.
One commenter did not agree believe it was appropriate to define a new function that was not in the NERC ROP, NERC Statement of
Registry Criteria or the NERC Functional Model. The drafting team stated that they had discussed this issue with NERC.
NERC staff will add this entity to the registered entity list in the same manner as the existing Reserve Sharing Group.
While this is not in the current version available online, NERC will have at least 24 months from the time of regulatory
approval to add the entity to the list of registered entities.
Organization
Yes or No
SERC OC Standards Review
Group
No
Question 2 Comment
A Balancing Authority may not be the entity maintaining or supplying resources, but
would be responsible for utilizing applicable resources within its BA Area. We would
modify the Duke Energy suggestion to read as follows: “A group whose members
consist of two or more Balancing Authorities that collectively utilize operating
resources with a goal to achieve a group FRM equal to or more negative than the sum
of the Frequency Response Obligations of its members.”
Response: Thank you for your comments. After review of suggested changes, the drafting team believes that the proposed definition
should remain unchanged. The drafting team developed the definition to be essentially the same as that currently used for
contingency Reserve Sharing Groups. This will help ensure that the different types of reserve groups are comparable as we move
forward with this new type of group.
American Electric Power
No
AEP does not necessarily disagree with the words of the definition. However, AEP does
Consideration of Comments: Project 2007-12
16
000853
Organization
Yes or No
Question 2 Comment
not believe it is appropriate to define a new function that is not in the NERC Rules of
Procedure, NERC Statement of Registry Criteria, or the NERC Functional Model. It is
premature to incorporate this entity without a proposed change to these governing
NERC documents.
Response: Thank you for your comments. The drafting team has discussed this issue with NERC. NERC staff will add this entity to
the registered entity list in the same manner as the existing Reserve Sharing Group. While not in the current version available online,
NERC will have at least 24 months from the time of regulatory approval to add the entity to the list of registered entities.
Duke Energy
No
As a Balancing Authority may not be the entity maintaining or supplying resources, but
would be responsible for utilizing applicable resources within its BA Area, Duke Energy
would suggest the following definition, “A group whose members consist of two or
more Balancing Authorities that collectively utilize operating resources required to
achieve a group FRM equal to or more negative than the sum of the Frequency
Response Obligations of its members.”
Response: Thank you for your comments. After review of suggested changes, the drafting team believes that the proposed
definition should remain unchanged. The drafting team developed the definition to be essentially the same as that currently used for
contingency Reserve Sharing Groups. This will help ensure that the different types of reserve groups are comparable as we move
forward with this new type of group.
Edison Electric Institute
No
EEI does not fully agree with the definition of a “Frequency Response Sharing Group”
(FRSG). In the definition offered in the new Standard, it states that the FRSG
“collectively maintain, allocate, and supply operating resources”. Of the three roles, a
balancing authority only maintains load-interchange-generation balance through the
allocation of resources. Therefore, EEI suggests that the definition be changed to more
appropriately align with the role of a BA, which we believe would be to allocate
resources in a manner that effectively allows the sharing of resources necessary to
achieve a FRO within the defined sharing group, which might otherwise not be possible
or practical by a BA on its own.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
Consideration of Comments: Project 2007-12
17
000854
Organization
Yes or No
Question 2 Comment
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
ACES Power Marketing
Standards Collaborators
No
We agree that a definition is needed and thank the drafting team for writing one.
However, we believe additional refinement of the definition is necessary. Although the
definition appears to be written to parallel the Reserve Sharing Group definition, we
think the definition needs to be simplified. For one, it encompasses actions that are not
necessary. For instance, the proposed definition includes the action to “maintain
operating resources”. This could literally include generating plant maintenance. We do
not agree that a Frequency Response Sharing Group would jointly perform
maintenance on their plants. In fact, since the definition applies to BAs, it is entirely
possible within the functional model that the BAs do not even own the plants and
could not perform joint maintenance. We assume the purpose of including “maintain”
was to recognize that maintenance of generating resources would need to be
coordinated to ensure that there was sufficient frequency response reserve. We do not
believe this needs to be explicitly identified in the definition. Furthermore, we find the
use of “operating resource” as a source of potential confusion. While we understand
operating resource is intended to mean a facility that provides the ability to increase or
decrease MW output based on the frequency deviation, resource has various meanings
throughout the standards and its use here could be confusing and contradictory. For
instance, TOP-006-2 R1 discusses transmission resources. Furthermore, if an “operating
resource” is capable of increasingor decreasing MW output based on frequency
deviation, what is a “resource”? In other words, why is “operating” added to the term
“resource”? We think it is best to avoid use of the term operating resource and, thus,
recommend changing the definition to: “A group of two or more Balancing Authorities
that share frequency response reserves and are required to jointly meet the Frequency
Response Obligations of its members.”
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
BC Hydro
Yes
Additionally, there should be language to clarify that the BAs must belong to the same
Consideration of Comments: Project 2007-12
18
000855
Organization
Yes or No
Question 2 Comment
Interconnections to form the FRSG
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
PPL NERC Registered
Affiliates
Yes
PPL Affiliates suggest additional detail be added to the definition to ensure the
members of the FRSG are all within the same interconnection. The following definition
includes the suggested changes: A group whose members consist of two or more
Balancing Authorities all within a single interconnection that collectively operate
resources required to jointly meet the sum of the Frequency Response Obligations of
its members.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
Ameren
Yes
The word "jointly" may add confusion and we believe it is unessassry.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
Manitoba Hydro
Yes
Northeast Power
Coordinating Council
Yes
NREL Transmission and Grid
Integration Group
Yes
MRO NSRF
Yes
Bonneville Power
Yes
No comment.
Consideration of Comments: Project 2007-12
19
000856
Organization
Yes or No
Question 2 Comment
Administration
SPP Standards REview
Group
Yes
Arizona Public Service
Company
Yes
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Xcel Energy
Yes
Southern Company
Yes
Idaho Power Company
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Consolidated Edison Co. of
NY, Inc.
Yes
Consideration of Comments: Project 2007-12
20
000857
Organization
Yes or No
Exelon Corporation and its
affiliates
Yes
NV Energy
Yes
Tucson Electric Power
Yes
Keen Resources Asia Ltd.
Yes
MISO
Yes
Independent Electricity
System Operator
Question 2 Comment
Not Applicable
Consideration of Comments: Project 2007-12
21
000858
3.
The SDT has added Requirement R3 for entities using variable Frequency Bias. R3. Each Balancing Authority that is a member of
a multiple Balancing Authority Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
3.1 Less than zero at all times, and
3.3 Equal to or more negative than its Frequency Response Obligation when Frequency varies from 60 Hz by more than +/-0.036
Hz.
Summary Consideration: A couple of commenters felt that the intent of the requirement needed to be clarified. The drafting team
explained that Requirement R3 is only applicable to a BA using a variable bias and does require a BA to maintain a bias
less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias have a bias at least equal to
the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are addressed in
Requirement R2.
A few commenters expressed concern with excluding a single BA interconnection from compliance with Requirement R3. The
drafting team stated that they had discussed the applicability of variable bias requirements to single BA
Interconnections extensively. The consensus of the drafting team was that single BA Interconnections inherently have
strong incentives to accurately represent their frequency response characteristic. Any adverse consequences of
misrepresenting the frequency response characteristic will be borne solely by that BA and cannot affect other BAs in
other Interconnections adversely.
One commenter disagreed with allowing the use of variable Frequency Bias in a multi-BA interconnection. The drafting team
believes that this concern may be better addressed within BAL-001. Variable frequency bias settings allow a Balancing
Authority to better match their frequency bias setting in use with the actual frequency response occurring at any
instant in time. If it is meeting its FRO for larger frequency deviations and the frequency bias setting in use at that time
meets or exceeds its FRO, then the BA is doing its part to support frequency and AGC will not be withdrawing that
frequency response.
Another commenter question the periodicity of a BA changing its Frequency Bias Setting to be considered using variable Frequency
Bias. They gave an example of an entity changing its FBS monthly. The drafting team stated that they had not defined
the periodicity for changing their bias to be variable. The example given would be a form of variable bias and would
trigger all rules related to variable bias. Requirement R3 is separate from Requirement R4. Requirement R4 is related
Consideration of Comments: Project 2007-12
22
000859
to those entities providing Overlap Regulation Service. It is possible for an entity to provide Overlap Regulation
Service and have a variable bias setting therefore an entity may be subject to compliance for both Requirement R3 and
Requirement R4.
Organization
Yes or No
American Electric Power
No
Question 3 Comment
AEP believes this question in the comment form is incorrect. It appears that R3 and R4
are inadvertenly merged together.
Response: The drafting team is not sure of the point you are trying to make. The question only contains the Requirement R3 from
the standard. The drafting team did notice that the numbering of the sub-bullets was incorrect.
Duke Energy
No
Duke Energy agrees with allowing single-BA Interconnections to utilize a variable
Frequency Bias Setting (FBS). Duke Energy disagrees with NERC allowing Balancing
Authorities in a multiple-BA Interconnection to change the ACE and bounds by which
the Balancing Authorities are measured under BAL-001 and BAL-002 by operating to a
variable FBS. It is desired that a Balancing Authority be capable of recognizing the
amount of primary response available in real-time operation, such information can be
included among other information in the generation control algorithm; however, the
obligation to support the Interconnection frequency under the secondary control
standards, and the amount provided for any given frequency, should be based on the
same criteria across all Balancing Authorities of the same size. Nathan Cohn in his
comments on Union Electric’s use of a variable FBS expressed similar concern regarding
the equitable sharing of the obligation to support Interconnection frequency in a
multiple-BA Interconnection. Take for example two Balancing Authorities with equal
total generation and load, but one operating under a fixed FBS and the other operating
under a variable FBS. To the extent that a Balancing Authority is not providing
Frequency Response comparable to its fixed Frequency Bias Setting, its ACE will reflect
the difference to be covered with secondary control and the Balancing Authority will be
measured in a manner similar to other BAs of its “size” based upon the FBS. To the
extent that the other BA using a variable FBS is not providing Frequency Response
Consideration of Comments: Project 2007-12
23
000860
Organization
Yes or No
Question 3 Comment
comparable to what it would be allocated using a fixed FBS, its ACE will not reflect the
difference or any further obligation to support Interconnection frequency at that time
with secondary control. Duke Energy’s concern regarding non-comparable treatment of
all BAs is further amplified by the lack of scrutiny placed on the BA algorithm used to
determine the real-time variable FBS, to ensure that compliance cannot be gamed by
such use.
Response: The drafting team believes that this concern may be better addressed within BAL-001. Variable frequency bias settings
allow a Balancing Authority to better match their frequency bias setting in use with the actual frequency response occurring at any
instant in time. If it is meeting its FRO for larger frequency deviations and the frequency bias setting in use at that time meets or
exceeds its FRO, then the BA is doing its part to support frequency and AGC will not be withdrawing that frequency response.
Northeast Power
Coordinating Council
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service
(supplying actual interchange, frequency response, and schedules to another BA), then
it can be assumed that the BA is supplying regulation service. Was the intent of the
requirement to simply state that all BA’s must have a bias setting less than zero at all
times? The intent of this requirement needs to be clarified.
Response: The drafting team is not sure if we understand your first comment. A BA not providing Overlap Regulation Service may
or may not be providing Supplemental Regulation Service. Requirement R3 is only applicable to a BA using a variable bias and
does require a BA to maintain a bias less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias
have a bias at least equal to the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are
addressed in Requirement R2.
Consolidated Edison Co. of
NY, Inc.
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service
(supplying actual interchange, frequency response, and schedules to another BA), then
we can assume it is supplying regulation service. Was the intent of the requirement to
simply state that all BA’s must have a bias setting less than zero at all times? Please
clarify the intent of this requirement.
Response: The drafting team is not sure if we understand your first comment. A BA not providing Overlap Regulation Service may
or may not be providing Supplemental Regulation Service. Requirement R3 is only applicable to a BA using a variable bias and
Consideration of Comments: Project 2007-12
24
000861
Organization
Yes or No
Question 3 Comment
does require a BA to maintain a bias less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias
have a bias at least equal to the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are
addressed in Requirement R2.
Exelon Corporation and its
affiliates
No
Please see response to question 8.
Response: Please refer to the drafting team response to Question #8.
MRO NSRF
No
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing
Authority Interconnections from compliance with Requirement R3. To ensure a
consistent approach in the application of the standard, recommend R3 be revised as
follows:(R3). Each Balancing Authority that is not receiving Overlap Regulation Service
and is utilizing a variable Frequency Bias Setting shall maintain a Frequency Bias Setting
that is: ...
Response: The drafting team discussed the applicability of variable bias requirements to single BA Interconnections extensively. The
consensus of the drafting team was that single BA Interconnections inherently have strong incentives to accurately represent their
frequency response characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will be borne
solely by that BA and cannot affect other BAs in other Interconnections adversely.
MISO
No
We agree with the general obligation but believe that the requirement should apply to
single BA Interconnections as well. This is supposed to be a North American standard.
What other standards shouldn’t apply to a single BA Interconnection? We have the
same concern with Requirement 2.
Response: The drafting team discussed the applicability of variable bias requirements to single BA Interconnections extensively.
The consensus of the drafting team was that single BA Interconnections inherently have strong incentives to accurately represent
their frequency response characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will
be borne solely by that BA and cannot affect other BAs in other Interconnections adversely.
PJM Interconnection, LLC
No
With what periodicity does a BA’s frequency bias setting have to change to be
Consideration of Comments: Project 2007-12
25
000862
Organization
Yes or No
Question 3 Comment
considered variable bias? For example, if a BA changes it’s frequency bias setting
monthly based on a percentage of each month’s forecast or historic load, is this
considered variable bias subject to compliance with R3 in lieu of R4?
Response: The drafting team has not defined the periodicity for changing their bias to be variable. The example given would be a
form of variable bias and would trigger all rules related to variable bias. Requirement R3 is separate from Requirement R4.
Requirement R4 is related to those entities providing Overlap Regulation Service. It is possible for an entity to provide Overlap
Regulation Service and have a variable bias setting therefore an entity may be subject to compliance for both Requirement R3 and
Requirement R4.
BC Hydro
Yes
BC Hydro applauds the STD’s efforts to recognize a more suitable bound for Variable
Frequency Bias settings
Response: Thank you for your affirmative response and clarifying comment.
Bonneville Power
Administration
Yes
BPA is responding to 3.1 and 3.2 of R3. The bullets listed in question 3 on the original
comment form appear to be for Requirement R4. BPA is in support of R3.1 and R3.2.
Response: Thank you for your affirmative response and clarifying comment.
Texas Reliability Entity
Yes
It appears that R3.2 is based on the assumption that governor dead-band settings are
0.036 Hz for all interconnections with multiple BAs. While the ERCOT region has a
standard 0.036 Hz dead-band specified in the ERCOT Protocols and Operating Guides,
we are not sure if this is applicable to the other regions.
Response: Thank you for your affirmative response and clarifying comment. In addition, as to the deadband setting, this number
was also considered to be within the frequency deviation range of the event determination criteria as defined in the Procedure
document.
Tucson Electric Power
Yes
N/A
Consideration of Comments: Project 2007-12
26
000863
Organization
Yes or No
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
SPP Standards REview
Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Southern Company
Yes
Idaho Power Company
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
Question 3 Comment
No comment.
Consideration of Comments: Project 2007-12
27
000864
Organization
Yes or No
Keen Resources Asia Ltd.
Yes
Independent Electricity
System Operator
Question 3 Comment
Not Applicable
Consideration of Comments: Project 2007-12
28
000865
4.
Based on Industry comments the SDT has modified ”Attachment A- Supporting Document” to provide additional clarity. Do you
agree with the modifications? If not, what modifications do you disagree with?
Summary Consideration: A few commenters felt that there were requirements stated within Attachment A. The drafting team
explained that the requirement stated in the standard was the only requirement related to FRM. Attachment A is
there to provide uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability
objectives in the requirements and put procedural steps in the attachment and procedure.
Several commenters expressed concern over the use of the largest event in the last 10 years for the Eastern Interconnection while all
of the other Interconnections used the Category C (N-2). The drafting team stated that the results for the current
Eastern Interconnection model do not represent observed response adequately. The models for the other
Interconnections have a better match. For this reason the drafting team has recommended the largest event in the
last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are
provided on pages 52 through 55 of the Frequency Response Initiative paper.
A couple of commenters questioned the difference between the present frequency bias of -6,360 MW/0.1 Hz and the proposed of 1,002 MW/0.1 Hz. The drafting team explained that the -6,630 MW/0.1 Hz represents a summation of the Frequency
Bias Settings of all Balancing Authorities in the Eastern Interconnection, most of which use the 1% default minimum as
required in the current BAL-003-0 standard, which far exceeds their real response. The IFRO of -1002 MW/0.1 Hz is the
response determined to avoid the first step of Underfrequency load shedding in the Interconnection for a 4,500 MW
generation loss.
A few commenters felt that clarification was need concerning changes in a BAs footprint and changes to the bias setting or FRO. The
drafting team felt that this was a problem that would take care of itself. If two BAs change footprint but do not raise
the issue the impact is transparent to the Interconnection. If one BA believes that its limits need to be adjusted the
process will adjust the limits of both BAs accordingly.
A couple of commenters requested clarity as to how changes to the process in Attachment A would be handled. The drafting team
explained that any change to the methodology described in Attachment A would have to go through the Standards
Development Process prior to being implemented.
Two commenters felt that there should be an exemption for non-conforming load performing contrary to the performance of
conventional load. The drafting team stated that they did not agree that there should be an exemption but has
designed the forms to allow for adjustments for non-conforming load. However the BA may find that no adjustment
for non-conforming load may be needed due to the measurement over multiple events rather than individual events.
Consideration of Comments: Project 2007-12
29
000866
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 4 Comment
(1) Frequency Response Obligation (FRO) is used inconsistently with the proposed
definition in the document. The document uses the term “Interconnection Frequency
Response Obligation” in many locations. However, FRO specifically is defined as the
BA’s “share of the required Frequency Response”. It does not apply to the
Interconnection. How can the Interconnection have a share of the required frequency
response? A new term may need to be defined for the Interconnection required
Frequency Response.
(2) On page 3 Attachment A states the ERO will post the Frequency Bias Setting for
each BA along with their Frequency Response Obligation. Later on the same page, the
document states that the BA shall set its Frequency Bias Setting to 100% to 125% of it
Frequency Response Measure or Interconnection Minimum. What is the purpose of the
ERO determining Frequency Bias Settings if the settings are not going to be used by the
BA? What are we missing in the explanation?
(3) Late on page 3, the document states that BAs are encouraged to notify NERC if load
or generation is transferred. Section 4(a) on page 8 of the Rules of Procedure Appendix
5A - Organization Registration and Certification Manual indicates that changes to a
Registered Entity’s footprint actually triggers a potential certification audit. Since BAs
are required to be certified and moving generation or load from the metered
boundaries of one BA to another BA would represent a change in footprint, we suggest
removing the word “encouraged” and stating affirmatively that BAs must notify NERC
of such changes and referencing the appropriate section of the Rules of Procedure.
Otherwise, BAs may not realize notification is actually required.
Response: (1) The drafting team believes the IFRO and FRO terms are used appropriately in Attachment A. Interconnection
Frequency Response Obligation is not defined in the standard nor is it a performance obligation. The drafting team has clarified
Attachment A in instances when using the terms to address your comments.
Consideration of Comments: Project 2007-12
30
000867
Organization
Yes or No
Question 4 Comment
(2) The ERO is not determining the FBS but is only validating the FBS provided by the BA on FRS Form 1.
(3) The SDT believes these are two coordinated but separate processes. If the Rules of Procedure apply, as worded this document
provides the avenue to make the necessary changes to Frequency Bias Setting.
Consolidated Edison Co. of
NY, Inc.
No
(1) This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource
contingency criteria (in the attachment, this is called the “target contingency criteria”),
etc.
(2) Of value to entities would be a sample calculation.
(3) “The largest category C (N-2) event is used for all interconnections except the
Eastern which uses the largest event in the last 10 years”. Why aren’t all
interconnections using the same design contingency design basis?
(4) The NERC 2012 CPS2 bounds has an Eastern Interconnection frequency bias of 6,360 MW/.1Hz. Can the DT explain why this attachment refers to an Interconnection
frequency response obligation of -1,002MW/.1Hz. This is a significant difference.
Response: (1) As stated in Attachment A these terms are defined in the Procedure. The drafting team clarified the use of multiple
terms of “resource contingency criteria” throughout both Attachment A and the Procedure documents.
(2) The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
(3) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
pages 52 through 55 of the Frequency Response Initiative paper.
(4) The -6,630 MW/0.1 Hz represents a summation of the Frequency Bias Settings of all Balancing Authorities in the Eastern
Interconnection, most of which use the 1% default minimum as required in the current BAL-003-0 standard, which far exceeds
their real response. The IFRO of -1002 MW/0.1 Hz is the response determined to avoid the first step of Underfrequency load
shedding in the Interconnection for a 4,500 MW generation loss.
Consideration of Comments: Project 2007-12
31
000868
Organization
Yes or No
American Electric Power
No
Question 4 Comment
AEP is under the impression that there are some requirements, which though not
explicitly stated, are implied in Attachment A. AEP feels strongly that these “subrequirements” should be clarified and contained within the body of the requirements
of the standard.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM.
Duke Energy
No
As indicated in our comments in the past, Duke Energy is certain that as the
Interconnection Frequency Bias Setting (FBS) is set closer to the actual Frequency
Response in a multi-BA Interconnection, most BAs will be challenged in meeting CPS2,
while CPS1 and the proposed Balancing Authority ACE Limit (BAAL) will be more
achieveable bounds, and in some cases CPS1 performance will improve. Though
probably most of the BAs may welcome a FBS set as high in magnitude as allowed to
address the potential compliance risk, there are some which may desire to set their FBS
closer to their required minimum allocation rather than have to take on a larger
obligation in frequency support under the secondary control measures. Duke Energy
believes that this proposed standard should incent BAs to provide more than their
share of Frequency Response to the Interconnection and allow that good performance
to be recognized; however the requirements described in Attachment A for
determining the minimum Frequency Bias Setting (FBS), which requires that the FBS be
set no lower in magnitude than the FRM, will leave certain over-performing BAs with
no choice but to reduce their actual Frequency Response (still well-above their FRO) if
they want to operate with a FBS set closer to the Interconnection Minimum allocation
and be relieved of the associated increased obligation for frequency support under the
secondary control measures. The FBS is embedded within the secondary control
measures of CPS1, CPS2 and the draft Balancing Authority ACE Limit (BAAL).
Comparable treatment of similarly-sized BAs (based upon the FRO allocation) is only
possible if all BAs are provided the same minimum FBS requirement. To the extent that
a BA provides more than its share of response to events, it’s over-performance will only
Consideration of Comments: Project 2007-12
32
000869
Organization
Yes or No
Question 4 Comment
be recognized if its ACE is allowed to reflect a FBS comparable to its peers, allowing its
over-performance to be reflected in ACE in support of bringing frequency closer to 60
Hz. Generation control algorithms implemented today to optimize CPS1 will allow nonzero ACE when in support Interconnection frequency within bounds determined by the
BA - there should be no concern of “response withdrawal” with such algorithms in
place, the BA will simply get credit for such performance. As depicted in the current
document, the over-performing BA would be required to set its minimum FBS at its
FRM (or greater in magnitude), taking away what should be considered overperformance, erasing it in ACE, and turning it into an obligation under the secondary
control measures. Based upon the draft, the only way that the BA could be treated
comparably to other similarly sized BAs held only to operating to the Interconnection
Minimum allocation, would be to reduce its actual response in FRM to a value less in
magnitude than its Interconnection Minimum allocation. Duke Energy believes that
BAs should be incented to provide more than their share of Frequency Response, and
be given the opportunity to report performance on a basis comparable to similar-sized
BAs. Our opinion is that Attachment A ensures that the Interconnection Frequency
Bias Setting will remain at some margin above the actual Interconnection Frequency
Response in magnitude - the reliability of the Interconnection will not be at risk by
allowing over-performing BAs to operate and report performance on a comparable
basis to other similarly-sized BAs based upon the Interconnection Minimum allocation
if they choose to do so - to that extent, Duke Energy suggests that the language on
page 3 be changed to:”A BA using a fixed Frequency Bias Setting may set its Frequency
Bias Setting to any number the BA chooses up to 125% of its Frequency Response
Measure as calculated on FRS Form 1, but no less in magnitude than its Interconnection
Minimum allocation as determined by the ERO.”Regarding the argument which could
be offered that a larger FBS in magnitude will also allow wider bounds for control
performance, Duke Energy agrees that a large portion of the BA operation will be
around 60 Hz where such a benefit could be realized, however it would also come at
the cost of a larger obligation than other comparably-sized BAs in sustained support of
frequency during the more critical times of significant deviation from 60 Hz where the
BA’s compliance could be at risk. Below 59.95 Hz in the Eastern Interconnection (the
Consideration of Comments: Project 2007-12
33
000870
Organization
Yes or No
Question 4 Comment
Frequency Trigger Limit under BAAL), the additional MWs needed to be compliant for
any given frequency are greater than the MWs of imbalance allowed by the larger BAAL
bound - comparably-sized BAs will not be comparably judged if the standard forces
over-performing BAs to assume a larger FBS (in magnitude) than their peers - that
should be the decision of the BA. We believe that the proposed language above will
create the proper incentive for a Balancing Authority to provide more than its
minimum allocation of Frequency Response, and allow it to choose if it wants to make
that performance part of a larger FBS (in magnitude), knowing the associated risks and
benefits of that decision.Duke Energy supports this standard allowing for Frequency
Response Sharing Groups, however the requirements and supporting documents need
to clearly allow the FRSG to be treated no differently than if it was a Balancing
Authority and shield the participating BAs from compliance scrutiny when all scrutiny
should be placed on the FRSG performance as a whole.
At the top of Page 3, the standard attachment allows the FRSG to “calculate a group
NIA and measure the group response to all events in the reporting year on a single FRS
Form 1”, however at the bottom of page 3, the standard attachment still requires the
FRSG BAs to individually fill out Form 1 and Form 2 for the purposes of determining the
minimum Frequency Bias Setting. Duke Energy believes that the standard language in
Attachment A, and the supporting form(s), should allow the FRSG, if it chooses, to also
report the split of the group FRM which the BAs will use to individually determine their
Frequency Bias Setting, rather than require each BA in an FRSG to still maintain Form 1
and Form 2 data. Form 1 could be modified for the FRSG to report the group’s FRM
along with the split of the FRM among the members, and another form could be
developed for each FRSG BA to fill out, replicating only the section of Form 1 (column S)
where each BA could provide values for its FRM allocation, its desired FBS, its minimum
FBS allocation, and so on.
Response: The drafting team has chosen to reduce the minimum Frequency Bias Settings for individual BAs on a controlled basis
on each Interconnection. Your suggestion would eliminate the ability of the drafting team to coordinate the reduction of the
minimum Frequency Bias Settings for the BAs. Other commenters have stated that they disagree with reducing the minimum
Consideration of Comments: Project 2007-12
34
000871
Organization
Yes or No
Question 4 Comment
Frequency Bias Setting. The drafting team is attempting to balance between the two positions stated in previous postings.
The drafting team understands your concern regarding the treatment of FRSG and the minimum Frequency Bias Setting. However,
the drafting team believes that this allocation of Frequency Bias among the FRSG members on a basis different from the measured
response could be detrimental to reliability under system separation conditions. Future consideration of this issue may be
possible once additional information is available.
Independent Electricity
System Operator
No
As indicated in our previous comments, the status of Attachment A is unclear. It is a
mixture of requirements, criteria, process and guideline. Making a direct reference in
the standard’s requirements (R1 and R2) makes Attachment A as part of the
requirement and hence is enforceable, but it contains process and guideline
information that is not subject to assessment. On the other hand, the absence of a
Measure to assess adherence to the criteria and process suggests that Attachment A is
not enforceable. It is this ambiguity that makes it difficult for the industry to assess the
extent to which they must follow the process. Again, we urge the SDT to keep only the
criteria/process parts that must be adhered to in Attachment A, and extract the
remaining parts and place them in a guideline document, or an appendix.In addition,
the Responsible Entities are required to submit Form 1 and Form 2, but such
requirements are not written explicitly as “shall”, and are imbedded in the
Attachement whose mandatory status is unclear. This makes the standard very
confusing from an Responsible Entity’s obligation and compliance perspective.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
BC Hydro
No
BC Hydro agrees with the principles outlined in the Attachment A but has some
concerns as follows:
1.Attachment A is no longer recognized as one of the associated document of the
proposed Standard in its currently posted version. We believe this was removed by
mistake.
Consideration of Comments: Project 2007-12
35
000872
Organization
Yes or No
Question 4 Comment
2.There is no clarity as to how certain factors used in determining the Interconnection
FRO such as CCADJ, CBR and BC’ADJ were determined. There is no apparent provision
to re-assess any potential changes to these factors over the future years. If such
provision is needed or has been provided then consideration should be given to
averaging the adjustment over a longer duration (i.e., using the average of the factor
observed over a number of years rather than just the year being assessed).
3.The method used for the allocation of the Interconnection FRO to BAs seems to not
recognize the fact that frequency response from Load is much less than frequency
response from Generation of an equal MW size.
4.If this Attachment A is considered an integral part of the standard then there should
be some enforceable measures to ensure applicable entities adhering to the prescribed
time line.
Response:
(1) The drafting team disagrees that Attachment A is not one of the associated documents of the standard. It is included by
reference in Requirements R1 and R2 and will be attached to the standard upon final approval.
(2) If the data inputs change then the number will change but the methodology used to calculate the number cannot change
without going through the standards process.
(3) The drafting team agrees with your conclusion. The source of the Frequency Response is not related to the distribution of the
obligation.
(4) The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide uniformity
in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the requirements and
put procedural steps in the attachment and procedure.
Bonneville Power
Administration
No
BPA does not agree with the methodology in Attachment A. Please see BPA’s response
to question 6 as well as BPA’s extensive comments submitted on 12/8/11 for Project
2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Consideration of Comments: Project 2007-12
36
000873
Organization
Yes or No
Question 4 Comment
Response: Please refer to our response to Question #6 and our responses to your comments submitted on 12/8/11.
Exelon Corporation and its
affiliates
No
Exelon is troubled by the approach of having requirements that rely so heavily on the
attachment to the standard. The use of both of the documents is required to be
compliant and this makes it difficult to determine what the obligations are and
increases the chance for error in interpretation. The suggested changes below in
response to question 8 take information from the Attachment and establish
requirements so that an entity does not have to go back and forth between the two
documents to identify its obligations. Attachment A should then be modified to include
examples of Forms 1 and 2 and instructions for completing the form for Balancing
Authorities and Frequency Response Sharing Groups.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
SERC OC Standards Review
Group
No
It is important for NERC to monitor the interaction between the deployment of this
standard and its impact on CPS1, CPS2, and BAAL. If performance in the CPS criteria is
degraded, there should be a halt in the reduction of the minimum bias setting allowed.
There is also concern that we are providing the correct incentives to the entities to
provide the appropriate amount of frequency response.
We also suggest that clarification be made so that changes in the BA’s footprint that
would necessitate changes in the bias setting or the FRO be permanent changes, not
just temporary.
It is unclear how performance would be measured for a BA versus a frequency
response sharing group.
Consideration of Comments: Project 2007-12
37
000874
Organization
Yes or No
Question 4 Comment
Response: The minimum is not required to be reduced but is allowed to be reduced if no significant impacts are seen on CPS1,
CPS2 and BAAL.
The drafting team agrees that temporary changes will not apply in this case. It is a problem that will take care of itself. If two BAs
change footprint but do not raise the issue the impact is transparent to the Interconnection. If one BA believes that its limits need
to be adjusted the process will adjust the limits of both BAs accordingly.
The Background Document and Attachment A explain how a FRSG would report. The FRS Forms allow BAs and RSGs to account
for contributions from either.
PPL NERC Registered
Affiliates
No
The NERC posting did not include a redline to Attachment A, therefore, it is not clear
what modifications were made. However, there are several modifications that would
add clarity to the attachment. The PPL Affiliates support the comments of the SERC OC
Standards Review Group on this question, additionally, the following issues should be
addressed:
In Attachment A, page 3 and elsewhere, clarify that temporary or small transfers of
load or generation between BAs do not require notification to the ERO or changes to
the FBS or CPS limits.
In Attachment A, page 4, a BA should be allowed to be exempt from evaluation any
single frequency event where non-conforming load performs contrary to the
performance of conventional load (ie. during a frequency decline, the non-conforming
load simultaneously increases significantly). By nature, non-conforming load is totally
unpredictable, changes quickly, and fluctuates widely. Other than interruption, the BA
has no control over the actions of such loads nor can the BA predict or assume any
“normal” action by a non-conforming load during a frequency disturbance event.
Setting a limit on the number of events that a BA could exempt (regardless of the
reason) from FR evaluation in any given year would be more fair and effective in
evaluating a BA’s frequency response performance.
Response: Please refer to our response to the SERC OC Standards Review Group.
Consideration of Comments: Project 2007-12
38
000875
Organization
Yes or No
Question 4 Comment
The drafting team does not agree that there should be an exemption but has designed the forms to allow for adjustments for nonconforming load. However the BA may find that no adjustment for non-conforming load may be needed due to the measurement
over multiple events rather than individual events.
Kansas City Power & Light
No
The Standard proposes a calculation that overstates the frequency response obligation
(FRO) for Balancing Authorities.
Response: The drafting team disagrees with your comment. However, the drafting team cannot provide any detail due to the lack
of details in your comment.
Arizona Public Service
Company
No
The supporting document on the standards page does not provide information on CB
Ratio and why it is used. It significantly increases FRO and should be justified based
upon strong technical basis and actual experience. (Please also see AZPS response to
question 6, The Frequency Response Initiative Report should be on the Standards
page).
Response: The rationale can be found beginning on page 14 of the Background document and page 49 of the FRI report.
Please refer to our response for Question #6.
PJM Interconnection, LLC
No
The target contingency protection criterion for the Eastern Interconnection is the
largest event in the last 10 years (believed to be a 2007 event) which is inconsistent
with the other Interconnections. Is periodic review required for this criteria?
Will this criteria be revised after the referenced event is older than 10 years?
Are the other three interconnection’s target contingency protection criteria subject to
revision if they experience an event larger than a category C?
This BA believes that future periodic analysis should be defined and subsequent
findings used to support changes via the standard revision process. What are the
procedural requirements for revising Attachment A?
This BA is concerned that the procedure for revising Attachment A is undefined and
Consideration of Comments: Project 2007-12
39
000876
Organization
Yes or No
Question 4 Comment
that, for example, the IFRO could be increased absent the formal standard revision
process, increasing a BA’s FRO and subsequently increasing a BA’s compliance risk
without providing BA’s the opportunity to review, comment, and ballot.Related to the
previous comment/question, how often are the statistically derived values in Table 1
subject to a required update? For example, the Eastern Interconnection is adjusted due
to observed primary frequency response withdrawal (‘lazy L’ characteristic). The other
Interconnections are adjusted for observed differences between point C and point B.
As the frequency response characteristics of any Interconnection change, is Table 1
subject to required analysis and revision? This BA believes that future periodic analysis
should be defined and subsequent findings used to support changes via the standard
revision process.
Attachment A indicates that a BA may exclude an event from annual Form 1 FRM
evaluation only if its tie-line or frequency data is corrupt or unavailable. This exempts
numerous scenarios that could result in a poor response score due to system
variations. These could include, but are not limited to, changing energy schedules,
changes in load, and AGC driving units up or down due to the ACE value at the time of
the frequency event. This subjects the BA to undue compliance risk even though the BA
may have adequate frequency responsive resources at the time. This BA suggests that
the FRSDT adopt language (and Form 2 functionality) that allows the exclusion of
events that are skewed by these types of situations.
Attachment A and Forms 1 & 2 specify that 20 to 52 seconds will be used as the postevent B point average for FRM determination. The number of fast responding
resources will increase as the technology for batteries, flywheels, and frequency
controlled demand side devices moves forward over time. The 20 to 52 second interval
does not adequately incentivize the devopment of these technologies.
Response: The results for the current Eastern Interconnection model do not represent observed response adequately. The
models for the other Interconnections have a better match. For this reason, the drafting team has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details
Consideration of Comments: Project 2007-12
40
000877
Organization
Yes or No
Question 4 Comment
are provided on pages 52 through 55 of the Frequency Response Initiative paper.
As the model for the EI is improved and information and experience is gained under this standard the answer to your question will
be determined through an open and inclusive process.
If it is determined that a change in any methodology used in the processes in this standard is needed it would have to go through
the standards process.
The drafting team does not agree that there should be an exemption but has designed the forms to allow for certain adjustments.
In addition, the methodology recommended utilizing the median addresses the concerns related to a single event occurrence.
Ultimately the BA may find that no adjustment may be needed due to the measurement over multiple events rather than
individual events.
This standard was not intended to provide incentives for the development of new technologies. It is intended to provide for the
reliable operation of the Bulk Electric System.
Northeast Power
Coordinating Council
No
This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource
contingency criteria (in the attachment, this is called the “target contingency criteria”),
etc. A sample calculation would be of value to entities. “The largest category C (N-2)
event is used for all interconnections except the Eastern which uses the largest event in
the last 10 years”. All interconnections should be using the same design basis
contingency. The NERC 2012 CPS2 bounds has an Eastern Interconnection frequency
bias of -6,360 MW/.1Hz. Why does this attachment refer to an Interconnection
frequency response obligation of -1,002MW/.1Hz.? This is a significant difference.
Response: As stated in Attachment A these terms are defined in the Procedure. The drafting team clarified the use of multiple
terms of “resource contingency criteria” throughout both Attachment A and the Procedure documents.
The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
The results for the current Eastern Interconnection model do not represent observed response adequately. The models for the
other Interconnections have a better match. For this reason, the drafting team has recommended the largest event in the last ten
years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on pages
Consideration of Comments: Project 2007-12
41
000878
Organization
Yes or No
Question 4 Comment
52 through 55 of the Frequency Response Initiative paper.
The -6,630 MW/0.1 Hz represents a summation of the Frequency Bias Settings of all Balancing Authorities in the Eastern
Interconnection, most of which use the 1% default minimum as required in the current BAL-003-0 standard, which far exceeds
their real response. The IFRO of -1002 MW/0.1 Hz is the response determined to avoid the first step of Underfrequency load
shedding in the Interconnection for a 4,500 MW generation loss.
Ameren
No
We disagree on having different methodologies for determining the targets, and would
like clarity added for when those targets may change, such as what will happen after
the largestest event in the last 10 years rolls off the books for the EI?
Response: The results for the current Eastern Interconnection model do not represent observed response adequately. The
models for the other Interconnections have a better match. For this reason, the drafting team has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details
are provided on pages 52 through 55 of the Frequency Response Initiative paper.
If it is determined that a change in any methodology used in the processes in this standard is needed it would have to go through
the standards process.
As the model for the EI is improved and information and experience is gained under this standard the answer to your question will
be determined through an open and inclusive process.
Manitoba Hydro
Yes
(1) Page 2, Balancing Authority Frequency Response Obligation (FRO) and Frequency
Bias Setting: States that the ERO is responsible for “annually assigning an FRO and
Frequency Bias Setting to each BA.” No mention is made of FRSGs.
(2) Neither R1 nor the referenced Attachment A clarifies the FRM requirements for an
FRSG to comply versus a BA. In particular, compared to BAL-002-0 R1.1, which clearly
states that the BA may elect to fulfill its obligation through an FRSG and that in such
cases the FRSG has the same responsibilities as each BA (that is a participant in the
FRSG).
(3)Attachment A refers to an FRSG calculating FRM, but the standard does not.
Consideration of Comments: Project 2007-12
42
000879
Organization
Yes or No
Question 4 Comment
Response: 1) - The FRSG FRO is a summation of its members’ FROs.
2) & 3) -The drafting team believes that it is clearly stated for a FRSG compliance with R1. The Requirement reads “Each
Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a member of a FRSG shall achieve an annual
Frequency Response Measure (FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each FRSG or
BA that is not a member of a FRSG to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation.”
Texas Reliability Entity
Yes
1. The calculation for the FRO for ERCOT includes a credit of 1400 MW for load
resources. 1400 MW is currently the maximum amount of LR that can be procured
through the ERCOT ancillary service process. There can be periods during the day
where 1400 MW was not procured or is not available (It was noted during the summer
of 2012 that on some days, only 900 MW of LR was available through the ancillary
service process). Should the calculated IFRO (-286 MW per 0.1 Hz) be modified to
account for this variation?
2. Background Document says: “Attachment A proposes the following Interconnection
event criteria as a basis to determine an Interconnection’s Frequency Response
Obligation: o Largest category C loss-of-resource (N-2) event o Largest total
generating plant with common voltage switchyard o Largest loss of generation in the
interconnection in the last 10 years” For ERCOT, the largest loss of generation in the
last 10 years was over 3400 MW, and does not match the 2750 MW (N-2) value used
for the IFRO calculation.
Response:
(1) The process used to determine the IFRO has been vetted through multiple forums. The drafting team feels that the proposed
calculation is appropriate for the standard at this time. As experience is gained through the implementation of this standard,
the calculation will be reviewed and any adjustments will be addressed through an open and inclusive process.
(2) The results for the current Texas Interconnection model represent observed response adequately so the recommended
Resource Contingency Criteria for ERCOT is the Category C N-2 event. For further details related to the full determination,
Consideration of Comments: Project 2007-12
43
000880
Organization
Yes or No
Question 4 Comment
please refer to the Frequency Response Initiative paper.
SPP Standards REview
Group
Yes
Delete the 2nd ‘that’ in the 2nd bullet at the top of page 3.
Response: Thank you for the comment. The drafting team has made the correction.
Xcel Energy
Yes
It is not clear however, as to if this is actually part of the standard or if it is a document
that can be revised without going through the standards development process.
Also, the formatting of the document should be modified to clearly identify where
'steps/actions' are needed from responsible parties, whether that be the ERO or
BA/FRSG.
Response: If it is determined that a change in any methodology used in the processes in this standard is needed it would have to
go through the standards process.
Please refer to the “timeline” on page #6 of Attachment A as this clearly provides for who has responsibility for each step in the
process.
NextEra Energy
Yes
NextEra Energy does not support the changes made. It is concerned that certian
changes were made to help some large East coast entities that could not comply at the
expense of the FRCC region. Specifically, now on page 3 of Attachment A 4th
paragraph from the bottom the statement is made “ sets its frequency bias to the
greater of”. We believe that this must be changed to either Statement 1 “ Any number
the BA chooses between 100% etc”Or Statement 2 “ Interconnection minimum as
determined by the ERO” Without this change, NextEra beleives the FRCC will be
unfiarly treated relative to others on the Eastern Interconnection. The technical
reasons for this is concern was explained during the Standard Drafting Team meetings.
In addition, the ERO limit which is set at 0.9% of load should be changed to read within
0.8 or 0.9% of peak load based on the BA’s choice.
Also, see page 7 of the Procedure document and compare to page 1 of Attachment A.
Consideration of Comments: Project 2007-12
44
000881
Organization
Yes or No
Question 4 Comment
The formulae abbreviations for the variables in the Procedure are not likewise
abbreviated in Attachment A. For example, “Credit for LR” on Attachment A is “CLR” in
the Procedure, but it requires cross checking each document to figure this out. Or CBr
in Attachment A, Table 1 is represented as DFCBR in the Procedure, Page 7. Since the
same variables are being described, these should be represented the same way in both
documents throughout.
2. Similarly, is “IFRO” in Table 1 of Attachment A the same as “FROInt” of the equation
that follows on page 2? The same abbreviation should be used to represent this
variable. The documents should be revised in general along these lines for all terms.
3. In Procedure document, page 5, paragraph 3 it should read “Table 2”, not “1”.
4. In the Procedure, it would be good to show Table 1 and Table 2 as Table 1 of
Attachment A (i.e. use table lines and borders).
5. At least in the first usage, ERO in the Procedure document should be spelled out as
“Electric Reliability Organization (ERO)”.
6. In Table 1 of Attachment A, the two footnotes preceded by asterisks (single and
double on page 2) should be connected to the table by adding a single superscripted
asterisk to the Eastern UFLS value of 59.5, and a double superscripted asterisk to the
ERCOT LR value of 1,400.
Response:
(1) The drafting team does not believe any BAs were favored over other BAs. However the drafting team is unclear as to your
expressed concerns related to FRCC. In direct communications with FRCC they concluded that the IFRO starting frequency of
the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS operation in FRCC
for an external resource loss event than for an internal FRCC event.
The drafting team does not agree with the recommended wording change for the bias setting because it would essentially
remove the Interconnection minimum FBS. The drafting team does not agree that we are mixing terms between the
Procedure and Attachment A. The drafting team uses CBR and DFCBR in both documents defining two different variables. The
drafting team clarified CLR.
Consideration of Comments: Project 2007-12
45
000882
Organization
Yes or No
Question 4 Comment
(2) The drafting team clarified IFRO/FRO in the documents.
(3) Thank you. The drafting team has corrected this in the document.
(4) The drafting team thanks you for your comment. However, the majority of the industry does not support your suggested
modification. Therefore, the drafting team will leave the tables as shown.
(5) The drafting team changed ERO to Electric Reliability Organization as per your suggestion.
(6) Thank you. The drafting team has made the changes.
NREL Transmission and Grid
Integration Group
Yes
Table 1: CB_r units should be unitless, CB'adj should be Hz.
Response: Thank you for the comment. The drafting team has made these changes.
NV Energy
Yes
This document is improved, and satisfactorily addresses comments from the prior
posting.
Response: Thank you for the comment.
New York Independent
System Operator
Yes
With a new process we are concerned that the interconnection minimum will initially
move from 1.0% to 0.9%.
Response: Thank you for your comment. The new process moves the minimum from 1.0% to 0.9%.
MRO NSRF
Yes
Edison Electric Institute
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Consideration of Comments: Project 2007-12
46
000883
Organization
Yes or No
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Southern Company
Yes
Idaho Power Company
Yes
Tucson Electric Power
Yes
Keen Resources Asia Ltd.
Yes
MISO
Yes
Puget Sound Energy
Question 4 Comment
In reviewing the Consideration of Comments document, it is clear that the standard
drafting team does not wish for the administrative elements of Attachment A to
become items addressed during compliance evaluations (“There is no intent to require
filing on a certain date and to have the BA prove to the auditor that a filing was made
on that date.” This quote appears at several places in the Consideration of Comments
documents, but first at page 113). However, because Attachment A is referenced in
the standard, its provisions, including the timing table, are all mandatory and
enforceable. This result is emphasized by the language of requirement R1, which states
that entities “...shall achieve an annual Frequency Response Measure (FRM) as
calculated and reported in accordance with Attachment A....” This language means
that a failure to file a document on a date specified in the attachment would be a
potential compliance violation. Because Attachment A is mandatory and enforceable,
the standard drafting team should carefully review its provisions and clarify which
elements are requirements and which elements are background statements or
guidance. In addition, the use of additional headings and section numbers would add
in clarifying the document (for example, at the top of page 3, there is a discussion of
how an FRSG would calculate its FRM; however, there is an entire section beginning on
Consideration of Comments: Project 2007-12
47
000884
Organization
Yes or No
Question 4 Comment
page 4 addressing FRM where that discussion should instead appear).
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
Consideration of Comments: Project 2007-12
48
000885
5.
The SDT has moved a portion of the material located in Attachment A and all of the material located in ”Attachment B- Process
for Adjusting Bias Setting Floor” into a new document “Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard”. The SDT created this document to assign tasks to the ERO and provide instructions for the ERO to follow
when carrying them out under the BAL-003-1 standard. Do you agree that the ERO should perform these tasks and that this
document provides sufficient detail for the ERO to do it under the BAL-003-1 standard? If not, what needs to be added to the
document?”.
Summary Consideration: Several commenters requested clarity on how modifications to the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard would be made. The drafting team explained that the
“Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard” was not incorporated into
the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure will not be developed
through the standard development process. Consistent with NERC’s commitment to an open and transparent process,
the procedure for modifying the event selection process for supporting the Frequency Response Standard is set forth in
the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and
will discuss the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in
addition, any modifications will be filed with FERC for informational purposes. This process provides the industry
assurance that changes will be properly vetted and that there is an opportunity for stakeholder input.
A couple of commenters questioned how events would be excluded, specifically with regards to during ramping periods. The drafting
team stated that all events are considered. Events that occur over known ramping periods are selected last. As an
example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used.
The benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
A few commenters did not understand why the frequency criteria are different for each Interconnection. The drafting team
explained that the frequency criteria was different for each interconnection because the frequency used to measure
frequency response is interconnection dependent and varies differently for each interconnection. Larger
interconnections have greater frequency response and as a consequence smaller frequency deviations for events of
the size typically experienced.
One or two commenters questioned whether certain events should always be included in the evaluation process. The drafting team
stated that based on event evaluation by this drafting team, it has been determined that it is impossible to require
certain events to be included. This is the reason that the drafting team has developed the Event Selection Criteria.
Consideration of Comments: Project 2007-12
49
000886
Organization
Yes or No
Keen Resources Asia Ltd.
No
Question 5 Comment
As a professionally trained published statistical expert never compensated by any
balloting participant, I consider event selection criterion 7 to be unacceptable because
it violates the fundamental statistical procedure of sampling statistical data "as is" and
not pre-selecting the data (to fit some preferred even-distribution over time) and
therefore biasing it before applying any statistical procedure to the data. Event
criterion 6 is also unacceptable for being an an "ad hoc" explicit exclusion, from the
definition of the frequency response being measured, of response to frequency events
that occur during a specific kind of scheduled generation and load changes. Said
exclusion needs to be written into the definition of the Frequency Response that is
being measured. It is procedurally improper and unacceptable to bias the sampling
procedure by explicit exclusion of data as an alternative to redefining the thing being
sampled. In that case it's not generic Frequency Response that is being sampled, but
some specific Frequency-Response-less-Response-to-Excluded-Events that is being
measured. It is non-transparent and subterfuge to avoid instead accordingy
reworking/narrowing the definition of Frequency Response, especially as said
reworking requires a clear technical justification that is absent from this standard, and
modifying the existing NERC Glossary definition of Frequency Response which Criterion
6 therefore stands in flat violation of.
Response: Criterion 7 is included in the Event Selection Criteria because the drafting team considers it very important to be able
to select and finalize events for analysis quarterly so that the BAs can evaluate their performance as the measurement year
unfolds. This necessarily requires minimal criteria to insure that this selection and finalization process can be completed
quarterly. The drafting team recognizes that this finalization may have some effect on the sampling, but values the quarterly
selection and finalization more than the pure statistical sampling theory. This is a trade-off that the drafting team has chosen to
make. Once several years of a regular disparity between seasons of the year were established in terms of number of events in a
season, the industry could propose modifying the Standard at that time to adjust Criterion 7 accordingly.
Criterion 6 is included because historic data indicate that the periods within 5 minutes of the top of the hour have shown to have
Consideration of Comments: Project 2007-12
50
000887
Organization
Yes or No
Question 5 Comment
higher frequency variability than other periods in the hour. Statistical analysis presented in the FRI Report indicates that predisturbance frequency is a significant contributor to the variability of frequency response. The drafting team has chosen to allow
the exclusion of events close to the top of the hour when other acceptable events are available until analysis is done of whether
these periods have a statistically different frequency response and therefore introduce bias. Meanwhile, as Balancing Authorities
are moving toward quarter-hourly scheduling, the higher top-of-the-hour frequency variability prompting the need and
application of Criterion 6 is expected to disappear. Therefore, while your recommended alternative of changing the NERC
definition of Frequency Response may be statistically correct, from a practical perspective it would likely prove to be a needless
chore and to yield a needlessly complicated definition only to have to be changed back again.
Southern Company
No
Attachment A states that Form 1 is posted annually. The ERO support document selects
events annually. The timing for the two documents needs to be aligned so that the set
of selected events does not change from quarter to quarter. (If three events are
selected for the first quarter those same events will be a sub-set of the 20 events
selected for the annual compliance calculations.)
Response: Attachment A indicates that Form 1 with the events from the previous quarter is posted on May 10th, August 10th,
November 10th and the second business day in February. It is the intent of the standard that events once posted will be included
in the FRM analysis.
BC Hydro
No
BC Hydro agrees in principle that the ERO should perform these tasks related to BAL003-1 but has the following concerns:
1. There is no clear indication whether the Interconnection FRO will be calculated every
year, and if yes, how each of the factors involved will be determined.
2. It is not clear whether data gathered in these procedures are only for the
determination of annual FRO and FBS, or also to determine whether the BA or the FRSG
was in compliance to BAL-003-1 for the assessed year. Since the ERO in this Document
seems to be the NERC Resources Subcommittee and its Frequency Work Group, we
think this fact should be made clear. The Background document should also be
reviewed to ensure its alignment in this regard.
Consideration of Comments: Project 2007-12
51
000888
Organization
Yes or No
Question 5 Comment
Response: The drafting team has chosen to use the methods presented in the FRI Report to determine the values presented in
Table 1 of Attachment A to determine the Interconnection FRO. If the method of calculation by the ERO or the base starting
values used to determine the IFRO change (i.e. Resource Contingency Criteria or Prevailing UFLS First Step), then those changes
will be subject to the standards process to accept those changes. If the statistical determinates used in the method change (i.e.
Starting Frequency, CCADJ, CBR, BC’ADJ, and Credit for LR) or the data used to allocate the IFRO among the BAs (i.e. FERC Form 714
data) changes, the new values will be implemented without being subject to the standards process.
The data gathered for the FRO calculation is not compliance related. The calculation of FBS is also not compliance related.
However, assuming the information is entered into FRS Form 1 correctly then the FBS number will be used by an auditor to
determine compliance with Requirement R2.
The drafting team has been instructed by NERC to refer to all NERC entities (i.e. Frequency Working Group, Resources
Subcommittee, etc) as the ERO.
Bonneville Power
Administration
No
BPA does not agree with the methodologies outlined in Attachment B. Please see
BPA’s response to question 6 as well as BPA’s extensive comments submitted on
12/8/11 for Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf
Response: Please refer to our response to your comment for Question #6 and our responses to your comments dated 12/8/11.
Kansas City Power & Light
No
Criteria 3 - Why are frequency thresholds different between regions when generator
governor reaction is supposed to be the same between regions?
Criteria 5 - What is the reasoning that multiple events that are not stabilized within 18
seconds not being considered?
Criteria 6 - How are "changes in scheduled interchange" or load change determined in
regions with interconnections with multiple BAs with different time zones?
Response: The frequency criteria is different for each interconnection because the frequency used to measure frequency response
is interconnection dependent and varies differently for each interconnection. Larger interconnections have greater frequency
response and as a consequence smaller frequency deviations for events of the size typically experienced.
Consideration of Comments: Project 2007-12
52
000889
Organization
Yes or No
Question 5 Comment
The standardized method used to measure frequency response will not work correctly for events that have not stabilized within
18 seconds.
This determination will be made by the ERO (presently the Frequency Working Group).
All events are considered. Events that occur over known ramping periods are selected last. As an example, the event reflected in
the right graph shown in the Procedure would be selected over the event reflected in the graph on the left. If an inadequate
number of events are available for that season, then these events may be used. The benefit of using the median of at least 20
events in a year helps minimize the impact of outliers.
Duke Energy
No
Duke Energy agrees with allowing the ERO to perform this function, however the
industry needs some assurance that this Procedure cannot be changed outside of the
Standards Process for approval by the industry. In the sixth line of the third paragraph
on page 5, the statement should reference Table 2. Page 5 reads as if the BAs will
submit their data based upon Form 1 which includes an adjustment to the
Interconnection peak load (initially 0.9), and then the ERO will determine whether the
Interconnection minimum FBS is still more than 20% above the measured response - if
so, the minimum FBS will be adjusted, requiring the BAs to reassess their new
minimum FBS based upon a different factor, and decide whether to use that value or
choose a value up to 125% of their FRM, resulting in another iteration of values being
submitted to the ERO. If the ERO is going to do an independent assessment of
Interconnection Frequency Response to the events, on an annual basis prior to
gathering data from the BAs, the ERO could compare the total FBS being used by the
BAs against the estimated Frequency Response over that period to determine if an
adjustment is warranted, and then the ERO could include the appropriate adjustment
factor (0.9, 0.8, etc..) in Form 1 for the BAs to use. If the ERO is not going to estimate
the Frequency Response aside from the BAs, multiple iterations will be likely. Duke
Energy suggests the following language to cover the point above: “On an annual basis,
the ERO will review the Interconnection total minimum Frequency Bias Setting for the
prior period and compare it against the Interconnection’s total natural Frequency
Response determined for that period. If an Interconnection’s total minimum
Frequency Bias Setting exceeds (in absolute value) the Interconnection’s total natural
Consideration of Comments: Project 2007-12
53
000890
Organization
Yes or No
Question 5 Comment
Frequency Response by more (in absolute value) than 0.2 percentage points of the
Interconnection non-coincident peak load (expressed in MW/0.1Hz), the minimum
Frequency Bias Setting for BAs within that Interconnection may be reduced (in absolute
value) based on the technical evaluation and consultation with the regions affected by
0.1 percentage point of Interconnection non-coincident peak load (expressed in
MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency
Response. The ERO will include the adjustment factor in the Interconnection Form 1
used by the Balancing Authorities for the calculation of the new minimum Frequency
Bias Setting. The Form 1 information from the Balancing Authorities will be gathered
by the ERO in coordination with the regions of each Interconnection to determine the
final Interconnection Frequency Bias Setting for the next period.”
Response: The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard” is not incorporated into
the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure will not be developed through the
standard development process. Consistent with NERC’s commitment to an open and transparent process, the procedure for
modifying the event selection process for supporting the Frequency Response Standard is set forth in the opening paragraph of
the Procedure for ERO Support of Frequency Response and Frequency Bias Setting document. NERC will post suggested
modifications for a 45-day formal comment period, respond to all comments and will discuss the revision request in a public
meeting. Revisions will be provided to the NERC BOT for approval and in addition, any modifications will be filed with FERC for
informational purposes. This process provides the industry assurance that changes will be properly vetted and that there is an
opportunity for stakeholder input.
The reference has been changed from Table 1 to Table 2. Thank you for your comment.
The review of the information provided by the BAs discussed in the Procedure document will take a significant amount of time.
Therefore, the change to the Interconnection Minimum Frequency Bias Setting will occur on the subsequent year’s Form 1. This
will eliminate the risk of multiple iterations and allow sufficient time for the ERO to consult with the regions as indicated in the
Procedure. The drafting team has included clarifying language in the document.
Tucson Electric Power
No
I think it should be more clear or better defined that an interconnection does have
some input into what events are selected.
Consideration of Comments: Project 2007-12
54
000891
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. Each interconnection has a representative on the Frequency Working Group that
performs the selection of events.
Exelon Corporation and its
affiliates
No
Please see response to question 8.
Response: Thank you for your comment. Please see response to Question 8.
PJM Interconnection, LLC
No
The Procedure indicates that events that occur when ‘large interchange schedule
ramping or load change is happening’ and ‘events occurring within 5 minutes of the top
of the hour’ should be excluded from consideration. Since interchange schedule
ramping and load change occurs at the BA level, this BA believes that the Procedure
allows for the selection of events that occur when a BA is experiencing these conditions
but Attachment A does not allow for exemption of these events. Also, the Procedure
specifies that events that occur at the top of the hour be excluded, if other qualifying
events exist, but this does not take into consideration energy markets that allow for
sub-hourly schedule changes (e.g. 15 minutes) and the BA is not permitted to exempt
these events on Form 1 subjecting the BA to undue compliance risks.
Response: Thank you for your comment. All events are considered. Events that occur over known ramping periods are selected
last. As an example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used. The
benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
Texas Reliability Entity
Yes
1. Event Selection Criteria Item 2: Should certain events require mandatory inclusion
for FRM calculation (i.e. DCS events)?
2. Event Selection Criteria Item 6: We disagree with the way this is worded. If a unit
trips during this time, as it often can, measured frequency response needs to occur.
We understand that the results are impacted by the grid condition and perhaps that is
why the SDT decided to exclude the issue. Need to define what is intended by a “large”
Consideration of Comments: Project 2007-12
55
000892
Organization
Yes or No
Question 5 Comment
interchange ramp schedule or load change. May also want to consider changing the
language from “will be excluded from consideration” to “MAY be excluded from
consideration”.
Response: Thank you for your comment. Based on event evaluation by this drafting team, it has been determined that it is
impossible to require certain events to be included. This is the reason that the drafting team has developed the Event Selection
Criteria.
The drafting team wrote the criteria to allow flexibility for any change that significantly impacts frequency.
The drafting team looked at the language and determined that the present language provides greater clarity. The “will be
excluded” is followed by “…if other acceptable frequency excursion events from the same quarter are available.” Therefore, it is
not a mandatory exclusion.
Edison Electric Institute
Yes
EEI supports the ERO’s role as defined in the procedure but is concerned that the
procedure, unlike approved NERC standards, is unbounded by the current rules for
developing standards. For that reason, EEI recommends that the procedure become
more formalized and integrated into the standard as an addendum thereby avoiding
any Industry concerns that future modification might occur outside the approved
processes
Response: Thank you for your comment. The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard” is not incorporated into the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure
will not be developed through the standard development process. Consistent with NERC’s commitment to an open and
transparent process, the procedure for modifying the event selection process for supporting the Frequency Response Standard is
set forth in the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and will discuss
the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in addition, any
modifications will be filed with FERC for informational purposes. This process provides the industry assurance that changes will be
properly vetted and that there is an opportunity for stakeholder input.
ACES Power Marketing
Yes
Overall, we agree. However, we suggest the document clarify that the ERO shall
Consideration of Comments: Project 2007-12
56
000893
Organization
Yes or No
Standards Collaborators
Question 5 Comment
perform these tasks in coordination with the Resources Subcommittee. It consists of
industry experts that can be an extra resource to NERC. Furthermore, NERC staff
working with the Resources Subcommittee will provide additional transparency to the
process.
Response: Thank you for your comment. The drafting team has been instructed by NERC to refer to all NERC entities (i.e.
Frequency Working Group, Resources Subcommittee, etc) as the ERO.
MISO
Yes
The first hyperlink on page 3 of the Procedure for ERO Support does not work.
Response: Thank you for your comment. The drafting team has corrected this.
Xcel Energy
YES
It is not clear however, as to if this is actually part of the standard or if it is a document
that can be revised without going through the standards development process. Also,
the formatting of the doucment should be modified to clearly identify where
'steps/actions' are needed from repsonsible parties, whether that be the ERO or
BA/FRSG.
Response: Thank you for your comment. The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard” is not incorporated into the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure
will not be developed through the standard development process. Consistent with NERC’s commitment to an open and
transparent process, the procedure for modifying the event selection process for supporting the Frequency Response Standard is
set forth in the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and will discuss
the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in addition, any
modifications will be filed with FERC for informational purposes. This process provides the industry assurance that changes will be
properly vetted and that there is an opportunity for stakeholder input.
Manitoba Hydro
Yes
NREL Transmission and Grid
Yes
No comment.
Consideration of Comments: Project 2007-12
57
000894
Organization
Yes or No
Question 5 Comment
Integration Group
SPP Standards REview
Group
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
NV Energy
Yes
New York Independent
System Operator
Yes
MRO NSRF
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
58
000895
6.
The SDT is now using the method detailed in the Frequency Response Initiative Report dated September 30, 2012 to calculate
the Interconnection Frequency Response Obligation. Do you agree that this method provides for the proper amount of
Frequency Response? If not, what specifically needs to be changed?
Summary Consideration: Many of the commenters requested clarification on how changes to the methodology defined in
Attachment A could be modified. The drafting team explained that Attachment A was part of the standard and as such
is subject to the NERC standards process for making any changes.
Several commenters questioned the use of the largest event in the last 10 years for the Eastern Interconnection. The drafting team
stated that the results for the current Eastern Interconnection model do not represent observed response adequately.
The models for the other Interconnections have a better match. For this reason the SDT has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. If the
largest event in the last 10 years falls below 4500 MW then the SDT believes that an N-2 event would be utilized.
One commenter wanted a method to discount outliers. The drafting team explained that this was one of the reasons that they had
chosen the median as the appropriate measure for FRM. The benefit of using the median of at least 20 events per year
helps to minimize the impact of outliers.
Organization
Yes or No
Bonneville Power
Administration
No
Question 6 Comment
BPA does not have specific changes to the methodology to suggest, however, a
methodology that arrives at a negative 840 MW per tenth Hz for WECC is obviously
under-calculating the frequency bias obligation. Currently WECC has an
interconnection bias of over 2000 MW / 0.1Hz and with this bias the frequency is
steady state following point B on the frequency response curve. BPA would expect to
see frequency decline after point B if the FBO is lowered by almost 60%. BPA also must
reiterate that there is still a problem with the method used for modifying the FBO and
frequency bias for Balancing Authorities. A high-performing Balancing Authority will
have its frequency bias increased each year due to higher response during the events
chosen by the ERO. Conversely, a low-performing Balancing Authority will have its
frequency bias reduced each year due to lower response during the events chosen by
Consideration of Comments: Project 2007-12
59
000896
Organization
Yes or No
Question 6 Comment
the ERO.
Response: After review of comments, the drafting team feels confident with the current method of calculating Frequency
Response Obligation as outlined in the Frequency Response Initiative report. This standard requires minimum bias setting not to
be less than 0.9% of the non-coincidental peak load for a multi-BA interconnection. This will ensure that minimum bias settings
will be based on Interconnection’s non-coincidental peak load rather than biased toward low-performer. The minimum Frequency
Bias settings requirement are outlined in Table 2 of “Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard”
The drafting team points out that there is not a Frequency Bias obligation and that the currently measured response for the
Western Interconnection is approximately -1200 MW/0.1 Hz. This number is above, but much closer to the required level of -840
MW/0.1 Hz under this standard.
Tucson Electric Power
No
I believe that the frequency bias obligation of the Western Interconnection is
understated.
Response: The drafting team points out that there is not a Frequency Bias obligation and that the currently measured response for
the Western Interconnection is approximately -1200 MW/0.1 Hz. This number is above, but much closer to the required level of 840 MW/0.1 Hz under this standard.
Duke Energy
No
Similar to our earlier concern, the industry needs some assurance that the calculation
of the Interconnection FRO described in the report cannot be changed outside of the
Standards Process for approval by the industry. Duke Energy does not support using a
4500 MW loss as the basis for determining the FRO for the Eastern Interconnection for
future events. However, as the calculation also includes 59.5 Hz as the basis for
determining the FRO, the result is an allocation which can be supported. To the extent
that the standard drafting team moves in the direction of using 59.7 Hz as the basis for
the FRO, then it needs to follow a methodology similar to the other Interconnections
for determining the credible multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
Consideration of Comments: Project 2007-12
60
000897
Organization
Yes or No
Question 6 Comment
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason the SDT has recommended the largest event in the last ten years be used to provide for an increased
reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the SDT
believes that an N-2 event would be utilized.
New York Independent
System Operator
No
The drafting team should consider some method for discounting outliers, that may not
be explainable.
Response: Thank you for your comment. All events are considered. Events that occur over known ramping periods are selected
last. As an example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used. The
benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
Southern Company
No
The industry needs some assurance that the calculation of the Interconnection FRO
described in the report cannot be changed outside of the Standards Process for
approval by the industry. We do not support using a 4500 MW loss as the basis for
determining the FRO for the Eastern Interconnection for future events. However, as the
calculation also includes 59.5 Hz as the basis for determining the FRO, the result is an
allocation which can be supported. To the extent that the standard drafting team
moves in the direction of using 59.7 Hz as the basis for the FRO, then it needs to follow
a methodology similar to the other Interconnections for determining the credible
multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
Consideration of Comments: Project 2007-12
61
000898
Organization
Yes or No
Question 6 Comment
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
PPL NERC Registered
Affiliates
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on
this question
Response: The Attachment A is part of the standard and as such is subject to the NERC standards process for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
Keen Resources Asia Ltd.
No
This question is falsely worded. The SDT is specifically NOT using the method detailed
in the Frequency Response Initiative Report dated September 30, 2012. So the term
"this method" is practically meaningless in this question because it is not clear if it
means "the SDT's method" or "the FRI's method". The Background Document
specifically states on page 29: "The NERC Frequency Response Initiative Report
addressed the relative merits of using the median versus linear regression for
aggregating single event frequency response samples into a frequency response
measurement score for compliance evaluation. This report provided 11 evaluation
criteria as a basis for recommending the use of linear regression instead of the median
for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but
concluded that the median would be the best aggregation technique to use initially
when the relative importance of each criterion was considered." What needs to be
changed, besides properly wording this question? The FRI method of linear regression
should be adopted, and the SDT method of median should be rejected, in the standard
to change the first sentence of this question into a true statement from a false
statement and to, in answer to the question, provide for the proper amount of
Consideration of Comments: Project 2007-12
62
000899
Organization
Yes or No
Question 6 Comment
Frequency Response.
Response: Thank you for your comments. The drafting team disagrees that the methodology for calculating the IFRO used in this
standard is different than that detailed in the FRI Report. The drafting team considered replacing median with linear regression but
chose to use the median because of its better resiliency to data quality problems found in the Actual Net Interchange data used in
the frequency-response calculation.
SERC OC Standards Review
Group
No
We believe the industry needs some assurance that the calculation of the
interconnection FRO cannot be changed without rigorous review and input from the
industry. In addition the clarification should be made how the one in ten year loss for
the Eastern Interconnection (4500 MW) would change after 10 years. Would the same
methodology be used or would the largest Category C (n-2) be used?
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
Arizona Public Service
Company
NO
1. The Frequency Response initiative report should be added to the standard as an
appendix. It is not clear where to find this report.
2. The jusitification for dividing delta frequency with C to B ratio is not adequate and
not clear.
Response: Thank you for your comment. 1) The drafting team disagrees that the FRI Report should be attached to this standard
as an appendix. We do agree that it should be easier to locate.
2) Please refer to the FRI Report for the reasoning you request.
Edison Electric Institute
Yes
EEI finds the method to be acceptable but as mentioned in our response to question
Consideration of Comments: Project 2007-12
63
000900
Organization
Yes or No
Question 6 Comment
No. 5 (above), we believe that the procedure should be more formally documented as
an addendum. Such a change would ensure that the document would remain
unchanged outside of the approved standards making process. Additionally, EEI does
not support using 4500 MW loss as the basis for determining the FRO for the Eastern
Interconnection for future events. However, as the calculation also includes 59.5 Hz as
the basis for determining the FRO, the results is an allocation which we believe is
acceptable. In the future, should the SDT decide to use 59.7 Hz as the basis for the
FRO, than it will need to follow a methodology similar to the other interconnections for
determining the credible multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
ACES Power Marketing
Standards Collaborators
Yes
We agree that this method will provide sufficient frequency response. However, we
believe Interconnection Frequency Response Obligation is used inconsistentently with
the definition of Frequency Response Obligation as documented in our response to
other comments.
Response: Please refer to our responses to your other comments.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
SPP Standards REview
Yes
No comment.
Consideration of Comments: Project 2007-12
64
000901
Organization
Yes or No
Question 6 Comment
Group
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
MISO
Yes
MRO NSRF
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
65
000902
7.
Based on Industry comments received the SDT made significant clarifying modifications to the Background Document. Do you
agree that this document provides sufficient information to justify the rationale used by the SDT in developing the draft
standard and provides the industry with sufficient understanding of the issues being addressed by the standard?
Summary Consideration: Several of the commenters questioned why the formula for FRO was missing. The drafting team explained
that this was a problem incurred during the conversion to a pdf file. Once the problem was recognized by NERC, it was
immediately fixed during the posting.
A couple of commenters felt that there should be discussion in the Background Document concerning “inertial response”. The
drafting team stated that they saw a limited role for inertial response in the context of this standard. The standard
inherently does not address inertial requirements. It is of interest herein because of its role in determining the postcontingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency nadir
(point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
A few of the commenters questioned the use of the largest event in the last 10 years as the criteria for the Eastern Interconnection.
The drafting team explained that the results for the current Eastern Interconnection model do not represent observed
response adequately. The models for the other Interconnections have a better match. For this reason the drafting
team has recommended the largest event in the last ten years be used to provide for an increased reliability margin for
the Eastern Interconnection. Further details are provided on pages 52 through 55 of the Frequency Response Initiative
paper.
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 7 Comment
(1) The formula for calculating Frequency Response Obligation appears to be missing
on page 23.
(2) We are confused by the varying sample rates for the different scan rates in the
Definitions of Frequency Values for Frequency Response Calculation table on page 13.
It would appear that the time range of values for the average B value varies more than
necessary by scan rate. For example, for 2-second scan rates, sampling would start at
20 seconds and end at 52 seconds. However, for the 4-second scan rates, sampling
Consideration of Comments: Project 2007-12
66
000903
Organization
Yes or No
Question 7 Comment
starts at 24 seconds and ends at 48 seconds. Why would it not also cover 20 and 52
seconds for a 4-second scan rate?
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The SDT has corrected the table.
Bonneville Power
Administration
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is
developing into. Please reference BPA’s extensive comments submitted on 12/8/11 for
Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Response: Thank you for your comment. Please refer to our response to your comments dated 12/8/11.
Keen Resources Asia Ltd.
No
See reply to Question 6. Also, the Background Document is seriously deficient in the
discussion of inertial response and therefore how imbalances "cause" frequency
deviation. The Background Document is overflowing in discussion of how frequency
deviation causes frequency response. In other words, the Background Document is
"reactive" and not "proactive". The Background Document lacks any discussion of the
internal dynamics of rotating machines, beginning with any definition of what Inertial
Response is. Inertial Response is the instantaneous power produced by the lag
("inertia") in the ability of the generator's rotor to slow down to the frequency of the
magnetic field in the generator's fixed stator whose frequency is instantaneously
lowered by a change in phase angle between voltage and current that is due to a
sudden loss of interconnected generation to meet load. Adjustments by voltage
response within milliseconds and near the location of the loss are sometimes possible
to avert rapid spread of a loss to the frequency of the entire interconnection, and
constitute the ongoing work of the Phasor Project long ago initiated by the DOE in the
persistent absence of NERC interest or work in this area. NERC and drafting team
members under advisement by NERC staff studiously resisted so much as any mention
of frequency deviation causation in discussions or in the Background Document. An
Consideration of Comments: Project 2007-12
67
000904
Organization
Yes or No
Question 7 Comment
inexplicable technical Cold War and Berlin Wall built in the 1970s and today separating
the DOE Phasor Project from NERC Frequency Response standard development and
NERC's so-called Frequency Response "Initiative" needs to be ended and torn down.
My document http://www.robertblohm.com/Inertia.doc provides missing technical
support and explanation for graphs 1-7 on pages 4-10 of the Background Document, on
the basis of an exact understanding of Inertial Response.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Northeast Power
Coordinating Council
No
While the discussion of primary frequency response includes inertial energy, the term
inertial energy is missing from the definition of “primary frequency response”.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Consolidated Edison Co. of
NY, Inc.
No
While the discussion of primary frequency response includes inertial energy, the term
inertial energy is missing from the definition of “primary frequency response”.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Consideration of Comments: Project 2007-12
68
000905
Organization
Yes or No
PPL NERC Registered
Affiliates
Yes
Question 7 Comment
The PPL Affiliates applaud the SDT for developing this technical justification document.
Response: Thank you for your comment.
Duke Energy
Yes
Though Duke Energy does not agree with some of the points in the Background
Document, it does justify the rationale used by the SDT. Additional comments: at the
top of page 23, it states that the basic Frequency Response Obligation is based on noncoincident peak load and generation data reported in FERC Form 714, however the
actual calculation is missing and should be based upon the reported MWh, not the
peak load as stated. At the bottom of page 23, it states that Attachment A proposes
the three options for event criteria, however doesn’t clarify why it was chosen that the
Eastern Interconnection would be held to the largest event over the last 10 years, while
others will be based upon the largest category C loss-of-resource (N-2) event.
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
pages 52 through 55 of the Frequency Response Initiative paper.
SERC OC Standards Review
Group
Yes
We agree with the Duke Energy comments on this question.
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
Consideration of Comments: Project 2007-12
69
000906
Organization
Yes or No
Question 7 Comment
pages 52 through 55 of the Frequency Response Initiative paper.
SPP Standards REview
Group
Yes
We like the document and feel that it provides a primer on the frequency response
standard.The following are typos in and suggested corrections to the document:-The
blue lines referenced in the paragraph under Figure 2 on page 14 are green (A) and red
(B).-Insert an ‘a’ in the 3rd line of the 2nd paragraph in the Sustained Response section
on page 19 between ‘provides’ and ‘greater’.-Insert a ‘for’ in the 2nd line of the 1st
paragraph on page 21 between ‘resource’ and ‘all’.-Change ‘provide’ to ‘provided’ in
the 3rd line from the bottom line of the 1st paragraph in the Single Event Frequency
Response Data section on page 24.-Change the ‘east’ to ‘Eastern Interconnection’ in
the 4th line of the 1st paragraph in the Median as the Standard’s Measure of Balancing
Authority Performance section on page 27. -Delete the ‘put’ in the 3rd bullet on page
29. Also, replace the ‘put’ in the 5th bullet with ‘gave’.
Response: Thank you for your affirmative response and clarifying comment. The errors you mentioned have been corrected.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
No comment.
Consideration of Comments: Project 2007-12
70
000907
Organization
Yes or No
Southern Company
Yes
Idaho Power Company
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
Tucson Electric Power
Yes
BC Hydro
Yes
MISO
Yes
MRO NSRF
Question 7 Comment
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
71
000908
8.
If you are not in support of this draft standard, what modifications do you believe need to be made in order for you to support
the standard? Please list the issues and your proposed solution to the issue.
Summary Consideration: A couple of commenters expressed concern with the fact that the onus for Frequency Response was being
put on the BAs who do not own or operate the generators. The drafting team explained that they had heard some of
the same concerns, but there are quite a few good reasons why this standard is a good starting point to meet the FERC
directives in Order No. 693 (which NERC was given a specific date next year to deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still,
they are responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the
standards. Similarly a TOP is responsible for maintaining voltage even though they may own no capacitor banks or
generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency
response (or generator governor response if the standard was generator centric) to about 30 events per year. There
are about 140 BAs in North America. There are on the order of 4000 generators that would have to report under a
generator-centric standard. How do you verify performance of 120,000 observations annually?
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large
contingency. It is not intended to be difficult to meet. As proposed, the standard has a performance obligation about
half of what we see today in actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have
about -2200MW/0.1Hz on average. The standard allows the formation of frequency response sharing groups (similar
in concept to DCS' RSGs) and allows obtaining response from other BAs contractually. This means there should be no
BAs out of compliance once the standard is in place.
A couple of commenters stated that they thought the standard was confusing. The drafting team stated that they appreciated their
concern that the standard is confusing, but the drafting team believed that the proposed standard is as clear as
possible while covering all of the issues involved and that based on comments received the industry was not in
agreement.
Consideration of Comments: Project 2007-12
72
000909
One or two commenters requested clarity on how modifications to the Attachment A could be made and if the FRS Forms 1 and 2 had
to be used. The drafting team explained that Attachment A was part of the standard and would have to use the
Standard Development Process to make any modifications. The drafting team also stated that the FRS Forms were
required to be used in the reporting.
A couple of commenters questioned the use of the Background Document. The drafting team explained that the Background
Document was only intended to be used for education and training similar to other training references in the NERC
Operating Manual.
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 8 Comment
(1) We believe that the drafting team work has demonstrated that the standard is
unnecessary. The data presented in the posting shows that all of the interconnections
easily exceed the required Frequency Response necessary to avoid actuating UFLS
relays. Since one of the main purposes of the standard is to provide sufficient
Frequency Response, it would seem the purpose is already met without implementing
and enforceable standard. So why is a standard needed to compel required Frequency
Response if it is already provided?
(2) Even though we believe the supporting data for the posting demonstrates the
standard is unnecessary, we understand NERC is required by a FERC directive to
provide a standard. Given this requirement, we do believe the drafting team has largely
provided a reasonable standard and supporting documents that only require a few
additional adjustments (see our comments in other questions for these adjustments) to
finalize the standard. As a result, we will likely end up supporting the standard once
these final adjustments are made.
Response: Thank you for your comment. We agree that the standard meets the primary directive to provide Frequency
Response. This standard will set a backstop to assure that Frequency Response will not decline past a “point of no return”
For issues raised in other questions please refer to our response to those questions.
Independent Electricity
No
a. We do not support R2 as drafted, specifically the phrase “until directed to change by
the ERO”. We do not agree that the ERO has any authority to “direct” a BA or FRSG, or
Consideration of Comments: Project 2007-12
73
000910
Organization
Yes or No
System Operator
Question 8 Comment
any responsible entities, to make changes to the Frequency Bias Setting or take any
operating or operations planning actions. We suggest to replace the word “directed”
with “requested”.
b. In R2, the words “subject to” can be interpreted differently. We suggest to replace
them with “in accordance with” to parallel the intent as conveyed in R1.
c. We are still concerned with the status of Attachment A, as indicated in our
comments submitted under Q4 - that it is unclear if the materials in Attachment A must
be adhered to or not. A standard should not have an attachment whose enforcement
status is unclear as part of a requirement.
d. FRS Forms 1 and 2 are referenced in Attachment 1, which itself has an unclear status
on measurability and enforceability. It is also unclear if FRS Forms 1 and 2 must be used
to submit the requested data. Collectively, Attachment 1, FRS Form 1 and Form 2 make
the standard very confusing as to which parts must be complied with. Much better
clarity is needed to clearly convey the standard ‘s requirements that are measurable,
enforceable and must be complied with.
Response: Thank you for your comments,
a) The drafting team believes that the term “direct” is less ambiguous. The drafting team believes that using the term “request”
could leave the impression that the action is optional.
b) The drafting team has adopted your suggested language.
c) Please refer to the drafting team response to Question #4.
d) The Attachment is mentioned in the standard requirements and is therefore enforceable. Since the FRS Forms are discussed in
the Attachment then they must be used in the calculation process.
Bonneville Power
Administration
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is
developing into. Please reference BPA’s extensive comments submitted on 12/8/11 for
Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Consideration of Comments: Project 2007-12
74
000911
Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment. Please refer to the drafting team response to your comments submitted on 12/8/11.
Exelon Corporation and its
affiliates
No
Exelon checked "no" because it does not support the current draft standard. Exelon’s
position is that efforts to modify frequency monitoring and control should be directed
at the existing standards. Since Frequency Bias is already a component of ACE, and ACE
performance is tracked by both CPS 1 and CPS 2, it seems evident that NERC already
has in place mechanisms for evaluating frequency response. NERC already has in place
mechanisms for ensuring sustained frequency response during a contingency, through
the Disturbance Control Standard (DCS) and its requirement for the contingent
Balancing Authority to deploy resources. Under the current BAL-003-0.1b language,
Balancing Authorities are given a consistent means for determining frequency bias, via
the minimum requirement of 1% peak generation or 1% peak load. Together with the
above references to existing CPS 1 performance measurements, current standards
meet the objectives outlined in BAL-003-1. This proposed draft BAL-003-1 complicates
the setting of Frequency Bias and attempts to go beyond that purpose into frequency
response performance, without clear rules for how to perform.
Exelon is also concerned with moving this standard forward while there is an ongoing
field trial that could impact whether this standard should be put into place. For
example, waivers are in place for CPS 2 for participating Balancing Authorities and
there is ongoing effort with the BAAL field trial set of standards that will establish
performance metrics around frequency control. As an alternate approach to waiting to
move forward on the standard, Exelon recommends the following BAL-003-1
Requirement language:
R1.
The ERO shall identify up to five [5] system frequency events in each
Interconnection that will be included in the Form 1 and 2 data requests for Balancing
Authorities by April 30th each year.
R2.
Each Balancing Authority shall submit the following data to the ERO annually
by July 15:
R2.1
Consideration of Comments: Project 2007-12
The total annual net output of generating plants inside the Balancing
75
000912
Organization
Yes or No
Question 8 Comment
Authority Area.
R2.2
The total annual load with losses inside the Balancing Authority Area.
R3.
Each Balancing Authority shall calculate its Frequency Response Measure using
Forms 1 and 2 as posted by the ERO. (See Attachment A_Form 1 and Form 2)
R4.
Each Balancing Authority or Frequency Response Sharing Group shall submit
Forms 1 and 2 to contacts designated by the ERO before the expiration of ERO
established deadlines, which shall be no earlier than 30 days after posting of Forms 1
and 2.
R5.
The ERO shall post the following information:
R5.1.
Each Interconnection’s Frequency Response Obligation
R5.2
Each Balancing Authorities Frequency Response Obligation
R5.3
Each Balancing Authorities Frequency Bias Setting
R6.
Each Balancing Authority shall implement in its ACE equation its ERO
established Frequency Bias Setting during the ERO established three-day
implementation period. No further adjustments can be implemented outside of the
parameters established below in the upcoming year unless a Balancing Authority
coordinates with the Regional Entity and the affected Balancing Authorities.
R6.1
A Balancing Authority using a fixed Frequency Bias Setting sets its
Frequency Bias Setting to the greater of (in absolute value):
R6.1.1. The number the BA chooses between 100% and 125% of its
Frequency Response Measure as calculated on FRS Form 1.
R6.1.2. The Balancing Authorities share of the Interconnection Minimum
as determined by the ERO.
R6.2 A Balancing Authority using a variable Frequency Bias Setting shall
maintain a setting that is:
Consideration of Comments: Project 2007-12
76
000913
Organization
Yes or No
Question 8 Comment
R6.2.1 Less than zero at all times, and
R6.2.2 Equal to or greater in magnitude than its Frequency Response
Obligations when Frequency varies from 60 Hz by more than +/-0.036
Hz.
R7.
Each Frequency Response Sharing Group or Balancing Authority that is not a
member of a FRSG shall monitor its Frequency Response Obligation and work with
generating facilities or demand response resources to provide sufficient Frequency
Response to meet the Frequency Response Obligation assigned by the ERO.
R8.
Each Balancing Authority that adds or removes generation or load, including
through the use of dynamic transfers, shall notify the ERO to ensure that any needed
adjustments to the Interconnection Frequency Response Obligation or Balancing
Authority Frequency Response Obligation and Bias can be calculated.
R8.1. The ERO shall notify all affected Balancing Authorities of modifications
to the Frequency Response Obligation due to the addition or removal of
generation or load.
R9.
Each Balancing Authority that is performing Overlap Regulation Service shall
modify its Frequency Bias Setting in its ACE calculation, in order to represent the
Frequency Bias Setting for the combined Balancing Authority Area, to be equivalent of
the sum of the Frequency Bias Setting as communicated by the ERO for the
participating Balancing Authorities.
Response: Thank you for your comment. ACE, CPS1, CPS2, BAAL and DCS are all standards that measure Secondary Control
actions. The inclusion of the Frequency Bias Setting in ACE and these standards make them blind to Primary Frequency Control
and thus incapable of helping with the evaluation of Frequency Response (Primary Frequency Control). R1 sets clear rules with
respect to how much Frequency Response is required from each BA through the Frequency Response Obligation (FRO) and
Frequency Response Measure (FRM). The BAAL Field Trial is investigating issues associated with Secondary Frequency Control
only and is not impacted by and has no impact on Primary Frequency Control and BAL-003. The drafting team has considered the
suggestions contained in the requirements suggested and has explained in the Background document the reasons for writing the
Consideration of Comments: Project 2007-12
77
000914
Organization
Yes or No
Question 8 Comment
requirements and measures as contained in the draft BAL-003-1.
Duke Energy
No
Given the FERC deadline approaching for NERC to deliver a Frequency Response
standard, Duke Energy supports the adoption of this standard with some reservations.
We believe that the proposed standard addresses the FERC directive to NERC, however
it also introduces some longer-term issues related to secondary control and related
costs that may have not been anticipated by the FERC. To that point, Duke Energy
believes that if this standard is adopted, the industry will have the time and
opportunity through the NERC standards development process to mitigate some of the
concerns presented in our comments.”
Response: Thank you for your affirmative response and clarifying comment. The drafting team agrees that there could be some
impact on other standards but the implementation period will allow for time to adjust and learn
Tucson Electric Power
No
I feel that a BA's frequency bias for the upcoming year should not be related to present
performance. A BA may have a good response one year and not good response
another year and therefore the threshold keeps moving around. I feel it should be
related to BA size and therefore somewhat standardized. E.g. a high-performing
Balancing Authority will have its frequency bias increased each year due to higher
response during the events chosen by the ERO. Conversely, a low-performing
Balancing Authority will have its frequency bias reduced each year due to lower
response during the events chosen by the ERO.
Response: Thank you for your comment. The drafting team believes that control and frequency performance improve if the Bias
Setting and the BA’s Frequency Response are as closely matched as possible. Low performing BAs will still have to provide the
Interconnection minimum Bias Setting. In an unlikely case where a high performing BA has an internal change that markedly
reduces their Frequency Response, there are provisions in the standard’s supporting document to accommodate an intra-year
change in its Bias Setting.
New York Independent
System Operator
No
In general we support the work of the DT, and the proposal to measure the systems
response to frequency events, along with the method to determine the FRO. My
Consideration of Comments: Project 2007-12
78
000915
Organization
Yes or No
Question 8 Comment
outstanding concern is with enforcement on an entity that does not own the resources
that provides the frequency response or the lack of obligation for the entity with the
information to provide to the BA to make the assessment of expected frequency
response. BA’s should at a minimum be given assurance that resources will provide
data that BA’s could use to forecast frequency response and take corrective actions.
Response: Thank you for your comment. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
Consideration of Comments: Project 2007-12
79
000916
Organization
Yes or No
Tri-State Generation and
Transmission Assn., Inc.
No
Question 8 Comment
It is our opinion that there has not been enough justification to merit creating a new
standard. If additional justification is provided then frequency responsive reserves
should be a subset of spinning reserves much like spinning reserves are a subset of
operating reserves.
Response: Thank you for your comment. This standard will set a backstop to assure that Frequency Response will not decline past
a “point of no return”
This standard does not prescribe a method to provide Frequency Response but does provide for measuring that Frequency
Response is delivered.
Spinning reserve is outside the scope of the industry approved SAR.
Puget Sound Energy
No
See comment in response to question 4 above for a discussion of Attachment A
concerns.
Appendix 1 of the Frequency Response Standard Background Document contains a
discussion about why the use of net actual interchange to calculate an entity’s
Frequency Response Measure might introduce inaccuracies into that calculation. That
discussion ends with the following statement: “The frequency response is buried within
the typical hour to hour operational cacophony superimposed on actual net
interchange values. The choice of metrics will be important to artfully extract
frequency response from the noise and other unrepresentative error.” Based on these
statements, it is very difficult to support the standard’s approach to calculating the
Frequency Response Measure.At Puget Sound Energy (PSE), though, we believe that
there is another factor to add to the “operational cacophony” listed in Appendix 1. PSE
is a comparatively small BA with limited internal generation. We are embedded
between two of the largest energy exporters in the Western Interconnection and,
when there is a frequency event, their response flows through PSE’s system. As a
result, PSE will experience transmission losses associated with the two BAs’ frequency
response as it flows through our system. When PSE’s frequency response is measured
using net actual interchange, these losses obscure, at least in part, our system’s
Consideration of Comments: Project 2007-12
80
000917
Organization
Yes or No
Question 8 Comment
frequency response. As a result, we ask the standard drafting team to consider
specifying a process that would allow us to propose and use an equivalent measure of
frequency response. For example, while we understand the concerns and difficulties
associated with measuring frequency response at the generator as the default measure
for all BAs, in our case, a choice to use that measurement option might prove to be a
more-feasible way to comply with the standard.
Response: Thank you for your comment. Please refer to our response to your comments on Question #4.
Analysis of Field trial data has not shown that this has been a problem.
The spreadsheets have been designed to allow for adjustment for dynamically scheduled resources located in another BA.
PJM Interconnection, LLC
No
See previous comments.
Also, this standard should be applicable to GOP’s as well as BA’s with, at a minimum,
the following requirements added:
Each GOP shall follow all directives of it’s Balancing Authority pertaining to
frequency responsive operation, including but not limited to the status, droop &
deadband settings of their governors.
Each GOP shall provide to their BA the status and droop & deadband settings of
their governors, and headroom available to respond to frequency deviations, as
requested.
Response: Thank you for your comment. MISO has done analysis to find all large frequency events over the past year and how the
generators in its footprint performed. It turns out that many of the generators aren't on line for any of the events and only a few of
the generators were on line for all large events. So what do you do with generators that are not frequently run? Even if a generator
ran 50% of the time, you wouldn't have enough events to do a quality measure in a year.
Generator verification standards (MOD 27) are scheduled to be revised. The drafting team believes that this will address your
second concern
PPL NERC Registered
No
The PPL Affiliates are concerned that the document referred to “Attachment A” is
Consideration of Comments: Project 2007-12
81
000918
Organization
Yes or No
Affiliates
Question 8 Comment
directly referenced in the proposed standard’s requirements but not actually attached
to the standard itself as Attachment A. Therefore, it is not clear how the proposed
document could be modified in the future. Having such material incorporated into a
standard takes away from the open and transparent stakeholder drive process.
Response: Thank you for your comment. The attachment is mentioned in the requirement within the standard and therefore
becomes a part of the standard. Any modifications needing to be made to the attachment will have to use the Standards Process.
Consolidated Edison Co. of
NY, Inc.
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in
BAL-001. The Standard is currently confusing to understand and it is unclear how the
bias is calculated. It is recommended that efforts should be made to clarify the
changes, especially Attachment A.
Response: Thank you for your comment. The drafting team appreciates your concern that the standard is confusing, but the
drafting team believes that the proposed standard is as clear as possible while covering all of the issues involved.
The drafting team will either develop training materials to provide better understanding for both the FRM and FBS calculations or
recommend to the NERC Resources Subcommittee to develop said materials.
Northeast Power
Coordinating Council
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in
BAL-001. The Standard is currently confusing to understand, and it is unclear how the
bias is calculated. It is recommended that efforts should be made to clarify the
changes, especially in Attachment A.
Response: Thank you for your comment. The drafting team appreciates your concern that the standard is confusing, but the
drafting team believes that the proposed standard is as clear as possible while covering all of the issues involved.
The drafting team will either develop training materials to provide better understanding for both the FRM and FBS calculations or
recommend to the NERC Resources Subcommittee to develop said materials.
Kansas City Power & Light
No
The Standard does not consider instances for smaller BAs that operate generation for
peak conditions and acquire energy for most of the operating year.
Consideration of Comments: Project 2007-12
82
000919
Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment. The drafting team is unsure of your precise question. However, if your question
concerns meeting your performance obligation year around, then the process does allow for mechanisms for a BA to obtain
Frequency Response from external resources
NV Energy
No
While I support the concept of a Frequency Response Standard with minimum
performance obligations, this Standard places the entire obligation for performance on
the Balancing Authority (and Frequency Reserve Sharing Group). Requirements R2-R4
are properly assigned to the BA, as this is the entity that is responsible for the
configuration and parameters in the ACE equation, including the provision of a
frequency bias setting. Requirement 1, however, is a performance requirement over
which the BA in the Functional Model has virtually no control or ability to influence.
Only a Generator Owner or Generator Operator is in a position of control over the
performance under this requirement through the operational control and configuration
of the responding generating units. In most BA's, the host BA entity also owns a fair
amount, even a vast majority in many cases, of the generation within the BA. However,
even in the event that the host BA owned 100% of the generation within its metered
boundary, it is the action of the entity exercising its GO/GOP function that impacts the
frequency response performance within the Balancing Area. Assignment of R1 to the
BA is inappropriate from the standpoint that reliability requirements are to be assigned
to the Reliability Functions who are capable of causing compliance to occur. A BA has
limited ability to influence the outcome of the R1 performance metric. This is unlike
other BA-assigned requirements, such as those related to DCS or CPS compliance. For
those, the BA does have considerable influence regarding the curtailment of
transactions to restore ACE, the direction of plant loading so as to distribute operating
reserve, etc. In contrast, performance under this proposed R1 of BAL-003-1 is
dependent upon the actions of the GO/GOP in such things as governor settings,
generator control system configuration and other operatinal or maintenance activities
conducted at the generating plant site. For this reason, it is inappropriate to assign this
performance requirement to the BA. Rather, the requirements should be allocated
among the GO/GOP's of the on-line generation in some fashion.In further support of
Consideration of Comments: Project 2007-12
83
000920
Organization
Yes or No
Question 8 Comment
this notion, refer to the NERC Functional Model, where it is provided that one of the
tasks for Generator Operation is to support Interconnection frequency.
Response: Thank you for your comment. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
Arizona Public Service
NO
1. Either do not use C to B Ratio or provide adequate rational for using it. It appears to
Consideration of Comments: Project 2007-12
84
000921
Organization
Yes or No
Company
Question 8 Comment
make FRO unnecessarily too conservative and is not justified based upon experience.
2. The VRF is too complicated and hard to understand. It must be either simplified or
should be followed by example.
3. The Frequency Response Obligation Methodology on Page 7 of “Procedure” does not
show any formula (it is blank).
Response: Thank you for your comment. 1) The rationale can be found beginning on page 14 of the Background document and
page 49 of the FRI report.
2) The drafting team is assuming you meant the VSLs. The VSL attempts to correct the VRF based on the BA’s size and its impact
on the interconnection.
3) This was corrected during the posting. The problem occurred when the Word document was translated to a pdf file.
Energy Mark, Inc.
Yes
Although I am in favor of using linear regression to determine the FRM, the standard
using Median is better than not having a standard.
Response: Thank you for your comment. The drafting team thanks you for your affirmative response and clarifying comment.
Southern Company
Yes
Please refer to comments for question 9.
Response: The drafting team thanks you for your affirmative response and clarifying comment. Please refer to our response for
Question #9.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
No comment.
Consideration of Comments: Project 2007-12
85
000922
Organization
Yes or No
California Independent
System Operator
Yes
Ameren
Yes
MISO
Yes
AESO
Question 8 Comment
1. The AESO disagrees with using a non-authoritative background document that has
definitions/description of terms used in the reliability standard. It is the opinion of the
AESO that these definitions/descriptions need to be authoritative.
2. The AESO has previously submitted comments to the SDT that for the purpose of the
FRM calculation, BAs should be able to exclude or include events based on specific
conditions or consideration, such as data quality or event suitability (e.g. BA separation
from the Interconnection). The revisions made by the SDT do not enable the inclusion
of other relevant events in the FRM calcualtion by a BA. The AESO would like to to see
these type of events to be permitted in the FRM calculation by a BA.
Response: Thank you for your comment. 1) The Background Document is intended for education and training similar to the other
training references in the NERC Operating Manual.
The drafting team believes that any new definitions that are located in the standard will ultimately be placed in the NERC glossary.
2) The drafting team believes that your concern will be addressed through the process since:
a) separation events would not be selected,
b) the median will exclude the outlier situations, and
c) If the data is corrupted, the FRS Forms allows for exclusion of that event.
Public Service Enterprise
Group
PSEG entities will vote “Negative” on the standard until this Project 2007-12 achieves
the following:
1. It coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-
Consideration of Comments: Project 2007-12
86
000923
Organization
Yes or No
Question 8 Comment
based Controls Reserves, specifically BAL-012-1, regarding (a) definitions and (b)
requirements that address frequency response in both standards.
a. Definitions that need to be coordinated: BAL-003-2 - “Frequency Response
Obligation” and BAL-012-1 - “Frequency Responsive Reserve.”
b. Requirements that need to be coordinated:
i. BAL-003-1, per R1, states “Each Frequency Response Sharing Group
(FRSG) or Balancing Authority that is not a member of a FRSG shall
achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that
sufficient Frequency Response is provided by each FRSG or BA that is not
a member of a FRSG to maintain Interconnection Frequency Response
equal to or more negative than the Interconnection Frequency Response
Obligation.”
ii. BAL-012 requires BAs to have sufficient Frequency Responsive
Reserves per R6, which requires BAs to “assess, on at least an hourly
basis, that it has sufficient Regulating Reserve, Contingency Reserve, and
Frequency Responsive Reserve to meet its reserve plan(s) to ensure
reliable operation of the Bulk Electric System.” For Frequency
Responsive Reserves, R3 in BAL-012-1 requires BAs to develop an annual
plan for these reserves.BAs should not be subject to duplicative
requirements for frequency response requirements in different
standards that are underdevelopment. Only one standard needs to
define the frequency response requirements for BAs (we suggest that be
BAL-003-1), although other standards, such as BAL-012-1, may reference
that obligation. However, this decision should be made by consensus
between the two SDTs.
2. It coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-
Consideration of Comments: Project 2007-12
87
000924
Organization
Yes or No
Question 8 Comment
based Controls Reserves, specifically BAL-012-1, to develop an application guide that
would be attached to one of the standards and that could be referenced by each
standard. The application guide would include:
a. A hypothetical implementation plan for a BA that demonstrates how the BA
may meet its Frequency Response Obligation or Frequency Responsive Reserve
prior to an event. This is a technical issue and should not be confused with the
institutional issue in #3 below.
b. An explanation of the relationship between Regulating Reserve, Contingency
Reserve, and Frequency Responsive Reserve contained in BAL-012-1 so that
potential double counting (and whether that is proper of improper), is
addressed.
3. Project 2007-12’s “Frequency Response Standard Background Document” dated
October, 2012 lists several methods of obtaining Frequency Response. Most of those
are extracted below. We have provided questions and commentary that we ask the
team to address.
a. “Regulation services.” This is addressed in BAL-001-0.1a. The purpose of this
standard is “To maintain Interconnection STEADY-STATE FREQUENCY within
defined limits by balancing real power demand and supply in real-time. How is
this related to Frequency Response for a disturbance? (The team may answer
this as part of 2.b above.)
b. “Through a tariff (e.g. Frequency Response and regulation service). “ The
team is advised to review the actual pro-forma OATT schedule for Schedule 3
“Regulation and Frequency Response Service” which is specifically limited to
services providers that are “capable of providing this service as necessary to
follow the moment-by-moment changes in load.” Again, how is this related to
Frequency Response for a disturbance? (The team may answer this as part of
2.b above.)
c. “From generators through an interconnection agreement.” The FERC’s pro-
Consideration of Comments: Project 2007-12
88
000925
Organization
Yes or No
Question 8 Comment
forma Standard Large Generator Interconnection Agreement (LGIA) per Order
2003 contains no requirement for generators to provide Frequency Response
service, and we are not aware on ANY interconnection agreement that does.
We ask that the team point to ANY interconnection agreement with such a
requirement. Modification of an interconnection agreement to incorporate
such a requirement would require the consent of both parties.
d. “Contract with an internal resource or loads.”Since Frequency Response
service would likely be considered as a necessary service to provide
Transmission Service under an OATT, it would require a tariff. What existing
tariff applies in the U.S.?The “methods” above that the team has listed have the
factual errors described. The standard BAL-003-1 cannot be implemented until
the necessary tariffs are developed that permit BAs and FRSGs to contract for
Frequency Response services. Once that is done, BAL-003-1 can dictate the
performance requirements of a BA or FRSG.
o For context, FERC OATT schedules relevant to Frequency Response DO NOT set
performance requirements. Schedule 3 (Regulation and Frequency Response Service)
sets forth a tariff for the service, while BAL-001-0.1a sets forth performance
requirements in aggregate for a BA or RSG. Likewise, Schedule 5 (Operating Reserve Spinning Reserve Service) and Schedule 6 (Operating Reserve - Supplemental Reserve
Service) set tariffs for both services, while BAL-002-1 sets performance requirement.
Without an OATT schedule for Frequency Response service, BAs and FRSGs will have no
means to contract with generators or loads to provide Frequency Response per BAL003-1. The team should address this concern.
Response: Thank you for your comment. There is significant coordination between the two drafting teams and this coordination
will continue as all standards referenced are posted for comment.
With regard to double jeopardy, both drafting teams have been coordinating to ensure this does not occur.
We believe it is important from a reliability perspective to have a performance based standard. The ultimate need for tariff
changes, interconnection agree, etc will be based on a BA’s need to meet the standard.
Consideration of Comments: Project 2007-12
89
000926
Organization
Yes or No
Question 8 Comment
Within the measures for R1 and the discussions in the Background document, the drafting team believes that FERC and the
industry will be able to develop the changes to tariffs to address your concerns with the BA contracting with sources of Frequency
Response to meet its FRO. The BA is also responsible for dispatch levels of resources that provide Frequency Response. Now that
Frequency Response has been clearly defined and is able to be measured, sources of Frequency Response for delivery of the
service can be developed by the industry.
Once both BAL-003-1 and BAL-012-1 have passed, the drafting team believes it would then be an appropriate time for the
members of the two drafting teams to develop an application guide.
American Electric Power
There is no leverage for the BA to require the generator to carry their burden of
addressing governor settings or droop settings, yet the BA is obligated to meet some
performance measures in that regard.This revision adds new performance measure
responsibilities on the BA who likely has no direct control over every resource affecting
their performance within their footprint. We are not necessarily challenging the
performance measures themselves, nor their underlying objectives, however AEP views
this as a gap in responsibilities which potentially effects reliability. AEP suggests that
GOPs be considered as part of this standard so that their performance can be factored
into the process to meet the performance objectives.
Response: Thank you for your comments. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VARs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
Consideration of Comments: Project 2007-12
90
000927
Organization
Yes or No
Question 8 Comment
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
SPP Standards REview
Group
We support the standard as proposed.
Response: The drafting team thanks you for your support.
Consideration of Comments: Project 2007-12
91
000928
9.
Please provide any other comments (that you have not already provided in response to the questions above) that you have on
the draft standard BAL-003-1.
Summary Consideration: A couple of commenter disagreed with the VSLs for Requirement R1. The drafting team explained that the
VSLs were a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a
violation’s impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide
resource. The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA
Interconnections. Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability, yet would be
sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not rational to sanction
this BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would treat
multi-BA Interconnections tens of times more harshly than single BA Interconnections. However, the drafting team has
added language to the requirement to reference the Interconnection Frequency Response Obligation.
One commenter felt that there was an inconsistency between Requirement R4 and Requirement R1 and Attachment A concerning
how a BA providing Overlap Regulation Services would calculate its FBS. The drafting team disagreed with their
comment. Under the two options in R4 the BAs must still comply with the minimum setting requirements through the
calculations performed under R2. In your example, if both BAs turned in FRS Form 1 showing a FBS based on the 100%
- 125% minimum these two numbers would be added together for compliance with R4.
One commenter felt that the definition should state that it is a negative value. The drafting team explained that while the desired
value would be negative it is mathematically feasible for the actual value to be positive but that value would by
definition mean that the entity failed the measurement for Requirement R1.
One commenter disagreed with putting the onus on the BA for providing Frequency Response. The drafting team The drafting team
explained that they had heard some of the same concerns, but there are quite a few good reasons why this standard is
a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still,
they are responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the
standards. Similarly a TOP is responsible for maintaining voltage even though they may own no capacitor banks or
generators to control VArs.
Consideration of Comments: Project 2007-12
92
000929
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency
response (or generator governor response if the standard was generator centric) to about 30 events per year. There
are about 140 BAs in North America. There are on the order of 4000 generators that would have to report under a
generator-centric standard. How do you verify performance of 120,000 observations annually?
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large
contingency. It is not intended to be difficult to meet. As proposed, the standard has a performance obligation about
half of what we see today in actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have
about -2200MW/0.1Hz on average. The standard allows the formation of frequency response sharing groups (similar
in concept to DCS' RSGs) and allows obtaining response from other BAs contractually. This means there should be no
BAs out of compliance once the standard is in place.
One commenter questioned how the event selection process would work. The drafting team stated that the event selection process
was outline in the Procedure for ERO Support of the Frequency Response and Frequency Bias Setting Standard.
Organization
Question 9 Comment
ACES Power Marketing
Standards Collaborators
(1) Please strike “that is a member of a multiple BA Interconnection” in R2 and R3. The language
makes the requirements difficult to read. We understand this is trying to clarify that these
requirements should not apply to BAs such as ERCOT since changing its Frequency Bias Setting does
not need to be coordinated with other BAs among other issues, and we do not have an issue with
this intent. However, there is an easier way to address this issue without creating a confusing
requirement. The SDT should include seeking a variance for the ERCOT area in conjunction with
developing the standard.
(2) Please strike “in order to represent the Frequency Bias Setting for the combined Balancing
Authority Area” in Requirement R4 as it is superfluous and incorrect. First, the two bullets provide
the necessary information making the statement unnecessary. Second, the BA Areas are not
combined into a single BA Area as implied with the statement “combined Balancing Authority
Area”. They are still in fact two distinct BA Areas.
Consideration of Comments: Project 2007-12
93
000930
Organization
Question 9 Comment
(3) The data retention period for R1, R2, R3, and R4 is not consistent with the NERC Rules of
Procedure. Section 3.1.4.2 of Appendix 4C - Compliance Monitoring and Enforcement Program
states that the compliance audit will cover the period from the day after the last compliance audit
to the end date of the current compliance audit. The data retention section states that data shall
be kept for the current calendar year plus the three previous calendar years. This could be up to
four years which exceeds the BA audit period of three years. It is unnecessary for a BA to maintain
evidence that was already verified in a prior audit. We recommend changing the evidence
retention period to three years.
(4) Has the drafting team coordinated the addition of the Frequency Response Sharing Group
(FRSG) with the Functional Model Working Group and the NERC staff responsible for organizational
registration? If not, please do so as NERC will need to be willing to register entities as a FRSG if it is
to be utilized. Furthermore, the Functional Model Working Group should document the purpose
and intent of the FRSG
.(5) We disagree with the VSLs for R1. The VSLs are structured such that a BA’s or FRSG’s violation
is dependent upon the rest of the interconnection to determine the severity level of the violation.
If the BAs collectively fail to achieve the Interconnection Frequency Response obligation, a 2%
violation of the Frequency Response Measure jumps from a Lower VSL to a High VSL. This should
never be the case. No violation by a registered entity should become potentially more or less
severe based on the violation of another entity. We encourage the drafting team to work with
NERC Legal department in reviewing this VSL further as FERC has already allowed ISO/RTO
violations investigation to draw in third parties that potentially contributed to the ISO/RTO
violation to ensure the appropriate party is fined. The principal is similar here in ensuring the
appropriate BA is fined for its violation not the violations/failures of other BAs. The background
document mentions on page 31 that the motivation for structuring the VSL in this manner was to
prevent BAs in multiple BA interconnections from being sanctioned disproportionately. We
appreciate the draftingteam considering this issue but believe there is a simpler solution. Four VSLs
could simply be written based on the percentage the BA misses its own Frequency Response
Obligation. Furthermore, the compliance enforcement process already considers if the violation
impacted reliability when assessing a sanction
Consideration of Comments: Project 2007-12
94
000931
Organization
Question 9 Comment
.(6) The Frequency Response Obligation (FRO) term is used inconsistently with the definition in the
VSLs for R1. The first part of each BA implies that the Interconnection has an FRO. However, the
definition specifically states that FRO is the BA’s “share of the required Frequency Response”. It
does not apply to the Interconnection. How can the Interconnection have a share of the required
frequency response? A new term may need to be defined for the Interconnection.
(7) The implementation plan still references Requirement R5. There is no such requirement
.(8) Requirement R1 is not consistent with the recent direction NERC has taken to refocus on
reliability and looking forward during compliance audits rather than backwards. For instance, NERC
has proposed monitoring internal controls of registered entities because this will provide a
reasonable assurance that the registered entity is prepared to comply in the future. Current
compliance audits focus mostly on past performance and provide no indication of future reliability.
How does Requirement R1 support this forward looking vision when it is a lagging indicator that
looks at historical performance?
(9) Requirement R4 appears to be inconsistent with Requirement R1 and Attachment A. On page 3,
Attachment A states the BA shall set its Frequency Bias Setting to 100% to 125% of it Frequency
Response Measure or Interconnection Minimum. However, Requirement R4 states that the BA
providing Overlap Regulation Service shall set its Frequency Bias Setting to the sum of its
Frequency Bias Settings on FRS Form 1 and FRS Form 2 of its own BA and the BA to which its
provides Overlap Regulation Service. For simplicity let’s call the BA providing Overlap Regulation
Service BA X and the BA receiving the service BA Y. Why would the BA X not set its Frequency Bias
Setting to 100% to 125% of the sum of BA X’s and BA Y’s Frequency Response Measure? This would
make Requirement R4 parallel with R2.
(10) We do not understand the difference between the two bullets in Requirement R4. They
appear to say essentially the same thing and the background document provides no discussion to
distinguish their differences. Please provide further explanation.
Response: Thank you for your comments.
(1) The proposed variance alternative could create unnecessary work for different organizations.
(2) The proposed elimination of words could help but, the elimination could bring more questions than benefits.
Consideration of Comments: Project 2007-12
95
000932
Organization
Question 9 Comment
(3) The drafting team believes that the language proposed in the draft standard is typical of other standards and is not in violation
of anything.
(4) The drafting team is coordinating as you stated.
(5) VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections. Consider a
small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the drafting team has added language to the requirement to reference the Interconnection
Frequency Response Obligation.
(6) The drafting team has clarified the VSL.
(7) The drafting team has corrected the Implementation Plan.
(8) The drafting team disagrees. The drafting team believes that this is a performance based standard similar to BAL-001 CPS and
BAL-002 DCS requirements. With regards to “internal controls” the drafting team believes that this is an enforcement activity
not a standards activity.
(9) The drafting team disagrees with your comment. Under the two options in R4 the BAs must still comply with the minimum
setting requirements through the calculations performed under R2. In your example, if both BAs turned in FRS Form 1 showing
a FBS based on the 100% - 125% minimum these two numbers would be added together for compliance with R4.
(10) Under the first bullet, two BAs have submitted two FRS Form 1 document in accordance with R1. Under the second bullet,
one entity has turned in a single FRS Form 1 with all information for the two BAs combined.
Keen Resources Asia Ltd.
A probabilistic/statistical basis needs to be developed for the FRM that assesses for usage of
frequency response (causation of frequency error) and not just for provision of it. This would also
overcome NERC’s singular focus on reaction, and NERC’s color-blindness to proaction, pointed out
in my reply to question 7.
Response: Thank you for your comment. As part of the ongoing evaluation of Frequency Response this may be considered.
SPP Standards REview Group
Additional typos:Change the ‘)’ to a ‘(‘ in the 4th line of M1 of the standard.No further comment
Consideration of Comments: Project 2007-12
96
000933
Organization
Question 9 Comment
Response: Thank you for your comment. This has been corrected.
Arizona Public Service Company
As mentioned in Item 8 above, the VRF language is too complicated and hard to follow. Even
though the VRF poll is non binding, it needs to be clear and simple enough to be understood.
Response: Thank you for your comments. The drafting team is assuming you mean the VSL. VSLs are a starting point for the
enforcement process. The combination of the VSL and VRF is intended to measure a violation’s impact on reliability and thus levy
an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed VSLs are intended to put multiBA Interconnections on the same plain as single-BA Interconnections. Consider a small BA that whose performance is 70% of it’s
FRO. If all other BAs in the Interconnection are compliant, the small BA’s performance has negligible impact on reliability, yet
would be sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not rational to sanction this
BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would treat multi-BA
Interconnections tens of times more harshly than single BA Interconnections. However, the drafting team has added language to
the requirement to reference the Interconnection Frequency Response Obligation.
BC Hydro
BC Hydro respectfully submits these additional comments/observations:
1.The proposed standard seems to indicate that it is applicable to the identified responsible
entities at all times. There might be circumstances where a BA that belongs to a multiple-BA
Interconnection became isolated and has to operate in restorative mode which might require
adjusting the frequency bias to a value less negative than the minimum FBS setting value in order
to follow the much reduced load/generation level in the area. We suggest adding some language in
either the Applicability section or in individual Requirements to recognize these circumstances.
2.Effective Dates: the proposed standard specifies a fixed period (12-month or 24-month) following
Regulatory Approval which may fall in the middle of the year while the calculation and
implementation are performed on an annual basis. Does this represent any conflicts?
3.The proposed standard does not clearly specify whether a BA must chose between using fixed
bias or variable bias for the entire year. Should BAs be allowed to switched back and forth between
the two methods? If yes, more details may be needed to account for the FRM and minimum FBS.
4.The proposed standard does not clearly specify whether a BA can be part of a FRSG for only part
Consideration of Comments: Project 2007-12
97
000934
Organization
Question 9 Comment
of the year or must be the whole year
5.The definition of FRO, FRM, FBS, etc. should all include language to indicate the “negative”
nature of the value.
6.Measure M2 should have “and uses a fixed bias” added for clarity purpose.
7.In the Additional Compliance Information section of the proposed standard the following info still
exists: For Interconnections that are also Balancing Authorities, Tie Line Bias control and fFlat
Ffrequency control are equivalent and either is acceptable. Since all reference to AGC Modes have
been removed from the Requirements, this additional info should also be removed.
Response: Thank you for your comments.
(1) The drafting team does not believe that there is any difference between adherence to the current standard and the proposed
standard. With regard to islanded operations, the drafting team believes that other standards prevail under those conditions.
(2) The timelines are not requirements and may be adjusted to meet the annual calculation process proposed by the standard.
(3) The drafting team believes the standard as drafted, allows for two types of bias, fixed and variable. A fixed bias is a single
number for the entire period. A number that changes within the period is a variable bias and is subject to Requirement R3.
(4) FRS Form 1 and 2 allows for the transfer of Frequency Response on a per event basis.
(5) While the desired value of the FRM would be negative it is mathematically feasible for the actual value to be positive but that
value would by definition mean that the entity failed the measurement for Requirement R1. The FBS definition states that it is
an inverse contribution to the interconnection frequency; therefore the definition does not need to reference a negative value.
The FRO will be an allocation of the IFRO whose calculation methodology will provide a negative number. The allocation of a
negative number will result in a negative number. For these reasons the SDT did not modify the definitions.
(6) Requirement R2 is only applicable to entity’s using a fixed bias therefore Measure M2 only applies to those utilizing a fixed
bias.
(7) The proposed elimination of words could help but, the elimination could bring up more questions than benefits.
Edison Electric Institute
EEI supports the efforts and improvements made by the Standards Drafting Team (SDT) in the
latest version of BAL-003 and believe those changes have been responsive to the directives in
Order 693. However, we recognizes that the Industry has struggled with this standard and remains
split as to how best to respond to those directives and in some cases there are those who question
Consideration of Comments: Project 2007-12
98
000935
Organization
Question 9 Comment
whether a standard is even necessary. Given the many open issues and the concerns expressed by
stakeholders we anticipate that this standard will once again fail to achieve sufficient support to
gain approval. Should the Standard fail to achieve ballet approval, it is our hope that NERC Staff
and the NERC Board of Trustees will allow the SDT a little more time to resolve any final issues that
have been identified in this latest ballet. Although we recognize that May 31, 2013 does not leave
the ERO with a lot of time to comply with this FERC imposed deadline, we still remain confident
that given the progress made by the SDT a standard, which is acceptable to the Industry, is still
possible. To the extent EEI can help, we are committed to working with member companies to
communicate the issues and exchange insights from the SDT to help as we can to achieve a positive
outcome.
Response: Thank you for your comment and support.
Manitoba Hydro
Purpose: Is the reference to ‘Interconnection Frequency’ supposed to be ‘Frequency Response’?
This would be consistent with later wording in the standard.
R1:
(1) The acronym ‘FRO’ is used inconsistently within the document.
(2) The phrase “to ensure that sufficient Frequency Response ...” should be separated from the
requirement as it is
(i) not descriptive of the required actions
(ii) redundant with the stated purpose at the beginning of the standard.
In general, such a drafting technique should be avoided as it may allow Responsible Entities to
argue that a violation has not occurred where the specific action that is described has not been
taken, but the purpose referenced in the requirement has been met.
M1: The reference to ‘documented formula’ is not clear. Does this imply that the FRSG or BA have
a record of their calculation? In addition, there is a typo, a random ‘)’ after FRM.
M2: Should include the words ‘and uses a fixed Frequency Bias Setting...’ after overlap Regulation
Consideration of Comments: Project 2007-12
99
000936
Organization
Question 9 Comment
Service to make the wording consistent within the Requirement.
M3: The wording of this measure switches tenses between ‘is’ and ‘was’. For consistency, we
suggest that this be corrected.
NERC Glossary definition of an FRSG is a group of BAs that collectively maintain, allocate and supply
operating resources required to jointly meet the sum of the Frequency Response Obligations of its
members.
No mention is made of the agreement including the sharing or delegation of responsibility related
to FRM. Accordingly, the standard should only reference a BA being able to delegate responsibility
to an FRSG if the RSG Agreement allows for such delegation.
Data Retention 1.3.
(1) As the standard is currently drafted, both the BA and the FRSG would be required to retain
data or evidence to show compliance with requirements R1 and M1. It is unclear whether
this is the intention, or whether it would be acceptable that just one or the other would
maintain such records
.(2) In the third paragraph, it should be clarified who is required to keep information related to
non compliance if the BA belongs to an FRSG - the BA or the FRSG or both.
Response: Thank you for your comments. The drafting team believes that the purpose statement is correct as written. The
standard is for both Frequency Response and Frequency Bias Setting both of which support Interconnection Frequency.
(1) The drafting team corrected the identified FRO inconsistencies within the documents.
(2) The drafting team was advised by NERC staff to include the language you are referencing.
(3) M1 – Yes the entity must have a record of their calculation. The typo has been fixed.
M2 - Requirement R2 is only applicable to entity’s using a fixed bias therefore Measure M2 only applies to those utilizing a
fixed bias.
M3 – The drafting team corrected the use of “is” in the last line of the measure.
(4) The drafting team believes that any agreement between members of a RSG is an issue that the RSG would handle. We have a
created the FRSG to address the concerns that an existing RSG may or may not be a FRSG.
Consideration of Comments: Project 2007-12
100
000937
Organization
Question 9 Comment
Data Retention
(1) Both the BA and FRSG must maintain data. At a minimum the BA needs data to document its bias setting obligation. In
addition, the BAs data may be needed to demonstrate FRSG performance.
(2) The drafting team believes that the language is clear; the entity that is found non-compliant would be the entity that would be
required to keep the data.
JEA
R1 places the burden for compliance on the BA but the BA does not control generation assets and
should not be solely responsible for maintaining frequency response. While the standard can still
define the amount of Frequency Response for each BA, there needs to be an obligation on the
GO/GOP to provide that service as directed by the BA and they should also be held accountable for
compliance.
Finally, we do not believe that a sufficient study has been conducted to determine the impact of
this standard. We are concerned that a substantial number of compliance issues could result and
that the resulting cost to maintain compliance could be excessive and we suggest it be put through
the Cost Effective Analysis Process (CEAP). We suggest that the proposed values be evaluated on a
sample size within each region to determine the number of compliance issues and for those issues
that are found determine what the BA would have to do be compliant.
Response: Thank you for your comments. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
Consideration of Comments: Project 2007-12
101
000938
Organization
Question 9 Comment
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
The SDT does not believe that there is a need to perform a “cost analysis”. The numbers are lower than the numbers we are
presently seeing.
Los Angeles Department of
Water and Power
Spinning reserves are intended to support the interconnection response to the loss of a resource. If
BAL-003-1 is adopted through this Project, the LADWP recommends that the spinning reserve
requirements of BAL-002-0.1b and BAL-STD-002-0 be removed, as the Spinning reserve
requirement would require utilities to reserve resources in excess of the reserves required in BAL003-1. LADWP recognizes that this recommendation may be handled through a separate NERC
Project, but wanted to submit this comment to bring light to this potential conflict in Reliability
Standards.
Response: Thank you for the observation.
Tacoma Power
The addition to the Frequency Bias Setting definition of “and discourage response withdrawal
through secondary control systems” seems incomplete. Tacoma Power does not see anything in
the standard that addresses (or measures) how a frequency bias setting will discourage response
withdrawal through secondary systems. This should either be more fully addressed or removed.
Consideration of Comments: Project 2007-12
102
000939
Organization
Question 9 Comment
Response: The FRI Report and the Background Documents contain explanations on this issue.
SERC OC Standards Review
Group
The comments expressed herein represent a consensus of the views of the above namedmembers
of the SERC OC Standards Review Group only and should not be construed as theposition of SERC
Reliability Corporation, its board, or its officers.
Response: Thank you for the clarification
Duke Energy
The concern raised in Duke Energy’s comments in item 4 will not be a factor for a few years, but
will be an issue as more and more BAs are in the position of their FRM being better than the
Interconnection Minimum allocation.
We believe that the language that we proposed for calculating the minimum FBS in a multiple-BA
Interconnection allows for the proper incentives for BAs to maintain FRM much better than
required, and allows for comparable measurement of secondary control performance between
similarly-sized BAs, while presenting no risk to reliability.
Response: Thank you for your comment. The industry will utilize information from the process related to this standard to make
future decisions. Also, please refer to our response to your Question #4 comment.
Puget Sound Energy
The definition of “Frequency Response Obligation” applies only to a Balancing Authority. However,
requirement R1 applies to both FRSGs and BAs and includes a Frequency Response Obligation that
applies to each of those entities. As a result, the definition must also address an FRSG’s Frequency
Response Obligation.
The acronym for Balancing Authority is not included following the first reference to the term in
requirement R1 (looks like an inadvertent deletion).
Requirement R1 states that an entity “... shall achieve an annual Frequency Response Measure
(FRM)....” However, the definition of Frequency Response Measure already includes the concept of
annual. As a result, the word “annual” should be removed from the requirement.
Requirement R1 includes the language “... to ensure that sufficient Frequency Response is provided
Consideration of Comments: Project 2007-12
103
000940
Organization
Question 9 Comment
by each FRSG or BA that is not a member of a FRSG to maintain Interconnection Frequency
Response equal to or more negative than the Interconnection Frequency Response Obligation.”
This language is a purpose statement rather than a requirement applicable to a FRSG or a BA and
should be excluded from the requirement. So long as an FRSG or BA achieves the FRM calculated
in accordance with Attachment A, it has done everything necessary to comply with the standard.
There are discrepancies between the implementation plan and the proposed standard:- The
definitions of “Frequency Response Measure” and “Frequency Response Obligation” in the
Implementation Plan are different from those proposed in the draft standard.- The Implementation
Plan references “Reserve Sharing Group” rather than “Frequency Response Sharing Group”.- The
Implementation Plan does not include a definition for the term “Frequency Response Sharing
Group”.The Implementation Plan continues to reference R5 in the discussion of the standard’s proposed
effective date.
The annual process dates listed on page 32 of the Background document appear to be inconsistent
with those listed in Attachment A.
Responses: Thank you for your comments.
The calculation of FRO is done at the individual BA level. Those BAs that are part of a FRSG must sum their individual FROs to
determine the FRSG FRO. This is clearly stated in Attachment A.
The drafting team corrected this oversight.
The drafting team disagrees that the term “annual” should be removed as it provides greater clarity as written.
The drafting team was advised by NERC staff to include the language you are referencing.
The drafting team has corrected the Implementation Plan.
The dates are not firm dates but are examples for the process.
California Independent System
Operator
The ISO supports the development of BAL-003-1 and would like to offer the following
comments/suggestions:
(1) Some BAs may have to develop a new Ancillary Service product to ensure that its FRO can be
met and believes that 12 months after FERC’s approval may not provide adequate time to
Consideration of Comments: Project 2007-12
104
000941
Organization
Question 9 Comment
stakeholder and modify market software applications. The ISO suggest increasing the
implementation timeline by at least one more year.
(2) If the implementation timeline cannot be changed, then the ISO suggests that compliance
should be waived for the first year of operation under BAL-003-1.
(3) Some BAs may elect to procure a portion of its FRO through bilateral agreements for certain
hours (e.g. off-peak) with a neighboring BA. Since a contingency could be in a BA other than the
two BAs under a bilateral agreement, the standard or background document needs to clarify the
duration of frequency response so that transmission reservation is not a requirement for frequency
response. The ISO believes that the BA experiencing the contingency should have adequate
arrangements in place to deal with internal contingencies.
Response: Thank you for your comments.
(1) The implementation date for Requirement R1 is 24 months after FERC approval, not 12 months. We believe that this would
provide ample time.
(2) See (1) above.
(3) The measurement period is 20 to 52 seconds after the beginning of the event. Additionally, there is no mention of
transmission requirements for purchase or delivery of Frequency Response.
Portland General Electric
Company
The issue with proposed Reliability Standard BAL-003-1, requirement R1, is that the Annual
Frequency Response Measure (FRM) is determined after the fact with an entity unable to identify
or monitor compliance (on non-compliance) along the way.
Also, the requirement seems to go the opposite direction of NERC’s risk based initiatives where
collecting historic compliance information become unsustainable.
Response: Thank you for your comments.
(1) The identification and posting of events will occur on a quarterly basis as stated in the Procedure Document. This will allow
BAs to monitor their compliance.
(2) The SDT believes that this is a performance based standard similar to BAL-001 CPS and BAL-002 DCS requirements.
Consideration of Comments: Project 2007-12
105
000942
Organization
Question 9 Comment
MRO NSRF
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing Authority
Interconnections from compliance with Requirement R2. To ensure a consistent approach in the
application of BAL-003-1, recommend R2 be revised as follows:
R2). Each Balancing Authority that is a member of a multiple Balancing Authority Interconnection
and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias Setting shall
implement the Frequency Bias Setting determined subject to Attachment A, as validated by the
ERO, into its Area Control Error (ACE) calculation ...
Response: Based on the comment rather than the proposed language the drafting team is providing the following response. The
drafting team discussed the applicability of bias requirements to single BA Interconnections extensively. The consensus of the
FRSDT was that single BA Interconnections inherently have strong incentives to accurately represent their frequency response
characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will be borne solely by that BA
and cannot affect other BAs in other Interconnections adversely.
Southern Company
The organization selecting events must ensure that the change in frequency is outside the normal
dead-band of generator governors. Many of the events selected in the past have not been outside
the dead-band and therefore, the frequency response was much less than expected. Southern
Company proposes .07 which is consistant with WECC.
Response: Thank you for your comments. The drafting team has created a Procedure Document that details the event selection
criteria for each Interconnection. This should alleviate the concern of smaller events being selected.
Independent Electricity System
Operator
The proposed effective date for this standard conflicts with Ontario regulatory practice respecting
the effective date of implementing approved standards. It is suggested that this conflict be
removed by appending to each of Section A1.3 and A1.4, after “months after applicable regulatory
approval”, of the standard to the following effect:”, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.”The same change should be made to the
two bullets in the proposed Implementation Plan.
Response: The drafting team appreciates your comment. However, this language is required to be used by the drafting team with
Consideration of Comments: Project 2007-12
106
000943
Organization
Question 9 Comment
the only modification allowed to be the number of months prior to implementation.
Northeast Power Coordinating
Council
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard,
then GO’s and GOP’s should be included in the applicability since they are the entities responding
to the AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s
should be updated.
Response: The FRM is not intended to measure response to AGC signals but is intended to measure response to frequency
changes. Therefore, the drafting team does not believe that any modification is warranted.
Consolidated Edison Co. of NY,
Inc.
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard,
then GO’s and GOP’s should be included in the applicability since they are the entities responding
to the AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s
should be updated.
Response: The FRM is not intended to measure response to AGC signals but is intended to measure response to frequency
changes. Therefore, the SDT does not believe that any modification is warranted.
Tucson Electric Power
This is an important task and the efforts of the drafting team are appreciated.
Response: Thank you for the recognition.
The United Illuminating
Company
UI believes the VRF should be High. The VRF justification for Medium is that the prior year’s bias
setting would exist in the control system so the impact would not cause a Cascade. UI thinks that is
an adjustment factor that is applied after non-compliance is determined. Not having settings is
likely to cause cascade so the VRF is High.
Response: The drafting team reviewed the definition for the VRF levels and believes that the appropriate levels were used for
each requirement.
Tri-State Generation and
We are concerned with the tariff implictations associated with this standard. Will this standard
Consideration of Comments: Project 2007-12
107
000944
Organization
Question 9 Comment
Transmission Assn., Inc.
create the need for an additional ancillary service under the FERC pro forma OATT?
Response: The drafting team believes that your comment is possible but does not think that it is in the scope of NERC to make
changes to the FERC pro forma OATT.
NREL Transmission and Grid
Integration Group
We commend the drafting team for a rigorous approach to this new and important standard. Being
observers who have a strong interest in this standard as it applies to much of the research that we
do, but not stakeholders of the ultimate standard, we submit our overall comments as
recommendations here. We believe there are a few potential issues, that may at least need more
thought before going forward. The first is the credit for LR.
(1) Overfrequency can be an issue: using ERCOT as an example, with -282 MW/0.1Hz response and
1400 MW of LR all responsive at 59.7 Hz, if just meeting FRO requirements, the 1400MW LR can all
be triggered with a loss of (282*3=) 846MW, causing (1400-846=)554MW of overgeneration. This
can be exacerbated by further increases of LR without recognition of the triggering frequency, and
the disconnect between BA and interconnection in the other interconnections.
(2) With crediting LR toward the Interconnection, it will not give incentive toward BAs to provide
it. We believe the LR should contribute to the BA FRO rather than discount the IFRO.
(3) There is no requirement for frequency response capacity (ie MW) available to provide the FR.
This is a nonissue in today's world with the amount of spinning reserve already available, but the
issue could be apparent on future systems with increased reserve sharing, or reserve capacity from
resources that operate in modes which do not provide frequency response. The European
Interconnection requirement has two intentions: a 3,000 MW capacity requirement and a 1,500
MW/0.1Hz FRO requirement that is allocated out to its Transmission System Operators. This could
solve the issue with LR and generators, where LR is in MW and generation governing is in
MW/0.1Hz.
(4) It is likely, and from our understanding is true in some areas like ERCOT, that the LR is selected
based on market solutions, and may not be available all times of the year. This is another reason
why the LR should contribute to the BA FRO rather than discount the IFRO.
(5) It may be beneficial to guide frequency settings for LR or even multiple settings to mimic a
Consideration of Comments: Project 2007-12
108
000945
Organization
Question 9 Comment
droop curve for LR. Other potential issues not related to the LR. We think the SDT has done an
outstanding job on reviewing the data sets and determining statistically based values to better
account for different factors that may affect minimum frequency levels. We agree that there are
current issues in the primary governing response, but that there may be a disconnect in fixing
those issues with the static values. We also agree that there is not an easy solution. In specific:
(a) The static CB ratio might not incentivize BAs to improve response with increased inertia
or faster responding governing response.
(b) The static withdrawal BC'adj may not incentivize BAs to improve their governing
response and limit their withdrawal. Improved technology may allow for better
measurement to account for these issues dynamically rather than using static numbers.
Guidance on increasing inertia, increasing governing speed, and reducing withdrawal should
be considered by stakeholders. We thank NERC and the SDT for the opportunity to provide
comments on this important standard.
Response: Thank you for your comments.
(1) The standard as presently written addresses both over and under frequency events.
(2) The credit given for LCR is based on numbers provided by the interconnection. The utilization of load by any individual BA will
be included in the calculation of their FRM through the Net Actual Interchange term rather than the IFRO.
(3) Thank you for your comment.
(4) Please refer to our response to (2) above.
(5) Thank you for your comment. As more information is gained through implementation of this standard modifications based on
this information will be possible.
Ameren
While we support this draft, we believe that this might only be a starting point and as additional
knowledge and experience is gained through the implementation of this standard and other efforts
such as the FRI, that the improvements can be embraced by all parties, even if those improvements
result in relaxed requirements.
Response: Thank you for your comments. The NERC process allows for adjustments and improvements for both its thresholds and
Consideration of Comments: Project 2007-12
109
000946
Organization
Question 9 Comment
methodologies when operational experience has been gained.
Xcel Energy
Xcel Energy supports this proposed revision to the standard as a first step and suggests that after
operating for a couple of years under the revised standard, that NERC initiates a more complete
study to support any modifications to the standard.
Response: Thank you for your comment. The drafting team agrees.
END OF REPORT
Consideration of Comments: Project 2007-12
110
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000947
Exhibit J
Analysis of how VRFs and VSLs were Determined
Using Commission Guidelines
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000948
Violation Risk Factor and Violation Severity
Level Assignments
Project 2007-12 – Frequency Response
This document provides the drafting team’s justification for assigning draft standard Requirement
violation risk factors (VRFs) and violation severity levels (VSLs) for:
•
BAL-003-1 — Frequency Response and Frequency Bias Setting
Each primary Requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violation of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard Drafting Team applied the following NERC criteria when proposing
VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration
to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000949
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs 1:
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk-Power System: 2
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
1
North American Electric Reliability Corp., 119 FERC 61,145, order on reh’g and compliance filing, 120 FERC 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000950
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence that would
be reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may find
during a typical audit. The SDT based its assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement in this standard meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence
of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in
the Determination of Penalties
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000951
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a
Cumulative Number of Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement
is a separate violation. Section 4 of the Sanction Guidelines states that assessing penalties per
violation per day basis is the “default” for penalty calculations.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000952
VRF and VSL Justification
BAL-003-1 VRF and VSL Justifications
Proposed VRF
Medium
NERC VRF Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G1
Discussion
This Requirement is more administrative in nature requiring
calculated FRM to be equal to or more negative than FRO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This requirement is similar in concept to
the current enforceable BAL-003-0.1b standard Requirement R2
which specifies a Medium VRF.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
R1
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000953
Discussion
Proposed Lower VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 1% but by at most 30% or 15
MW/0.1 Hz, whichever one is the greater deviation from its
FRO
Proposed Moderate VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 30% or by more than 15 MW/0.1
Hz, whichever is the greater deviation from its FRO
Proposed High VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 1% but by at most
30% or 15 MW/0.1 Hz, whichever one is the greater deviation
from its FRO
Proposed Severe VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 30% or by more
than 15 MW/0.1 Hz, whichever is the greater deviation from its
FRO
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated FRM being less
negative than FRO.
FERC VSL G1
Discussion
This is not applicable since there was not a Requirement mandating a
certain level of Frequency Response prior to this standard.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the amount the
calculated FRM is less negative than FRO.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000954
Proposed VRF
NERC VRF Discussion
FERC VRF G1
Discussion
R2
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
This Requirement is more administrative in nature requiring entities
to implement the Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R3,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000955
Proposed Lower VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting failed to implement the
validated Frequency Bias Setting value into its ACE calculation
within the implementation period specified but did so within 5
calendar days from the implementation period specified by the
ERO.
Proposed Moderate VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 5 calendar days but less than or equal to 15
calendar days from the implementation period specified by the
ERO.
Proposed High VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 15 calendar days but less than or equal to 25
calendar days from the implementation period specified by the
ERO.
Proposed Severe VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting did not implement the
validated Frequency Bias Setting value into its ACE calculation
in more than 25 calendar days from the implementation period
specified by the ERO.
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating increments
for tardiness implementing the validated Frequency Bias Setting into
the ACE calculation.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Lower VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on how late the validated
Frequency Bias Setting is implemented.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider performance of required action. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Proposed VSL’s are based on a single violation and not a cumulative
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000956
Discussion
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting in its ACE equation and
would provide support for a contingency. This is consistent with the
NERC definition.
This Requirement is more administrative in nature requiring entities
to implement a Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R3
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R2,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for a contingency. This is consistent with
the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000957
Discussion
Proposed Lower VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 1% but by at most 10%.
Proposed Moderate VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 10% but by at most 20%.
Proposed High VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 20% but by at most 30%.
Proposed Severe VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
obligation by more than 30%..
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G1
Discussion
FERC VSL G2
Discussion
Proposed VSL is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based on the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000958
FERC VSL G3
Discussion
Proposed VSL does not expand on what is required. The VSLs
assigned only consider compliance with the Frequency Bias Setting
calculation and implementation required. Proposed VSL’s are
consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
This Requirement is more administrative in nature requiring entities
providing Overlap Regulation Services to correctly increase its
Frequency Bias Setting. The requirement does not directly correlate
to the list of critical areas identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R4
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R6 which
specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000959
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error less than
10% of the validated or calculated value.
Proposed Moderate VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
10% but less than or equal to 20% of the validated or calculated value
Proposed High VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
20% but less than or equal to 30% of the validated or calculated
value.
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with setting error more than 30% of the validated
or calculated value.
OR
The Balancing Authority failed to change the Frequency Bias Setting
value used in its ACE calculation when providing Overlap Regulation
Services
Proposed Severe VSL
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the absolute value of the
Balancing Authorities’ calculated monthly average Frequency Bias
Setting being below the minimum percentage specified by the ERO.
The VSL also includes a binary requirement for failing to change the
Frequency Bias Setting value when providing Overlap Regulation
Services.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R6 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s has both a percentage of noncompliance
performance and binary element. The binary element is designated
severe. Proposed VSL language does not include ambiguous terms
and ensures uniformity and consistency in the determination of
penalties based only on the amount the calculated monthly average
Frequency Bias Setting is below the minimum percentage specified
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000960
by the ERO or if the entity fails to change the Frequency Bias Setting
value when providing Overlap Regulation Services.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required and if the
Frequency Bias Setting is correctly set when providing Overlap
Regulation Services. Proposed VSL’s are consistent with the
requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000961
Exhibit K
Summary of the Reliability Standard Development Proceeding and
Complete Record of Development of Proposed Reliability Standard
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000962
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
SUMMARY OF THE RELIABILITY STANDARD DEVELOPMENT PROCEEDING
A. Overview of the Standard Drafting Team
The Frequency Response Standard Drafting Team is comprised of some of the foremost
experts in the field. The team is chaired by David Lemmons, Senior Manager, Market
Operations at Xcel Energy, and vice-chairman, Dr. Terry Bilke, Consulting Advisor in
Compliance Services at the Midwest Independent System Operator, Inc. Drafting Team
members include Howard Illian of Energy Mark, Inc., who has published a variety of papers on
the subject of Frequency Response, including a 2010 report that was funded by the FERC, Office
of Electric Reliability,51 Sydney Niemeyer, a Control System Specialist at NRG Texas, LP,
Michael Potishnak, a principal engineer at ISO New England, Inc., and Carlos Martinez, who has
also published several papers on the subject of Frequency Response, including a 2010 report that
was funded by the FERC, Office of Electric Reliability that reviewed the frequency performance
of the Eastern, Western and ERCOT interconnections.52
Don Badley has been a member of the Northwest Power Pool (“NWPP”) Staff since
1975. Don manages the NWPP Operating Committee. He is currently Chairman of the NERC
Resources Subcommittee, a member of Western Electricity Coordinating Council’s (WECC)
Performance Work Group and has chaired numerous NERC and WECC groups. In the past Mr.
Badley has served as Chairman of the North American Power Systems Interconnection
Committee’s Performance Subcommittee, a member of the WECC Technical Operations
51
See e.g., Illian, H. (2010), Frequency Control Performance Measurement and Requirements, LBNL-2145E,
Ernest Orlando Lawrence Berkeley National Laboratory; available at:
http://www.ferc.gov/eventcalendar/Files/20110120114346-Frequency-Control-Performance-Measurement-andRequirements.pdf; Eto, J. H., Undrill, J., Mackin, P., Daschmans, R., Williams, B., Illian, H., et al. (2010). Use of
Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of
Variable Renewable Generation. LBNL-4142E. Ernest Orlando Lawrence Berkeley National Laboratory; available
at: http://www.ferc.gov/industries/electric/indus-act/reliability/frequencyresponsemetrics-report.pdf.
52
Martinez, C., Xue, S., Martinez, M (2010), Review of the Recent Frequency Performance of the Eastern,
Western and ERCOT Interconnections, LBNL-4144E; available at: http://www.ferc.gov/industries/electric/indusact/reliability/interconnectionfrequencyperformance.pdf.
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000963
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
Subcommittee, and a member of the WECC Control Work Group. Mr. Badley is a member of
the IEEE Power Engineering Society and has co-authored three IEEE papers on system control.
Mr. Clyde Loutan is presently a Senior Advisor at the California Independent System
Operator Corporation (“ISO”) focusing on power system operation performance, and was the
lead investigator for the ISO’s renewable resource integration studies published in 2007 and
2010. Mr. Loutan was also the principal investigator for the ISO’s Frequency Response Study53
done by General Electric International, Inc. and the ISO to investigate the ISO’s frequency
response due to large loss-of-generation under conditions with high levels of wind and solar
generation published in 2011. He co-authored an IEEE technical paper on “Frequency Response
of California and WECC under High Wind and Solar Conditions,” which was presented at the
2012 IEEE Power & Energy Society General Meeting on July 24 in San Diego California.
Mr. Loutan previously worked at the Pacific Gas and Electric Company for 14 years in various
capacities such as Real Time System Operations, Transmission Planning and High Voltage
Protection. Mr. Loutan is a licensed professional engineer in the State of California. He holds
B.S. and M.S. degrees in Electrical Engineering from Howard University in Washington D.C.,
and is a senior member of the IEEE.
Darrel Richardson, with over thirty-seven years of experience in the electric industry, is
the NERC Standards Developer for the project. Robert Cummings, Director of Reliability
Initiatives and System Analysis, supported the drafting team via the Frequency Response
Initiative and the publication of the related report, included herein as Exhibit F. Mr. Cummings,
an IEEE Senior Member, who joined NERC in 1996, has over thirty-six years of extensive
experience in the industry in system planning, operations engineering, and wide area planning.
53
http://www.caiso.com/Documents/Report-FrequencyResponseStudy.pdf
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000964
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
B. Standard Authorization Request Development
The Standard Authorization Request (“SAR”) for BAL-003-1 was submitted on April 7,
2004 as a request for a new Frequency Response Standard. The initial draft of the SAR was
posted from January 17, 2005 to February 17, 2005 for a 30-day public comment period. A
white paper prepared by the Frequency Task Force of the NERC Resources Subcommittee was
posted with the first draft of the SAR. Based on industry comments, the drafting team revised
the SAR and posted a second draft for comment from April 4, 2006 to May 3, 2006. Following
further modifications, a third draft of the SAR was posted from February 8, 2007 to March 9,
2007. In these successive drafts, the standard drafting team further defined the scope of the
standard, identified applicability, and came to a consensus on the need to specify the quality and
quantity of frequency response. A fourth and final draft of the SAR was posted on June 30, 2007
and the drafting team was formed on July 30, 2007.
C. The First Posting – Informal Comment Period
The first draft of BAL-003-1 was posted for a 30-day comment period from February 4,
2011 to March 7, 2011. Several documents were posted for guidance with the first draft,
including Attachment A to the standard, a supplemental SAR identifying the modifications to
BAL-003-0 that were originally part of Project 2007-18 – Reliability-based Control, a Frequency
Response Survey Form that was used for data collection, and a document containing the outline
of a proposed field test to be used in creating the standard. There were 36 sets of comments on
the first draft, with comments from more than 139 different people from approximately 86
companies representing all 10 of the industry segments. In response to comments, the standard
drafting team made several changes to the draft standard including:
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000965
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
‐
‐
‐
‐
Removed the Single Event Frequency Response Data (SEFRD) definition and
modified several others;
Modified Attachment A, and created Attachment B – Process for Adjusting
Bias Floor Setting;
Modified FRS Form 1 to correct errors, allow for adjustments and provide
clarity; and
Added VRFs and VSLs.
D. The Second Posting – Formal Comment Period, Initial Ballot and Non-Binding
Poll
The second draft of the standard was posted for a formal 45-day comment period from
October 25, 2011 to December 9, 2011, with an initial ballot held from November 30, 2011
to December 9, 2011. The initial ballot achieved a 93.92% quorum, and an approval of
30.82%. The standard drafting team received 43 sets of comments from 133 different people
from approximately 86 different companies representing all 10 industry segments. Several
changes were made to the draft of the BAL-003-1 standard including:
‐
‐
‐
‐
‐
‐
‐
‐
‐
Modified the definitions for Frequency Response Measure (FRM) and
Frequency Bias Setting;
Removed the references to Reserve Sharing Groups (RSGs) and replaced
them with a new definition Frequency Response Sharing Group (FRSG) and
defined FRSG;
Modified Requirement R2 to provide clarity and incorporate Requirement R5;
Created a new Requirement R3 for entities using variable Frequency Bias
Removed the requirement for operating in Tie Line Bias mode as duplicative
of other requirements in other standards;
Modified Attachment A to provide additional clarity;
Re-wrote the Background Document to incorporate additional language for
justification of requirements and provide additional clarity;
Created a procedure document for the ERO support of the standard; and
Adopted the Frequency Response Initiative Report methodology for
calculating the Interconnection Frequency Response Obligation (IFRO)
E. Frequency Response Technical Conferences
In order to obtain industry input of the development of the Frequency Response standard,
NERC held technical conferences in Arlington, Virginia on May 22, 2012, and in Denver,
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000966
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
Colorado on May 24, 2012. The conferences focused on discussing which Functional Entities
should be responsible for Frequency Response and how Frequency Response should be
measured. NERC solicited comments on the standard, the development process, and the topics
discussed at the technical conference and gave a deadline of June 15, 2012 for comment
submission.
F. Third Posting - Formal Comment Period, Successive Ballot, and Non-Binding
Poll
The third draft of the standard was posted with the implementation plan, mapping
document, Attachment A to the standard, FRS Forms 1 and 2, a procedure document for ERO
support of the standard, and a background document on the development, testing and
implementation of the BAL-003-1 standard. The 30-day comment period ran from October 5,
2012 to November 6, 2012, and included a successive ballot and non-binding poll from October
26, 2012 to November 6, 2012. The successive ballot for the draft of BAL-003-1 received a
quorum of 82.04% and a 76.08% approval. The non-binding poll received a quorum of 76.28%
and a 76.30% approval. The standard drafting team received 50 sets of comments from 144
individuals from 100 different companies representing eight of the ten industry segments. As a
result of the industry comments, the standard drafting team made changes to the standard
including:
‐
‐
‐
Made language and grammatical corrections in the proposed standard;
Clarified the description of the calculation for the Interconnection Frequency
Response Obligation (“IFRO”) in Attachment A to the standard; and
Modified Attachment A and the Procedure for consistency on the use of the
term “resource contingency criteria.”
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000967
EXHIBIT K – Summary of the Reliability Standard Development Proceeding
G. Fourth Posting – Recirculation Ballot
The fourth draft of the BAL-003-1 standard was posted for a recirculation ballot from
December 12, 2012 to December 21, 2012. The recirculation ballot achieved a quorum of
86.19% and an approval of 76.53%.
H. Board of Trustees Approval of BAL-003-1
The final proposed BAL-003-1 standard was presented to the NERC Board of Trustees
on February 7, 2013. NERC staff provided a summary of the proposed standard, as well as a
summary of minority issues and associated drafting team responses. The NERC Board of
Trustees approved the standard, and NERC staff recommended that it be filed with applicable
regulatory authorities.
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000968
Project 2007-12
Frequency Response
Related Files
Status:
A recirculation ballot for BAL-003-1 closed on December 21, 2012 with a quorum of
86.19% and 76.53% approval. The standard will be presented to the NERC Board of
Trustees for adoption at its February meeting.
Purpose/Industry Need:
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency
immediately following the sudden loss of generation or load, is a critical component to
the reliable operation of the bulk power system, particularly during disturbances and
restoration. Failure to maintain frequency can disrupt the operation of equipment and
initiate disconnection of power plant equipment to prevent them from being damaged,
which could lead to wide-spread blackouts. There is evidence of continuing decline in
Frequency Response in the three Interconnections over the past 10 years, but no
confirmed reason for the apparent decline. The proposed standard would set a
minimum Frequency Response obligation for each Balancing Authority, provide a
uniform calculation of Frequency Response and Frequency Bias Settings that transition
to values closer to natural Frequency Response, and encourage coordinated AGC
operation.
Draft
Action
Dates
Results
Draft 4
BAL-003-1
Clean 92| Redline to
Last Posting 93
Attachment A
Clean 94| Redline to
Last Posting 95
Recirculation
Ballot
Info 117
Implementation Plan
Clean 96| Redline to
Last Posting 97
Supporting Materials:
Procedure
Clean 98| Redline to
Last Posting 99
Vote>>
12/12/12
12/21/12
(closed)
Summary
118
Full Record
119
Consideration
of Comments
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000969
Background
Document
Clean 100 | Redline to
Last Posting 101
Mapping Document
102
VRFs and VSLs 103
Frequency Response
Initiative Report 104
FRS Form 1:
Multiple BA
Interconnection
(Eastern & Western)
105
ERCOT 106
Quebec
Interconnection 107
Excel 97 - 2003
Version
Multiple BA
Interconnection
(Eastern &
Western)108
ERCOT 109
Quebec
Interconnection 110
FRS Form 2:
Multiple BA
Interconnection
(Eastern & Western)
111
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000970
ERCOT 112
Quebec
Interconnection 113
Excel 97 - 2003
Version
Multiple BA
Interconnection
(Eastern & Western)
114
ERCOT 115
Quebec
Interconnection 116
Draft 3
BAL-003-1
Clean 59| Redline to
Last Posting 60
Successive
Ballot and NonBinding Poll
Updated Info 84
Info 85
Attachment A
Clean 61
Summary 87
10/26/12
11/06/12
(Closed)
Vote>>
Full Record
88
Non-binding
Poll Results
89
Implementation Plan
Clean 62| Redline to
Last Posting 63
Supporting Materials:
Procedure 64
Background Document
65
BAL-003-0.1b 66
Unofficial Comment
Form (Word) 67
Updated 10/16/12)
Comment
Period
Info 86
Submit
Comments>>
10/05/12
11/06/12
(Closed)
Comments
Received 90
Consideration
of Comments
91
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000971
Mapping Document
Clean 68 | Redline to
Last Posting 69
VRF/VSL
Clean 70|Redline to
Last Posting 71
FRS Form 1:
Multiple BA
Interconnection
(Eastern & Western)
72
ERCOT 73
Quebec
Interconnection 74
Excel 97 - 2003
Version
Multiple BA
Interconnection
(Eastern & Western)
75
ERCOT 76
Quebec
Interconnection 77
FRS Form 2:
Multiple BA
Interconnection
(Eastern & Western)
78
ERCOT 79
Quebec
Interconnection 80
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000972
Excel 97 - 2003
Version
Multiple BA
Interconnection
(Eastern & Western)
81
ERCOT 82
Quebec
Interconnection 83
Frequency Response
Technical Conferences
Unofficial Comment
Form (Word) 56
Draft 2
BAL-003-1
Clean 27| Redline to
Last Posting 28
Attachment A
Clean 29
Attachment B
Clean 30
Implementation Plan
Clean 31| Redline to
Last Posting 32
Supporting Materials:
Informal
Comment
Info 57
Submit
Comments>>
Initial Ballot and
Non-Binding
Poll of VRFs and
VSLs
Vote>>
05/30/12
06/15/12
(closed)
Summary 51
11/30/11
12/09/11
(closed)
Info 48
Formal
Comment
Period
Info 49
10/25/11
12/09/11
(closed)
Submit
Comments>>
Join Ballot Pool
Initial and NonBackground Document
Binding
Comments
Received 58
10/25/11
11/23/11
Full Record
52
Non-Binding
Poll Results
53
Comments
Received 54
Consideration
of Comments
55
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000973
33
(closed)
Info 50
BAL-003-0.1b 34
Join>>
Comment Form
(Word) 35
Mapping Document
36
FRS Form 1:
Eastern
Interconnection 37
ERCOT 38
Quebec
Interconnection 39
Western
Interconnection 40
FRS Form 2 for
Interconnection with
Multiple BAs:
Two-second Sample
Data 41
Three-second Sample
Data 42
Four-second Sample
Data 43
Five-second Sample
Data 44
Six-second Sample
Data 45
FRS Form 2 for
Interconnection wit
One BA:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000974
Two-second Sample
Data 46
Three-second Sample
Data 47
Draft 1
BAL-003-1
Clean 15
Attachment A 16
Supporting Materials:
BAL-003-0 17
Formal
Comment
Period
Supplemental SAR 18
FRS Form 1
Instructions 19
FRS Form 1 20
Info 24
02/04/11
–
03/07/11
Submit
Comments>>
Implementation Plan
21
Comment Form
(Word) 22
Field Test 23
Final SAR Version 3 13
Standard
Drafting Team
Nominations
07/17/07
07/30/07
Comments
Received 25
Consideration
of Comments
26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000975
(closed)
Info 14
Submit
Nomination>>
Draft 3
Frequency Response
SAR
Draft SAR Version 3 9
Draft 2
Frequency Response
SAR
Draft SAR Version 2 5
Draft 1
Draft SAR Version 1 1
White Paper 2
Comment
Period
Info 10
Submit
Comments>>
Comment
Period
Info 6
Submit
Comments>>
02/08/07
03/09/07
(closed)
Comments
Received 11
Consideration
of Comments
12
04/04/06
05/03/06
(closed)
Comments
Received 7
Consideration
of Comments 8
01/17/05
02/17/05
(closed)
Comments
Received 3
Consideration
of Comments 4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000976
When completed, email to: [email protected]
Standard Authorization Request Form
Title of Proposed Standard
Frequency Response
Request Date
4/7/04
SAR Type (Put an ‘x’ in front of one of
these selections)
SAR Requestor Information
Name
Don McInnis
x
Primary Contact Don McInnis
Telephone
New Standard
Revision to existing Standard
(305) 442-5272
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose/Industry Need (Provide one or two sentences)
In regard to frequency response, one shortcoming of the recommendations in policy today is that there is
no guidance regarding how much governor response (in MW) is required at the 5% droop rate. This has
led to confusion among plant operators and turbine-generator manufacturers alike, and has led to
confusion among CA and Generation Operators as to their responsibilities and obligations.
This SAR is suggested to ensure frequency of Interconnection remains above underfrequency load
shedding setpoints during transient period following the sudden loss of generation on the Interconnection.
SAR-1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000977
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
X
Reliability
Authority
Ensures the reliability of the bulk transmission system within its Reliability
Authority area. This is the highest reliability authority.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within its metered boundary and supports system
frequency in real time
Interchange
Authority
Authorizes valid and balanced Interchange Schedules
Planning
Authority
Plans the bulk electric system
Resource
Planner
Develops a long-term (>1year) plan for the resource adequacy of specific
loads within a Planning Authority area.
Transmission
Planner
Develops a long-term (>1 year) plan for the reliability of transmission
systems within its portion of the Planning Authority area.
Transmission
Service
Provider
Provides transmission services to qualified market participants under
applicable transmission service agreements
Transmission
Owner
Owns transmission facilities
Transmission
Operator
Operates and maintains the transmission facilities, and executes switching
orders
Distribution
Provider
Provides and operates the “wires” between the transmission system and
the customer
Generator
Owner
Owns and maintains generation unit(s)
Generator
Operator
Operates generation unit(s) and performs the functions of supplying energy
and Interconnected Operations Services
PurchasingSelling Entity
The function of purchasing or selling energy, capacity and all necessary
Interconnected Operations Services as required
Market
Operator
Integrates energy, capacity, balancing, and transmission resources to
achieve an economic, reliability-constrained dispatch.
Load-Serving
Entity
Secures energy and transmission (and related generation services) to
serve the end user
SAR-2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000978
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric systems
shall be trained, qualified and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk electric systems shall be assessed, monitored and
maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with that
Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR-3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000979
Detailed Description (Provide enough detail so that an independent entity familiar with the
industry could draft, modify, or withdraw a Standard based on this description.)
This proposed standard would coordinate with and complement the Load and Balancing SAR, which
addresses Interconnection frequency control from 10 minutes and longer, by addressing the requirements
for control during the seconds timeframe. Ideally, an integrated set of performance-based “balancing
standards” should be in place that monitors the entire spectrum of the adequacy component of reliability.
Figure 1 depicts the interrelationships of the set of “Balancing” standards, which ultimately checks that
Control Areas have and deploy adequate resources to maintain reliability.
Seconds
Minutes
Hours
Days
Proposed FRS
DCS
CPS1
CPS2
Figure 1 Interrelationships of "Balancing" Standards
The Control Performance Standards (CPS1 and CPS2) are well-defined and generally accepted by the
Industry. The Disturbance Control Standard (DCS) measures deployment of reserves for specific
events. This SAR is proposed to develop a standard to measure sub-minute responses to changes in
frequency and to set minimum acceptable responses to system these events.
A Frequency Response Standard should address the following issues:
•
•
•
•
•
There must be a minimum response for each event (rate, amount, and duration). Reliance on average
response could result in all areas being short at the same time (similar to the short-term excursions
seen with CPS1). The amount (depth of response) should not be under-emphasized.
The measurement selected must be accurate and, to the extent practical, easy to implement.
The requirements must integrate with and be consistent with the assumptions used in setting the
BAAL limits within the Load and Balancing Standard (if and as ultimately adopted)
A method of allocation must be developed
The standard should not preclude market solutions (e.g. allow purchasing of response as long as
deliverability and restoration criteria can be met).There must be a means for sale/purchase of
frequency response as for any other quantity.
SAR-4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000980
Related Standards
Standard No.
Explanation
300
Address frequency control during the transient period of 1-30
seconds currently not covered by the Balance Resource and
Demand Standard
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
Related NERC Operating Policies or Planning Standards
ID
Explanation
Planning
Standards
III Section
C Generation
Control and
Protection
The planning standards address the requirement for generator
governors. This proposed standard broadens the concept to
include not only governors but other equipment including load
that responds to frequency.
SAR-5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000981
SAR-6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000982
NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731
Frequency Response Standard Whitepaper
April 6, 2004
Prepared by the Frequency Task Force of the NERC
Resources Subcommittee
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000983
Frequency Response Standard Whitepaper
1/17/2005
PREFACE.............................................................................................................3
INTRODUCTION ..................................................................................................3
Background .........................................................................................................3
CURRENT SITUATION ........................................................................................6
EASTERN INTERCONNECTION .....................................................................................................................................6
WESTERN INTERCONNECTION ....................................................................................................................................6
TEXAS INTERCONNECTION .........................................................................................................................................7
IS THERE A PROBLEM?.....................................................................................8
Analysis of a Load Only Response....................................................................... 11
Secondary Impacts ................................................................................................ 13
CURRENT REQUIREMENTS ............................................................................14
ISN’T EXISTING POLICY SUFFICIENT? ..........................................................14
COMMENTS TO THE FIRST PROPOSED FREQUENCY RESPONSE
STANDARD........................................................................................................15
FREQUENCY RESPONSE STANDARD CONSIDERATIONS ..........................16
INTRODUCTION ........................................................................................................................................................16
ISSUES---------------------..........................................................................................................................................16
REFERENCES ...................................................................................................17
ACRONYMS, TERMS AND DEFINITIONS ........................................................19
-
-2--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000984
Frequency Response Standard Whitepaper
1/17/2005
PREFACE
Frequency response as used in this paper is defined as an automatic and sustained change
in the power consumption or output of a device that occurs within 5-30 seconds of and is
in a direction to oppose a change in the Interconnection frequency. Frequency response as
so defined is declining within the Eastern and Western Interconnections when it should
be increasing because of increasing load and the associated increase in generation.
Frequency Response within the Texas Interconnection has been statistically constant.
The NERC Resources subcommittee posted a Frequency Response Standard for comment
in 2001. The comments received against the standard centered on 1) those not
understanding the metric and 2) those questioning the need for a standard.
The intent of this paper is to create an understanding of the need for a standard and the
technical and economic drivers motivating its development
INTRODUCTION
The NERC Resources subcommittee drafted this paper to document the need for a
frequency response standard. Provided in this paper are statistical background data
showing how the frequency response of the Interconnections has declined along with an
analysis of the technical and economic drivers that have contributed to the decline.
Further, the paper attempts to refute through examples and simulation the arguments that
this decline in the response is not a reliability issue. Instead, the paper will demonstrate
that both the Western and Eastern Interconnections run a strong risk of under-frequency
action if a standard is not adopted that establishes minimum levels of frequency response.
The Union for the Coordination for the Transmission of Electricity (a European
Standards Group) has already adopted a standard addressing the same technical issues
raised within this paper. While the primary focus of the paper is the impact to each
Interconnection as a whole, the need for primary frequency response also is a major
consideration in islanding situations.
Background
Each Control Area’s contribution to frequency support is provided by the natural
response of its generators and load to frequency variations. Figure 1 depicts a typical
frequency excursion caused by a loss of a large generator on an Interconnection.
Frequency Response is typically comprised of two components:
“Load rejection” or the reduction in the power consumption by motors that slow down in
response to a decline in frequency. This is reflected in the general slope of the line from
Points A-C. Load response to a change in frequency can vary anywhere from no
response from equipment like computers to 1.5 times for some motor loads. Load
response occurs directly or with minimal lag as the frequency changes. In addition,
-
-3--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000985
Frequency Response Standard Whitepaper
1/17/2005
Control Areas may use “high set” interruptible loads that disconnect on a pre-determined
trigger frequency.
“Generator response” or a change in the output of a generating unit due to inertia and the
movement of its governor valves. Governor response from properly tuned units occurs in
the 3-10 second timeframe and is responsible for the bottoming of frequency at Point C
and the partial recovery of frequency to Point B.
Point A represents the Interconnection
frequency immediately before the
disturbance.
SystemFrequency for Colstrip Power Plant Outage on April 28, 1999
60.05
A
Point B represents the Interconnection
frequency at the point immediately after
the frequency stabilizes due to governor
action but before the contingent control
area takes corrective action.
60
59.95
D
59.9
Point C represents the Interconnection
frequency at its maximum deviation due
to the loss of rotating kinetic energy
from the Interconnection.
B
59.85
59.8
C
59.75
30
36
42
48
54
60
66
72
78
84
90
Point D represents the Interconnection
settling frequency at 60 seconds after
the Point A.
Time [sec]
Figure 1 Typical Frequency Excursion
All else being constant, frequency will not recover to its scheduled value (typically 60
Hz) unless the Control Area that lost the resource replaces it.
The turn around in frequency from points C to B attributable to unit governor response
has markedly declined and at times is non-existent in the Eastern Interconnection. The
line from points C to D is shifting down and becoming horizontal. This means that on
many occasions the only frequency response in the East is coming solely from load
response. This critical fact is important since as will be discussed later in the paper. The
changing nature of loads means that there will be markedly less load response available
in the future. Therefore, reliance on load as the sole support to arrest the frequency can
lead to a decline in the reliability of the grid.
One of the fundamental obligations of a Control Area as stated the Control Area Criteria
of the NERC Operating Manual is the provision of frequency support. Once this support
is produced it is the purpose and the intent of the frequency bias component of the ACE
-
-4--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000986
Frequency Response Standard Whitepaper
1/17/2005
equation to ensure that this response is not withdrawn after the initial transient period or
through AGC action.
Ideally, an integrated set of performance-based “balancing standards” should be in place
that monitors the entire spectrum of the Adequacy component of Reliability. Figure 2
shows the interrelationships of the set of “Balancing” standards, which ultimately checks
that Control Areas have and deploy adequate resources to maintain reliability.
Seconds
Minutes
Hours
Days
Proposed FRS
DCS
CPS1
CPS2
Figure 2 Interrelationships of "Balancing" Standards
The Control Performance Standards (CPS1 and CPS2) are well-defined and generally
accepted by the Industry. The Disturbance Control Standard (DCS) measures
deployment of reserves for specific events. This paper focuses on a proposed standard to
measure sub-minute responses to changes in frequency. This sub-minute response is
commonly called Governor Response (if viewed at the generator level) and Primary
Frequency Control or Frequency Response (from a Control Area perspective).). The
resource pyramid diagram below shows the same concept in a different fashion.
Response Time
Resources
Seconds
Frequency
Response
Seconds to Minutes
Regulation
Operating Reserves
10 to 15 minutes
30 minutes
Load Following
Hourly
Market
-
-5--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000987
Frequency Response Standard Whitepaper
1/17/2005
Note: Frequency Response is actually a negative value i.e. as frequency drops a
generator’s output should increase. When discussing Frequency Response, people
generally talk about the raw numbers (i.e. 50MW/0.1Hz); the (-) sign is assumed. This
should be kept in mind when reading this paper.
CURRENT SITUATION
Eastern Interconnection
Technical papers (Ingleson and Nagle) and analysis (Bourque) point to a continued
decline in Eastern Interconnection Frequency Response. Figure 3 is a summary of this
work.
Eastern Interconnection Frequency Response
3800
MW/0.1Hertz
3700
y = -70.531x
+ 144335
Decline
= 70 MW/0.1Hz/Year
3600
3500
3400
3300
3200
3100
3000
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Figure 3 Trend in Eastern Interconnection Frequency Response
The plot shows an annual decline of slightly over 70 MW/0.1 Hz. This nine-year trend
reflects an 18% decline in frequency response while load and generation grew nearly
20% over the same period. Frequency response should have increased proportionally
with generation and load.
Western Interconnection
-
-6--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000988
Frequency Response Standard Whitepaper
1/17/2005
MW/0.1 Hz
WECC Frequency Response
1580
1560
1540
1520
1500
1480
1460
1440
1420
1400
Decline = 20 MW/0.1 Hz/Year
1998
1999
2000
2001
2002
Year
Figure 4 Trend in Western Interconnection Frequency Response
Figure 4 shows a proportionally similar decline in the Western Interconnection’s
Frequency Response. The graph represents response to events 25 milliHz or larger.
There were a few data points available for prior years that put the West’s response in the
order of 1650MW/0.1Hz in 1994. This would be consistent with a decline of
20MW/year. Again, response should be increasing with increasing load and generation.
Texas Interconnection
The trend in the Texas Interconnection frequency response has been statistically flat.
Figure 5 is a different representation of response over an 8-year period (1995-2002). The
plot is a “box and whisker” graph. The rectangle or bar for each year represents the range
of the “middle 50%” of observed events. The average value is the horizontal line within
the year’s rectangle. The “whiskers” attached to each box represent the upper and lower
“quartiles”. The asterisk in 1999 is an “outlier” or rare events. The plots represent 65
“medium sized” events over this period.
Comparing the Texas Interconnection Frequency Response to the other Interconnections
is a challenge. This is because ERCOT has two groups of “high set” interruptible load.
The first group trips at 59.8 Hz, the second at 59.7 Hz. Customers in the Texas
Interconnection choose to participate in this and ERCOT uses it as a supplement to
governor response. Once disconnected, the load provides no other assistance to
frequency control such as inertial response. Additionally, this interruptible load provides
no response to high frequency events.
-
-7--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000989
Frequency Response Standard Whitepaper
1/17/2005
1000
900
800
smallc
MW/
0.1Hz
700
600
500
400
300
200
0
1
2
3
4
5
6
7
*
Year
Trend
Figure 5 ERCOT Frequency Response 1995-2002
IS THERE A PROBLEM?
Those arguing against the need for a standard contend that the decline in the frequency
response illustrated above is not a significant reliability problem. The argument put
forward against a standard is that even if frequency response is declining there is so much
margin in the system that reliability i.e. loss of load from under- frequency is not
impacted. The calculation to demonstrate this argument is straightforward. The first
significant amount of under-frequency load shedding in the Eastern Interconnection is set
at 59.70Hz1. The current level of frequency response of the Eastern Interconnection is
taken as 3100MW/0.1Hz. Therefore an under-frequency decline to 59.7Hz would require
a generation loss of 9300MW. This is well beyond any generation loss that has ever
occurred except in an islanded situation. Furthermore, at the current rate of decline of
70MW/yr, as shown in figure 3 it will be thirty-four years before the response level
declines to a level where a loss of even 2400MW becomes a problem with respect to
potential under-frequency load shedding.
As a starting point, this paper will show that the above logic is based on at least three
incorrect assumptions.
The first assumption is that the Interconnection frequency starts at 60Hz. An examination
of Eastern Interconnection frequency statistics shows significant periods when the
1
The highest under-frequency setting in the Eastern Interconnection is 59.82 Hz. This is limited to a single
Control Area. The 59.7Hz setting is widely used as a first step.
-
-8--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000990
Frequency Response Standard Whitepaper
1/17/2005
Interconnection frequency is operating at or below 59.98Hz. If 59.98 Hz is used to
determine how long before the loss of 2400MW causes an under-frequency the result
reduces to 25 years. This is still beyond the range of concern.
The second and most critical assumption is that the frequency response will be
3100MW/0.1 Hz. This is representative of the average frequency response within the
Eastern Interconnection. However, the standard (or average) deviation of responses is ±
1870MW/0.1 Hz; giving a range of responses from 4970 to 1230 MW/0.1 Hz. If the
lower response of 1230MW/0.1Hz is used in the calculation then, even today, a loss of
2400Mw has significant potential to cause under-frequency load shedding to occur. The
fact that an under-frequency event has not happened yet is only coincidence. The multiple
unit trips that have approached 2400MW have, fortunately, occurred when there was
good response available.
A third assumption that is believed to be unfounded but is harder to disprove explicitly is,
namely that the decline in frequency response will continue at a rate of only
70MW/0.1Hz. Many drivers are contributing to the response decline. Among these are:
• Steam turbine generators operating on “sliding pressure” or “boiler-follower”
control and/or with “valves wide-open” (VWO) operation.
• Blocked governors on nuclear units for licensing reasons.
• Less heavy manufacturing in North America (proportionally fewer large motor
loads and a reduction in “load rejection”).
• Variable-speed drives on motors that do not provide the traditional “load
rejection”.
• A larger proportion of combine cycle units being installed on the system.
Combined-cycle units when operating at full output operate in temperature control
mode. When the frequency declines, there is a drop in combustion air volume that
results from the slowing of compressor speed. This drop in combustion air
volume can cause a reduction in the unit output. Figure 6 is a graph of the output
of a combine cycle unit responding to a frequency decline.
-
-9--
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000991
Frequency Response Standard Whitepaper
1/17/2005
40.8
60.2
Output should increase 6+ MW
60.1
40.6
60
40.4
40.2
59.9
Frequency
59.8
40
59.7
39.8
59.6
39.6
59.5
Poplar Hills MW Output
39.4
59.4
39.2
8:24:00
8:31:12
8:38:24
8:45:36
8:52:48
9:00:00
9:07:12
POPLAR H.A790S POPLAR HILL GEN .AV
9:14:24
9:21:36
9:28:48
59.3
9:36:00
Freq
Figure 6 Combustion Turbine Response to Frequency Change
The blue line in Figure 6 is frequency and the red is MW output of the generators.
The oval envelops the Frequency Response time window. For a change in
frequency of -0.83%, the station lost 2.5% of machine output. If the plant
provided 5% droop, its output should have increased 6.6 MW with the frequency
event. The drop in output implies a POSITIVE Frequency Response
characteristic.
While this is one specific model of combined-cycle unit, the graph is illustrative
of this class of unit. As more of this class of unit comes on line, not only may
there be no response but the response may actually decline as the frequency
declines. This is of particular concern during Interconnection valley periods when
these units may potentially make up a large proportion of the on-line generation.
It is noteworthy that this phenomenon in the form of deloading or outright
tripping after no more than one or two seconds of good response was a
contributing factor in the Malaysia blackout in 1996 (Mansour 2003). Combinedcycle units can be tuned to provide correct frequency response; however, the
operators need to be educated to the problem or have contractual or financial
obligations and incentives to ensure that their units meet the requirements.
•
Deregulation has resulted in a large increase in reserve-sharing groups. In the
past, many Control Areas carried full reserves for their individual largest
contingency and some for multiple contingencies. De-regulation and competitive
-
- 10 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000992
Frequency Response Standard Whitepaper
1/17/2005
pressures have ended both of these practices. The majority of Control Areas
have formed into Reserve Sharing Groups and each now carries its proportional
share of the largest contingency.
While some of the above trends have slowed, the rate of decline has not been linear. In
four out of the eight years examined, the frequency response decline has been over
100MW/0.1Hz.
Analysis of a Load Only Response
Currently, the wide variation of frequency response tends to be a self-correcting problem.
During high load periods when units are operating at full output, the frequency response
is available from the load. In light load periods when there is less load response, the online units are at less than full output and produce governor response. Without a standard
in place, however, there is no guarantee that unit response will continue. What happens if
it does not? A simple calculation provides the answer.
The Eastern Interconnection peaks at 600,000 MW and remains at loads of
200,000MW and below for roughly 20% of the time. At best, motor and other
similar types of loads respond on a linear basis as the frequency declines. In other
words a 1% change in frequency, equivalent to 0.6Hz, produces a 1% change in
load. A drop in the Interconnection frequency that reaches the first step of underfrequency load shedding, 59.7 Hz, represents a 0.5% change in frequency and
therefore would produce only a 0.5% change in load or 1000MW. There are
roughly 16-22 single generators of this size or larger within the Eastern
Interconnection. Without unit or other equivalent frequency support, a single unit
trip could potentially cause the Eastern Interconnection to drop firm load.
-
- 11 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000993
Frequency Response Standard Whitepaper
1/17/2005
The following simulation results show the response of the Eastern Interconnection under
two scenarios. The load level analyzed is 280,000MW or about the load on 4/23/03 when
there was a loss of 2500MW on the system. Figure 7 shows the response of the system
assuming there had only been load response available. The model assumes a linear
decline of load with frequency as stated above. At 59.5Hz, the simulation drops 7% of the
load by under-frequency load shedding.
Eastern Interco nnectio n 4/23/02
To tal Lo ad 280,000M W Generatio n Lo ss 2500M W
Lo ad Linear with Freq. With no Gen Respo nse
61
291000
60.8
281000
60.6
60.4
271000
GEN
60.2
LOA D
FREQ
60
261000
59.8
251000
59.6
59.4
241000
59.2
231000
59
Figure 7 Simulation Assuming no Governor Response
-
- 12 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000994
Frequency Response Standard Whitepaper
1/17/2005
Figure 8 shows the same system conditions and assumptions except that there is
1000MW of generator governor reserves.
Gen & Load (MW)
Eastern Interconnection 4/23/02
Total Load 280,000MW Generation Loss 2500MW
Load Linear with Freq. plus 1000MW of Gov. Reserves
281000
61
280000
60.8
279000
60.6
278000
60.4
GEN
277000
60.2
276000
60
LOAD
FREQ
275000
59.8
274000
59.6
273000
59.4
272000
59.2
271000
59
1
3
5
7
9
11
13
15
17
19
Figure 8 Simulation with 1000 MW of Governor Reserves
The impact of the governor response even though only half of the unit loss is sufficient to
maintain the frequency above the under frequency tripping point.
Without a frequency response standard there is no assurance that unit response will be
available in any of the Interconnections. Current economics will continue to drive most
units to operate at maximum output. Presently, system operating conditions are
counterbalancing and the problem is self-correcting. As pointed out above, combinedcycle units are an increasing proportion of the generation. What incentive is there for
other, newer technologies to incorporate frequency response if no requirement (i.e. a
standard) exists to define adequacy?
Secondary Impacts
There are many secondary effects from having an unknown and uncontrolled frequency
response. Among these are:
• System oscillations may not be damped and may actually be aggravated. Recent
testing of governor response in the Western Interconnection (Pereira) shows that
existing models using an expected 5% governor droop are overly optimistic.
Calculations indicate only 40% of expected response was obtained. As a result,
-
- 13 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000995
Frequency Response Standard Whitepaper
1/17/2005
•
•
•
•
oscillations persist for roughly twice as long as models predict, and they are
substantially stronger.
Some areas may be incapable of “self restoration” during islanding and black-start
conditions.
Without a measure or requirement, market forces will likely continue to drive a
decline in performance.
Stability transfer limits will be incorrect if assumptions about frequency response
are wrong.
There is no way to tell whether the decline in response is spread among all
Control Areas or whether there are regions with little or no response (and
therefore not able to provide support to the Interconnection during disturbances or
“self start” during restoration).
CURRENT REQUIREMENTS
This section highlights the current requirements and good practices regarding Frequency
Response.
The NERC Control Area Criteria document outlines the fundamental obligations of the
operation of the grid. In particular, it states:
The CONTROL AREA shall operate generation or have the necessary
contracts to operate generation to… Provide its frequency bias
obligations.
Policy 1 has several guides (suggested good practices) regarding governors:
•
•
•
•
Generating units with nameplate ratings of 10 MW or greater should be equipped
with governors operational for Frequency Response unless restricted by
regulatory mandates.
Turbine governors and HVDC controls, where applicable, should respond to
system frequency deviation, unless there is a temporary operating problem.
All turbine generators equipped with governors should be capable of providing
immediate and sustained response to abnormal frequency excursions. Governors
should provide a 5% droop characteristic. Governors should, as a minimum, be
fully responsive to frequency deviations exceeding ± 0.036 Hz.
Turbine control systems that provide adjustable limits to governor valve
movement (valve position limit or equivalent) should not restrict travel more than
necessary to coordinate boiler and turbine response characteristics.
ISN’T EXISTING POLICY SUFFICIENT?
Current NERC policy, as seen above, has no “requirements” for primary frequency
response. Policy 1C deals primarily with Bias, which relates more to determining
regulation and Secondary Frequency Control, rather than Frequency Response. The
-
- 14 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000996
Frequency Response Standard Whitepaper
1/17/2005
portions of Policy 1C regarding governors are “guides” and carry no force. This may
partially explain why Frequency Response is declining. Mandatory requirements for
governors, even if adopted, do not guarantee that the unit would not be operated at wideopen valves and, therefore, have no response for an under-frequency condition. In other
words, both responsiveness and depth of response must be assured.
COMMENTS TO THE FIRST PROPOSED FREQUENCY
RESPONSE STANDARD
A Frequency Response Standard was proposed in mid 2001 in conjunction with approval
of the current version of Policy 1. Table 1 summarizes the comments received.
Summary Comment
“Wordsmithing” or clarification or minor modification
comments
Governor requirement needs more definition (what is a
“governor” on a combined cycle unit) and should be
consistent with Planning Standards.
In favor of a standard
Measure should be tested before implementation
Add a requirement for common set points for under-frequency
load shedding so that one CONTROL AREA won’t drag
another one down,
“Loss of load” risk should not be the basis for establishing the
standard.
There does not appear to be sufficient evidence on hand at this
time to warrant rigorous Standards and possible noncompliance penalties.
Not sure using one-minute data will measure what’s needed.
Respondents
62
1
3
2
1
1
1
1
Table 1 Summary of Comments to Policy 1C
The Balancing SAR task force posed questions to the Industry on the need for a
Frequency Response Measure (FRM) that would likely mirror the FRS suggested by the
Resources Subcommittee. The NERC Director of Standards returned the proposal
because of concerns raised by the Industry. A closer look at the responses reveals that
the Industry was not so much opposed to the standard as they were looking for
information and clarification of the requirements. Table 2 summarizes the responses.
Summary Comment
Difficulty measuring
Didn’t understand measure
Only if Generation governors required in “interconnection
standard”
More work needed in definition
In favor
Should hold sub-entities (generators, LSEs) accountable
-
Respondents
6
1
1
1
6
6
- 15 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000997
Frequency Response Standard Whitepaper
1/17/2005
Current guides requiring generators to respond are adequate
Eliminate the Frequency Response Measure
2
1
Table 2 Summary of Comments Received on a Frequency Response Measure
FREQUENCY RESPONSE STANDARD CONSIDERATIONS
Introduction
A frequency response standard must explain clearly what is to be measured and why.
This will help with the design of the process and provide direction on how it should
evolve. Logical goals and considerations for a FRS include:
•
•
•
•
•
•
•
•
•
Benchmark and track performance (both Control Area and Interconnection).
Maintain historic levels of reliability (or some other level justified by an in-depth
analysis).
Be performance-based rather than commodity-based.
o This is similar to CPS where impact on interconnection frequency is measured
rather than requiring a target set-aside of regulating resources.
o Specifically measuring Frequency Response allows more flexibility in
meeting the needs of the Interconnection and Region (a target spinning
reserve amount does not ensure Frequency Response)
o Rather than telling entities how to meet the standard, let the Industry and
markets find innovative solutions.
Be “tunable”, thereby providing a means to adjust the standards as information
allows.
Be empirically valid (results statistically provable).
Be objectively calculated.
Be consistent and verifiable in application by all parties.
Enable simple compliance monitoring.
Be consistent with direction of the Industry (i.e. FERC RTO rule, IOSITF, etc.).
Issues
A Frequency Response Standard should address the following issues:
• There must be a minimum response for each event (rate, amount, and duration) such
that the problems described above do not occur. Reliance on average response could
result in all areas being short at the same time (similar to the short-term excursions
seen with CPS1). The amount (depth of response) should not be under-emphasized.
One shortcoming of the recommendations in policy today is that there is no guidance
regarding how much governor response (in MW) is required at the 5% droop rate.
This has led to confusion among plant operators and turbine-generator manufacturers
alike, and has resulted in an objectionable lack of response from some units when the
-
- 16 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000998
Frequency Response Standard Whitepaper
1/17/2005
•
•
•
•
boiler controls are suppressed out of legitimate fear of tripping the unit on a
frequency change.
The measurement selected must be accurate and, to the extent practical, easy to
implement.
The requirements must integrate with and be consistent with the assumptions used in
setting the BAAL limits within the Load and Balancing Standard (if and as ultimately
adopted)
A method of allocation must be developed
The standard should not preclude market solutions (e.g. allow purchasing of response
as long as deliverability and restoration criteria can be met).There must be a means
for sale/purchase of frequency response as for any other quantity.
REFERENCES
Bourque, E., Frequency Response Data provided to the NERC Resources subcommittee.
Cohn, N., Control of Generation and Power Flow on Interconnected Power Systems, John
Wiley and Sons, 1961.
Comments to posting of Policy 1 (Policy1-Version2-0601-comments1.doc)
EPRI Report TR-101080, Impacts of Governor Response Changes on the Security of
North American Interconnections, October 1992.
Ingleson, J., Nagle, M., “Decline of Eastern Interconnection Frequency Response”,
Prepared for the Fault and Disturbance Conference at Georgia Tech, May, 1999.
NERC Policy 1, Generation Control and Performance.
NERC Frequency Response Characteristic Survey Training Document.
NERC Resources Subcommittee Minutes .
NERC Training Resource Working Group Understand and Calculate Frequency
Response”.
NERC “Interconnected Operations Services Reference Document”.
Pereira, L., “NEW THERMAL TURBINE GOVERNOR MODELING FOR THE WECC”,
Presentation dated August 27, 2002.
-
- 17 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
000999
Frequency Response Standard Whitepaper
1/17/2005
“WSCC FRR SURVEYS CONDUCTED” (Rev. November 21, 2001) Report by WECC
Performance Work Group (PWG).
Mansour, Yakout. Correspondence with investigator of the 1996 Malaysian blackout..
-
- 18 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001000
Frequency Response Standard Whitepaper
1/17/2005
ACRONYMS, TERMS AND DEFINITIONS
ACE - AREA CONTROL ERROR: ACE is the algebraic sum of the net scheduled and net
actual interchange and a bias term based on the difference between scheduled and actual
system frequency. This parameter is used to determine a Control Area’s control
performance with respects to its impact on system frequency.
CPS – CONTROL PERFORMANCE STANDARD: CPS defines a standard of minimum
control performance. Each Control Area is to have the best operation above this
minimum that can be achieved within the bounds of reasonable economic and physical
limitations. Each Control Area shall monitor its performance on a continuous basis
against two standards: CPS1 and CPS2.
CPS1 – CONTROL PERFORMANCE STANDARD 1: Over a (running) year, the
average of the clock-minute averages of a Control Area’s ACE times the clock
minute average frequency error shall be less than a specific limit. This limit is a
constant derived from a target frequency bound reviewed and set as necessary by
the NERC Resources Subcommittee.
CPS2 – CONTROL PERFORMANCE STANDARD 2: The average ACE for each of
six ten-minute periods during the hour (i.e., 10, 20, 30, 40, 50 and 60 minutes
after the hour) must be within L10 at least 90 % of the time during each calendar
month.
DCS – DISTURBANCE CONTROL STANDARD: The standard used to monitor a Control
Area’s ability to recover from a disturbance.
ERCOT – ELECTRIC RELIABILITY COUNCIL OF TEXAS: One of the ten NERC regional
coordinating councils.
FRC – FREQUENCY RESPONSE CHARACTERISTIC: For any change in generation/load
balance in an interconnection, a frequency change occurs. FRC defines how any system
(Control Area) responds to this change during any imbalance resulting from a sudden loss
of load or generation. System frequency does not usually return to its pre-disturbance
level until the Control Area experiencing the imbalance corrects its imbalance.
FRS – Frequency Response Standard.
IOS – INTERCONNECTED OPERATING SERVICES: IOS are the elemental ‘reliability
building blocks’ from generation (and sometimes load) necessary to maintain bulk
electric system reliability, (sometimes referred to as ancillary services, such as regulation,
load following, contingency reserves, Frequency Response, reactive power supply, and
black-start capability).
LSE- Load Serving Entity.
NAESB – North American Energy Standards Board.
-
- 19 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001001
Frequency Response Standard Whitepaper
1/17/2005
SAR - Standards Authorization Request.
-
- 20 - -
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001002
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Phil Creech
Organization:
Progress Energy – Carolinas
Telephone:
919-546-6738
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001003
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001004
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001005
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001006
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Scope:
The scope of the proposed standard is appropriate. However, the reliability requirements would be
better addressed by a comprehensive review that considers the adequacy of existing reliability
standards.
Applicability:
The applicability of the proposed standard is understood to be Reliability Authorities, Balancing
Authorities, and Generator Operators. However, substantial questions remain as to how the
responsibilities implied in the proposed standard will be equitably distributed.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001007
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
The reliability requirements provided in the proposed standard would be better addressed by a
comprehensive review that considers the adequacy of the existing reliability standards (i.e., 300 Balance Resources and Demand)
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001008
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001009
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Les Pereira
Organization:
Northern California Power Agency
Telephone:
916-781-4218
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
x
4 - Transmission-dependent Utilities
MAIN
MAPP
NPCC
SERC
SPP
x
WECC
NA - Not
Applicable
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
7 - Large Electricity End Users
8 - Small Electricity End Users
9 - Federal, State, Provincial Regulatory or other Government Entities
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001010
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 8
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001011
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001012
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
x
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001013
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
x
No
If no, please explain in the space provided below.
The scope needs to be expanded – see detailed comments in a following section – based on
extensive modeling and validation work in WECC.
Comments
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001014
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
x
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
A new SAR will be more prescriptive, however there is also need for other related sections in
NERC Operating Policy and Planning that need to be modified – see other comments below.
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001015
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
x
Yes
No
If yes, please share those comments in the space provided below.
Two statements are made in the SAR:
1. The purpose of the proposed SAR is to ensure that frequency of the Interconnection
remains above underfrequency load shedding setpoints during the transient period
following the sudden loss of generation on the Interconnection.
2. Furthermore, it is stated that “ In regard to frequency response, one shortcoming of
the recommendations in policy today is that there is no guidance regarding how
much governor response (in MW) is required at the 5% droop rate.”
The first is a calculated number and depends not only on the amount of generation tripped, but also
the total generation in the Whole Interconnection at the time of trip. Obviously two very different
answers will be obtained : one with the Interconnection intact (normal operation) and the second
when islanded. Both affect reliability.
The second issue has been thoroughly investigated in the WECC and a new Thermal Governor
modeling approach has been implemented in the WECC after system tests, an exhaustive modeling
validation effort and obtaining data from the generator owners. This has been documented in two
IEEE Transaction papers described below. These papers present the development of a new turbinegovernor modeling approach in WECC that correctly represents thermal units that have
demonstrated unresponsive characteristics such as “base loaded” units operated with limiters, or
partially responsive units with MW-load-controllers. The May 18th 2001 system trip test for 1250
MW performed with all AGCs off indicated that only about 40% of the governors effectively
responded in the real system. If all the governors were responsive the calculated generation pickup
for governors with a 5% droop for a 0.1 Hz frequency deviation would be 3185 MW instead of
1250 MW. The new modeling approach has been extensively validated against recordings from
three WECC system tests and several large disturbances, and has been approved for use in all
operation and planning studies in the WECC. The second paper describes the steps being taken to
obtain validated data for the new governor models.
The work done by WECC indicate clearly that we do not get the required 5% droop from all units
as required by NERC. The modeling approach taken was to model the governors in planning and
operating studies exactly as they are being actually operated. Enforcement/compliance of the 5%
droop is a separate issue and must be addressed by operating policies.
Obviously, the SAR touches upon only part of the problem, but it is a good start and
should be expanded. It also needs to be cross-referenced with other areas such as the 5%
droop requirement, an effective spinning reserves policy that actually works (see the
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001016
Comment Form – Proposed Frequency Response Standard
papers), and the effect on ‘governor’ powerflow and voltage stability analysis as a result of
“unresponsive” governors.
The white paper referred by the SAR only touches upon the WECC effort and seems to
miss the whole point of the modeling and validation work by the Governor Modeling Task
Force in WECC - and what we have achieved in WECC to address realistic modeling of
unresponsive governors in the real system.
1. "A New Thermal Governor Modeling Approach in the WECC"
by L. Pereira, J. Undrill, D. Kosterev, D. Davies, S. Patterson, IEEE Trans. Power Systems,
vol. 18, Issue.2, pp. 819-829, May 2003. (IEEE 2004 prize paper). Presented at Toronto IEEE
PES, July 2003.
2. “New Thermal Governor Model Selection and Validation in the WECC”
by Les Pereira, Dmitry Kosterev, Donald Davies, and Shawn Patterson - IEEE TPWRS –
Vol.19, No.1, pp 517-523, February 2004. Presented at Denver IEEE PES, July 2004.
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001017
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Calimano
Organization:
New York Independent System Operator
Telephone:
518-356-6129
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001018
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
New York Independent System Operator
Lead Contact:
Mike Calimano
Contact Organization: NYISO
Contact Segment:
2
Contact Telephone:
518-356-6129
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Page 2 of 8
Region*
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001019
Comment Form – Proposed Frequency Response Standard
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001020
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
We agree in general that there is a reliability need to have frequency response, particularly during
disturbances, islanding and restoration. The standard should provide the process for a technically
sound calculation of frequency response and bias (both fixed and variable).
Any new standards on frequency response need not and should not be onerous by finding BAs
noncompliant with response less than average or below some un-validated norms. There may be
valid reasons why a BA is below observed norms in response. For example, the BA may meet
most of its obligations with schedules or its native load may be non-responsive.
If performance is significantly less than an Interconnection norm, the standard should not trigger an
automatic non-compliance. In these situations the BA should perform an internal
review/assessment that ensures governors are working as designed, that the BA knows which
resources are frequency responsive (so the information can be included in restoration plans),
whether governors can be put in more responsive modes during disturbances, etc.
When required, the validation of governor performance could be achieved either through online
monitoring in an EMS or periodic testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not provide response under normal
operations (e.g. nuclear units operating at full load) and that response is highly variable event-toevent based on simultaneous load changes. The standard should acknowledge the differing
Interconnection requirements (smaller Interconnections need greater response).
The standard should also track Interconnection response over time (years) and be reevaluated as
performance changes.
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001021
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
There is a general need for a standard, but the outcomes and expectations should address the
comments raised in question 1.
While we agree that the standard should not preclude market solutions (e.g. allow purchasing of
response as long as deliverability and restoration criteria can be met), we have concerns with the
statement: There must be a means for sale/purchase of frequency response as for any other
quantity.
It is not clear what is meant by A method of allocation must be developed”. Is this an allocation of
Interconnection response to BAs, BA allocation to generators or something different?
.
Comments
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001022
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001023
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
We appreciate the opportunity to comment and believe there is a need for such a standard.
Published studies show frequency response is declining when it should be increasing with load.
The main concerns with this decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be unable to fulfill their blackstart
and restoration responsibilities, thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency response, they are likely overoptimistic
and may misstate grid stability limits.
This standard would allow the industry to determine whether the decline is local or global.
Rather than implementing a complicated infrastructure or process, we would suggest that NERC
automate the calculation of frequency response by either:
Asking BAs to save their CPS-source data in a common format so a common tool can be
used (MAPP BAs and some others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring application.
Refer to our earlier comments the structure of the standard (where lower amounts of BA response
trigger an internal assessment rather than automatic assignment of non-compliance). BAs (and
ultimately generators) would only be initially non-compliant if their response was low AND the
BA failed to perform a reliability assessment in conjunction with its TOP. This default assessment
would be at the BA level, but could be on an area basis (likely islanding area or where a TSP has
responsibility for frequency responsive and black start ancillary services).
The standard should employ a methodology that not only captures initial response (first few
seconds after the event) but also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further define the standard to meet its
needs.
Providing visibility on where and when performance is substandard will likely initiate sufficient
action to arrest the decline in performance. Minimum performance standards could be
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001024
Comment Form – Proposed Frequency Response Standard
implemented after the industry has identified what is reasonably achievable and technically
justified.
CHANGE
This SAR is proposed to develop a standard to measure sub-minute responses to changes in
frequency and to set minimum acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure sub-minute responses to changes in
frequency and to set minimum acceptable responses to these system events.
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001025
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
James Stanton
Organization:
Calpine
Telephone:
832-476-4453
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001026
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001027
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001028
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001029
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001030
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001031
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Given the language in the accompanying White Paper: The standard should not preclude market
solutions (e.g. allow purchasing of response as long as deliverability and restoration
criteria can be met).There must be a means for sale/purchase of frequency response as for
any other quantity. – I believe this Standard should be developed in conjunction with
NAESB. The definition, attributes and procurement metrics of the frequency response
product will be a critical component of this Standard. Some guidance in defining and
developing this service to the bulk interconnected system can be found in the NERC IOS
Reference Document. The Standard should build on this previous IOS work.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001032
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001033
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Operating Reliability Working Group (ORWG)
Lead Contact:
Robert Rhodes
Contact Organization: Southwest Power Pool
Contact Segment:
1, 2
Contact Telephone:
501-614-3241
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Ron Ciesiel
Southwest Power Pool
SPP
2
Bob Cochran
SPS
SPP
1
Mike Gammon
KCPL
SPP
1
Steve Hillman
WPEK
SPP
1
Allen Klassen
Westar
SPP
1
Bill Nolte
SECI
SPP
1
Robert Rhodes
Southwest Power Pool
SPP
2
Mike Stafford
GRDA
SPP
1
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001034
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001035
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
A frequency response standard is needed but only within the scope and range of the previously
provided guides in Policy 1 such as a design criteria of 5% droop, a 36 mHz deadband with
exclusions for nuclear, combined cycle and small generating units.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001036
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001037
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
We would recommend that this standard be incorporated into the Balance Resource and Demand
Standard (Standard 300) or the Version 0 BAL Standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001038
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001039
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001040
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
California ISO
Lead Contact:
Ed Riley
Contact Organization: California ISO
Contact Segment:
2
Contact Telephone:
916 351 4463
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Yuri Makarov
California ISO
WECC
2
Steve McCoy
California ISO
WECC
2
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001041
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001042
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
X Yes
No
If no, please explain in the space provided below.
Comments
Frequency response provided by speed governors and loads helps to prevent load shedding and
generator trips at significant frequency excursions caused by sudden active power mismatches in
the systems. Without a sufficient frequency response emerging during the first seconds after a
frequency disturbance, there is a danger of further cascading development or frequency instability
and system collapse cased by underfrequency generator trips. It has been already noted that
insufficient frequency response in some parts of an Interconnection may cause certain temporary
redistribution of power flows and reduce stability margins after frequency disturbances that may
limit the OTC on critical paths within the Interconnection. It has been also observed that
insufficient frequency response may cause a weaker frequency recovery that bears a greater risk of
system collapse at subsequent frequency disturbances. Therefore, frequency response is definitely a
reliability issue that needs to be addressed by a NERC standard.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001043
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
X Yes
No
If no, please explain in the space provided below.
Comments
Generally, our answer is yes, but the matter of applicability needs a very careful consideration. The
question is whether the proposed standard should be applied to only the reliability and balancing
authorities and plant operators, or also to the resource and system planning authorities and
generator owners. For example, wind generators do not provide a frequency response, whereas the
response from the Combined Cycle units is limited. This is a matter of design as well as the matter
of controllability of the primary energy source. If the generation portfolio contains a lot of wind
and CC generators, the balancing authority cannot do much to improve its summary frequency
response in general terms. Also, if frequency responsive generators in a CA are heavily loaded,
would the new standard force the balancing authorities to re-dispatch generation in favor of nonresponsive generation and commit more responsive generation ahead of the non-responsive
generation? Another issue is whether the standard should specify the required response in the area
or individual responses from generators. Perhaps, NERC should work with NASB to find the right
answers before establishing the standard. One possible solution is to establish penalties for noncompliance that would stimulate generator owners to invest in frequency responsive generation.
Another possible recommendation could be establishing a market for frequency response. Without
resolving these difficult issues, this standard cannot be accepted.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001044
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
X No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
The new standard should a stand-alone standard because of its potential implications for control
areas and the necessity to stage the implementation of the standard in coordination with resolution
of the issues discussed above.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001045
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
X No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001046
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Travis Besier or Ellis Rankin
Organization:
TXU Electric Delivery Company
Telephone:
214-812-4917 or 214-743-6825
Email:
[email protected] or [email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001047
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001048
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001049
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
TXU Electric Delivery proposes that Frequency Response Guidelines at the NERC level should
only be in general terms and require that each Reliability Authority establish a specific Frequency
Response Standard with detailed specifications as appropriate for its region.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001050
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001051
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001052
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001053
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001054
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
RTO/ISO Standards Review Committee
Lead Contact:
Karl Tammar
Contact Organization: NYISO
Contact Segment:
2
Contact Telephone:
518-356-6205
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Dale McMaster
AESO
WECC
2
Ed Riley
CAISO
WECC
2
Sam Jones
ERCOT
ERCOT
2
Peter Henderson
IESO
NPCC
2
Peter Brandien
ISO-NE
NPCC
2
Bill Phillips
MISO
Karl Tammar
NYISO
NPCC
2
Bruce Balmat
PJM
MAAC
2
Charles Yeung
SPP
SPP
2
2
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001055
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001056
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
We agree in general that there is a reliability need to have frequency response, particularly during
disturbances, islanding and restoration. The standard should provide the process for a technically
sound calculation of frequency response and bias (both fixed and variable).
Any new standards on frequency response need not and should not be onerous by finding BAs
noncompliant with response less than average or below some un-validated norms.
If performance is significantly less than an Interconnection norm, the standard should not trigger an
automatic non-compliance. In these situations the BA should perform an internal
review/assessment that ensures governors are working as designed, that the BA knows which
resources are frequency responsive (so the information can be included in restoration plans),
whether governors can be triggered to be more responsive during disturbances, etc and satisfy the
Interconnection requirement. If the Interconnection requirement is not met within a reasonable
timeframe then the BA should be deemed as non-compliant.
When required, the validation of governor performance could be achieved either through online
monitoring in an EMS or periodic testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not provide response under normal
operations (e.g. nuclear units operating at full load) and that response is highly variable event-toevent based on simultaneous load changes.
The standard should acknowledge the differing Interconnection requirements (smaller
Interconnections need greater response).
The standard should also track Interconnection and BA areas response over time (years) and be
reevaluated as performance changes.
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001057
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
There is a general need for a standard, but the outcomes and expectations should address the
comments raised in question 1.
While we agree that the standard should not preclude market solutions (e.g. allow purchasing of
response as long as deliverability and restoration criteria can be met), we have concerns with the
statement There must be a means for sale/purchase of frequency response as for any other
quantity.
It is not clear what is meant by A method of allocation must be developed” Is this an allocation of
Interconnection response to BAs, BA allocation to generators or something different?
Comments
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001058
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Unless the Version 0 (BAL-003-0 — Frequency Response and Bias) can be clarified and brought
in line with this proposed standard, it should be stand-alone.
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001059
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
We appreciate the opportunity to comment and believe there is a need for such a standard.
It needs to be recognized that there are two objectives for governor response, namely, to provide
response on an interconnection wide basis to maintain an acceptable frequency and secondly to
control frequency in island situations. The former may allow for averaging over an area of the
response requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it should be increasing with load.
The main concerns with this decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be unable to fulfill their blackstart
and restoration responsibilities, thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency response, they are likely over optimistic
and may misstate grid stability limits.
This standard would allow the industry to determine whether the decline is local or global.
Rather than implementing a complicated infrastructure or process, we would suggest that NERC
automate the calculation of frequency response by either:
Asking BAs to save their CPS-source data in a common format so a common tool can be
used (MAPP BAs and some others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring application.
Refer to our earlier comments the structure of the standard (where lower amounts of BA response
trigger an internal assessment rather than automatic assignment of non-compliance). BAs (and
ultimately generators) would only be initially non-compliant if their response was low AND the
BA failed to perform a reliability assessment in conjunction with its TOP. Non compliance should
be assessed if the BA does not alleviate the deficiency within a reasonable timeframe. This default
assessment would be at the BA level, but could be on an area basis (likely islanding area or where a
TSP has responsibility for frequency responsive and black start ancillary services).
The standard should employ a methodology that not only captures initial response (first few
seconds after the event) but also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further define the standard to meet its
needs.
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001060
Comment Form – Proposed Frequency Response Standard
Providing visibility on where and when performance is substandard will likely initiate sufficient
action to arrest the decline in performance. Minimum performance standards could be
implemented after the industry has identified what is reasonably achievable and technically
justified.
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001061
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Bonneville Power Administration
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001062
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Bonneville Power Administration
Lead Contact:
Bart McManus
Contact Organization:
Contact Segment:
Contact Telephone:
(360)418-2309
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Brian Tuck
BPA
James Randall
BPA
Francis Halpin
BPA
Bill Mittlestat
BPA
James Murphy
BPA
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001063
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001064
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
NERC should not involve itself in the development of these standards and should allow individual
interconnections to address frequency response issues independently. For example, the WECC is
currently working on standards that will address this concern. They will be tailored to the specific
requirements of this interconnection and will provide the best possible solution to the problem.
There may be a need to specify frequency response requirements within some interconnections;
however, it is not necessary, or most effective for them to be defined at the NERC level.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001065
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
The main theme that there needs to be a relationship between response and frequency decline is the
right approach but requirements would be different from region to region. Standards to manage
frequency response should be developed by individual interconnections; not NERC. The scope and
applicability should be defined by the needs of the interconnection to provide the most benefit to
system wide reliability.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001066
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
WECC has been working on frequency response standards for a few years and is close to finalizing
standards specifically for the WECC interconnection. We do think there is a need for
standardization of frequency response (clearly we do since WECC is doing it) BUT this standard
should be developed at the Regional Council or Interconnection level and then adopted by NERC
as a "Standard" with regional differences. Any new standards concerning frequency response
should be developed by the individual interconnections.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001067
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Frequency response requirements are likely different for each of the three interconnected regions
and a generalized approach will likely not meet WECC needs. The danger here is that a NERCwide approach may not be compatible with the needs of a regional approach. Standards are
currently being developed within WECC to address the frequency response concerns of this
interconnection. We feel that if the Eastern Interconnection needs a Frequency Response Standard,
they should utilize the NERC Frequency Response Standard Whitepaper to draft an Eastern
Interconnection-specific Frequency Response Standard.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001068
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Richard P. Schulz
Organization:
Richard Schulz LLC
Telephone:
614.899.9184
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
RichardSchulz-RichardSchulzLLC.doc
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001069
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
RichardSchulz-RichardSchulzLLC.doc
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001070
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
RichardSchulz-RichardSchulzLLC.doc
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001071
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
RichardSchulz-RichardSchulzLLC.doc
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001072
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
The proposed scope and applicability, to the extent that they are in the given in the SAR, are
good.
RichardSchulz-RichardSchulzLLC.doc
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001073
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
RichardSchulz-RichardSchulzLLC.doc
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001074
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Please see the attachment
RichardSchulz-RichardSchulzLLC.doc
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001075
Comments on SAR Frequency Response
First, I make these comments based on work that I've done principally at American Electric
Power Service Corp, before my retirement from there in November 2000, and as founding Chair
of the IEEE Task Force on Large Interconnected Power System Response to Generation
Governing. These comments are entirely mine, and reflect no views of either body.
Second. It appears that the final standard will differ from any single person's opinions.
Thus the specific comments below may not prevail.
Specific Comment 1:
The comment on page 4 of the SAR, "The standard should not preclude market solutions
(e.g. allow purchasing of response as long as deliverability and restoration criteria can be
met).There must be a means for sale/purchase of frequency response as for any other quantity."
is workable only in near-normal operating conditions. But it will fail miserably when there is
any islanding condition. An analogy:
Several skydivers agree that reserve parachutes are a very good idea,
but don't want to invest in 1 reserve each. So they agree that they'll buy
one to share among them, so each will be saved by that spare. This means
that they will hold hands until they pull their ripcords.
Sounded good, until they tried it, and the first guy to pull his cord came
unhitched, had a failed main 'chute, and the spare was on someone else.
Specific Comment 2:
The comment on page 4 of the SAR, "The measurement selected must be accurate and, to
the extent practical, easy to implement.' may be met in the Eastern Interconnection by the
underway DOE "Eastern Interconnection Phasor Project ' and by the similar WECC
measurement systems, commonly called "WAMS". Les Peieira's paper, cited in the White
Paper, used the WAMS measurements.
Dick Schulz
Chair, IEEE Task Force on Large Interconnected Power System Response to Generation
Governing
433 S. Spring Rd.
Westerville, Ohio 43081-2732
(614) 899-9184 home
(614) 306-8233 cell
[email protected] or [email protected]
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001076
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roy Boyer
Organization:
TXU Electric Delivery
Telephone:
214-743-6682
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
x ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001077
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001078
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001079
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
xYes
No
If no, please explain in the space provided below.
Comments
Yes, I agree there is a reliability need for specifying the quality and quantity of frequency response.
There is ample evidence that specifying a droop value or that specifying governors must be in
operation will not necessarily result in any useful governor response to a sudden large drop in
system frequency. So yes, I think a SAR team should look into this matter. I would suggest the
part load can play in arresting frequency decline be included in the scope. I would also suggest that
the frequency response needs of the regions will likely vary, so final specific requirements should
probably be made at the region level.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001080
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
x Yes
No
If no, please explain in the space provided below.
Comments
Yes, I agree.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001081
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
No opinion.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001082
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
xNo
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001083
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Linda Campbell
Organization:
FRCC
Telephone:
813-289-5644
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001084
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
FRCC Region
Lead Contact:
Eric Senkowicz
Contact Organization:
Contact Segment:
2
Contact Telephone:
813-289-5646
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Ron Donahey
TEC
FRCC
1
Mark Bennett
GRU
FRCC
3
Steve Wallace
SEC
FRCC
5
Steve McElhaney
FMPA
FRCC
5
Ted Hobson
JEA
FRCC
1
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001085
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001086
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
The FRCC does not support the development of a Frequency Response Standard at this time. A
standard for each Interconnection, although informative would be unenforceable as far as
identifying short term, frequency response deficient, entities or areas. As such measurability and
compliance by the relevant entities would be all but impossible. As far as an Interconnection
allocation program for frequency response, we feel that the “apparent” decline in response is not
significant enough to warrant a standard at this time and we would require additional details of how
such a plan would be implemented and the potential economic impacts on the Regions that would
be associated with that plan.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001087
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
The SAR indicates a measure of frequency response for the Interconnection, as a measure of
performance. This would be very difficult to translate to individual entity compliance and thus
render the standard applicable to no entities.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001088
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001089
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
At this time the FRCC has the highest frequency settings for load shedding in the Eastern
Interconnection (southern part of the Region). Being a peninsula and out of necessity, the Region
has developed a well coordinated, under-frequency program for extreme frequency excursions.
Ambiguity of the requirements, uncertainty of measurement and the lack of benefit to the Region
require that the FRCC to oppose this Standard Authorization Request at this time.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001090
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Gerald Rheault
Organization:
Manitoba Hydro
Telephone:
204-487-5423
Email:
[email protected]
NERC Region
ERCOT
Registered Ballot Body Segment
X
ECAR
FRCC
2 - RTOs, ISOs, Regional Reliability Councils
X
MAAC
MAIN
MAPP
NPCC
1 - Transmission Owners
3 - Load-serving Entities
4 - Transmission-dependent Utilities
X
5 - Electric Generators
X
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001091
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001092
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001093
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
X Yes
No
If no, please explain in the space provided below.
Comments
Manitoba Hydro , from a reliability perspective, supports the idea of specifying the quantity and
quality of frequency response and incorporating these elements in a Standard. However, the
development of this standard should not be rushed since the evidence provided in the Standard
Authorization Request form and in the Frequency Response Standard White paper shows that
current frequency response and projected frequency response trends do not pose a significant
potential for compromising system reliability and for major under-frequency load shedding to
occur in the near term.
Also in the section of the white paper which examines “frequency response standard
considerations”, a broad scope and outline is given, more detail is required especially regarding
methods of ensuring compliance.
In paragraph 2, page 9 of the white paper where the current frequency response of the Eastern
Interconnection is stated as 3100 MW/0.1 Hz with a standard deviation of 1870 MW/0.1 Hz and
the statement is made that “the fact that an under-frequency event has not happened yet is only
coincidence” requires much more detailed information regarding the origin and calculations of
these numbers before these assumptions can be made. Could it be that instead of a frequency
response closer to 1230MW/ 0.1 Hz it is actually practically closer to 3100 MW/ 0.1 Hz or even
4970 MW/ 0.1 Hz most of the time?
One understandable major concern addressed in the white paper is the response of combined-cycle
units to frequency decline and the fact that due to a drop in combustion air volume their output may
actually decrease with a drop in frequency or even result in unit tripping. Also there was concern
with the possibility that larger amounts of these types of units will be installed on the system
thereby potentially increasing the decline in frequency response rate from 70 MW/ 0.1 Hz /Year
(Eastern Interconnection) .
It is also mentioned (on page 10) that with proper tuning combined cycle units can provide correct
frequency response. Maybe part of the focus should be on finding ways of enforcing the Current
Requirements (Page 14) and including specific frequency response requirements for combinedcycle units.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001094
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001095
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing standards
as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001096
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Below are a few general comments on the SAR:
There is general agreement with the statement “reliance on load as the sole support to arrest the
frequency can lead to a decline in the reliability of the grid” in paragraph 3, page 4 of the white
paper. However enough information is not provided to substantiate statements earlier in the
paragraph such as, “the turn around in frequency from points C to B attributable to unit governor
response has markedly declined and at times is non-existent in the eastern interconnection” and
“the line from points C to D is shifting down and becoming horizontal”.
In areas where governor response is limited it may be necessary to explore the necessity of
earmarking “high-set” blocks of load , as is practiced in ERCOT, to act as a supplementary to
governor response. Although it is anticipated that this approach would probably be much more
difficult and challenging to co-ordinate in larger areas.
There should be careful thought put into the system/interconnection performance targets for
frequency response. Perhaps the bar should be higher than preventing UFLS for credible generation
loss events, i.e., provide a margin above this level. At the same time the standard should not
impose unreasonable costs on entities to demonstrate compliance. The performance target should
address both total interconnection response and also area or system response (potential islanding)
and be very clear how generator operators (or load) obligations are allocated to achieve the
performance targets.
NERC should investigate a process to monitor interconnection frequency response to be able to
measure performance.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001097
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
P.D. Henderson
Organization:
Independent Electricity System Operator
Telephone:
905 855-6258
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001098
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 8
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001099
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001100
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
We agree in general that there is a reliability need to have frequency response, in order to maintain
interconnection frequency and particularly during disturbances, islanding and restoration. The
standard need to address both the system needs as well as island requirements for frequency
response.
The standard should provide the process for a technically sound calculation of frequency response
and bias.
The standard should acknowledge that some units might not provide response under normal
operations (e.g. nuclear units operating at full load) and that load response is highly variable event
based on time of day or year.
The standard should acknowledge smaller areas need greater response.
Where BA areas are deficient in meeting the interconnection requirement , they should be allowed
a reasonable period of time to take appropriate steps to make corrections before being assessed as
non compliant.
The standard should also track area response over time (years) and be reevaluated as performance
changes.
Quality should be defined. For generators it should include dead-band, droop characteristics, etc.
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001101
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
While we agree that the standard should not preclude market solutions (e.g. allow purchasing of
response as long as deliverability and restoration criteria can be met), we have concerns with the
statement There must be a means for sale/purchase of frequency response as for any other
quantity. The scope should exclude any reference to a means for sale/purchase of frequency
response as it should only address reliability requirements.
It is not clear what is meant by A method of allocation must be developed. Is this an allocation of
Interconnection response to BAs, BA allocation to generators or something different?
The requirements should recognize the capabilities and limitations of generators (e.g. nuclear units
operating at full load).
Comments
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001102
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
If the existing Frequency Response and Bias Standard Version 0 (Bal-003-0) can not be clarified
and brought in line with this proposed standard, it should be standalone .
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001103
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
We appreciate the opportunity to comment and believe there is a need for such a standard.
It needs to be recognized that there are two objectives for governor response, namely, to provide
response on an interconnection wide basis to maintain an acceptable frequency and secondly to
control frequency in island situations. The former may allow for averaging over an area of the
response requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it should be increasing with load.
The main concerns with this decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be unable to fulfill their blackstart
and restoration responsibilities, thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency response, they are likely over optimistic
and may misstate grid stability limits.
This standard would allow the industry to determine whether the decline is local or global.
Rather than implementing a complicated infrastructure or process, we would suggest that NERC
automate the calculation of frequency response by either:
Asking BAs to save their CPS-source data in a common format so a common tool can be
used (MAPP BAs and some others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring application.
The standard should employ a methodology that not only captures initial response (first few
seconds after the event) but also the sustained response until AGC action takes over
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001104
Comment Form – Proposed Frequency Response Standard
Providing visibility on where and when performance is substandard will likely initiate sufficient
action to arrest the decline in performance. Minimum performance standards could be
implemented after the industry has identified what is reasonably achievable and technically
justified.
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001105
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kenneth A. Goldsmith
Organization:
Alliant Energy
Telephone:
319-786-4167
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001106
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001107
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001108
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001109
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001110
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Version 0 of BAL-003-0, Frequency Response and Bias; or its successor
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001111
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001112
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001113
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
MAAC Staff
Lead Contact:
Albert DiCaprio
Contact Organization: PJM
Contact Segment:
2
Contact Telephone:
610-666-8854
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Bruce M. Balmat
PJM
MAAC
2
Joseph D. Willson
PJM
MAAC
2
Mark Kuras
PJM
MAAC
2
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001114
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001115
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
There is a need for governors but not for frequency response.
Governors are needed to resynchronize during restoration. But the need for a short-term frequency
response characteristic has been obviated by the pending Version1 Balancing Standard. That
standard is designed to ensure that interconnection frequency is never at such a level that the loss of
the largest contingency will cause instability or cascading outages. If the system is always in such a
state why would the instantaneous response to the loss of a single contingency add to the system
reliability?
The SAR has not provided any definitive need.
The SAR has not provided sufficient focus vis-à-vis who is responsible to meet the standard (the
generator, the BA, the Load, the RA)
This proposal has not provided any additional information concerning the need for this proposed
Standard since the last time (during the Balancing Resources and Demand consensus) that a similar
Frequency Response Requirement was overwhelming rejected by those who commented to that
proposal.
Transient frequency response has not been the target of any major public concern. The current
Version 1 Control Standard proposal provides limits on the frequency excursions that can be
controlled by system-operators and their control systems. Relays and other Protection Devices
serve to protect those time frames too short for an operator to respond to. What does this standard
add?
Comments
This SAR is not clear as to what it really is intended to mandate. Does the requestor want to create
a standard for Generator Owners to install governors? Or a standard on Generator Operators for
individuals unit governor response? Or a standard for Balancing Authorities for Area response? Or
for Reliability Authorities for Regional response? All of these are different requirements and have
different effects.
The requestor must be clear as to what is intended. To ensure that frequency doesn’t hit a relay
limit (as in the Balancing standard?) or is it to address the need for governors when synchronizing?
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001116
Comment Form – Proposed Frequency Response Standard
When does the standard apply? All times (which means that NERC can go to a unit, BA or RA to
check that some finite response is available?) Just at times when large events occur (the problem is
of course whether or not the outage is near or far from the entity being checked)? Only during test
conditions (since a unit under stress – ‘valves wide open’ has not governor response at that time –
even though it may have the greatest of responses at other times).
The requestor’s intent may be laudable but the description is no where near ready to be considered
as ‘standard material’.
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001117
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Frequency Response characteristics should be dictated by the Reliability entities as part of their
respective control services to meet the regional synchronizing requirements as well as the longer
duration control standards and of the needs of the interconnection in which they operate.
Comments
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001118
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001119
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
The SAR requestor has not provided any indication of a reliability problem. Decreasing frequency
response is in and of itself not a reliability problem - more evidence is required as to the magnitude
of the threat.
Any standard that is proposed, regarding frequency response, should consider both generator and
load response. If Load response does provide a significant portion of the frequency response (as
some people contend) then that resource must be considered in the proposal. In short the standard
must make clear whether it is for interconnection response or for balancing area response or for
individual generator response and individual load response.
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001120
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Theodore Pappas
Organization:
New York State Reliability Council
Telephone:
516-545-4011
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
ECAR
FRCC
MAAC
MAIN
MAPP
X NPCC
1 - Transmission Owners
X
2 - RTOs, ISOs, Regional Reliability Councils
3 - Load-serving Entities
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001121
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001122
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001123
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
X Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001124
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
X Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001125
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
X No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001126
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
X Yes
No
If yes, please share those comments in the space provided below.
The Standard should define the term “event” in terms of time and frequency deviation. The
frequency deviation the event must fall outside the droop deadband.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001127
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Howard Rulf
Organization:
We Energies
Telephone:
262-574-6046
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001128
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001129
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001130
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001131
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001132
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001133
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001134
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Raymond L. Vice
Organization:
Chairman of NERC Frequency Taskforce
Telephone:
(205) 257-6209
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001135
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001136
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001137
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Trends in Eastern and Western Interconnection Turbine Governor Response and primary frequency
response over the past two decades (as documented by EPRI Project RP2473-53 and Decline of
Eastern Interconnection Frequency Response by Ingleson and Nagle) as well as trends in frequency
error magnitude and variance over the past five years (as documented by the NERC Resources
Subcommittee at URL http://www.nerc.com/~filez/rs.html) indicate that significant frequency
response degradation is occurring, particularly in the Eastern Interconnection. While not yet a
crisis, these trends are indicative of significant changes in design and operational practices on the
interconnected electrical systems of North America which, if not managed intelligently, can cause
significant degradation in reliability. I strongly urge the industry to support this SAR and begin the
process of controlled management before the processes behind these trends reach crisis proportion.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001138
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001139
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
The Frequency Response Standard could be included as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the Balance Resources and Demand Standard
address frequency, they obviously must work together closely. If they are crafted, as originally
intended by the Frequency Taskforce, to utilize the same CPS database, there may be savings in
administrative overhead in putting them both in the same standard.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001140
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
I personally believe that the industry will be exposing the interconnected electrical systems of
North America to a significant degree of reliability risk if a Frequency Response Standard similar
to the one proposed by this SAR is not adopted. This risk can be mitigated somewhat by the
turbine governor requirements of Standard MOD-014-1 from the Phase III/IV Standards SAR, if
passed. However, the risk can be managed properly (and in the most economical manner) only on
an interconnection/balancing authority basis, not on an individual generator basis as required by
Standard MOD-014-1.
What is important is that the interconnections maintain sufficient frequency responsive resources to
ensure the stability of interconnection frequency under first contingency conditions. The
Frequency Response Standard, as proposed, sets requirements for the management and deployment
of frequency responsive resources that achieve this goal without unduly interfering with the on
going operation of the interconnection. I strongly urge the industry to support this SAR.
RLV
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001141
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001142
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission, Operations, Planning and EMS divisions
Lead Contact:
Marc Butts
Contact Organization: Southern Company
Contact Segment:
1
Contact Telephone:
205-257-4839
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Raymond Vice
Southern Company Services
SERC
1
Steve Corbin
Southern Company Services
SERC
1
Jim Viikinsalo
Southern Company Services
SERC
1
Jim Griffith
Southern Company Services
SERC
1
Doug McLaughlin
Southern Company Services
SERC
1
Monroe Landrum
Southern Company Services
SERC
1
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001143
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001144
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Trends in Eastern and Western Interconnection Turbine Governor Response and primary frequency
response over the past two decades (as documented by EPRI Project RP2473-53 and Decline of
Eastern Interconnection Frequency Response by Ingleson and Nagle) as well as trends in frequency
error magnitude and variance over the past five years (as documented by the NERC Resources
Subcommittee at URL http://www.nerc.com/~filez/rs.html) indicate that significant frequency
response degradation is occurring, particularly in the Eastern Interconnection. While not yet a
crisis, these trends are indicative of significant changes in design and operational practices on the
interconnected electrical systems of North America which, if not managed intelligently, can cause
significant degradation in reliability. We strongly urge the industry to support this SAR and begin
the process of controlled management before the processes behind these trends reach crisis
proportion.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001145
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001146
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
The Frequency Response Standard could be included as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the Balance Resources and Demand Standard
address frequency, they obviously must work together closely. If they are crafted, as originally
intended by the Frequency Taskforce, to utilize the same CPS database, there may be savings in
administrative overhead in putting them both in the same standard.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001147
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
We believe that the industry will be exposing the interconnected electrical systems of North
America to a significant degree of reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be mitigated somewhat by the turbine
governor requirements of Standard MOD-014-1 from the Phase III/IV Standards SAR, if passed.
However, the risk can be managed properly (and in the most economical manner) only on an
interconnection/balancing authority basis, not on an individual generator basis as required by
Standard MOD-014-1.
What is important is that the interconnections maintain sufficient frequency responsive resources to
ensure the stability of interconnection frequency under first contingency conditions. The
Frequency Response Standard, as proposed, sets requirements for the management and deployment
of frequency responsive resources that achieve this goal without unduly interfering with the on
going operation of the interconnection. We strongly urge the industry to support this SAR.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001148
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001149
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization
Lead Contact:
Lawrence R Larson, P E
Contact Organization: Otter Tail Power Company
Contact Segment:
2
Contact Telephone:
218/739-8572
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Lawrence R Larson, P E
Otter Tail Power Company
MRO
2
Al Boesch
Nebraska Public Power District
MRO
2
Terry Bilke
Midwest ISO
MRO
2
Robert Coish
Manitoba Hydro
MRO
2
Dennis Florom
Lincoln Electric System
MRO
2
Ken Goldsmith
Alliant Energy
MRO
2
Todd Gosnell
Omaha Public Power District
MRO
2
Wayne Guttormson
Saskatchewan Power
Corporation
MRO
2
Jim Maenner
WPS Resources
MRO
2
Tom Mielnik
MidAmerican Energy
MRO
2
Darrick Moe
Western Area Power
Administration
MRO
2
Joe Knight
Midwest Reliability Organization
MRO
2
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001150
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001151
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
We agree (with qualifications). Any new standards on frequency response need not and should not
be onerous (identifying BAs noncompliant with less than average response or some un-validated
norms).
The standard should provide the process for a sound calculation of frequency response and bias
(both fixed and variable).
There may be valid reasons why a BA is below observed norms in response. It may meet most of
its obligations with schedules.
Rather than generate an automatic non-compliance when response is below some benchmark, the
standard should require an internal review that ensures governors are working as designed, that the
BA knows which resources are frequency responsive (so the information can be included in
restoration plans), whether governors can be put in more responsive modes during disturbances,
etc.
The standard should have some requirements on generators if the BA is not providing the response
outlined in the standard (governors should be working as designed).
The standard should also track Interconnection response over time and identify a target response
(different for each Interconnection). NERC or NAESB will want to look at how this is allocated to
BAs and generators.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001152
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001153
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Version 0 (BAL-003-0 — Frequency Response and Bias) or its successor is a logical place.
Depending on the outcome of the V1 Balance Resource and Demand standard, it could reside there.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001154
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
We appreciate the opportunity to comment and believe there is a need for such a standard.
Published studies show frequency response is declining when it should be increasing with load.
Because there is no process in place to track BA or Interconnection response, we don’t know
whether the decline is local or global. Primary concerns with this decreasing performance in
primary control:
1. There may be areas unable to withstand severe disturbances.
2. Following a grid separation or collapse, control areas may be unable to fulfill their
blackstart and restoration responsibilities, thereby becoming a burden to neighbors.
3. Because engineering models use theoretical frequency response, they are likely
overoptimistic and may misstate grid stability limits.
Rather than putting in a complicated infrastructure or process, we would suggest that NERC
automate the calculation of frequency response by either:
• Asking BAs to save their CPS-source data in a common format so a common tool can be used
(MAPP BAs and some others use a common tool that can calculate frequency response with
CPS-source data).
• Embed the calculation in the NERC ACE-monitoring application.
The standard will need to acknowledge the large variability in individual responses at each BA due
to coincident load changes and amount and mix of generation. In addition, smaller
Interconnections likely need greater response.
Refer to our earlier comments the structure of the standard (where lower amounts of response
trigger an internal assessment rather than assessment non-compliance). BAs (and ultimately
generators) would only be initially non-compliant if their response was low AND they failed to
perform the reliability assessment.
Providing visibility on where and when performance is substandard will likely initiate sufficient
action to arrest the decline in performance. Minimum performance standards could be
implemented after the industry has identified what is reasonably achievable and technically
justified.
The standard should not preclude market solutions to providing frequency response, but such
arrangements would need to be looked at closely to be sure they fulfill reliability needs.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001155
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Peter Burke [on behalf of ATC’s John Ratajczyk ([email protected], 262-506-6769)]
Organization:
American Transmission Company
Telephone:
262-506-6863
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001156
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001157
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001158
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Based on the NERC white paper Frequency Response Standard Whitepaper dated April 6, 2004
that was prepared by the Frequency task Force of the NERC Resources Subcommittee, it would
appear that the decline in frequency response of both the Eastern and Western Interconnections is a
reliability concern. As a transmission provider, however, there is probably little that can be done
other than make sure that governor response and load modeling can be made as accurate as
reasonably possible in conducting dynamic simulations and be aware of this issue in studying
existing as well as new generating facilities. The control area, generation operators and turbinegenerator manufacturers need guidance provided as to their responsibilities and obligations
regarding frequency response. Changes in the load characteristics (e.g. fewer large motors,
variable speed drives, etc ) over time, plus changes in reserve sharing practices brought on by
deregulation and competition are and will affect load response to frequency excursions. The type
of generation (e.g. combustion turbine units, combined-cycle units) being interconnected to the
system as well as the operation of the governors (e.g. blocked or improper settings) and turbines
(e.g. sliding pressure, boiler-follower, etc.) of existing generators have a significant effect on the
system frequency response.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001159
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
The Frequency control standard needs to address levels required for reliability, be consistent and
verifiable, and be simple to monitor for compliance purposes.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001160
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
II.B.S1M5, Test results of speed/load governor controls.
Comments
It may be appropriate to include this standard in the Phase III/IV standards that address speed/load
governor controls (II.B.S1M5, Test results of speed/load governor controls). The three following
customer demand related standards would be helpful in defining load response to frequency
excursions:
II.E.S1.M1, Plans for the evaluation and reporting of voltage & Frequency characteristics of
customer demands.
IIE.S1.M2 Documentation or requirements for determining dynamic characteristics of customer
demands.
II.E.S1.M3, Customer (dynamic) demand data.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001161
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001162
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
X
5 - Electric Generators
X
6 - Electricity Brokers, Aggregators, and Marketers
X SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001163
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Co. Generation
Lead Contact:
Roman Carter
Contact Organization: Southern Co. Generation
Contact Segment:
6
Contact Telephone:
205.257.6027
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Roman Carter
Southern Generation
SERC
6
Tony Reed
Southern Generation
SERC
6
Joel Dison
Southern Generation
SERC
6
Lucius Burris
Southern Generation
SERC
6
Lloyd Barnes
Southern Generation
SERC
6
Clifford Shepard
Southern Generation
SERC
6
Terry Crawley
Southern Generation
SERC
5
Roger Green
Southern Generation
SERC
5
Tom Higgins
Southern Generation
SERC
5
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001164
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001165
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Trends in Eastern and Western Interconnection Turbine Governor Response and primary frequency
response over the past two decades (as documented by EPRI Project RP2473-53 and Decline of
Eastern Interconnection Frequency Response by Ingleson and Nagle) as well as trends in frequency
error magnitude and variance over the past five years (as documented by the NERC Resources
Subcommittee at URL http://www.nerc.com/~filez/rs.html) indicate that frequency response
degradation is occurring, particularly in the Eastern Interconnection. While not yet a crisis, these
trends are indicative of significant changes in design and operational practices on the
interconnected electrical systems of North America which, if not managed intelligently, can cause
degradation in reliability. We support this SAR in an effort to begin the process of controlled
management before the processes behind these trends reach crisis proportion.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001166
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001167
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
The Frequency Response Standard could be included as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the Balance Resources and Demand Standard
address frequency, they obviously must work together closely. If they are crafted, as originally
intended by the Frequency Taskforce, to utilize the same CPS database, there may be savings in
administrative overhead in putting them both in the same standard.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001168
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
It is believed that the industry will be exposing the interconnected electrical systems of North
America to a significant degree of reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be mitigated somewhat by the turbine
governor requirements of Standard MOD-014-1 from the Phase III/IV Standards SAR, if passed.
However, the risk can be managed properly (and in the most economical manner) on an
interconnection/Balancing Authority basis, not on an individual generator basis as required by
Standard MOD-014-1.
The governor response in MW for generators is not just dependent on the governor droop and
dead-band settings, but on the design of the plant control system (sliding pressure boiler, nuclear
pressurized water reactor, etc.). For example, nuclear plant operators must control reactivity
changes in the core and generally cannot allow external controls to increase or decrease power
levels on demand. This standard should take such factors into account and address frequency &
MW response at the Balancing Authority level, not at the individual generator level.
What is important is that the interconnections maintain sufficient frequency responsive resources to
ensure the stability of interconnection frequency under first contingency conditions. The
Frequency Response Standard, as proposed, sets requirements for the management and deployment
of frequency responsive resources that achieve this goal without unduly interfering with the on
going operation of the interconnection. We support this SAR.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001169
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
Email:
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001170
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC CP9, Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization: Northeast Power Coordinating Council
Contact Segment:
2
Contact Telephone:
212-840-1070
Contact Email:
[email protected]
Additional Member Name
Additional Member Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Kathleen Goodman
ISO-New England
NPCC
2
Al Adamson
New York State Reliability Council
NPCC
2
Bob Pelligrini
United Illuminating
NPCC
1
David Kiguel
Hydro One Networks, (Ontario)
NPCC
1
Peter Lebro
US National Grid
NPCC
1
Roger Champagne
TransEnergie, (Quebec)
NPCC
1
Brian Hogue
NPCC
NPCC
2
Guy Zito
NPCC
NPCC
2
Khaqan Khan
The IESO, (Ontario)
NPCC
2
Michael Potisnak
ISO-NewEngland
NPCC
2
Greg Campoli
New York ISO
NPCC
2
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001171
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001172
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001173
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
The applicability of this Standard to the LSE should be considered.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001174
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001175
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
CHANGE
This SAR is proposed to develop a standard to measure sub-minute responses to changes in
frequency and to set minimum acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure sub-minute responses to changes in
frequency and to set minimum acceptable responses to these system events.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001176
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Howard F. Illian
Organization:
Energy Mark, Inc.
Telephone:
847-910-9510
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001177
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001178
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001179
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
There is a reliability need but it is not an immediate reliability need for all of the interconnections.
The amount of Frequency Response on the Texas Interconnection is close to the minimum
acceptable amount, and therefore, there is an immediate need for a FRS on the Texas
Interconnection. On the Western Interconnection, the WECC keeps close tabs on Frequency
Response and takes immediate action when a problem arises with frequency response on that
interconnection. Although there is no immediate need for a Frequency Response Standard on the
Western Interconnection at this time, the observed reductions in Frequency Response on that
interconnection make this issue an ongoing concern. Finally, there is no current need for a
Frequency Response Standard on the Eastern Interconnection because current Frequency Response
is adequate. However, it takes significant time to develop an effective standard and put it in place.
The Balancing Resources and Demand Standard is entering its fourth year of development with
expectations of at least another year before implementation. A Frequency Response Standard
would be expected to take a similar period to develop. That means that it will be at least 2010
before a new FRS would be put in place. There is no question that adequate Frequency Response
is required for reliability. There is no question that Frequency Response on the Eastern
Interconnection is declining. There are two paths of action available; 1) Wait until adequate
Frequency Response causes reliability problems and then begin the five year process to develop a
standard; 2) Begin development of a FRS and determine the final need for implementation during
the five year development process. I would rather have a standard that requires measurement that
does not result in enforcement action, and therefore, has no effect on operations, than not have a
standard when there are definite reliability problems. It will be much easier to implement a
standard for Frequency Response before reliability problems occur than to implement a standard
after reliability problems occur. NERC should develop a Frequency Response Standard and
continue to investigate the need for the standard during its development.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001180
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Planning standards are not enough by themselves. Without continuous measurement, there can be
no assurance that those responsible for meeting the reliability need for Frequency Response are
fulfilling those responsibilities. Only a Frequency Response Standard that continuously measures
response can insure that the response is available when required.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001181
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Frequency Response is closely related to the Frequency Bias used in the Balancing Resources and
Demand Standard and therefore this standard should be included as an addition to that standard. If
it is not included in the BRD Standard, a separate standard would require coordination between the
two standards. This would make the process of updating the standards more complex.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001182
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
NERC has the responsibility of maintaining reliability on the North American Interconnections.
NERC cannot perform that function effectively if it waits for reliability problems to become
apparent in system operations before it takes actions to address those problems. NERC must be a
forward looking organization that anticipates future reliability problems and takes actions to
resolve those problems before they affect interconnection reliability.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001183
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Terry Bilke
Organization:
Midwest ISO
Telephone:
317-249-5463
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001184
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Page 2 of 7
Region*
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001185
Comment Form – Proposed Frequency Response Standard
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001186
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
These are my individual comments as a member of the NERC Resources subcommittee and not
those of representing any organization.
There is a reliability need for a light-handed standard that allows us to do a better job of ensuring
response is available when required. As some entities might comment, there is adequate response
in all interconnections during “system normal” conditions. The problem is what occurs during
major disturbances and restoration.
A primary reason the industry needs to do a better job of tracking frequency response is the fact
that response is declining when it should actually be increasing with load and generation growth.
The standard should not be structured such that it finds BAs noncompliant if response is below
average or if response is low for a given event. Frequency response at the BA level is extremely
variable as the measure is mingled with load fluctuation.
The standard should guide a technically sound calculation of response at the BA level and track
interconnection performance over time to enable informed decisions.
If a BA performs significantly below an Interconnection norm, the standard should require the BA
do an internal assessment of its key generation to verify governors are working as designed and
that there will be frequency responsive resources for disturbances and restoration.
If Interconnection response significantly changes over time, the standard should be reevaluated.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001187
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
I agree, with some qualification. While the standard shouldn’t preclude market solutions, I don’t
think it must enable a market as the scope implies. A little more clarity on the goals of the standard
is needed.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001188
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
It’s not a major issue. It appears it should be include in the Version 0 (BAL-003-0 — Frequency
Response and Bias).
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001189
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Thanks for the opportunity to comment. I hope the SAC puts all comments in perspective. We are
in a period where the industry is reluctant to adopt new standards that generate extra work and
compliance exposure. The reliability of the Interconnections can benefit with minimal impact to
most BAs with a light-handed standard.
Rather than implementing a complicated process, why not embed most of the effort in the NERC
ACE-monitoring application? Only those BAs with unusually low response would need to drill
down and do an internal assessment to determine their ability to withstand disturbances and
whether they have responsive resources for blackstart.
Knowing where and when performance is substandard will likely arrest the decline in performance.
Minimum performance standards could be implemented once the industry has identified what is
reasonably achievable and technically justified.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001190
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
John Horakh – 02-15-2005
Organization:
MAAC
Telephone:
609-625-6014
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
ECAR
1 - Transmission Owners
X
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
X
MAAC
3 - Load-serving Entities
MAIN
4 - Transmission-dependent Utilities
MAPP
5 - Electric Generators
NPCC
SERC
SPP
WECC
NA - Not
Applicable
6 - Electricity Brokers, Aggregators, and Marketers
7 - Large Electricity End Users
8 - Small Electricity End Users
9 - Federal, State, Provincial Regulatory or other Government Entities
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001191
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001192
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001193
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
X
Yes
No
If no, please explain in the space provided below.
Comments
There may be a reliability need in the near future. The Whitepaper does an excellent job of making
that case. For the purpose of commenting on a SAR that has not yet produced a proposed Standard,
I can give it the benefit of the doubt and say yes, there is reliability need.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001194
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
X
No
If no, please explain in the space provided below.
Quoted from the SAR (with corrections): This SAR is proposed to develop a standard to measure
sub-minute responses to changes in frequency and to set minimum acceptable responses of the
system to these events. Also quoted: The measurement selected must be accurate and, to the extent
practical, easy to implement. This seems more like a research project than a request for a standard.
There is no mention of any possible measurements that might be in the standard. I’m afraid that
proceeding with such a vague idea of a measurement will lead the SAR or later Standard to become
bogged down with research and field testing even more so than the Balance Load and Demand
Standard. And Balance Load and Demand did have definite measurements in mind, thereby not
requiring much research, mainly field testing. Come back with a SAR after the research is done, or
at least started.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001195
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
X
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Adding this requirement to another standard would only slow down the progress of both.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001196
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
X
Yes
No
If yes, please share those comments in the space provided below.
It appears Frequency Response is an accepted term used for this requirement, and therefore might
be difficult to change. However, Frequency Response is not a very good description of the
requirement. A term such as Transient Generator and Load Response would be more
descriptive.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001197
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathy Davis
Organization:
Tennessee Valley Authority
Telephone:
423-751-6172
Email:
[email protected]
NERC Region
ERCOT
Registered Ballot Body Segment
x
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
x SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001198
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Electric System Operations
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
Segment*
Larry Akens
TVA
SERC
1
Mitch Needham
TVA
SERC
1
Chuck Feagans
TVA
SERC
1
Edd Forsythe
TVA
SERC
1
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001199
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001200
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
x Yes
No
If no, please explain in the space provided below.
Comments
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001201
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
x No
If no, please explain in the space provided below.
If the purpose is to purchase frequency response, then the Market Operator needs to be includes.
Will this be considered an Ancillary Service?
Others that may need to be involved are Transmission Service Provider, Generator Owner,
Planning Authority and Resource Planner.
Applicability should include #2
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001202
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
x No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001203
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
x No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001204
Comment Form – Proposed Frequency Response Standard
COMMENT FORM
Proposed Frequency Response Standard
This form is to be used to submit comments on the proposed Frequency Response Standard
Authorization Request. Comments must be submitted by February 17, 2005. You may submit the
completed form by emailing it to: [email protected] with the words “Frequency Response SAR
Comments” in the subject line. If you have questions please contact Mark Ladrow at
[email protected] or by telephone at 609-452-8060.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO
A DATABASE AND IT IS THEREFORE IMPORTANT TO ADHERE TO THE
FOLLOWING REQUIREMENTS:
DO:
Do enter text only, with no formatting or styles added.
Do use punctuation and capitalization as needed (except quotations).
Do use more than one form if responses do not fit in the spaces provided.
Do submit any formatted text or markups in a separate WORD file.
DO NOT: Do not insert tabs or paragraph returns in any data field.
Do not use numbering or bullets in any data field.
Do not use quotation marks in any data field.
Do not submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Robert Blohm
Organization:
Telephone:
609 585 5451
Email:
[email protected]
NERC Region
Registered Ballot Body Segment
ERCOT
1 - Transmission Owners
ECAR
2 - RTOs, ISOs, Regional Reliability Councils
FRCC
3 - Load-serving Entities
MAAC
MAIN
MAPP
NPCC
4 - Transmission-dependent Utilities
5 - Electric Generators
6 - Electricity Brokers, Aggregators, and Marketers
SERC
7 - Large Electricity End Users
SPP
8 - Small Electricity End Users
WECC
9 - Federal, State, Provincial Regulatory or other Government Entities
NA - Not
Applicable
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001205
Comment Form – Proposed Frequency Response Standard
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact Email:
Additional Member Name
Additional Member Organization
Region*
* If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
Segment*
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001206
Comment Form – Proposed Frequency Response Standard
Background Information:
Posted for comments is the first posting of the Frequency Response SAR. The Frequency Task
Force of the NERC Resources Subcommittee has identified the transient frequency response
characteristics as degrading over time and potentially threatening the reliability of the bulk electric
system. This Standard Authorization Request was initiated to address this concern by developing a
standard to specify a measuring convention for frequency response and by specifying a minimum
required response to system disturbances based on the convention.
The requestor would like to receive industry comments on this SAR and to obtain the input of the
industry prior to determining the final scope and requirements of the SAR. Accordingly, we
request your comments included on this form, emailed with the subject “Frequency Response SAR
Comments” by February 17, 2005.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001207
Comment Form – Proposed Frequency Response Standard
Question 1: Do you agree there is a reliability need for a specifying the quality and quantity
of frequency response?
Yes
No
If no, please explain in the space provided below.
Comments
The CPS1 equation is a single equation in two variables, primary (governor) response and
secondary response. Two variables require two equations in order to have a unique solution. That
second equation does not currently exist and must be the proposed Frequency Response standard
that pins down the value of primary (governor) response. Currently, the single CPS1 equation
allows any Balancing Authority an infinity of solutions for any given CPS1 value. Accordingly,
Balancing Authorities have been tending to reduce expensive primary response and increase
cheaper secondary response (AGC, regulation, load following) to achieve a given CPS1 score,
which is an average over time. The result has been a halving of system bias in the Eastern
Interconnection and the rest of the case made for the standard in the supporting White Paper.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001208
Comment Form – Proposed Frequency Response Standard
Question 2: Do you agree with the scope and applicability of the proposed standard?
Yes
No
If no, please explain in the space provided below.
Comments
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001209
Comment Form – Proposed Frequency Response Standard
Question 3: Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Yes
No
If yes, please identify the location you believe would be the most appropriate for the proposed
standard.
Comments
The SAR acknowledges that the proposed Standard not only is complementary to the Balancing
Resources and Demand Standard, but also must be coordinated with that Standard. The two
standards could be combined. But that is insufficient reason to oppose development of a separate
Frequency Response Standard. Moreover, combining the standards would reverse the great
progress made in consensus on the Balancing Resources and Demand Standard.
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001210
Comment Form – Proposed Frequency Response Standard
Question 4: Do you have any additional comments regarding the SAR that you believe should
be addressed?
Yes
No
If yes, please share those comments in the space provided below.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001211
Consideration of Comments on First Draft of Frequency Response SAR
Background:
The Frequency Response SAR drafting team thanks all commenters who submitted comments on the first
draft of the Frequency Response SAR. The SAR was posted for comment from January 17 – February
17, 2005. The SAR drafting team asked stakeholders to provide feedback on the SAR through a special
SAR Comment Form. There were 30 sets of comments.
Based on the comments received, the drafting team has revised the SAR and is reposting it for an
additional 30-day comment period
In this ‘Consideration of Comments’ document, stakeholder comments have been organized so that it is
easier to see the summary of changes being requested of the SAR. All comments received on the first
draft of the Frequency Response SAR can be viewed in their original format at:
ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Frequency_Response_SAR_Comments_02_17_05.pdf
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Cauley at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Process Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
Page 1 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001212
Consideration of Comments on First Draft of Frequency Response SAR
Index to Questions, Comments and Responses:
1.
Do you agree there is a reliability need for specifying the quality and quantity of frequency
response?............................................................................................................................................ 3
2.
Do you agree with the scope and applicability of the proposed standard?....................................... 16
3.
Do you believe these standards are more appropriately additions to existing standards as opposed
to creating new standards? ............................................................................................................... 22
4.
Do you have any additional comments regarding the SAR that you believe should be addressed? 28
Page 2 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001213
Consideration of Comments on First Draft of Frequency Response SAR
1. Do you agree there is a reliability need for specifying the quality and quantity
of frequency response?
Summary Consideration: Most commenters agreed that there is a reliability need to specify
the quality and quantity of frequency response.
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
No
Comment
9
There is a need for governors but not for frequency response.
Governors are needed to resynchronize during restoration. But
the need for a short-term frequency response characteristic has
been obviated by the pending Version1 Balancing Standard. That
standard is designed to ensure that interconnection frequency is
never at such a level that the loss of the largest contingency will
cause instability or cascading outages. If the system is always in
such a state why would the instantaneous response to the loss of
a single contingency add to the system reliability?
The SAR has not provided any definitive need.
The SAR has not provided sufficient focus vis-à-vis who is
responsible to meet the standard (the generator, the BA, the
Load, the RA)
This proposal has not provided any additional information
concerning the need for this proposed Standard since the last
time (during the Balancing Resources and Demand consensus)
that a similar Frequency Response Requirement was
overwhelming rejected by those who commented to that proposal.
Transient frequency response has not been the target of any
major public concern. The current Version 1 Control Standard
proposal provides limits on the frequency excursions that can be
controlled by system-operators and their control systems. Relays
and other Protection Devices serve to protect those time frames
too short for an operator to respond to. What does this standard
add?
Comments
This SAR is not clear as to what it really is intended to mandate.
Does the requestor want to create a standard for Generator
Owners to install governors? Or a standard on Generator
Operators for individuals unit governor response? Or a standard
for Balancing Authorities for Area response? Or for Reliability
Authorities for Regional response? All of these are different
requirements and have different effects.
The requestor must be clear as to what is intended. To ensure
that frequency doesn’t hit a relay limit (as in the Balancing
standard?) or is it to address the need for governors when
synchronizing?
When does the standard apply? All times (which means that
NERC can go to a unit, BA or RA to check that some finite
response is available?) Just at times when large events occur
(the problem is of course whether or not the outage is near or far
from the entity being checked)? Only during test conditions (since
a unit under stress – ‘valves wide open’ has not governor
response at that time – even though it may have the greatest of
Page 3 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001214
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
responses at other times).
The requestor’s intent may be laudable but the description is no
where near ready to be considered as ‘standard material’.
Response: The drafting team (Resources Subcommittee Frequency Task Force) attempted to answer
many of the questions raised by the commenters in the Frequency Response Standard Whitepaper. We
agree that the standard needs to be clear to who and when it would apply and this is addressed in the
revised SAR. While the Interconnections may have sufficient frequency response for normal operations,
we don’t know how this response is dispersed and at what point it will pose a reliability risk. A primary
purpose of this standard is to collect information so informed decisions can be made before there is a
problem.
We disagree that the Balance Resources and Demand (BRD) standard is sufficient for all operating
states. The BRD addresses steady state and fully interconnected conditions. Refer to “A New Thermal
Governor Modeling Approach in the WECC” by Les Pereira, John Undrill, Dmitry Kosterev, Donald
Davies, and Shawn Patterson. Also, keep in mind that response has continued to decline since the last
published study, even though it should be increasing with load growth.
As you request, the draft standard addresses who is required to meet the standard (BA). The standard
will be designed such that a BA can mirror the metrics within its boundaries (evaluate generators and
LSEs) if they so choose.
The standard is not intended to establish a large set of arbitrary requirements, but will establish the
framework to collect the information to make informed engineering decisions.
The revised SAR clarifies what is expected.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
NERC should not involve itself in the development of these
standards and should allow individual interconnections to address
frequency response issues independently. For example, the
WECC is currently working on standards that will address this
concern. They will be tailored to the specific requirements of this
interconnection and will provide the best possible solution to the
problem. There may be a need to specify frequency response
requirements within some interconnections; however, it is not
necessary, or most effective for them to be defined at the NERC
level.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and, as envisioned, the proposed standard would accommodate
Interconnection differences both in amounts of response and methodology in calculating response. The
standard would identify technical and engineering principles that should be met to calculate and evaluate
the amount and distribution of frequency response within each Interconnection. The drafting team
believes that stakeholders would prefer the assurance of knowing that NERC is providing oversight to
ensure that all Interconnections have a technically sound basis for the development of respective
frequency response requirements.
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
9
The FRCC does not support the development of a Frequency
Response Standard at this time. A standard for each
Interconnection, although informative would be unenforceable as
far as identifying short term, frequency response deficient, entities
or areas. As such measurability and compliance by the relevant
entities would be all but impossible. As far as an Interconnection
allocation program for frequency response, we feel that the
“apparent” decline in response is not significant enough to
warrant a standard at this time and we would require additional
details of how such a plan would be implemented and the
potential economic impacts on the Regions that would be
Page 4 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001215
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
associated with that plan.
Response: The standard as envisioned does not mandate a specific amount of frequency response.
With regard to the “apparent” decline in frequency response, the most widely published report (Ingleson
and Nagle, 1999) documented a change in Eastern Interconnection response from 3750MW/0.1Hz in
1994 to 3390MW/0.1Hz in 1998. The Resources Subcommittee evaluation of 44 events in 2005 showed
an average frequency response well below 3000MW/0.1Hz. Theoretically, response should be increasing
over time with increasing load and generation in an Interconnection. One of the primary reasons for the
standard is to enable a better analysis of response and also enable informed decisions. As envisioned,
the standard will provide a fairly simple methodology to verify compliance.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT
(2)
P. Henderson – IESO
(2)
P. Brandien – ISO-NE
(2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
9
9
We agree in general that there is a reliability need to have
frequency response, particularly during disturbances, islanding
and restoration. The standard should provide the process for a
technically sound calculation of frequency response and bias
(both fixed and variable).
Any new standards on frequency response need not and should
not be onerous by finding BAs noncompliant with response less
than average or below some un-validated norms.
If performance is significantly less than an Interconnection norm,
the standard should not trigger an automatic non-compliance. In
these situations the BA should perform an internal
review/assessment that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be triggered to be more
responsive during disturbances, etc and satisfy the
Interconnection requirement. If the Interconnection requirement is
not met within a reasonable timeframe then the BA should be
deemed as non-compliant.
When required, the validation of governor performance could be
achieved either through online monitoring in an EMS or periodic
testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that response is highly variable eventto-event based on simultaneous load changes.
The standard should acknowledge the differing Interconnection
requirements (smaller Interconnections need greater response).
The standard should also track Interconnection and BA areas
response over time (years) and be reevaluated as performance
changes.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
Page 5 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001216
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes No
Comment
an analysis if response were measurably below the norm (this detail has been added to the detailed
description in the SAR).
There is another standard under development, (Phase III & IV MOD-027 - Verification and Status of
Generator Frequency Response) that requires Generator Owners to verify that their governors are
working as designed.
The standard would accommodate the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that could calculate the
BA’s performance to the standard.
The SAR was also changed to reflect the suggestions to accommodate:
•
Both fixed and variable bias.
•
Cases where a specific unit (e.g. nuclear) is prohibited from providing frequency response.
•
Differing Interconnection needs.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
Frequency response provided by speed governors and loads
helps to prevent load shedding and generator trips at significant
frequency excursions caused by sudden active power
mismatches in the systems. Without a sufficient frequency
response emerging during the first seconds after a frequency
disturbance, there is a danger of further cascading development
or frequency instability and system collapse cased by
underfrequency generator trips. It has been already noted that
insufficient frequency response in some parts of an
Interconnection may cause certain temporary redistribution of
power flows and reduce stability margins after frequency
disturbances that may limit the OTC on critical paths within the
Interconnection. It has been also observed that insufficient
frequency response may cause a weaker frequency recovery that
bears a greater risk of system collapse at subsequent frequency
disturbances. Therefore, frequency response is definitely a
reliability issue that needs to be addressed by a NERC standard.
Response: The Resources Subcommittee Frequency Task Force agrees that there are several issues
that must be addressed in the standard or in supporting business practices. As envisioned, the proposed
standard would not be prescriptive with regard to “how much” and “where” the response is carried.
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Manitoba Hydro , from a reliability perspective, supports the idea
of specifying the quantity and quality of frequency response and
incorporating these elements in a Standard. However, the
development of this standard should not be rushed since the
evidence provided in the Standard Authorization Request form
and in the Frequency Response Standard White paper shows
that current frequency response and projected frequency
response trends do not pose a significant potential for
compromising system reliability and for major under-frequency
load shedding to occur in the near term.
Also in the section of the white paper which examines “frequency
response standard considerations”, a broad scope and outline is
given, more detail is required especially regarding methods of
ensuring compliance.
In paragraph 2, page 9 of the white paper where the current
frequency response of the Eastern Interconnection is stated as
3100 MW/0.1 Hz with a standard deviation of 1870 MW/0.1 Hz
and the statement is made that “the fact that an under-frequency
Page 6 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001217
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
event has not happened yet is only coincidence” requires much
more detailed information regarding the origin and calculations of
these numbers before these assumptions can be made. Could it
be that instead of a frequency response closer to 1230MW/ 0.1
Hz it is actually practically closer to 3100 MW/ 0.1 Hz or even
4970 MW/ 0.1 Hz most of the time?
One understandable major concern addressed in the white paper
is the response of combined-cycle units to frequency decline and
the fact that due to a drop in combustion air volume their output
may actually decrease with a drop in frequency or even result in
unit tripping. Also there was concern with the possibility that
larger amounts of these types of units will be installed on the
system thereby potentially increasing the decline in frequency
response rate from 70 MW/ 0.1 Hz /Year (Eastern
Interconnection) .
It is also mentioned (on page 10) that with proper tuning
combined cycle units can provide correct frequency response.
Maybe part of the focus should be on finding ways of enforcing
the Current Requirements (Page 14) and including specific
frequency response requirements for combined-cycle units.
Response: The Resources Subcommittee Frequency Task Force agrees that the standard should not
rush to a decision on the amount and location of frequency response, but should set the framework for
making informed decisions. Frequency response is needed for more than protection against UFLS.
Response is also needed during disturbances and restoration. With regard to “current requirements”, the
Whitepaper listed what existed in NERC Policy, mostly as guides. There is very little in the V0 Standards
regarding governors or frequency response. We agree that the standard should not impose
unreasonable costs to demonstrate compliance. We agree that frequency response should be monitored
both at the BA and Interconnection level.
Characterizing how frequency response changes under varying interconnection load and unit
commitment conditions will be addressed by a sampling methodology.
The drafting team is pursuing the addition of functionality in the “NERC –ACE monitoring application” that
will identify generator trips and automate the calculation of Interconnection frequency response.
Evidence to date indicates that frequency response declines significantly during light load periods, even
though the exact mechanism for this is not well defined. Most of the major frequency excursions
experienced in the Eastern Interconnection have occurred during the shoulder period of the year during
either the early morning or late evening periods.
Regarding the last comment, there currently are no governor or frequency response requirements for
generators.
Energy Mark, Inc. (8)
Howard Illian
9
There is a reliability need but it is not an immediate reliability
need for all of the interconnections. The amount of Frequency
Response on the Texas Interconnection is close to the minimum
acceptable amount, and therefore, there is an immediate need for
a FRS on the Texas Interconnection. On the Western
Interconnection, the WECC keeps close tabs on Frequency
Response and takes immediate action when a problem arises
with frequency response on that interconnection. Although there
is no immediate need for a Frequency Response Standard on the
Western Interconnection at this time, the observed reductions in
Frequency Response on that interconnection make this issue an
ongoing concern. Finally, there is no current need for a
Frequency Response Standard on the Eastern Interconnection
because current Frequency Response is adequate. However, it
Page 7 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001218
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
takes significant time to develop an effective standard and put it
in place. The Balancing Resources and Demand Standard is
entering its fourth year of development with expectations of at
least another year before implementation. A Frequency
Response Standard would be expected to take a similar period to
develop. That means that it will be at least 2010 before a new
FRS would be put in place. There is no question that adequate
Frequency Response is required for reliability. There is no
question that Frequency Response on the Eastern
Interconnection is declining. There are two paths of action
available; 1) Wait until adequate Frequency Response causes
reliability problems and then begin the five year process to
develop a standard; 2) Begin development of a FRS and
determine the final need for implementation during the five year
development process. I would rather have a standard that
requires measurement that does not result in enforcement action,
and therefore, has no effect on operations, than not have a
standard when there are definite reliability problems. It will be
much easier to implement a standard for Frequency Response
before reliability problems occur than to implement a standard
after reliability problems occur. NERC should develop a
Frequency Response Standard and continue to investigate the
need for the standard during its development.
Response: The Resources Subcommittee Frequency Task Force agrees with the comments that the
standard should initially focus on measuring the amount of response and not impose restrictions on
current operations. As envisioned, the proposed standard would identify a consistent, objective
calculation of frequency response The standard would require regional and local analyses when BAs
have low response. This way, informed technical decisions can be made prior to reaching a point where
reliability is truly threatened.
MAAC (2)
John Horakh
9
There may be a reliability need in the near future. The white
paper does an excellent job of making that case. For the purpose
of commenting on a SAR that has not yet produced a proposed
Standard, I can give it the benefit of the doubt and say yes, there
is reliability need.
Response: The Resources Subcommittee Frequency Task Force appreciates your support and agrees
that there is a reliability need for this proposed standard.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
9
We agree (with qualifications). Any new standards on frequency
response need not and should not be onerous (identifying BAs
noncompliant with less than average response or some unvalidated norms).
The standard should provide the process for a sound calculation
of frequency response and bias (both fixed and variable).
There may be valid reasons why a BA is below observed norms
in response. It may meet most of its obligations with schedules.
Rather than generate an automatic non-compliance when
response is below some benchmark, the standard should require
Page 8 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001219
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
Yes
No
Comment
an internal review that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be put in more responsive modes
during disturbances, etc.
The standard should have some requirements on generators if
the BA is not providing the response outlined in the standard
(governors should be working as designed).
The standard should also track Interconnection response over
time and identify a target response (different for each
Interconnection). NERC or NAESB will want to look at how this is
allocated to BAs and generators.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned the proposed standard would not mandate a given amount of response, but would
require an analysis if response is measurably below the norm. As envisioned the proposed standard is
would acknowledge the variability inherent in measuring frequency response and would provide two
methods of capturing sufficient samples to make an objective measurement. The standard would not
preclude market solutions. The SAR detailed description has been expanded to state that the standard
will include a sound calculation for measuring frequency response with consideration of interconnection
specifics. Another detail added to the SAR requires generator units with nameplate ratings of 10 MW or
greater to be equipped with governors. There is another standard under development, (Phase III & IV
MOD-027 - Verification and Status of Generator Frequency Response) that requires Generator Owners to
verify that their governors are working as designed. Finally, the SAR was modified to accommodate both
fixed and variable bias.
Southern Company
Transmission,
Operations, Planning
and EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that significant
frequency response degradation is occurring, particularly in the
Eastern Interconnection. While not yet a crisis, these trends are
indicative of significant changes in design and operational
practices on the interconnected electrical systems of North
America which, if not managed intelligently, can cause significant
degradation in reliability. We strongly urge the industry to support
this SAR and begin the process of controlled management before
the processes behind these trends reach crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York ISO (2)
Mike Calimano
9
We agree in general that there is a reliability need to have
frequency response, particularly during disturbances, islanding
and restoration. The standard should provide the process for a
technically sound calculation of frequency response and bias
(both fixed and variable).
Any new standards on frequency response need not and should
Page 9 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001220
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
not be onerous by finding BAs noncompliant with response less
than average or below some un-validated norms. There may be
valid reasons why a BA is below observed norms in response.
For example, the BA may meet most of its obligations with
schedules or its native load may be non-responsive.
If performance is significantly less than an Interconnection norm,
the standard should not trigger an automatic non-compliance. In
these situations the BA should perform an internal
review/assessment that ensures governors are working as
designed, that the BA knows which resources are frequency
responsive (so the information can be included in restoration
plans), whether governors can be put in more responsive modes
during disturbances, etc.
When required, the validation of governor performance could be
achieved either through online monitoring in an EMS or periodic
testing (both methods should be explained in a reference
document to support the standard).
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that response is highly variable eventto-event based on simultaneous load changes. The standard
should acknowledge the differing Interconnection requirements
(smaller Interconnections need greater response).
The standard should also track Interconnection response over
time (years) and be reevaluated as performance changes.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
an analysis if response were measurably below the norm (this detail has been added to the detailed
description in the SAR).
There is another standard under development, (Phase III & IV MOD-027 - Verification and Status of
Generator Frequency Response) that requires Generator Owners to verify that their governors are
working as designed.
The standard would accommodate the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that could calculate the
BA’s performance to the standard.
The SAR was also changed to reflect the suggestions to accommodate:
•
Cases where a specific unit (e.g. nuclear) is prohibited from providing frequency response.
•
Differing Interconnection needs.
IESO (2)
Pete Henderson
9
We agree in general that there is a reliability need to have
frequency response, in order to maintain interconnection
frequency and particularly during disturbances, islanding and
restoration. The standard need to address both the system
needs as well as island requirements for frequency response.
The standard should provide the process for a technically sound
Page 10 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001221
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
calculation of frequency response and bias.
The standard should acknowledge that some units might not
provide response under normal operations (e.g. nuclear units
operating at full load) and that load response is highly variable
event based on time of day or year.
The standard should acknowledge smaller areas need greater
response.
Where BA areas are deficient in meeting the interconnection
requirement , they should be allowed a reasonable period of time
to take appropriate steps to make corrections before being
assessed as non compliant.
The standard should also track area response over time (years)
and be reevaluated as performance changes.
Quality should be defined. For generators it should include deadband, droop characteristics, etc.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the standard would not mandate a given amount of response, but would require
an analysis if response were measurably below the norm (this detail has been added to the detailed
description).
The standard accommodates the simplification ideas you propose, and in fact, if data is saved in a
common format, the Resources Subcommittee Frequency Task Force has a tool that will calculate the
BA’s performance to the standard. The Resources Subcommittee Frequency Task Force agrees with your
“governor quality” comment and has added governor installation and operation details to the SAR’s
detailed description.
As envisioned, the standard will provide the Balancing Authority with sub-par frequency response time to
analyze their situation and make necessary changes and corrections.
ATC (1)
Peter Burke
9
Based on the NERC white paper Frequency Response Standard
Whitepaper dated April 6, 2004 that was prepared by the
Frequency task Force of the NERC Resources Subcommittee, it
would appear that the decline in frequency response of both the
Eastern and Western Interconnections is a reliability concern. As
a transmission provider, however, there is probably little that can
be done other than make sure that governor response and load
modeling can be made as accurate as reasonably possible in
conducting dynamic simulations and be aware of this issue in
studying existing as well as new generating facilities. The control
area, generation operators and turbine-generator manufacturers
need guidance provided as to their responsibilities and
obligations regarding frequency response. Changes in the load
characteristics (e.g. fewer large motors, variable speed drives, etc
) over time, plus changes in reserve sharing practices brought on
by deregulation and competition are and will affect load response
to frequency excursions. The type of generation (e.g.
combustion turbine units, combined-cycle units) being
interconnected to the system as well as the operation of the
Page 11 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001222
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
governors (e.g. blocked or improper settings) and turbines (e.g.
sliding pressure, boiler-follower, etc.) of existing generators have
a significant effect on the system frequency response.
Response: The Resources Subcommittee Frequency Task Force agrees with your technical comments
in support of this standard. The team also supports the development of the planning “MOD” standards
that address frequency response at the generator level.
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that significant
frequency response degradation is occurring, particularly in the
Eastern Interconnection. While not yet a crisis, these trends are
indicative of significant changes in design and operational
practices on the interconnected electrical systems of North
America which, if not managed intelligently, can cause significant
degradation in reliability. I strongly urge the industry to support
this SAR and begin the process of controlled management before
the processes behind these trends reach crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
Robert Blohm
9
The CPS1 equation is a single equation in two variables, primary
(governor) response and secondary response. Two variables
require two equations in order to have a unique solution. That
second equation does not currently exist and must be the
proposed Frequency Response standard that pins down the
value of primary (governor) response. Currently, the single CPS1
equation allows any Balancing Authority an infinity of solutions for
any given CPS1 value. Accordingly, Balancing Authorities have
been tending to reduce expensive primary response and increase
cheaper secondary response (AGC, regulation, load following) to
achieve a given CPS1 score, which is an average over time. The
result has been a halving of system bias in the Eastern
Response: The Resources Subcommittee Frequency Task Force appreciates your comment and your
support for the frequency response standard.
SPP Operating
Reliability Working
Group
Robert Rhodes –SPP
(2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
9
A frequency response standard is needed but only within the
scope and range of the previously provided guides in Policy 1
such as a design criteria of 5% droop, a 36 mHz deadband with
exclusions for nuclear, combined cycle and small generating
units.
Page 12 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001223
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA
(1)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force agrees with the comments and has
added statements to the detailed description to reflect the comments. However, the SAR is intended to
capture the scope of the standard and the specific parameters will be determined by the standard drafting
team.
Southern Co.
Generation (6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
Trends in Eastern and Western Interconnection Turbine Governor
Response and primary frequency response over the past two
decades (as documented by EPRI Project RP2473-53 and
Decline of Eastern Interconnection Frequency Response by
Ingleson and Nagle) as well as trends in frequency error
magnitude and variance over the past five years (as documented
by the NERC Resources Subcommittee at URL
http://www.nerc.com/~filez/rs.html) indicate that frequency
response degradation is occurring, particularly in the Eastern
Interconnection. While not yet a crisis, these trends are indicative
of significant changes in design and operational practices on the
interconnected electrical systems of North America which, if not
managed intelligently, can cause degradation in reliability. We
support this SAR in an effort to begin the process of controlled
management before the processes behind these trends reach
crisis proportion.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
TXU Energy Delivery
Roy Boyer
9
Yes, I agree there is a reliability need for specifying the quality
and quantity of frequency response. There is ample evidence
that specifying a droop value or that specifying governors must be
in operation will not necessarily result in any useful governor
response to a sudden large drop in system frequency. So yes, I
think a SAR team should look into this matter. I would suggest the
part load can play in arresting frequency decline be included in
the scope. I would also suggest that the frequency response
needs of the regions will likely vary, so final specific requirements
should probably be made at the region level.
Response: The Resources Subcommittee Frequency Task Force agrees that load can provide frequency
response and load contribution is, by default, included in the balancing authority’s performance. The
standard is indifferent to whether response is provided by load or generation. The proposed standard
recognizes the role and importance of both the Interconnection and the Regional Reliability Organization
in the establishment of requirements. In general, it is expected there is a “base” Interconnection target
response that will be addressed in this standard. Each Interconnection would have a different target,
based on its size and historic response. There are areas (e.g. Maritimes) that require additional
response. It is expected these unique situations will be primarily addressed in the “MOD” standards. This
standard would enable improved data for the MOD standards.
MISO
Terry Bilke
9
These are my individual comments as a member of the NERC
Resources subcommittee and not those of representing any
organization.
There is a reliability need for a light-handed standard that allows
us to do a better job of ensuring response is available when
Page 13 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001224
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
required. As some entities might comment, there is adequate
response in all interconnections during “system normal”
conditions. The problem is what occurs during major
disturbances and restoration.
A primary reason the industry needs to do a better job of tracking
frequency response is the fact that response is declining when it
should actually be increasing with load and generation growth.
The standard should not be structured such that it finds BAs
noncompliant if response is below average or if response is low
for a given event. Frequency response at the BA level is
extremely variable as the measure is mingled with load
fluctuation.
The standard should guide a technically sound calculation of
response at the BA level and track interconnection performance
over time to enable informed decisions.
If a BA performs significantly below an Interconnection norm, the
standard should require the BA do an internal assessment of its
key generation to verify governors are working as designed and
that there will be frequency responsive resources for disturbances
and restoration.
If Interconnection response significantly changes over time, the
standard should be reevaluated.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
TXU Electric Delivery proposes that Frequency Response
Guidelines at the NERC level should only be in general terms and
require that each Reliability Authority establish a specific
Frequency Response Standard with detailed specifications as
appropriate for its region.
Response: The Resources Subcommittee Frequency Task Force intent was not to mandate a specific
amount of frequency response, but to require a consistent, objective calculation of frequency response.
The balancing authority and the Regional Reliability Organization must do an assessment of adequacy if
response is measurably below the norm. The proposed standard recognizes the role and importance of
the Interconnection and the Regional Reliability Organization in the establishment of requirements. In
general, it is expected there is a “base” Interconnection target response that will be addressed in this
standard. Each Interconnection would have a different target, based on its size and historic response.
There are areas (e.g. Maritimes) that require additional response. It is expected these unique situations
will be primarily addressed in the “MOD” standards. This standard would enable improved data for the
MOD standards.
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
9
Page 14 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001225
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Ed Forsythe
Yes
Alliant Energy (1)
Kenneth A. Goldsmith
9
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System
Response to Generation
Governing
9
NCPA (4)
Les Pereira
9
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE
(2)
Al Adamson – NYSRC
(2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One
(1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE
(2)
G. Campoli – NYISO (2)
9
New York State
Reliability Council (2)
Theodore Pappas
9
We Energies (3, 4, 5)
Howard Rulf
9
Calpine (6)
James Stanton
9
No
Comment
Page 15 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001226
Consideration of Comments on First Draft of Frequency Response SAR
2. Do you agree with the scope and applicability of the proposed standard?
Summary Consideration: Most commenters agreed that the proposed standard should apply
to the Reliability Authority (or Reliability Coordinator), Balancing Authority and Generator
Operator. With the revisions to the SAR, there are requirements for the Generator Owner to
ensure that certain governors meet a minimum set of criteria
There was no consensus amongst commenters on the scope of the proposed standard. The
drafting team made extensive changes to try to better define the scope.
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
No
9
Comment
Frequency Response characteristics should be dictated by the
Reliability entities as part of their respective control services to
meet the regional synchronizing requirements as well as the
longer duration control standards and of the needs of the
interconnection in which they operate.
Response: The Resources Subcommittee Frequency Task Force’s intent is that the standard be
designed such that a BA can mirror the metrics within its boundaries (evaluate generators and LSEs) if it
so chooses.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
The main theme that there needs to be a relationship between
response and frequency decline is the right approach but
requirements would be different from region to region.
Standards to manage frequency response should be developed
by individual interconnections; not NERC. The scope and
applicability should be defined by the needs of the
interconnection to provide the most benefit to system wide
reliability.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and, as envisioned, the Standard would accommodate Interconnection
differences both in amounts of response and methodology in calculating response. The drafting team
believes that stakeholders would prefer the assurance of knowing that NERC is providing oversight to
ensure that all Interconnections have a technically sound basis for the development of respective
frequency response requirements.
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC (2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One (1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE (2)
9
The applicability of this Standard to the LSE should be
considered.
Page 16 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001227
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
G. Campoli – NYISO (2)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force will add LSE to the standard’s
applicability list.
MAAC (2)
John Horakh
9
Quoted from the SAR (with corrections): This SAR is proposed
to develop a standard to measure sub-minute responses to
changes in frequency and to set minimum acceptable responses
of the system to these events. Also quoted: The measurement
selected must be accurate and, to the extent practical, easy to
implement. This seems more like a research project than a
request for a standard. There is no mention of any possible
measurements that might be in the standard. I’m afraid that
proceeding with such a vague idea of a measurement will lead
the SAR or later Standard to become bogged down with
research and field testing even more so than the Balance Load
and Demand Standard. And Balance Load and Demand did
have definite measurements in mind, thereby not requiring much
research, mainly field testing. Come back with a SAR after the
research is done, or at least started.
Response: The Resources Subcommittee Frequency Task Force agrees that the whitepaper bears
some resemblance to the description for a research project. Many in the industry are concerned with the
decline in Frequency Response, while at the same time some are asking how much of a problem is the
decline in response. The drafting team’s goal is to put the infrastructure and process in place to make
informed decisions in the future and to allow the Regions to evaluate the distribution and adequacy of
response and take mitigating action if there are areas found to be deficient. The Resources
Subcommittee Frequency Task Force disagrees with delaying the standard development. The SAR will
define the scope of the standard. The specific detailed requirements and measures will be developed by
the standard drafting team.
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
If the purpose is to purchase frequency response, then the
Market Operator needs to be includes. Will this be considered
an Ancillary Service?
Others that may need to be involved are Transmission Service
Provider, Generator Owner, Planning Authority and Resource
Planner.
Applicability should include #2
Response: The Resources Subcommittee Frequency Task Force agrees that others have roles in
providing Frequency Response, but have focused on the higher level calculation of response at the
balancing authority and Interconnection level. The primary reason for this is that there are about 150
balancing authorities. Only those balancing authorities with sub-normal response need to investigate to
the generator level. The NERC 2002 Generating Unit Statistical Brochure identifies 3694 generators of 1
MW or greater. It would be difficult (and unnecessary if the BA has good response) to monitor thousands
of generators with this standard. The standard doesn’t preclude market solutions, which NAESB may
adopt. The Resources Subcommittee Frequency Task Force agrees with the comment to include #2 in
the SAR.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
9
There is a general need for a standard, but the outcomes and
expectations should address the comments raised in question 1.
While we agree that the standard should not preclude market
solutions (e.g. allow purchasing of response as long as
deliverability and restoration criteria can be met), we have
concerns with the statement There must be a means for
sale/purchase of frequency response as for any other quantity.
Page 17 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001228
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
P. Henderson – IESO (2)
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
Comment
It is not clear what is meant by A method of allocation must be
developed.” Is this an allocation of Interconnection response to
BAs, BA allocation to generators or something different?
New York ISO (2)
Mike Calimano
Response: The Resources Subcommittee Frequency Task Force agrees with these comments, and has
revised the SAR to omit the italicized statements. As envisioned, the proposed standard would not
mandate a given amount of frequency response, but would require an analysis if response were
measurably below the norm. The standard doesn’t preclude market solutions, which NAESB may adopt.
9
NCPA (4)
Les Pereira
The scope needs to be expanded – see detailed comments in a
following section – based on extensive modeling and validation
work in WECC.
Response: The Resources Subcommittee Frequency Task Force appreciates the significant work that
has been done in this area by the WECC and has referenced some of this research in the Whitepaper.
We believe the Planning Standards under development (MOD-13 and MOD-27) deal with the governor
issues that you outline. As envisioned, this standard will provide improved data into the modeling
process.
9
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
The SAR indicates a measure of frequency response for the
Interconnection, as a measure of performance. This would be
very difficult to translate to individual entity compliance and thus
render the standard applicable to no entities.
Response: The interconnection measure of response is intended as a benchmark and as a validation of
the balancing authority’s reported performance. The revised SAR indicates that if frequency response is
outside the norm for the BA, based on its size, BAs and Regions would be required to conduct analyses
to determine the reason for the performance.
9
IESO (2)
Pete Henderson
The Frequency control standard needs to address levels
required for reliability, be consistent and verifiable, and be
simple to monitor for compliance purposes.
Response: This is the intent.
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
Scope:
The scope of the proposed standard is appropriate. However,
the reliability requirements would be better addressed by a
comprehensive review that considers the adequacy of existing
reliability standards.
Applicability:
The applicability of the proposed standard is understood to be
Reliability Authorities, Balancing Authorities, and Generator
Page 18 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001229
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Operators. However, substantial questions remain as to how
the responsibilities implied in the proposed standard will be
equitably distributed.
Response: The Resources Subcommittee Frequency Task Force appreciates your comment. The new
standard for verifying generator governor controls will be under field test through part of 2007 and then
will be finalized, balloted and then implemented. The implementation plan for MOD-027 includes
additional time for entities to become compliant with the requirements. This would mean that any work on
this standard could be delayed for several years. With the decline in Eastern Interconnection frequency
response, the drafting team thinks it would be unwise to wait for the new standards to be developed and
reviewed before developing this standard.
Your questions regarding the applicability of the responsibilities will be better defined during the standard
drafting phase of this standard.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
Generally, our answer is yes, but the matter of applicability
needs a very careful consideration. The question is whether the
proposed standard should be applied to only the reliability and
balancing authorities and plant operators, or also to the resource
and system planning authorities and generator owners. For
example, wind generators do not provide a frequency response,
whereas the response from the Combined Cycle units is limited.
This is a matter of design as well as the matter of controllability
of the primary energy source. If the generation portfolio contains
a lot of wind and CC generators, the balancing authority cannot
do much to improve its summary frequency response in general
terms. Also, if frequency responsive generators in a CA are
heavily loaded, would the new standard force the balancing
authorities to re-dispatch generation in favor of non-responsive
generation and commit more responsive generation ahead of
the non-responsive generation? Another issue is whether the
standard should specify the required response in the area or
individual responses from generators. Perhaps, NERC should
work with NASB to find the right answers before establishing the
standard. One possible solution is to establish penalties for noncompliance that would stimulate generator owners to invest in
frequency responsive generation. Another possible
recommendation could be establishing a market for frequency
response. Without resolving these difficult issues, this standard
cannot be accepted.
Response: The Resources Subcommittee Frequency Task Force agrees that there are several issues
that must be addressed in the standard or in supporting business practices. As envisioned, the draft
standard would not be prescriptive with regard to “how much” and “where” the response is carried. The
standard would allow balancing authorities, reliability coordinators, load-serving entities and Regional
Reliability Organizations to make informed decisions based on their unique situation.
Energy Mark, Inc. (8)
Howard Illian
9
Planning standards are not enough by themselves. Without
continuous measurement, there can be no assurance that those
responsible for meeting the reliability need for Frequency
Response are fulfilling those responsibilities. Only a Frequency
Response Standard that continuously measures response can
insure that the response is available when required.
Response: The Resources Subcommittee Frequency Task Force agrees with your comment. The SAR
drafting team will follow the Planning Standards under development (MOD-13 and MOD-27) that deal with
governors and frequency response to be sure there are no conflicts.
Page 19 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001230
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
TXU Energy Delivery
Roy Boyer
Yes
9
No
Comment
Yes, I agree.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MISO
Terry Bilke
9
I agree, with some qualification. While the standard shouldn’t
preclude market solutions, I don’t think it must enable a market
as the scope implies. A little more clarity on the goals of the
standard is needed.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments and has
removed the reference in the original SAR to market solutions.
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System Response
to Generation Governing
9
The proposed scope and applicability, to the extent that they are
in the given in the SAR, are good.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
We Energies (3, 4, 5)
Howard Rulf
9
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Calpine (6)
James Stanton
9
Alliant Energy (1)
Kenneth A. Goldsmith
9
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
Southern Company
Transmission,
Operations, Planning and
9
Page 20 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001231
Consideration of Comments on First Draft of Frequency Response SAR
Commenter
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
Yes
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
Robert Blohm
9
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA (1)
9
Southern Co. Generation
(6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
New York State Reliability
Council (2)
Theodore Pappas
9
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
No
Comment
Page 21 of 42
April 1, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001232
Frequency Response SAR – Comment Report
3. Do you believe these standards are more appropriately additions to existing
standards as opposed to creating new standards?
Summary Consideration: There was no consensus amongst commenters on this issue.
Refinement of this SAR was delayed for a year. During that time other related standards have
undergone considerable development, and are on a schedule that would not be improved by the
addition of the requirements envisioned with the Frequency Response standard. For these
reasons, the drafting team is recommending that the new requirements for Frequency
Response be in a new, stand-alone standard.
Commenter
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
Yes
No
Comment
9
WECC has been working on frequency response
standards for a few years and is close to finalizing
standards specifically for the WECC interconnection.
We do think there is a need for standardization of
frequency response (clearly we do since WECC is
doing it) BUT this standard should be developed at the
Regional Council or Interconnection level and then
adopted by NERC as a "Standard" with regional
differences. Any new standards concerning frequency
response should be developed by the individual
interconnections.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and the proposed standard accommodates Interconnection
differences both in amounts of response and methodology in calculating response. The SAR’s detailed
description has been expanded to include broader parameters, including frequency response
calculations that are Interconnection-specific. The drafting team believes that stakeholders would
prefer the assurance of knowing that NERC is providing oversight to ensure that all Interconnections
have a technically sound basis for the development of respective frequency response requirements.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
The new standard should a stand-alone standard
because of its potential implications for control areas
and the necessity to stage the implementation of the
standard in coordination with resolution of the issues
discussed above.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
Robert Blohm
9
The SAR acknowledges that the proposed Standard
not only is complementary to the Balancing Resources
and Demand Standard, but also must be coordinated
with that Standard. The two standards could be
combined. But that is insufficient reason to oppose
development of a separate Frequency Response
Standard. Moreover, combining the standards would
reverse the great progress made in consensus on the
Balancing Resources and Demand Standard.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MAAC (2)
John Horakh
9
Adding this requirement to another standard would
only slow down the progress of both.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
ISO/RTO Standards Review
9
Unless the Version 0 (BAL-003-0 — Frequency
Page 22 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
P. Henderson – IESO (2)
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
001233
Comment
Response and Bias) can be clarified and brought in
line with this proposed standard, it should be standalone.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
NCPA (4)
Les Pereira
9
A new SAR will be more prescriptive, however there is
also need for other related sections in NERC
Operating Policy and Planning that need to be
modified – see other comments below.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
IESO (2)
Pete Henderson
9
If the existing Frequency Response and Bias Standard
Version 0 (Bal-003-0) can not be clarified and brought
in line with this proposed standard, it should be
standalone.
Response: The Resources Subcommittee Frequency Task Force agrees with this comment.
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
9
Manitoba Hydro (1, 3, 5, 6)
Gerald Rheault
9
We Energies (3, 4, 5)
Howard Rulf
9
Calpine (6)
James Stanton
9
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
9
Page 23 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001234
Frequency Response SAR – Comment Report
Commenter
Steve Wallace – SEC (5)
S. McElhaney – FMPA (5)
Ted Hobson – JEA (1)
Yes
No
New York ISO (2)
Mike Calimano
9
New York State Reliability
Council (2)
Theodore Pappas
9
TXU Electric Delivery (1)
Travis Besier or Ellis Rankin
9
NPCC CP9, Reliability
Standards Working Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA (1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC (2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One (1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE (2)
G. Campoli – NYISO (2)
9
Progress Energy – Carolinas
(1, 3, 5, 6)
Phil Creech
9
Comment
The reliability requirements provided in the proposed
standard would be better addressed by a
comprehensive review that considers the adequacy of
the existing reliability standards (i.e., 300 - Balance
Resources and Demand)
Response: Frequency Response was consciously left out of the Balance Resources and Demand
(BR&D) standard. We agree that the Frequency Response standard should complement the BR&D
standard and believe it does.
Energy Mark, Inc. (8)
Howard Illian
9
Frequency Response is closely related to the
Frequency Bias used in the Balancing Resources and
Demand Standard and therefore this standard should
be included as an addition to that standard. If it is not
included in the BRD Standard, a separate standard
would require coordination between the two standards.
This would make the process of updating the
standards more complex.
Response: The Resources Subcommittee Frequency Task Force acknowledges that if the frequency
response requirements and measures were to be included in another standard that the Balance
Resources and Demand standards would be the most likely standard(s). The Resources
Subcommittee Frequency Task Force is working with the Balance Resources and Demand standard
drafting team to ensure that the efforts of both teams are coordinated.
Page 24 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001235
Frequency Response SAR – Comment Report
Commenter
Alliant Energy (1)
Kenneth A. Goldsmith
Yes
9
No
Comment
Version 0 of BAL-003-0, Frequency Response and
Bias; or its successor.
Response: The Balance Resources and Demand standard drafting team has a successor version of
Frequency Bias posted for review. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson – SaskPwr
Jim Maenner – WPS
Tom Mielnik – MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
Version 0 (BAL-003-0 — Frequency Response and
Bias) or its successor is a logical place. Depending on
the outcome of the V1 Balance Resource and Demand
standard, it could reside there.
Response: : The Balance Resources and Demand standard drafting team has a successor version of
Frequency Bias posted for review. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated.
Southern Company
Transmission, Operations,
Planning and EMS Divisions
(1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The intent is for the Frequency Response Standard to complement the Balance
Resources and Demand standards. The Resources Subcommittee Frequency Task Force is working
with the Balance Resources and Demand standard drafting team to ensure that the efforts of both
teams are coordinated. The ‘new’ Balance Resources and Demand standards are close to completion
and cover related but different topics from those in the proposed Frequency Response SAR. There
doesn’t seem to be any benefit in stalling the implementation of the new Balance Resources and
Demand standards while the technical details of the new Frequency Response standard are
developed, tested and then implemented.
ATC (1)
Peter Burke
9
II.B.S1M5, Test results of speed/load governor
controls.
Page 25 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001236
Comment
Comments
It may be appropriate to include this standard in the
Phase III/IV standards that address speed/load
governor controls (II.B.S1M5, Test results of
speed/load governor controls). The three following
customer demand related standards would be helpful
in defining load response to frequency excursions:
II.E.S1.M1, Plans for the evaluation and reporting of
voltage & Frequency characteristics of customer
demands.
IIE.S1.M2 Documentation or requirements for
determining dynamic characteristics of customer
demands.
II.E.S1.M3, Customer (dynamic) demand data.
Response: The drafting team will follow the development of the Phase III/IV planning standards under
development (MOD-13 and MOD-27) that deal with governors and frequency response to be sure there
are no conflicts. The Resources Subcommittee Frequency Task Force believes that a Frequency
Response standard could simplify what is proposed in the planning standards if it allowed an on-line
calculation of generator response.
NERC Frequency Task Force
Raymond L. Vice, Chairman
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL (1)
Steve Hillman – WPEK (1)
Allen Klassen – Westar (1)
9
We would recommend that this standard be
incorporated into the Balance Resource and Demand
Standard (Standard 300) or the Version 0 BAL
Standard.
Page 26 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001237
Frequency Response SAR – Comment Report
Commenter
Bill Nolte – SECI (1)
Mike Stafford – GRDA (1)
Yes
No
Comment
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
Southern Co. Generation (6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
9
The Frequency Response Standard could be included
as part of the Balance Resources and Demand
Standard.
Comments
Since both the Frequency Response Standard and the
Balance Resources and Demand Standard address
frequency, they obviously must work together closely.
If they are crafted, as originally intended by the
Frequency Taskforce, to utilize the same CPS
database, there may be savings in administrative
overhead in putting them both in the same standard.
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
MISO
Terry Bilke
9
It’s not a major issue. It appears it should be include
in the Version 0 (BAL-003-0 — Frequency Response
and Bias).
Response: The Resources Subcommittee Frequency Task Force’s intent is for the Frequency
Response Standard to complement the Balance Resources and Demand standards. The ‘new’
Balance Resources and Demand standards are close to completion and cover related but different
topics from those in the proposed Frequency Response SAR. There doesn’t seem to be any benefit in
stalling the implementation of the new Balance Resources and Demand standards while the technical
details of the new Frequency Response standard are developed, tested and then implemented.
Dick Schulz
Chair, IEEE Task Force on
Large Interconnected Power
System Response to
Generation Governing
No comment.
TXU Energy Delivery
Roy Boyer
No opinion.
Page 27 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001238
Frequency Response SAR – Comment Report
4. Do you have any additional comments regarding the SAR that you believe should be
addressed?
Commenter
MAAC Staff (2)
Al DiCaprio – MAAC (2)
Joe Willson – MAAC (2)
Mark Kuras – MAAC (2)
Yes
9
No
Comment
The SAR requestor has not provided any indication of a reliability
problem. Decreasing frequency response is in and of itself not a
reliability problem - more evidence is required as to the
magnitude of the threat.
Any standard that is proposed, regarding frequency response,
should consider both generator and load response. If Load
response does provide a significant portion of the frequency
response (as some people contend) then that resource must be
considered in the proposal. In short the standard must make
clear whether it is for interconnection response or for balancing
area response or for individual generator response and individual
load response.
Response: Most commenters indicated that they feel that there is a reliability-related need for a standard
to address Frequency Response.
The standard is not intended to establish a large set of arbitrary requirements, but will establish the
framework to collect the information to make informed engineering decisions. Additional detail has been
added to the SAR’s Purpose/Industry Need and the Detailed Description. The revised SAR does not
specifically consider load response but does state that the proposed standard will include requirements
for the Interconnection response, for the installation of governors and for BAs to operate their automatic
generation control function on tie-line frequency bias and for BAs to respond to requests for information
on frequency response. The revised SAR does not include requirements for generators to provide
response and does not address load response.
BPA
Bart McManus
Brian Tuck
James Randall
Francis Halpin
Bill Mittlestat
James Murphy
9
Frequency response requirements are likely different for each of
the three interconnected regions and a generalized approach will
likely not meet WECC needs. The danger here is that a NERCwide approach may not be compatible with the needs of a
regional approach. Standards are currently being developed
within WECC to address the frequency response concerns of
this interconnection. We feel that if the Eastern Interconnection
needs a Frequency Response Standard, they should utilize the
NERC Frequency Response Standard Whitepaper to draft an
Eastern Interconnection-specific Frequency Response Standard.
Response: The Resources Subcommittee Frequency Task Force agrees that frequency response is
primarily an Interconnection issue and the proposed standard accommodates Interconnection differences
both in amounts of response and methodology in calculating response. As noted in and earlier response,
we would expect some general technical and engineering principles that should be met in order to
calculate and evaluate the amount and distribution of frequency response. Additional SAR Detailed
Description details have been added.
The drafting team believes that stakeholders would prefer the assurance of knowing that NERC is
providing oversight to ensure that all Interconnections have a technically sound basis for the development
of respective frequency response requirements.
Manitoba Hydro (1, 3, 5,
6)
Gerald Rheault
9
Below are a few general comments on the SAR:
There is general agreement with the statement “reliance on load
as the sole support to arrest the frequency can lead to a decline
in the reliability of the grid” in paragraph 3, page 4 of the white
paper. However enough information is not provided to
Page 28 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001239
Comment
substantiate statements earlier in the paragraph such as, “the
turn around in frequency from points C to B attributable to unit
governor response has markedly declined and at times is nonexistent in the eastern interconnection” and “the line from points
C to D is shifting down and becoming horizontal”.
In areas where governor response is limited it may be necessary
to explore the necessity of earmarking “high-set” blocks of load ,
as is practiced in ERCOT, to act as a supplementary to governor
response. Although it is anticipated that this approach would
probably be much more difficult and challenging to co-ordinate in
larger areas.
There should be careful thought put into the
system/interconnection performance targets for frequency
response. Perhaps the bar should be higher than preventing
UFLS for credible generation loss events, i.e., provide a margin
above this level. At the same time the standard should not
impose unreasonable costs on entities to demonstrate
compliance. The performance target should address both total
interconnection response and also area or system response
(potential islanding) and be very clear how generator operators
(or load) obligations are allocated to achieve the performance
targets.
NERC should investigate a process to monitor interconnection
frequency response to be able to measure performance.
Response: As envisioned, the standard will accommodate special needs of each Interconnection. It will
not preclude load from being part of the solution.
While not part of the standard, the Resources Subcommittee is pursuing the addition of functionality in the
“NERC ACE-Frequency monitoring application” that will identify generator trips and automate the
calculation of Interconnection frequency response. Evidence to date indicates that frequency response
declines significantly during light load periods, even though the exact mechanism for this is not well
defined. Most of the major frequency excursions experienced in the Eastern Interconnection have
occurred during the shoulder period of the year during either the early morning or late evening periods.
NPCC CP9, Reliability
Standards Working
Group
Guy V. Zito – NPCC (2)
Ralph Rufrano – NYPA
(1)
K. Goodman – ISONE (2)
Al Adamson – NYSRC
(2)
Bob Pelligrini – UI (1)
D. Kiguel – Hydro One
(1)
P. Lebro – Nat’l Grid (1)
R. Champagne – TE (1)
B. Hogue – NPCC (2)
K. Khan – IESO (2)
M. Potishnak – ISONE
9
CHANGE
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to these system events.
Page 29 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001240
Frequency Response SAR – Comment Report
Commenter
(2)
G. Campoli – NYISO (2)
Yes
No
Comment
Response: The SAR has been revised and no longer includes this phrase.
Energy Mark, Inc. (8)
Howard Illian
9
NERC has the responsibility of maintaining reliability on the
North American Interconnections. NERC cannot perform that
function effectively if it waits for reliability problems to become
apparent in system operations before it takes actions to address
those problems. NERC must be a forward looking organization
that anticipates future reliability problems and takes actions to
resolve those problems before they affect interconnection
reliability.
Response: The Resources Subcommittee Frequency Task Force agrees with the comments and has
made substantial changes to the SAR’s Purpose/Industry Needs and the Detailed Description reflecting
the industry comments.
Calpine (6)
James Stanton
9
Given the language in the accompanying White Paper: The
standard should not preclude market solutions (e.g. allow
purchasing of response as long as deliverability and restoration
criteria can be met).There must be a means for sale/purchase of
frequency response as for any other quantity. – I believe this
Standard should be developed in conjunction with NAESB. The
definition, attributes and procurement metrics of the frequency
response product will be a critical component of this Standard.
Some guidance in defining and developing this service to the
bulk interconnected system can be found in the NERC IOS
Reference Document. The Standard should build on this
previous IOS work.
Response: The Resources Subcommittee Frequency Task Force intent for this proposed standard does
not preclude market solutions. Language in the original SAR that referenced markets has been removed
and is not in the revised SAR.
We hope that the previous IOS work and the related MOD standards will provide balancing authorities a
means to obtain frequency response where needed. It is quite possible that NAESB will pick up where
the IOS left off.
MAAC (2)
John Horakh
9
It appears Frequency Response is an accepted term used for
this requirement, and therefore might be difficult to change.
However, Frequency Response is not a very good description of
the requirement. A term such as Transient Generator and Load
Response would be more descriptive.
Response: Transient Generator and Load Response probably is a more descriptive than Frequency
Response. Note that the focus of the proposed standard would be on generator response, not on load
response. . The Resources Subcommittee Frequency Task Force agrees that changing the name from
Frequency Response would likely encounter resistance.
ISO/RTO Standards
Review Committee (2)
K. Tammar – NYISO (2)
D. McMaster – AESO (2)
Ed Riley – CAISO (2)
Sam Jones – ERCOT (2)
P. Henderson – IESO (2)
9
We appreciate the opportunity to comment and believe there is a
need for such a standard.
It needs to be recognized that there are two objectives for
governor response, namely, to provide response on an
interconnection wide basis to maintain an acceptable frequency
and secondly to control frequency in island situations. The
former may allow for averaging over an area of the response
Page 30 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
P. Brandien – ISO-NE (2)
B. Phillips – MISO (2)
B. Balmat – PJM (2)
C. Yeung – SPP (2)
Yes
No
001241
Comment
requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it
should be increasing with load. The main concerns with this
decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely over optimistic and may misstate grid
stability limits.
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
Refer to our earlier comments the structure of the standard
(where lower amounts of BA response trigger an internal
assessment rather than automatic assignment of noncompliance). BAs (and ultimately generators) would only be
initially non-compliant if their response was low AND the BA
failed to perform a reliability assessment in conjunction with its
TOP. Non compliance should be assessed if the BA does not
alleviate the deficiency within a reasonable timeframe. This
default assessment would be at the BA level, but could be on an
area basis (likely islanding area or where a TSP has
responsibility for frequency responsive and black start ancillary
services).
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further
define the standard to meet its needs.
Page 31 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001242
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. A envisioned, the standard will measure response for perhaps a minute to ensure response is not
withdrawn immediately after it is provided.
The proposed standard would not mandate a given amount of response, but would requires an analysis if
response were measurably below the norm. The proposed standard would accommodate the
simplification ideas you propose, and in fact, if data is saved in a common format, the Resources
Subcommittee has a tool that could calculate the BA’s performance to the standard.
The drafting team agrees that performance requirements must be validated by the industry. As you
suggested, a long field test may be needed before justifiable minimum performance standards can be
identified.
MRO (2)
Larry Larson – OTTP
Al Boesch – NPPD
Terry Bilke – MISO
R. Coish – MH
Dennis Florom – LES
K. Goldsmith – Alliant
Todd Gosnell – OPPD
W. Guttormson –
SaskPwr
Jim Maenner – WPS
Tom Mielnik –
MidAmerican
Darrick Moe – WAPA
Joe Knight – MRO
9
We appreciate the opportunity to comment and believe there is a
need for such a standard. Published studies show frequency
response is declining when it should be increasing with load.
Because there is no process in place to track BA or
Interconnection response, we don’t know whether the decline is
local or global. Primary concerns with this decreasing
performance in primary control:
1. There may be areas unable to withstand severe
disturbances.
2. Following a grid separation or collapse, control areas may
be unable to fulfill their blackstart and restoration
responsibilities, thereby becoming a burden to neighbors.
3. Because engineering models use theoretical frequency
response, they are likely overoptimistic and may misstate
grid stability limits.
Rather than putting in a complicated infrastructure or process,
we would suggest that NERC automate the calculation of
frequency response by either:
•
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
•
Embed the calculation in the NERC ACE-monitoring
application.
The standard will need to acknowledge the large variability in
individual responses at each BA due to coincident load changes
and amount and mix of generation. In addition, smaller
Interconnections likely need greater response.
Refer to our earlier comments the structure of the standard
Page 32 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001243
Comment
(where lower amounts of response trigger an internal
assessment rather than assessment non-compliance). BAs (and
ultimately generators) would only be initially non-compliant if
their response was low AND they failed to perform the reliability
assessment.
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
The standard should not preclude market solutions to providing
frequency response, but such arrangements would need to be
looked at closely to be sure they fulfill reliability needs.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. As envisioned, the proposed standard would not mandate a given amount of response, but would
require an analysis if response were measurably below the norm. The proposed standard would
accommodate the simplification ideas you propose, and in fact, if data is saved in a common format, the
Resources Subcommittee has a tool that could calculate the BA’s performance to the standard.
The Resources Subcommittee Frequency Task Force acknowledges the variability inherent in measuring
frequency response. The standard will require capturing sufficient samples to make an objective
measurement. The proposed standard does not preclude market solutions.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. As envisioned, the standard does not mandate a specific amount of
response, but requires analysis if response is markedly below the norm. Analysis may identify the need
for corrective measures and the standard will accommodate the necessary time to make corrections.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
NCPA (4)
Les Pereira
9
Two statements are made in the SAR:
1. The purpose of the proposed SAR is to ensure that
frequency of the Interconnection remains above
underfrequency load shedding setpoints during the
transient period following the sudden loss of generation
on the Interconnection.
2. Furthermore, it is stated that “ In regard to frequency
response, one shortcoming of the recommendations in
policy today is that there is no guidance regarding how
much governor response (in MW) is required at the 5%
droop rate.”
The first is a calculated number and depends not only on the
amount of generation tripped, but also the total generation in the
Whole Interconnection at the time of trip. Obviously two very
different answers will be obtained : one with the Interconnection
intact (normal operation) and the second when islanded. Both
affect reliability.
The second issue has been thoroughly investigated in the
WECC and a new Thermal Governor modeling approach has
Page 33 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001244
Comment
been implemented in the WECC after system tests, an
exhaustive modeling validation effort and obtaining data from the
generator owners. This has been documented in two IEEE
Transaction papers described below. These papers present the
development of a new turbine-governor modeling approach in
WECC that correctly represents thermal units that have
demonstrated unresponsive characteristics such as “base
loaded” units operated with limiters, or partially responsive units
with MW-load-controllers. The May 18th 2001 system trip test for
1250 MW performed with all AGCs off indicated that only about
40% of the governors effectively responded in the real system. If
all the governors were responsive the calculated generation
pickup for governors with a 5% droop for a 0.1 Hz frequency
deviation would be 3185 MW instead of 1250 MW. The new
modeling approach has been extensively validated against
recordings from three WECC system tests and several large
disturbances, and has been approved for use in all operation and
planning studies in the WECC. The second paper describes the
steps being taken to obtain validated data for the new governor
models.
The work done by WECC indicate clearly that we do not get the
required 5% droop from all units as required by NERC. The
modeling approach taken was to model the governors in
planning and operating studies exactly as they are being actually
operated. Enforcement/compliance of the 5% droop is a
separate issue and must be addressed by operating policies.
Obviously, the SAR touches upon only part of the problem, but it
is a good start and should be expanded. It also needs to be
cross-referenced with other areas such as the 5% droop
requirement, an effective spinning reserves policy that actually
works (see the papers), and the effect on ‘governor’ powerflow
and voltage stability analysis as a result of “unresponsive”
governors.
The white paper referred by the SAR only touches upon the
WECC effort and seems to miss the whole point of the modeling
and validation work by the Governor Modeling Task Force in
WECC - and what we have achieved in WECC to address
realistic modeling of unresponsive governors in the real system.
1. "A New Thermal Governor Modeling Approach in the
WECC"
by L. Pereira, J. Undrill, D. Kosterev, D. Davies, S.
Patterson, IEEE Trans. Power Systems, vol. 18,
Issue.2, pp. 819-829, May 2003. (IEEE 2004 prize
paper). Presented at Toronto IEEE PES, July 2003.
2. “New Thermal Governor Model Selection and
Validation in the WECC” by Les Pereira, Dmitry
Page 34 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001245
Comment
Kosterev, Donald Davies, and Shawn Patterson - IEEE
TPWRS – Vol.19, No.1, pp 517-523, February 2004.
Presented at Denver IEEE PES, July 2004.
Response: The Resources Subcommittee Frequency Task Force appreciates the significant work that
has been done in this area by the WECC and has referenced some of this research in the Whitepaper.
We believe the Planning Standards under development (MOD-13 and MOD-27) deal with the detailed
governor issues that you have outlined.
The Resources Subcommittee Frequency Task Force appreciates the importance of the modeling effort
you mention. This standard is not intended to address the modeling issues, but provides the framework
and data needed to support the modeling.
The SAR was modified to include basic governor requirements.
FRCC (2)
Linda Campbell
Ron Donahey – TEC (1)
Mark Bennett – GRU (3)
Steve Wallace – SEC (5)
S. McElhaney – FMPA
(5)
Ted Hobson – JEA (1)
9
At this time the FRCC has the highest frequency settings for load
shedding in the Eastern Interconnection (southern part of the
Region). Being a peninsula and out of necessity, the Region has
developed a well coordinated, under-frequency program for
extreme frequency excursions. Ambiguity of the requirements,
uncertainty of measurement and the lack of benefit to the Region
require that the FRCC to oppose this Standard Authorization
Request at this time.
Response: The interconnection measure of response is intended as a benchmark and as a validation of
BAs’ reported performance.
Southern Company
Transmission,
Operations, Planning and
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
9
We believe that the industry will be exposing the interconnected
electrical systems of North America to a significant degree of
reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be
mitigated somewhat by the turbine governor requirements of
Standard MOD-014-1 from the Phase III/IV Standards SAR, if
passed. However, the risk can be managed properly (and in the
most economical manner) only on an interconnection/balancing
authority basis, not on an individual generator basis as required
by Standard MOD-014-1.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection.
We strongly urge the industry to support this SAR.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York ISO (2)
Mike Calimano
9
We appreciate the opportunity to comment and believe there is a
need for such a standard. Published studies show frequency
response is declining when it should be increasing with load.
The main concerns with this decreasing performance are:
Page 35 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001246
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely overoptimistic and may misstate grid
stability limits.
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
Refer to our earlier comments the structure of the standard
(where lower amounts of BA response trigger an internal
assessment rather than automatic assignment of noncompliance). BAs (and ultimately generators) would only be
initially non-compliant if their response was low AND the BA
failed to perform a reliability assessment in conjunction with its
TOP. This default assessment would be at the BA level, but
could be on an area basis (likely islanding area or where a TSP
has responsibility for frequency responsive and black start
ancillary services).
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Each Interconnection should have the ability to add and further
define the standard to meet its needs.
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Page 36 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001247
Frequency Response SAR – Comment Report
Commenter
Yes
No
Comment
CHANGE
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to system these events.
TO
This SAR is proposed to develop a standard to measure subminute responses to changes in frequency and to set minimum
acceptable responses to these system events.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments as a
whole. The proposed standard does not mandate a given amount of response, but requires an analysis
if response is measurably below the norm. The proposed standard accommodates the simplification
ideas you propose, and in fact, if data is saved in a common format, the Resources Subcommittee has a
tool that will calculate the BA’s performance to the standard. The Resources Subcommittee Frequency
Task Force has added to the Detailed Description requirements that all balancing authorities shall operate
their AGC function on tie-line frequency bias and that all balancing authorities shall perform frequency
response characteristics surveys when called for by NERC. The Resources Subcommittee Frequency
Task Force agrees with the sub-minute responses comment and has made the change.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. A long field test with extensive data collection may be needed before
justifiable minimum performance standards can be identified.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
As envisioned, the standard will measure the response for up to 60 seconds to ensure initial response is
not withdrawn. The standard will also provide interconnection flexibility.
The phrase noted (starting with , ‘This SAR. . . ’) was removed from the revised SAR.
IESO (2)
Pete Henderson
9
We appreciate the opportunity to comment and believe there is a
need for such a standard.
It needs to be recognized that there are two objectives for
governor response, namely, to provide response on an
interconnection wide basis to maintain an acceptable frequency
and secondly to control frequency in island situations. The
former may allow for averaging over an area of the response
requirement but the latter may limit the extent of averaging.
Published studies show frequency response is declining when it
should be increasing with load. The main concerns with this
decreasing performance are:
There may be areas unable to withstand severe disturbances.
Following a grid separation or collapse, control areas may be
unable to fulfill their blackstart and restoration responsibilities,
thereby becoming a burden to neighbors.
Because engineering models use theoretical frequency
response, they are likely over optimistic and may misstate grid
stability limits.
Page 37 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001248
Comment
This standard would allow the industry to determine whether the
decline is local or global.
Rather than implementing a complicated infrastructure or
process, we would suggest that NERC automate the calculation
of frequency response by either:
Asking BAs to save their CPS-source data in a common
format so a common tool can be used (MAPP BAs and some
others use a common tool that can calculate frequency
response with CPS-source data).
Embed the calculation in the NERC ACE-monitoring
application.
The standard should employ a methodology that not only
captures initial response (first few seconds after the event) but
also the sustained response until AGC action takes over
Providing visibility on where and when performance is
substandard will likely initiate sufficient action to arrest the
decline in performance. Minimum performance standards could
be implemented after the industry has identified what is
reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments. We
agree that smaller areas need greater response, and this concept will be applied in establishing the initial
target responses for the interconnections (the historic response will bear this out). Under the ERO,
interconnections can also establish stricter targets.
The new requirements may need to be field tested for a long duration before compliance with the
requirements is mandatory. A long field test with extensive data collection may be needed before
justifiable minimum performance standards can be identified.
As envisioned, the standard will measure the response for up to 60 seconds to ensure initial response is
not withdrawn.
The references to market solutions that were contained in the original SAR have been removed. NAESB
may choose to develop associated business practices.
NERC Frequency Task
Force
Raymond L. Vice,
Chairman
9
I personally believe that the industry will be exposing the
interconnected electrical systems of North America to a
significant degree of reliability risk if a Frequency Response
Standard similar to the one proposed by this SAR is not adopted.
This risk can be mitigated somewhat by the turbine governor
requirements of Standard MOD-014-1 from the Phase III/IV
Standards SAR, if passed. However, the risk can be managed
properly (and in the most economical manner) only on an
interconnection/balancing authority basis, not on an individual
generator basis as required by Standard MOD-014-1.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
Page 38 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001249
Comment
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection. I
strongly urge the industry to support this SAR.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
Dick Schulz
Chair, IEEE Task Force
on Large Interconnected
Power System Response
to Generation Governing
First, I make these comments based on work that I've done
principally at American Electric Power Service Corp, before my
retirement from there in November 2000, and as founding Chair
of the IEEE Task Force on Large Interconnected Power System
Response to Generation Governing. These comments are
entirely mine, and reflect no views of either body.
Second. It appears that the final standard will differ from any
single person's opinions. Thus the specific comments below
may not prevail.
Specific Comment 1:
The comment on page 4 of the SAR, "The standard should not
preclude market solutions (e.g. allow purchasing of response as
long as deliverability and restoration criteria can be met).There
must be a means for sale/purchase of frequency response as for
any other quantity." is workable only in near-normal operating
conditions. But it will fail miserably when there is any islanding
condition. An analogy:
Several skydivers agree that reserve parachutes are
a very good idea, but don't want to invest in 1
reserve each. So they agree that they'll buy one to
share among them, so each will be saved by that
spare. This means
that they will hold hands
until they pull their ripcords.
Sounded good, until they tried it, and the first guy to
pull his cord came
unhitched, had a failed main 'chute, and the spare
was on someone else.
Specific Comment 2:
The comment on page 4 of the SAR, "The measurement
selected must be accurate and, to the extent practical, easy to
implement.' may be met in the Eastern Interconnection by the
underway DOE "Eastern Interconnection Phasor Project ' and by
the similar WECC measurement systems, commonly called
"WAMS". Les Peieira's paper, cited in the White Paper, used the
WAMS measurements.
Response: The Resources Subcommittee Frequency Task Force appreciates the comments. The
proposed standard does not preclude market solutions. The SAR’s intent is to define the proposed
standard’s scope, the actual detail that you recommend will be developed during the standard drafting
phase. The phasor projects in both the Eastern and Western Interconnections may indeed be a source of
accurate and time stamped frequency data for this standard’s application.
Page 39 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001250
Frequency Response SAR – Comment Report
Commenter
Southern Co. Generation
(6)
Roman Carter
Tony Reed
Joel Dison
Lucius Burris
Lloyd Barnes
Clifford Shepard
Terry Crawley
Roger Green
Tom Higgins
Yes
9
No
Comment
It is believed that the industry will be exposing the interconnected
electrical systems of North America to a significant degree of
reliability risk if a Frequency Response Standard similar to the
one proposed by this SAR is not adopted. This risk can be
mitigated somewhat by the turbine governor requirements of
Standard MOD-014-1 from the Phase III/IV Standards SAR, if
passed. However, the risk can be managed properly (and in the
most economical manner) on an interconnection/Balancing
Authority basis, not on an individual generator basis as required
by Standard MOD-014-1.
The governor response in MW for generators is not just
dependent on the governor droop and dead-band settings, but
on the design of the plant control system (sliding pressure boiler,
nuclear pressurized water reactor, etc.). For example, nuclear
plant operators must control reactivity changes in the core and
generally cannot allow external controls to increase or decrease
power levels on demand. This standard should take such factors
into account and address frequency & MW response at the
Balancing Authority level, not at the individual generator level.
What is important is that the interconnections maintain sufficient
frequency responsive resources to ensure the stability of
interconnection frequency under first contingency conditions.
The Frequency Response Standard, as proposed, sets
requirements for the management and deployment of frequency
responsive resources that achieve this goal without unduly
interfering with the on going operation of the interconnection.
We support this SAR.
Response: The Resources Subcommittee Frequency Task Force appreciates and supports your
comments. As envisioned, the standard will measure response at the Interconnection and Balancing
Authority level. Only when a Balancing Authority’s response measurably below the norm is additional
analysis involved.
MISO
Terry Bilke
9
Thanks for the opportunity to comment. I hope the SAC puts all
comments in perspective. We are in a period where the industry
is reluctant to adopt new standards that generate extra work and
compliance exposure. The reliability of the Interconnections can
benefit with minimal impact to most BAs with a light-handed
standard.
Rather than implementing a complicated process, why not
embed most of the effort in the NERC ACE-monitoring
application? Only those BAs with unusually low response would
need to drill down and do an internal assessment to determine
their ability to withstand disturbances and whether they have
responsive resources for blackstart.
Knowing where and when performance is substandard will likely
arrest the decline in performance. Minimum performance
standards could be implemented once the industry has identified
Page 40 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response SAR – Comment Report
Commenter
Yes
No
001251
Comment
what is reasonably achievable and technically justified.
Response: The Resources Subcommittee Frequency Task Force agrees with these comments.
New York State
Reliability Council (2)
Theodore Pappas
9
The Standard should define the term “event” in terms of time and
frequency deviation. The frequency deviation the event must fall
outside the droop deadband.
Response: Response: The Resources Subcommittee Frequency Task Force agrees that there should
be clear criteria set for identifying events that will be used in calculating frequency response. The SAR
was revised to indicate that the standard will require governors to provide droop characteristics within a
specified range (to be determined during standard drafting). At this point, the Resources Subcommittee
Frequency Task Force recommends each interconnection set a target excursion size that is used for
selection of samples and recommends that the target be at least equal to the traditional 36 mHz
deadband.
CAISO (2)
Ed Riley
Yuri Makarov
Steve McCoy
9
TXU Electric Delivery (1)
Travis Besier or Ellis
Rankin
9
Progress Energy –
Carolinas (1, 3, 5, 6)
Phil Creech
9
TXU Energy Delivery
Roy Boyer
9
Robert Blohm
9
SPP Operating Reliability
Working Group
Robert Rhodes –SPP (2)
Ron Ciesiel – SPP (2)
Bob Cochran – SPS (1)
Mike Gammon – KCPL
(1)
Steve Hillman – WPEK
(1)
Allen Klassen – Westar
(1)
Bill Nolte – SECI (1)
Mike Stafford – GRDA
(1)
9
ATC (1)
Peter Burke
9
Southern Company
Transmission,
Operations, Planning and
Page 41 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001252
Frequency Response SAR – Comment Report
Commenter
EMS Divisions (1)
Marc Butts
Steve Corbin
Jim Viikinsalo
Jim Griffith
Doug McLaughlin
Monroe Landrum
Yes
No
TVA (1)
Kathie Davis
Larry Akens
Mitch Needham
Chuck Feagans
Ed Forsythe
9
Alliant Energy (1)
Kenneth A. Goldsmith
9
We Energies (3, 4, 5)
Howard Rulf
9
Comment
Page 42 of 42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001253
When completed, email to: [email protected]
Standard Authorization Request Form
Title of Proposed Standard
Frequency Response, version 1
Request Date
4/1/06
SAR Type (Put an ‘x’ in front of one of
these selections)
SAR Requestor Information
Name
Don McInnis
x
New Standard
(Terry Bilke as substitute for Mr.
McInnis)
Primary Contact Terry Bilke
Telephone
(317) 249-5463
Fax
(317) 249-5994
E-mail
[email protected]
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
Purpose/Industry Need (Provide one or two sentences)
There is evidence of continuing decline in frequency response in the three
Interconnections over the past 10 years, while it should be increasing with
increasing load and generation. The Interconnections may have sufficient
frequency response for normal operations, however, it is not known how this
response is dispersed or at what point it will pose a reliability risk. The
proposed standard’s intent is to ensure frequency of the Interconnections
remains above under-frequency load shedding setpoints during transient period
following the sudden loss of generation on the Interconnections. By addressing
the requirements for control during the “seconds” timeframe, this proposed
standard coordinates with and complements the Balance Resources and Demand
standards, which addresses Interconnection frequency control generally 5
minutes and longer. (The whitepaper submitted with the original Frequency
Response SAR provides the rationale and justification for this standard.)
SAR-1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001254
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
Reliability
Authority
Ensures the reliability of the bulk transmission system within its Reliability
Authority area. This is the highest reliability authority.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within its metered boundary and supports system
frequency in real time
Interchange
Authority
Authorizes valid and balanced Interchange Schedules
Planning
Authority
Plans the bulk electric system
Resource
Planner
Develops a long-term (>1year) plan for the resource adequacy of specific
loads within a Planning Authority area.
Transmission
Planner
Develops a long-term (>1 year) plan for the reliability of transmission
systems within its portion of the Planning Authority area.
Transmission
Service
Provider
Provides transmission services to qualified market participants under
applicable transmission service agreements
Transmission
Owner
Owns transmission facilities
Transmission
Operator
Operates and maintains the transmission facilities, and executes switching
orders
Distribution
Provider
Provides and operates the “wires” between the transmission system and
the customer
Generator
Owner
Owns and maintains generation unit(s)
Generator
Operator
Operates generation unit(s) and performs the functions of supplying energy
and Interconnected Operations Services
PurchasingSelling Entity
The function of purchasing or selling energy, capacity and all necessary
Interconnected Operations Services as required
Market
Operator
Integrates energy, capacity, balancing, and transmission resources to
achieve an economic, reliability-constrained dispatch.
Load-Serving
Entity
Secures energy and transmission (and related generation services) to
serve the end user
SAR-2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001255
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric systems
shall be trained, qualified and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk electric systems shall be assessed, monitored and
maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with that
Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR-3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001256
Detailed Description (Provide enough detail so that an independent entity familiar with the
industry could draft, modify, or withdraw a Standard based on this description.)
The proposed standard will require or provide the following:
o
A technically-sound calculation and report of Balancing Authority and
Interconnection frequency response.
o
Flexibility to meet specific needs of each Interconnection.
o
Will require Balancing Authority and Regional analysis if response is
measurably below the Interconnection norm.
o
An objective measure of the Balancing Authority’s and Interconnection’s
sub-minute response to changes in frequency.
o
The standard will accommodate both fixed and variable bias.
o
Will not mandate a given amount of frequency response, but will provide
long-term Interconnection target levels for average response to
frequency excursions, performance below which triggers Balancing
Authority and Regional Reliability Organizations evaluation and
analysis.
-
Reasonable time to make corrections, if analysis show a Balancing
Authority needs additional frequency response.
o
Balancing Authorities to operate their automatic generation control
function on tie-line frequency bias.
o
Balancing Authorities to perform frequency response characteristic
surveys when called for by NERC.
o
Generator owners to equip generating units with nameplate ratings of 10
MW or greater, with a governor capable of providing immediate and
sustained response to frequency deviations.
o
-
Governors shall provide droop characteristics within a specified
range (to be determined during standard drafting.
-
Governors shall, as a minimum, respond to frequency deviations
with a deadband not to exceed a specific limit (to be determined
during standard drafting).
Generator owners seeking exception to the governor requirements to
provide specific information (to be determined during standard drafting)
to their Balancing Authority and Regional Reliability Organization.
SAR-4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001257
Related Standards
Standard No.
Explanation
BAL-001-0
through BAL006-0
Balancing Standards, version 0
Balance
Resources
and Demand
draft
standards
Balancing Resources and Demand BAL-007 through BAL-012 draft
standards, are in standards development process
MOD-013-0
The proposed standard would enable better input data to the
modeling standards.
Related SARs
SAR ID
Explanation
MOD-027
Verification and Status of Generator Frequency Response. The
proposed standard would provide a mechanism to validate
compliance with MOD-027. The proposed standard could also
provide a means to achieve MOD-027 (if the Balancing Authority
implements on on-line measurement of generator frequency using
SCADA data).
Regional Differences
Region
Explanation
ECAR
ERCOT
Single Balancing Authority Interconnections calculate Frequency
Response based on the change in generation (or load) rather
than Tie-Line deviation (ERCOT).
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
SAR-5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001258
SAR-6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001259
NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731
April 4, 2006
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement
Comment Periods, Ballot Pool, and Drafting Team Self-nominations Open April 4
The Standards Authorization Committee (SAC) announces the following standards actions:
Reliability Standards Process Manual Posted for 45-day Comment Period (April 4–May
18, 2006)
The Reliability Standards Process Manual was revised to align with NERC’s electric reliability
organization application and to make modifications based on ‘lessons learned’. Several of the changes
are to ‘basic tenets’ and, in accordance with the latest version of the Reliability Standards Process
Manual, must go through a full review and approval process. Please use the comment form to provide
comments on the changes to the manual.
One of the proposed changes to the reliability standards process is to move the responsibility for
development of compliance information from standard drafting teams to the compliance program. The
proposed Compliance Elements Development Process and an associated comment form are posted for
review and comment.
Nominations for Reliability Standards Process Manual Drafting Team Open (April 4–18,
2006)
The SAC is soliciting drafting team members to respond to stakeholder comments on the proposed
changes to the Reliability Standards Process Manual. If you are interested in volunteering for this
drafting team, please submit the nomination form by April 18, 2006.
Ballot Pool for Reliability Standards Process Manual Open (April 4)
A ballot pool has been created in anticipation of voting on the proposed changes to the Reliability
Standards Procedure Manual. The ballot pool is available for any ballot body member to join until the
respective ballot is opened.
Two Phase III & IV Standards Posted for 30-day Comment Period (April 4–May 3, 2006)
Two of the Phase III & IV standards were revised based on stakeholder comments and are being re-posted
for a fourth comment period. Please use the comment form to provide comments on these two standards:
PRC-002-1 Define Regional Disturbance Monitoring and Reporting Requirements requires regions to
establish requirements for installation of disturbance monitoring equipment and reporting of disturbance
data to facilitate analyses of events.
PRC-018-1 Disturbance Monitoring Equipment Installation and Data Reporting requires entities to install
Disturbance Monitoring Equipment and report disturbance data to facilitate analyses of events.
A New Jersey Nonprofit Corporation
Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
REGISTERED BALLOT BODY
April 4, 2006
Page Two
001260
One SAR Posted for 30-day Comment Period (April 4–May 3, 2006)
A revised SAR for Frequency Response is posted for a 30-day comment period. The SAR proposes
adding requirements to ensure frequency of the Interconnections remains above underfrequency load
shedding set points during transient periods following the sudden loss of generation. Please use the
comment form to provide comments on this SAR.
Standards Development Process
The NERC posting and balloting procedures are described in the Reliability Standards Process Manual,
which contains all the procedures governing the standards development process. The success of the
NERC standards development process depends on stakeholder participation. We extend our thanks to all
those who participate.
Please send questions to Maureen Long at [email protected], or call 813-468-5998.
Sincerely,
Maureen E. Long
Maureen E. Long
Standards Process Manager
cc:
Registered Ballot Body Registered Users
Standards Group
NERC Roster
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001261
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Baj Agrawal
Organization: Arizona Public Service Co.
Telephone:
602-371-6386
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001262
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001263
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001264
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The requirements on individual generator are unnecessary. The requirements
should be on a group of generators in a control area to achieve a desired
response. Thus, one could have some generators which are being operated as
non responsive and the others which are responding well to offset for those
which are not responsive.
Additionally, the 10 MW size requirements are too restrictive and
unnecessary. It should be plant based and should apply to plants of 100 MW
or more aggregate capacity. In any realistic scenario, the smaller plants are
not expected to contribute much to frequency response and hence subjecting
them to frequency response requirements is uneconomic.
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Comments:
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001265
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001266
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Most of the frequency recovery happens in first 30 seconds. Thus anything
more than 30 seconds is unnecessary. It is also seen that the response of a
unit varies greatly within that 30 seconds period. Thus, it is very important
that the measured response be the average response over the 30 seconds
period and not be the response at 30 seconds.
Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001267
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Anita Lee
Organization: AESO - Alberta Electric System Operator
Telephone:
403 539 2497
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001268
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Page 2 of 6
Region* Segment*
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001269
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001270
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The purpose is definitely suggested for under frequency conditions. However,
when specifying that the generators shall have governors with droop etc...
the role of the governor is for both high and low frequency conditions and not
just underfrequency FRR. In a market environment it is very possible that not
every generator will provide FRR services. Thus, the governor and governor
deadband should be a requirement to interconnect to a power system.
Generators that provide FRR shall have responsive governor and prime
mover.
The standard is based on balancing area response which will include
generators and in some jurisdications will include load. So is the intent that
whatever load is considered, additional FRR resources such as generators are
used to provide the required FRR?
What about load as FRR providers? Some industrial facilities are capable to
dynamically vary the load of the facility to frequency (ie virtual governor).
The standard should apply to FRR providers which can be generators and
loads.
We agree that generator owners have an obligation to have working
governors or provide explanations why not. The "10 MW" requirement should
be evaluated for consistency with other standards. This should not hold up
the progress of the SAR, but should be evaluated by the ultimate standard
drafting team. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001271
Comment Form for Second Posting of Frequency Response SAR
Yes
No
The Generator Operator may also have some responsibilities, such as the
selection of control modes.
We're not sure what the LSE can do regarding the standard. They cannot
control response from load. The exception may be coordination of frequency
response with UFLS.
Planners may have some responsibilities with regard to new interconnections
and also using observed frequency response in models as opposed to
theoretical response. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
There should be a safeguard in place, such that if frequency performance
declines, the industry reverts to the 1% minimum. Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001272
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Sixty seconds is a reasonable balance to capture the period prior to AGC
response. Comments:
6. Do you have other comments on the SAR?
No Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001273
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001274
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
CP9, Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
Northeast Power Coordinating Council
Contact Segment:
2
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
Kathleen Goodman
ISO-New England
NPCC
2
Ed Thompson
ConEdison
NPCC
1
Peter Lebro
National Grid US
NPCC
1
Al Adamson
New York State Rel. Council
NPCC
2
Bill Shemley
ISO-New England
NPCC
2
Ron Falsetti
The IESO, Ontario
NPCC
2
Murale Gopinathan
Northeast Utilities
NPCC
2
Ralph Rufrano
New York Power Authority
NPCC
1
Roger Champagne
TransEnergie HydroQuebec
NPCC
1
David Kiguel
Hydro One Networks
NPCC
2
Greg Campoli
New York ISO
NPCC
2
Jim Ingleson
New York ISO
NPCC
2
Alden Briggs
New Brunswick System Operator
NPCC
2
Donald Nelson
MA Dept of Tel. and Energy
NPCC
9
Guy Zito
Northeast Power Coor. Council
NPCC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001275
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001276
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
No - The intent of this SAR is unclear which highlights that this issue requires
additional studies and investigation. In the future, it may be beneficial to
develop a standard after a reliabliity issue is identified, and a specific
standard can be developed and implemented to address the issue.
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The proposed requirements nor the White Paper adequately make the case
that there is a need for a frequency response standard at this time. However,
it is recommended that the subject be further investigated. The analysis
should evaulate if a frequency response standard that addresses the three
major short term frequency control components (inertial response, governor
response, and automatic generation control) are required. The report writers
should include a broad range of participants including (at least) 3 OEM's
(original equipment manufacturers) representing steam, gas and hydro
generation control. Some specific issues that should be addressed are:
1. Inertial Response: Evaluate historical changes in the inertial response of
the electric grid as a result of changing power equipment designs and types of
load. For example, the addition of new industrial and aero-derivative turbinegenerators have lower inertia-power ratios than tranditonal nuclear/fossil
units and, in addition, they are not base loaded (as a result of more efficient
dispatching and improved power plant controls).
3. Governor Response: Evaulate generation governor performance as a
result of newer, more configurable prime mover controls. Digital controls
provide increased plant reliability, however, this may be at the expense of
decreased governor response. For example, the use of main steam pressure
controls on steam units and low NOx controls on gas turbines may produce
unexpected droop output responses.
3. Automatic Generation Control (AGC): Perform a control area survey to
determine if there is sufficient regulation capacity within control areas to
maintain generation and load balance. Include a review of incentives and
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001277
Comment Form for Second Posting of Frequency Response SAR
penalties for generators to respond accurately and reliably to AGC signals.
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
If required. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001278
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
This question is not clear. AGC control pulses generation every 5 seconds,
therefore, the measurement should be based on the amount of time it takes
to restore the generation load balance. Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001279
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001280
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
PJM - Corporate Development Division
Lead Contact:
Albert DiCaprio
Contact Organization:
PJM
Contact Segment:
2
Contact Telephone:
610 - 666 - 8854
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
Joseph D. Willson
PJM
RFC
2
Mark Kuras
PJM
RFC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001281
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001282
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
The Resources Subcommittee in a response to the first draft states "A primary
purpose of this standard is to collect information so informed decisions can be
made before there is a problem." It is clear from that reply that the Resources
Subcommittee wishes to undertake an analysis of the system and needs to
collect additional information. This data collection effort may be laudable but
it does not rise to the level of being a federally enforced mandatory standard.
What if later on the 'data' were to show there is no problem, then there will
be a need to rescind the standard and repay those who were non-compliant
to a data collection effort.
In their response to the first draft, the Resources Subcommittee cite a WECC
study. But they have no similar study for the East. The Resources
Subcommittee still has not shown that the decrease in sub-minute response is
either (1) a problem or (2) nothing more than an indication that a larger
system has more inertia and therefore less response that the smaller system
in the past.
This SAR, with its present theoretical focus, posits the BA as the responsible
entity for governor response. Even those who agreed with the first posting
that Frequency Response is an important issue - stated that a standard
cannot define fixed norms (MRO, NYISO, IESO(2) ). The BA is not responsible
to instantaneous response -at best it can establish a capacity obligation but it
can't guarantee continuous response.
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The SAR is still not clear about what is to be developed in the standard. Of
the ten bulleted items several seem to show a misunderstanding between a
sub-minute frequency response obligation and Automatic Generation control.
The RS must make clear what it wants to do. Sub-minute frequency response
occurs with or without frequency bias; sub-minute frequency response is not
helped or hurt by having AGC. This is a major problem with the proposal. It is
not clear and it is not definitive.
Page 4 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001283
Comment Form for Second Posting of Frequency Response SAR
Item 1 indicates the standard will be a Report
Item 2 states the standard will be flexible (that is mandated in the Process
Manual)
Item 3 seems to indicate that non-compliance will be met with a requirement
to analyze the incident (if this is standard is so important why isn't every
event critical?)
Item 5 is the most unusual - the standard will not mandate a response but
will provide "LONG-TERM" targets (how is it that a sub-minute response gets
translated into a long-term target?)
Item 6 is to mandate AGC. This is not related to sub-minute frequency
response.
Item 7 is to mandate a post-incident survey. Again this is a good idea but it a
data collection mandate - it is not a frequency response standard. The RS has
the tools to collect that information today, without the need to resort to
mandatory penalties.
Item 10 will allow generators to seek exceptions (which means that the RS
will allow a generator to opt out and still require the BA to comply. In the
absurd case that all generators opt out (let's say the BA has only nuclear
units) then according to the RS, the BA is held non-compliant. This is just not
a good idea.
In summary: #1 is a calculation and report on response but no measure of
performance; #3 requires a BA and the RRO to perform an analysis if
response is measurable (by what amount) below the norm (which is a
constantly moving value); #4 is the only possibility for true standard; #9
generators must have governors is more a certification issue than a BA
standard. Three of the bullets are not requirements (#2, #5, and #10). Two
of the bullets are already in other standards while two of the bullets duplicate
each other. The SAR team needs to better describe exactly what is being
proposed to be in the standard so that the industry can evaluate the proposal.
The industry does not need to get involved in a research project. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
This question would require an assumption of what the standard would be. If
the standard is to provide sub-minute frequency response, then the only
entity should be the generator owner.
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
Page 5 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001284
Comment Form for Second Posting of Frequency Response SAR
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
The RS again is avoiding the issue of what sub-minute frequency response it
MUST mandate. The 1% is related to the frequency bias setting (basically a
long term average response). The BRD deals with the longer term issue of
frequency response - this standard was designed for the shorter-term
response.
If the RS is willing to accept under-biased systems then it would seem to be
going against conventional wisdom, and should explain why it would even
consider such an idea. If the real intent of this frequency SAR is to establish
a minimum frequency response value then the SAR needs to state that.
Perhaps the SAR should establish a minimum 1 minute response for every
generator (if they can't provide it they are obligated to contract for it from
another unit) and maybe a 1 minute average over a week, month, or year if a
longer term value is needed. However, since the SAR authors state the
problem is sub-minute response, it is suggested that the long term response
is better be addressed by the BRD standard.
In addition the SAR does not adequately address the load portion of the
frequency response. The standard seems to presuppose the solution is having
governors.
Comments:
Page 6 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001285
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Unsure as to what is being suggested here. The SAR drafters need to be
specific about what requirements are needed and how they will be measured.
The details contained in the white paper are supporting information but they
do not define the standard that is being proposed. Comments:
6. Do you have other comments on the SAR?
Please be clear about the terminology. Frequency response comes in many
flavors - sub-minute; several minutes; and hours. The RS seems to touch on
all of them in this proposal.
Comments:
Page 7 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001286
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001287
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization (MRO)
Lead Contact:
Terry Bilke
Contact Organization:
Midwest ISO
Contact Segment:
2
Contact Telephone:
317-249-5463
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
Al Boesch
NPPD
MRO
2
Robert Coish
MHEB
MRO
2
Dennis Florom
LES
MRO
2
Ken Goldsmith
ALT
MRO
2
Todd Gosnell
OPPD
MRO
2
Wayne Guttormson
SPC
MRO
2
Darrick Moe, Chair
WAPA
MRO
2
Tom Mielnik
MEC
MRO
2
Pam Oreschnick
XEL
MRO
2
Dick Pursley
GRE
MRO
2
Dave Rudolph
BEPC
MRO
2
Jim Maenner
WPS
MRO
2
Joe Knight, Secretary
MRO
MRO
2
27 Additional MRO Members
Companies Not Named Above
MRO
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001288
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001289
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
In particular we agree that generator owners have an obligation to have
working governors or provide explanations why not. The 10 MW requirement
should be evaluated for consistency with other standards. This should not
hold up the progress of the SAR, but should be evaluated by the ultimate
standard drafting team. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
The Generator Operator may also have some responsibilities, such as the
selection of control modes.
We're not sure what the LSE can do regarding the standard. They cannot
control response from load. The exception may be coordination of frequency
response with UFLS.
Planners may have some responsibilities with regard to new interconnections
and also using observed frequency response in models as opposed to
theoretical response. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001290
Comment Form for Second Posting of Frequency Response SAR
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
There should be a safeguard in place, such that if frequency performance
declines, the industry reverts to the 1% minimum. Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001291
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
This is a significant issue, because if the governor system withdraws the unit's
support prior to the recovery of frequency, this does have a problematic
impact. A period of at least 60 seconds should be considered, and 60 seconds
may not be adequate as often frequency recovery of the interconnection
extends beyond the initial 60 seconds. Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001292
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001293
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001294
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001295
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Yes, with respect to the responses to the IESO's comments. However, the
revised SAR appears to get somewhat mixed up between sub-minute
frequency response performance with a longer term (> 1 minute)
performance, and lacks clarity on what the proposed standard is intended to
stipulate.
Is the proposed standard intended to stipulate:
(a) a minimum frequency response performance level with which to
determine if follow-up analysis is to be conducted, or,
(b) requirements for calculating, measuring, reporting and analyzing
frequency response, or,
(c) both, in addition to,
(d) requirements for generators to be equipped with governors and if so, the
target to be responding to?
If (a) is not specified in the standard, we see a difficulty in stipulating the
threshold for (b) and the target for (d).
From the SDT's response to our previous comments ("The new requirements
may need to be field tested for an extended duration before compliance with
the requirements becomes mandatory. A long field test with extensive data
collection may be needed before justifiable minimum performance standards
can be identified"). It is our belief the standard is intended to stipulate (b)
only. We see this as a necessary first step. However, it may then beg the
question of the need of having a standard to develop the basis for a future
standard. Might there not be other alternatives to achieve (b) such as by
means of a request from the standing committees or NERC to the BAs and the
regions to compile this information? Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The intent of some of the requirements is again unclear to the IESO, for
example.
Page 4 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001296
Comment Form for Second Posting of Frequency Response SAR
(i) Does Bullet #2 mean the flexibility in the calculation and reporting process
or in the target/minimum frequency response level?
(ii) Assuming Bullet #4 a requirement, and one which relates to the minimum
level of frequency response, how is this requirement stipulated at this time
while data collection and follow-up analysis are to be proposed as standard
requirements and field testing has yet to commence? Same comment applies
to Bullet #9.
(iii) Bullet #6 appears to go beyond the sub-minute time frame. Further, we
are unable to understand the leading sentence "Will not mandate a given
amount of frequency response". We feel it is important that if poor frequency
response performance in the sub-minute time frame is to be assessed and
improved, specific target which may well be the minimum amount of
frequency recovery would need to be stipulated.
(iv) Bullet #7 also appears to be beyond the sub-minute time frame, which is
to mandate AGC but which should be covered by other BAL standards.
(v) Bullets #8 and #1 appear to be the main requirements for the proposed
standard that are achievable at this time.
(vi) As mentioned in (ii) above, we are unable to visualize how the range and
target of response be stipulated in the standard before Bullets #1 and #8 are
implemented.
(v) If generators are allowed to seek exception, the standard should provide
some basic premise that bounds the exception cases rather than leaving the
door wide open and the decision solely to the judgment of the BAs and RROs.
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Not having a good handle on what the standard is intended to achieve and
stipulate, we are unable to comment on whom the standard should apply to.
Among the ones included in the question, we are unclear on the role of the RC
in requiring anyone to install devices or take actions to improve frequency
response in day to day operation.
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
Page 5 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001297
No
(i) The question seems to get the sub-minute and longer-term targets
intertwined. We are unclear on which "standard be provided an incentive". Is
it the proposed sub-minute standard which has yet to be determined or the
current standard on Bias? If it is the former, then this question seems a bit
premature as we don't even know what the performance target for subminute response should be. If it's the latter, then the issue belongs to other
BAL standards.
Comments:
Page 6 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001298
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
This should cover the entire spectrum of immediate response before AGC
kicks in. Comments:
6. Do you have other comments on the SAR?
(i) The SAR does not address the load portion of the frequency response but
it indicates that the standard would apply to the LSEs as well. Please clarify or
eliminate LSE from the Reliability Function check list.
(ii) We feel that the SAR needs to be very clear on what the proposed
standard is intended and what will be included. Conducting calculation,
measuring and report on frequency excursion events followed by analysis
would help to ascertain whether or not poor performance exists. However, the
determination of poor performance also relies on having a minimally
acceptable level to gauge. If the standard is to provide requirements for
calculation, reporting and conducting analysis only, then there needs to be
some general guideline on the threshold for reporting and analyzing, which in
turn begs the question of should this "guideline" be included as the initial
standard, whose compliance would not be enforced until sufficient experience
has been gained and field test conducted, with possible revision as experience
and field test so suggest. Absent a minimum performance level, the
requirements for governor setting would be difficult to determine. Comments:
Page 7 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001299
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Howard F. Illian
Organization: Energy Mark, Inc.
Telephone:
847-913-5491
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001300
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001301
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001302
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
There is an expectation apparent in the first set of responses that indicates
that the drafting team believes they have more knowledge of the solutions
that will be required than the final standard will contain. The two greatest
areas of insufficient understanding lie in the measurement of Frequency
Response at less than the full interconnection level and the effect of the
standard as envisioned on markets. These two problems are addressed in the
comments to later questions in this comment form. Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Requirements that apply to individual generators cannot be implemented as
indicated in the standard without failing to comply with Market Interface
Principle 2. Frequency Response (Governor Response) have economic costs
associated with standing ready to supply. These costs have been
documented in EPRI Reports on Ancillary Services. If any generator is given
an exception to not provide a response, that generator will also be given a
market advantage resulting from the savings they will receive by not
providing a response. The SAR as currently written will create a market
advantage for all generators below 10 MW and all generators that are given
an exception to the governor response requirement. The alternatives to
these generator requirements are either not have a competitive market and
decide the provision of frequency response administratively (the old VIU
method), or determine who provides frequency response through a
competitive market process. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Page 4 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001303
The requirements applicable to the Generator Owner and Load-serving Entity
may only include requirements for measurement processes, not necessairly
requirements to provide any frequency response. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
There is a minimum frequency response below which the interconnection will
be less reliable than acceptable. We currently do not know what this value is
but we do know that a value exists. We also know that this value is less than
the 1% of peak load specificed in the current standards. A standard that
arbitrairly requires a 1% of peak load response without a technical
justification based on reliability cannot be called a reliabiltiy standard.
However, even though we do not know the minimum frequency response
below which the interconnection will be less reliable than acceptable, we can
perform the work necessary to estimate a reasonable value for a minimum
frequency response and assign responsibility for that response among the
Balancing Authorities on an interconnection. A Frequency Response Standard
without this characteristic cannot maintain reliability of the interconnection.
Comments:
Page 5 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001304
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
There are two issues associated with this question. The first is that the
change in instantaneous frequency be limited to within a range that limits the
risk of a cascading outage on the interconnection. The second is that each
generation technology provides a different response characteristic within the
first minute after a sudden frequency excursion. Work performed at NIPSCo
and published by IEEE indicated that a measurement interval of one to two
minutes worked well for the measurement of frequency response. Without
specific knowledge of the nature of the individual responses that make up the
sustained frequency response to an excursion, it may be difficult to justify the
selection of a measurement interval shorter than one-minute that might put
some generation technologies at a disadvantage with respect to the
measurement method. This is a subject that the drafting team should
technically evaluate before including a specific measurement period in the
standard. Comments:
6. Do you have other comments on the SAR?
The current measurement methods for determining individual Balancing
Authority Frequency Response may not be reliable. This is because the
current measurement methods only capture a small sample of the frequency
responses provided limited to only several minutes per year. The metering
methods we currently use on the interconnection can shed some light on this
problem. Since the each BA measures its Tie Line Error with common
metering with adjancent BAs, the sum of the Tie Line Errors over the total
interconnection must equal zero at all times. Each tie line has a positive error
for one BA and a negative error of equal value to the other BA that the tie line
connects. If the errors must sum to zero, then the change in errors must also
sum to zero between any two points in time. Since the Frequency on an
interconnection is the same throughtout the interconnection at any point in
time for the purpose of the frequency response measurement, the change in
frequency between two points in time must also be the same throughout the
interconnection. Therefore, the change in tie-line error divided by the change
in frequency must indicate a total frequency response for the interconnection
as measured by the sum of the individual BA frequency responses must be
equal to zero. In other words, there is a BA or a set of BAs that cause each
frequency response on the interconnection. Only knowledge of the
distribution of individual frequency responses among BAs will provide the
necessary information to determine whether or not the frequency response
indicated by current measurement methods will maintain adequate reliablity.
It may not be the average frequency response to large events that indicates
interconnection reliability, but the distribution of frequency responses among
BAs including both the positive and negative responses. Therefore, the
measurement methods included in the standard should have the goal of
Page 6 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001305
Comment Form for Second Posting of Frequency Response SAR
capturing the distribution of both positive and negative frequency responses
over the entire range of frequency operation should be a goal of standard.
The measurement methods suggested will not accomplish this goal.
Comments:
Page 7 of 7
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001306
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization: Southern Company Transmission
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001307
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Marc Butts
Contact Organization:
Southern Company Services (SCS)
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
Raymond Vice
SCS Bulk Power Operations
SERC
1
Jim Busbin
SCS Bulk Power Operations
SERC
1
Roman Carter
SCS Bulk Power Operations
SERC
1
J T Wood
SCS Bulk Power Operations
SERC
1
Jim Viikinsalo
SCS Bulk Power Operations
SERC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001308
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001309
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
The 1% minimum frequency bias is obsolete and does not take into account
the changes in interconnection frequency response over recent years. If not
modified, it will lead to increased frequency oscillations within the
interconnections and needless maneuvering of generating assets with
associated wear and tear on these assets.
Comments:
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
Page 5 of 6
001310
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001311
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
AGC response begins within only a few seconds after the disturbance with a
maximum ramp rate achieved within three to five minutes. Governor
response and load frequency response typically peak within 30 seconds.
There is some logic to monitoring governor respone for sustainability past its
initial peak, but we have not seen anything about that in this SAR.
Comments:
6. Do you have other comments on the SAR?
In our opinion, this SAR, or one like it, is required to ensure that the primary
frequency response of the interconnections and the BAs do not deteriorate to
a point where 1) the interconnection can not adequately respond to major
generator trips (including potential multiple contingencies which, though rare,
do happen) and 2) primary frequency response of the BAs is inadequate to
support islanding during severe local disturbances, thus allowing local
disturbances to cascade into regional or interconnection wide disturbances.
Primary frequency response is declining in at least the Eastern and Western
Interconnections. WECC has taken a proactive approach to addressing this
problem, but there is no similar work being done in the Eastern
Interconnection. This SAR, or one like it, is needed to take the best practices
in the industry, wherever they may be found, and utilize them to protect the
interconnections from disturbances that could be avoided if we take action
now rather than waiting until the problems actually occur.
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001312
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jeff Baker
Organization: Duke Energy Midwest
Telephone:
513-287-3368
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 5
April 3, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001313
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
N/A
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 5
April 3, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001314
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 5
April 3, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001315
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Not totally, I need to understand more of what would be reuired to meet the
obligation of Generator owners to equip generating units with nameplate
ratings of 10 MW or greater, with a governor capable of providing immediate
and sustained response to frequency deviations. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
I believe that an incentive should be included in the standard Comments:
Page 4 of 5
April 3, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001316
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
I did not provide an answer but believe that this is a decision that could be
made over time and not necessarily with the inception of the standard..
Comments:
6. Do you have other comments on the SAR?
I believe we have to address the frequency issue, but feel that it can be
developed over time proactivly. Comments:
Page 5 of 5
April 3, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001317
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 5
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001318
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
WECC Reliability Coordination Subcommittee
Lead Contact:
Terry Baker
Contact Organization:
WECC
Contact Segment:
2
Contact Telephone:
970-229-5341
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
Nancy Bellows
WACM
WECC
1
Tom Botello
SCE
WECC
1
Rich Cornelius
RDRC
WECC
2
Robert Johnson
PSC
WECC
1
Bert Peters
APS
WECC
1
Greg Tillitson
CMRC
WECC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 5
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001319
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 5
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001320
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
The WECC RCS believes that although this SAR is applicable to the WECC
Reliability Authority (RA), it is not applicable to the WECC Reliability
Coordinator (RC). Surveys, etc. will be performed after-the-fact, not during
real-time. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Comments:
Page 4 of 5
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001321
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Comments:
6. Do you have other comments on the SAR?
Comments:
Page 5 of 5
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001322
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001323
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
BPA
Lead Contact:
Bart McManus
Contact Organization:
BPA
Contact Segment:
1,3,5,6
Contact Telephone:
360-418-2309
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
John Anasis
Lynn Aspaas
Mike Viles
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001324
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001325
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
We are still concerned with a NERC standard countering some aspects of the
standard we are in the process of drafting in WECC, so will continue to be
active on the drafting team to insure it does not adversely impact the WECC
standard. Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
RE: bullet 2: Instead of flexibility to meet interconnection needs, each
interconnection should have its own requirements on frequency response, this
is due to the unique frequency response of each interconnection.
re bullet 4: This Standard will need to measure frequency response for the
duration of the frequency deviation. Measuring it until frequency recovers will
overlap with the Balance Resources and Demand standard slightly, but will
give much better results than simply going out a few minutes.
re bullet 6: Target levels should be BA specific to insure there is not an
incentive to lean on other BA's. How will the target levels be calculated?
Re bullet 7: BAs must be free to operate their automatic generation control in
any method they desire. The tie-line frequency bias is used for compliance
monitoring, but must not be a requirement for the actual automatic
generation control algorithm. Recommend this be modified to state:
Balancing Authorities will calculate an Area Control Error for monitoring
purposes using tie-line frequency bias.
re bullet 8: WECC should call FRC surveys for WECC instead of NERC.
re bullet 9: Recommend generating unit nameplate of 10 MW plus multi-unit
installations of 10 MW or greater be required to have a governor(s) capable of
providing immediate and sustained response to frequency deviations.
Re bullets 9 and 10: Currently wind generation does not have governor
response capability. Due to the amount of wind integration planned in the
next decade, new installations should have a requirement for frequency
responsive units. Historically, requirements have provided incentive for
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001326
Comment Form for Second Posting of Frequency Response SAR
manufacturers to modify machine design (low-voltage ride-through capability,
voltage control capability) to meet the requirements.
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
The only portion we can think of that would applicable to the Load-serving
entity is for the load-serving entity to report their underfrequency load
shedding settings. We believe LSEs should be removed as applicable entities.
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
The standard should not provide an incentive, but the standard should
provide a methodology that would allow a Balancing Authority to calculate a
bias based on their natural response, provided that response is above an
acceptable target. Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001327
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
The standard should measure out to when the frequency recovers. This could
be up to the 15 minute DCS limit. AGC control may or may not kick in within
60 seconds depending on deadbands, etc. However, generators on setpoint
control may hold for between 10 and 60 seconds then drop back off prior to
AGC pulses reaching the generator. In order to see the full response of a BA
it is necessary to see data for the full event rather than just the first minute.
Rather than overlapping the BRD standard, this will work hand-in-hand with
this standard. Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001328
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Tom Pruitt
Organization: Duke Energy Carolinas
Telephone:
704-382-4676
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001329
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001330
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001331
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Generally, yes, but more clarity is desired on a number of points, e.g., who
decides which generators will be granted exemptions - the BA or the RRO;
who sets the criteria - BA or RRO. In addition, I think some of the proposed
requirements may conflict with each other as details are driven out; if a
number of a BA's generators applied for and were granted exemptions from
governor response, the (anticipated) 5% droop range may need to be
adjusted for the generators which do provide governor response for the BA.
Governor response is not the only equipment consideration at the plant/unit.
Plant/unit control systems also should be operated so that the desired unit
response will occur and be sustained. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
However, the standard applies to each entity in different ways. The lion's
share of responsibility lies with the BA to insure that the aggregate of the Gen
Owners responses provide the response needed. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001332
Comment Form for Second Posting of Frequency Response SAR
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Calculation of each BA's bias should be based on a rigorous analysis which
demonstrates that the BA can provide the expected response, regardless of
peak load. This is consistent with the proposed requirements - 'technicallysound calculation and report of frequency response' and 'Will not mandate a
given amount of frequency response'. Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001333
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
At least. Based on the words in the SAR Purpose statement, 'this proposed
standard coordinates with and complements the Balance Resources and
Demand standards, which addresses Interconnection frequency control
generally 5 minutes and longer', it seems that this standard should cover out
to the 5 minute mark of an event. AGC actions will commence at the first
scan cylcle or two after the event (5 -15 secs), but the actual generation
response may not settle out for several minutes, depending on the type and
amount of generation on AGC at the time. Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001334
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jason Shaver
Organization: American Transmission Company LLC
Telephone:
262 506 6885
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001335
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001336
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001337
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
The SAR identifies Load-Serving Entities as a function that will be affected by
any requirements that are developed from this SAR. Question three, on this
comment form, goes one step further and asked the industry if the proposed
standard would be applicable to Load-Serving Entities. ATC was unable to
determine from the detailed description section any requirements that would
apply to a Load-Serving Entity. With that being said ATC suggests that
language be added to the SAR that would require the Load-Serving Entities to
be responsible for procurement of adequate frequency response.
ATC found bullet number six lacks a clear description of the standard that
could be developed. ATC recommends that this bullet be rewritten to better
inform the industry of the type of standard the SAR requestor wants
developed. Is the SAR requestor requesting a standard that will not mandate
frequency response, but instead recommend a frequency response? ATC, in
general, feels that standards should require something not make
recommendation. or, Is the SAR requestor requesting that a standard be
develop that would set long-term Interconnection target levels and then
require the industry to meet those target-levels? ATC is in support of a
standard that would require entities to set long-term target levels and require
other entities to meet the determined target levels. ATC is not in support of a
standard that requires functions to set long-term target levels but not require
other entities to meet those levels. Lastly, this bullet should clearly identify
who are the responsible entities.
ATC is concerned that Generator Owners could be allowed to categories the
same generating units differently. A Generator Owner that aggregates their
units for purposes of determining a voltage schedule (VAR-001-1) should then
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001338
Comment Form for Second Posting of Frequency Response SAR
not be allowed to individualize their units for this standard to escape under
the nameplate rating of 10 MW. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Please see comment in questions two about the Load-serving Entity.
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Although ATC is in support of this recommendation, we feel that it should be
classified as an "allowable exemption" not an "incentive". Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001339
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001340
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization: NERC Resources Subcommittee
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001341
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
NERC Resources Subcommittee
Lead Contact:
Terry Bilke
Contact Organization:
Resources Subcommittee
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
Raymond Vice
Southern Company
SERC
John Tolo
TEP
WECC
Rhett Trease
Duke Power
RFC
Sydney Niemeyer
Texas
ERCOT
Don Badley
RS Vice Chairman
WECC
Carlos Martinez
CERTS
Robert Rhodes
SPP
Tom Vandervort
NERC
Terry Bilke
RS Chairman
RFC
Bill Herbslab
PJM
RFC
Larry Akens
TVA
SERC
Bart McManus
BPA
WECC
Mike Potishnak
NEISO
NPCC
Gerry Beckerle
AMREN
SERC
SPP
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001342
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001343
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Re Bullet 7 - BAs must be free to operate their automatic generation control
in any method they desire. The tie-line frequeency bias is used for
complinace monitoring, but should not be a requirement for the actual
automatic generation algorithm. Recommend this be modified to state :
Balancing authorities will calculate an Area Control Error for compliance
reporting purposes using tie-line frequency bias. Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
The proposed standards may apply to LSEs when demand side resources are
utilized for frequency control, but will not apply to many of the LSEs. There
may also be cases where Generator Operators have obligations under the
standard. Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001344
The 1% minimum frequency bias should be evaluated to take into account the
reliability requirements of the interconnections. frequency response over
recent years. We suggest that the minimum bias be addressed during the
development of the Frequency Response Standard. It is unclear what the
word "incentive" means above.
Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001345
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
AGC response begins within only a few seconds after the disturbance with a
maximum ramp rate achieved within three to five minutes. Governor
response and load frequency response typically peak within 30 seconds.
There is logic to monitoring governor respone for sustainability past its initial
peak and this should be investigated during standard development.
Comments:
6. Do you have other comments on the SAR?
In our opinion, this SAR, or one like it, is required to ensure that the primary
frequency response of the interconnections and the BAs do not deteriorate to
a point where 1) the interconnection can not adequately respond to major
generator trips (including potential multiple contingencies which, though rare,
do happen) and 2) primary frequency response of the BAs is inadequate to
support islanding during severe local disturbances, thus allowing local
disturbances to cascade into regional or interconnection wide disturbances.
Primary frequency response is declining in all Interconnections, Eastern,
Western and ERCOT. WECC and ERCOT have taken a proactive approach to
addressing this problem, but there is no similar work being done in the
Eastern Interconnection. This SAR, or one like it, is needed.
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001346
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Bruce Sembrick
Organization: Tri-State Generation and Transmission Association
Telephone:
303 254-3675
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001347
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region* Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001348
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001349
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Since the standard is concerned with governor regulated frequency response
of generating units that applicability should also apply to the Generator
Operator (currently this box is not checked). It will ultimately be the
Generator Operators responsibility to ensure frequency responsiveness of the
units, e.g. ensuring that the unit is not operating in Valve Wide Open mode.
Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Yes
No
Comments:
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
Page 5 of 6
001350
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001351
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Comments:
6. Do you have other comments on the SAR?
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001352
Comment Form for Second Posting of Frequency Response SAR
Please use this form to submit comments on the second draft of the Frequency
Response SAR. Comments must be submitted by May 3, 2006. You must submit
the completed form by emailing it to [email protected] with the words “Frequency
Response” in the subject line. If you have questions please contact Maureen Long at
[email protected] or 813-468-5998.
ALL DATA ON THIS FORM WILL BE TRANSFERRED AUTOMATICALLY TO A
DATABASE.
DO:
Do
Do
Do
Do
enter text only, with no formatting or styles added.
use punctuation and capitalization as needed (except quotations).
use more than one form if responses do not fit in the spaces provided.
submit any formatted text or markups in a separate WORD file.
DO NOT: Do
Do
Do
Do
not
not
not
not
insert tabs or paragraph returns in any data field.
use numbering or bullets in any data field.
use quotation marks in any data field.
submit a response in an unprotected copy of this form.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
NA – Not
Applicable
1 — Transmission Owners
2 — RTOs, ISOs, Regional Reliability Councils
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
Page 1 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001353
Comment Form for Second Posting of Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
ITCTransmission
Lead Contact:
Jim Cyrulewski
Contact Organization:
ITCTransmission
Contact Segment:
Transmission Owner
Contact Telephone:
248-374-7130
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region* Segment*
Beth Howell
ITCTransmission
RFC
1
Mike Moltane
ITCTransmission
RFC
1
Van Greening
ITCTransmission
RFC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of
these comments. Regional acronyms and segment numbers are shown on the
prior page.
Page 2 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comment Form for Second Posting of Frequency Response SAR
001354
Background Information
Please review the drafting team’s consideration of the comments submitted with the
first draft of the Frequency Response SAR and then review the drafting team’s
conforming changes made to SAR. Because the changes to the SAR were so
extensive, there is no ‘red line’ version to show the changes from the first draft.
Page 3 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001355
Comment Form for Second Posting of Frequency Response SAR
You do not have to answer all questions. Enter All Comments
in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that comments from the first posting of the SAR were adequately
addressed?
Yes
No
Comments:
2. Do you agree with the list of proposed requirements included in the detailed
description of the revised SAR?
Yes
No
However some bullets need further clarification
Bullet 2: The standards process allows for regional differences. What more
flexibility is needed?
Bullet 6: Keep this bullet simple by simply stating target levels will be set for
BAs and RROs to take actions cited. Also a sub-bullet needs to be added on
what are options to get additional frequency response; specifically for the
BAs. In particular what can the BAs do if the Generation Owners do not
provide adequate response. The BAs don't have generation interconnection
agreements, the transmission owners do.
Comments:
3. Do you agree that the proposed standard(s) would be applicable to the Reliability
Coordinator, Balancing Authority, Generator Owner, and Load-serving Entity?
Yes
No
Also pertains to Generator Operator Comments:
4. The current standard on Bias requires a Balancing Authority to carry a minimum
bias equal to 1% of peak load. As an example, in the Eastern Interconnection,
this value is double current natural frequency response. Should the standard
provide an incentive, such that a Balancing Authority can use a bias equal to their
natural response, but less than 1% of peak, if the response is above an
acceptable target?
Page 4 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001356
Comment Form for Second Posting of Frequency Response SAR
Yes
No
However this requirement still does not address the need for enough
frequency response on the system. Comments:
Page 5 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001357
Comment Form for Second Posting of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended
period after a frequency excursion, up to the point where automatic generation
control (AGC) would take over. This was to ensure initial response wasn’t
withdrawn prematurely. Should the standard measure out to 60 seconds
following an excursion?
Yes
No
Needs to be verified with a field trial. Comments:
6. Do you have other comments on the SAR?
Reliability and Market Interface Principles 3, 5 and 6 should be checked as
well.
Comments:
Page 6 of 6
April 4, 2006
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001358
Consideration of Comments on Second Draft of Frequency Response SAR
Background:
The Frequency Response SAR Drafting Team thanks all commenters who submitted comments on the
first draft of the SAR for Frequency Response. This SAR was posted for a 30-day public comment period
from April 4, 2006–May 3, 2006. The SAR DT asked stakeholders to provide feedback on the SAR
through a special SAR Comment Form. There were 16 sets of comments, including comments from more
than 59 different people from more than 41 companies representing 6 of the 9 Industry Segments as
shown in the table on the following pages.
The primary changes to the SAR were made based on comments:
• Clarification on the role of the LSE and Generator Operator.
• Inclusion of the applicability of Reliability Principles 3, 5 and 6.
• Reduced the scope to address only the collection of data needed to model Frequency Response in
North America.
In this ‘Consideration of Comments’ document stakeholder comments have been organized so that it is
easier to see the responses associated with each question. All comments received on the SAR can be
viewed in their original format at:
http://www.nerc.com/~filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Adamski at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Update:
The original SAR on Frequency Response was submitted in large part due to a study that showed a 10+%
decline in Eastern Interconnection Frequency Response over a 5 year period, when response should be
increasing over time as an Interconnection grows. The drafting team posted a whitepaper along with the
SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern Interconnection
Frequency Response and found it to be on the order of 2800MW/0.1Hz and still trending downward.
1
The appeals process is in the Reliability Standards Process Manual:
http://www.nerc.com/standards/newstandardsprocess.html.
January 9, 2007
Page 1 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001359
Consideration of Comments on Second Draft of Frequency Response SAR
Figure 1 Original Eastern Interconnection Frequency Response Study (Ingleson and Nagle)
Figure 2 Updated Eastern Interconnection Frequency Response (NERC Resources Subcommittee)
Based on these observations, at its June, 2006 meeting, the NERC Operating Committee
endorsed developing a frequency response standard that includes the following goals and
objectives:
- Improving Interconnection frequency response event cataloging and benchmarking
- Calculating balancing authority frequency response and requiring balancing
authorities to analyze those cases where the response is significantly below the norm
- Establishing time limits to complete the analyses
January 9, 2007
Page 2 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001360
Consideration of Comments on Second Draft of Frequency Response SAR
- Tabulating non-responsive generators
- Measuring generator response (including those units on line)
- Including regional participation and review
Unfortunately, the stakeholders who responded to the second draft of the proposed SAR offered
a wide range of opinions on what should be in the standard, without a clear consensus. Given
this, the drafting team revised the SAR to only require collection of data needed to model
frequency response in each of the interconnections. Once frequency response has been modeled
and analyzed, the Resources Subcommittee and the industry will be in a better position to
recommend specific frequency response targets for each Interconnection.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006.
January 9, 2007
Page 3 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001361
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
6
Ken Goldsmith
ALT
Baj Agrawal
APS
x
Bert Peters
APS
x
Dave Rudolph
BEPC
Bart McManus
BPA
x
x
x
x
John Anasis
BPA
x
x
x
x
Lynn Aspaas
BPA
x
x
x
x
Mike Viles
BPA
x
x
x
x
Greg Tillitson
CMRC
Edwin Thompson
ConEdison
Rhett Trease
Duke (NERC RS)
Tom Pruitt
Duke Energy Carolinas
x
x
x
x
Jeffrey T. Baker
Duke Energy Midwest
x
x
x
x
Howard Illian
Energy Mark, Inc.
Dick Pursley
GRE
David Kiguel
Hydro One Network
x
Anita Lee
IESO
x
Ron Falsetti
IESO (Ontario)
x
Kathleen Goodman
ISO-New England
x
Bill Shemley
ISO-New England
x
Jim Cyrulewski
ITC Transmission
Dennis Florom
LES
x
Donald Nelson
MA Dept of Energy and Tele.
x
Tom Mielnik
MEC
x
Robert Coish
MHEB
x
Terry Bilke
MISO
x
Pete Lebro
National Grid
Sydney Niemeyer
NRG Texas LP (NERC RS)
Alden Briggs
NBSO
Greg Campoli
New York ISO
x
James W. Ingleson
New York ISO
x
Alan Adamson
New York State Rel. Council
x
Don Badley
NWPP (NERC RS)
Brian Hogue
NPCC
x
Guy Zito
NPCC
x
Alan Boesch
NPPD
Murale Gopinathan
NU
January 9, 2007
7
8
9
x
x
x
x
x
x
x
x
x
Page 4 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001362
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
Mark Kuras
PJM
x
Joe Willson
PJM
x
Al DiCaprio
PJM
x
Robert Johnson
PSC
Rich Cornelius
RDRC
Wayne Guttormson
SaskPower
x
Tom Botello
SCE
x
Jim Busbin
Southern Company Services
x
Jim Viikinsalo
Southern Company Services
x
Marc M. Butts
Southern Company Services
x
Raymond Vice
Southern Company Services
x
Roman Carter
Southern Company Services
x
J.T. Wood
Southern Company Services
x
Wayne Guttormson
SPC
John Tolo
TEP (NERC RS)
Roger Champagne
TransEnergie (Quebec)
x
Bruce Sembeck
Tri-State Generation and
Transmission Association, Inc.
x
Nancy Bellows
WACM
x
Darrick Moe
WAPA
Terry Baker
WECC Reliability Coordination
Subc.
x
Jim Maenner
WPS
x
Pam Oreschnick
XEL
x
January 9, 2007
3
4
5
6
7
8
9
x
x
x
Page 5 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001363
Consideration of Comments on Second Draft of Frequency Response SAR
Index to Questions, Comments and Responses
1.
Do you agree that comments from the first posting of the SAR were adequately addressed? .......... 7
2.
Do you agree with the list of proposed requirements included in the detailed description of the
revised SAR?..................................................................................................................................... 12
3.
Do you agree that the proposed standard(s) would be applicable to the Reliability Coordinator,
Balancing Authority, Generator Owner, and Load-serving Entity? ................................................... 22
4.
The current standard on Bias requires a Balancing Authority to carry a minimum bias equal to 1% of
peak load. As an example, in the Eastern Interconnection, this value is double current natural
frequency response. Should the standard provide an incentive, such that a Balancing Authority can
use a bias equal to their natural response, but less than 1% of peak, if the response is above an
acceptable target? ............................................................................................................................. 25
5.
Several commenters suggested response should be measured for an extended period after a
frequency excursion, up to the point where automatic generation control (AGC) would take over.
This was to ensure initial response wasn’t withdrawn prematurely. Should the standard measure
out to 60 seconds following an excursion?........................................................................................ 28
6.
Do you have other comments on the SAR? ......................................................................................32
January 9, 2007
Page 6 of 34
1. Do you agree that comments from the first posting of the SAR were adequately addressed?
Summary Consideration: Most commenters indicated that the SAR drafting team did provide an adequate response to the comments
submitted with the first posting of the SAR.
Commenter
Energy Mark, Inc. (8)
Howard F. Illian
Yes
No
Comment
9
There is an expectation apparent in the first set of responses that indicates that the drafting
team believes they have more knowledge of the solutions that will be required than the final
standard will contain. The two greatest areas of insufficient understanding lie in the
measurement of Frequency Response at less than the full interconnection level and the effect of
the standard as envisioned on markets. These two problems are addressed in the comments to
later questions in this comment form.
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response in each of the interconnections. Once that data is collected and analyzed,
a standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
NPCC CP9 Reliability Standards
Working Group
K. Goodman – ISONE
Edwin Thompson – ConEd
Pete Lebro – Ngrid
Alan Adamson – NYSRC
Bill Shemley – ISONE
Ron Falsetti – IESO
Murale Gopinathan – NU
Ralph Rufrano – NYPA
R. Champagne – TransÉnergie
David Kiguel – Hydro One
Greg Campoli – NYISO
Jim Ingleson – NYISO
Alden Briggs – NBSO
Don Nelson – MA Dept. of Tel.
and Energy
Brian Hogue – NPCC
Guy Vito – NPCC
January 9, 2007
9
No - The intent of this SAR is unclear which highlights that this issue requires additional studies
and investigation. In the future, it may be beneficial to develop a standard after a reliabliity
issue is identified, and a specific standard can be developed and implemented to address the
issue.
Page 7 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001364
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: We agree that there needs to be additional studies and investigation. There were varying opinions on the scope of the second draft
of the SAR. The drafting team revised the scope of the SAR again to focus solely on collection of data needed to model frequency response in
each of the interconnections. Once that data is collected and analyzed, a standard can be proposed that includes performance requirements that
will motivate entities to operate in ways that keep frequency response within an acceptable range.
9
PJM Corporate Development
Div. (2)
Al DiCaprio
Joseph D. Willson
Mark Kuras
The Resources Subcommittee in a response to the first draft states "A primary purpose of this
standard is to collect information so informed decisions can be made before there is a problem."
It is clear from that reply that the Resources Subcommittee wishes to undertake an analysis of
the system and needs to collect additional information. This data collection effort may be
laudable but it does not rise to the level of being a federally enforced mandatory standard. What
if later on the 'data' were to show there is no problem, then there will be a need to rescind the
standard and repay those who were non-compliant to a data collection effort.
In their response to the first draft, the Resources Subcommittee cite a WECC study. But they
have no similar study for the East. The Resources Subcommittee still has not shown that the
decrease in sub-minute response is either (1) a problem or (2) nothing more than an indication
that a larger system has more inertia and therefore less response that the smaller system in the
past.
This SAR, with its present theoretical focus, posits the BA as the responsible entity for governor
response. Even those who agreed with the first posting that Frequency Response is an
important issue - stated that a standard cannot define fixed norms (MRO, NYISO, IESO (2) ).
The BA is not responsible to instantaneous response -at best it can establish a capacity
obligation but it can't guarantee continuous response.
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response in each of the interconnections. Once that data is collected and analyzed,
a standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
IESO (2)
Ron Falsetti
January 9, 2007
9
9
Yes, with respect to the responses to the IESO's comments. However, the revised SAR appears
to get somewhat mixed up between sub-minute frequency response performance with a longer
term (> 1 minute) performance, and lacks clarity on what the proposed standard is intended to
stipulate.
Is the proposed standard intended to stipulate:
(a) a minimum frequency response performance level with which to determine if follow-up
analysis is to be conducted, or,
(b) requirements for calculating, measuring, reporting and analyzing frequency response, or,
(c) both, in addition to,
(d) requirements for generators to be equipped with governors and if so, the target to be
responding to?
Page 8 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001365
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
If (a) is not specified in the standard, we see a difficulty in stipulating the threshold for (b) and
the target for (d).
From the SDT's response to our previous comments ("The new requirements may need to be
field tested for an extended duration before compliance with the requirements becomes
mandatory. A long field test with extensive data collection may be needed before justifiable
minimum performance standards can be identified"). It is our belief the standard is intended to
stipulate (b) only. We see this as a necessary first step. However, it may then beg the question
of the need of having a standard to develop the basis for a future standard. Might there not be
other alternatives to achieve (b) such as by means of a request from the standing committees or
NERC to the BAs and the regions to compile this information?
Response: There were varying opinions on the scope of the second draft of the SAR. The drafting team revised the scope of the SAR again to
focus solely on collection of data needed to model frequency response within each interconnection. Once that data is collected and analyzed, a
standard can be proposed that includes performance requirements that will motivate entities to operate in ways that keep frequency response
within an acceptable range.
BPA (1, 3, 5, 6)
Bart McManus
John Anasis
Lynn Aspaas
Mike Viles
9
We are still concerned with a NERC standard countering some aspects of the standard we are
in the process of drafting in WECC, so will continue to be active on the drafting team to insure it
does not adversely impact the WECC standard.
Response: We encourage WECC to be actively involved in the drafting of the standard. Note that the drafting team revised the scope of the
SAR so that the SAR focuses solely on the collection of data needed to model frequency response in each interconnection. This should not
conflict with WECC’s work on its frequency response standard.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
9
ATC LLC (1)
Jason Shaver
9
NERC Resources Subcommittee
Raymond Vice – SOCO
John Tolo – TEP
Rhett Trease – Duke
Sydney Niemeyer – Texas
9
January 9, 2007
Page 9 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001366
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Don Badley – NWPP
Carlos Martinez – CERTS
Robert Rhodes – SPP
Tom Vandervort – NERC
Terry Bilke – MISO
Bill Herbsleb – PJM
Larry Akens – TVA
Bart MaManus – BPA
Mike Pitishnak – ISONE
Gerry Beckerle – Ameren
Yes
IESO (1)
Anita Lee
9
Midwest Reliability Organization
(2)
Terry Bilke
Wayne Guttormson
Jim Maenner
Al Boesch – NPPD (2)
Terry Bilke – MISO (2)
Bob Coish – MHEB (2)
Dennis Florom – LES (2)
Ken Goldsmith – ALT (2)
Todd Gosnell – OPPD (2)
W. Guttormson – SPC (2)
Tom Mielnik – MEC (2)
Darrick Moe – WAPA (2)
P. Oreschnick – XEL (2)
Dick Pursley – GRE (2)
Dave Rudolph – BEPC (2)
Joe Knight – MRO (2)
9
Southern Company Transm. (1)
Marc Butts
9
January 9, 2007
No
Comment
Page 10 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001367
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Raymond Vice
Jim Busbin
Roman Carter
J.T. Wood
Jim Viikinsalo
Yes
Southern Company Transm. (1)
Marc Butts
Raymond Vice
Jim Busbin
Roman Carter
J.T. Wood
Jim Viikinsalo
9
January 9, 2007
No
Comment
Page 11 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001368
Consideration of Comments on Second Draft of Frequency Response SAR
2. Do you agree with the list of proposed requirements included in the detailed description of the revised SAR?
Summary Consideration: Most commenters disagreed with the proposed requirements included in the second draft of the SAR. The drafting
team revised the SAR to focus solely on the collection of data needed to model frequency response in each interconnection. Additional SARs may
be proposed in the future to propose requirements for operating in ways that support frequency response.
Commenter
Yes
No
Comment
The requirements on individual generator are unnecessary. The requirements should be on a
group of generators in a control area to achieve a desired response. Thus, one could have
some generators which are being operated as non responsive and the others which are
responding well to offset for those which are not responsive.
Additionally, the 10 MW size requirements are too restrictive and unnecessary. It should be
plant based and should apply to plants of 100 MW or more aggregate capacity. In any
realistic scenario, the smaller plants are not expected to contribute much to frequency
response and hence subjecting them to frequency response requirements is uneconomic.
Arizona Public Service Co. (1, 5)
Baj Agrawal
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional SARs may be proposed with specific performance requirements for generators.
IESO(1)
Anita Lee
9
The purpose is definitely suggested for under frequency conditions. However, when
specifying that the generators shall have governors with droop etc... the role of the governor
is for both high and low frequency conditions and not just underfrequency FRR. In a market
environment it is very possible that not every generator will provide FRR services. Thus, the
governor and governor deadband should be a requirement to interconnect to a power
system. Generators that provide FRR shall have responsive governor and prime mover.
The standard is based on balancing area response which will include generators and in some
jurisdications will include load. So is the intent that whatever load is considered, additional
FRR resources such as generators are used to provide the required FRR?
What about load as FRR providers? Some industrial facilities are capable to dynamically vary
the load of the facility to frequency (ie virtual governor). The standard should apply to FRR
providers which can be generators and loads.
We agree that generator owners have an obligation to have working governors or provide
explanations why not. The "10 MW" requirement should be evaluated for consistency with
other standards. This should not hold up the progress of the SAR, but should be evaluated
by the ultimate standard drafting team.
Response: The SAR drafting team agrees that governors must work for both high and low frequency events. One methodology under
discussion would monitor both high and low events. The logic behind capturing low frequency (typically associated with trips of large
generators) is that these events are much more common than large loss of load.
January 9, 2007
Page 12 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001369
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Any resource (load or generation) within the BA can provide frequency response. As envisioned, the standard would have provided a
methodology whereby a BA could monitor its FRR providers. Load, by default, would have been measured along with generators when the BA
calculated its performance.
We agree that all generators may not need to provide frequency response. As envisioned, as long as the BA had adequate response, it would
have had some flexibility under the proposed standard. Note, however, that the SAR has been revised and no longer includes these
performance requirements. The SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional SARs may be proposed with specific performance requirements
for generators.
As each new standard is developed, greater attention will be paid on the ‘applicability’. The threshold of ’10 MW’ will need to be reviewed from
a reliability-related perspective rather than ‘consistency across all standards’ perspective.
IESO (2)
Ron Falsetti
9
The intent of some of the requirements is again unclear to the IESO, for example.
(i) Does Bullet #2 mean the flexibility in the calculation and reporting process or in the
target/minimum frequency response level?
(ii) Assuming Bullet #4 a requirement, and one which relates to the minimum level of
frequency response, how is this requirement stipulated at this time while data collection and
follow-up analysis are to be proposed as standard requirements and field testing has yet to
commence? Same comment applies to Bullet #9.
(iii) Bullet #6 appears to go beyond the sub-minute time frame. Further, we are unable to
understand the leading sentence "Will not mandate a given amount of frequency response".
We feel it is important that if poor frequency response performance in the sub-minute time
frame is to be assessed and improved, specific target which may well be the minimum
amount of frequency recovery would need to be stipulated.
(iv) Bullet #7 also appears to be beyond the sub-minute time frame, which is to mandate
AGC but which should be covered by other BAL standards.
(v) Bullets #8 and #1 appear to be the main requirements for the proposed standard that are
achievable at this time.
(vi) As mentioned in (ii) above, we are unable to visualize how the range and target of
response be stipulated in the standard before Bullets #1 and #8 are implemented.
(v) If generators are allowed to seek exception, the standard should provide some basic
premise that bounds the exception cases rather than leaving the door wide open and the
decision solely to the judgment of the BAs and RROs.
Response: ”Flexibility to meet the needs of each Interconnection” was intended to mean some flexibility in calculation (for example ERCOT is
interested in “point C” (the extreme) of an event, but this point is not observable and has little value in the East. The WECC has expressed
January 9, 2007
Page 13 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001370
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
concern for extended contribution of response (perhaps out several minutes). As envisioned, there would have been different target levels in
each Interconnection. Interconnections would have been able to choose to have a tighter target droop setting.
Bullet 4 relates to a statistically-sound measurement of frequency response at both the Interconnection and BA level. The data would have
been collected and reported each year of the standard. In effect, the data collection in the first year of the standard would have served as the
field test.
“Long term target measure” intended to imply that the BA would be measured on many events over the year and its performance would have
been evaluated on the whole, not on single events.
It is true operation of AGC goes beyond the sub-minute window of time. The intent of this bullet was that the bias a BA provides should match
its natural frequency response. Just as was originally intended in Policy 1, a BA calculates its natural response in one year and uses those
observations to operate in the next year. The drafting team envisioned the same would occur in the originally proposed standard. The
establishment of the “12 month basis” either on a calendar year or on a rolling 12 month period like CPS1 would have been determined during
standard drafting.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional SARs may be proposed with specific performance requirements
for generators.
NPCC CP9 Reliability Standards
Working Group
January 9, 2007
9
The proposed requirements nor the White Paper adequately make the case that there is a
need for a frequency response standard at this time. However, it is recommended that the
subject be further investigated. The analysis should evaulate if a frequency response
standard that addresses the three major short term frequency control components (inertial
response, governor response, and automatic generation control) are required. The report
writers should include a broad range of participants including (at least) 3 OEM's (original
equipment manufacturers) representing steam, gas and hydro generation control. Some
specific issues that should be addressed are:
1. Inertial Response: Evaluate historical changes in the inertial response of the electric grid
as a result of changing power equipment designs and types of load. For example, the
addition of new industrial and aero-derivative turbine-generators have lower inertia-power
ratios than tranditonal nuclear/fossil units and, in addition, they are not base loaded (as a
result of more efficient dispatching and improved power plant controls).
2. Governor Response: Evaulate generation governor performance as a result of newer,
more configurable prime mover controls. Digital controls provide increased plant reliability,
however, this may be at the expense of decreased governor response. For example, the use
of main steam pressure controls on steam units and low NOx controls on gas turbines may
Page 14 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001371
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
produce unexpected droop output responses.
3. Automatic Generation Control (AGC): Perform a control area survey to determine if there
is sufficient regulation capacity within control areas to maintain generation and load balance.
Include a review of incentives and penalties for generators to respond accurately and reliably
to AGC signals.
Response:
When the first draft of the SAR was posted for comment, the drafting team asked stakeholders if they felt that there was a reliability-related
need for a standard that focuses on frequency response, and most stakeholders indicated there is a reliability-related need for a frequency
response standard.
While we don’t know the exact amount of frequency response needed for each interconnection, a 12 year decline in response when it is
expected to be increasing and without knowledge of where the response is low is a reliability concern.
Failure of generators to follow AGC signals would appear to be either a CPS issue or a business practice.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
Energy Mark, Inc. (8)
Howard F. Illian
9
Requirements that apply to individual generators cannot be implemented as indicated in the
standard without failing to comply with Market Interface Principle 2. Frequency Response
(Governor Response) have economic costs associated with standing ready to supply. These
costs have been documented in EPRI Reports on Ancillary Services. If any generator is
given an exception to not provide a response, that generator will also be given a market
advantage resulting from the savings they will receive by not providing a response. The SAR
as currently written will create a market advantage for all generators below 10 MW and all
generators that are given an exception to the governor response requirement. The
alternatives to these generator requirements are either not have a competitive market and
decide the provision of frequency response administratively (the old VIU method), or
determine who provides frequency response through a competitive market process.
Response: We appreciate the comments on Market Interface Principle 2. As envisioned the original SAR proposed measuring the
approximately 140 Balancing Authorities rather than the roughly 4000 individual generators (NERC 2004 Generating Unit Statistical Brochure).
The SAR intended to be indifferent to what entity provides response (whether load, large generator or small generator). It was intended to
measure the BA, with the expectation that the BA would have had to document exceptions that would have been reviewed by the BA and the
Region for reliability implications. As envisioned, the drafting team did not expect owners to install many small generators rather than one
larger generator to avoid providing data for the standard.
January 9, 2007
Page 15 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001372
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Note that the SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once
more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
9
Not totally, I need to understand more of what would be required to meet the obligation of
Generator owners to equip generating units with nameplate ratings of 10 MW or greater, with
a governor capable of providing immediate and sustained response to frequency deviations.
Response: As envisioned, all generators would have governors that respond to frequency deviations. The BA and the Region would need to
be aware of exceptions for study purposes. If the BA’s performance were significantly below the norm, an analysis and assessment would
have been required.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators.
BPA (1, 3, 5, 6)
January 9, 2007
9
RE: bullet 2: Instead of flexibility to meet interconnection needs, each interconnection should
have its own requirements on frequency response, this is due to the unique frequency
response of each interconnection.
re bullet 4: This Standard will need to measure frequency response for the duration of the
frequency deviation. Measuring it until frequency recovers will overlap with the Balance
Resources and Demand standard slightly, but will give much better results than simply going
out a few minutes.
re bullet 6: Target levels should be BA specific to insure there is not an incentive to lean on
other BA's. How will the target levels be calculated?
Re bullet 7: BAs must be free to operate their automatic generation control in any method
they desire. The tie-line frequency bias is used for compliance monitoring, but must not be a
requirement for the actual automatic generation control algorithm. Recommend this be
modified to state: Balancing Authorities will calculate an Area Control Error for monitoring
purposes using tie-line frequency bias.
re bullet 8: WECC should call FRC surveys for WECC instead of NERC.
re bullet 9: Recommend generating unit nameplate of 10 MW plus multi-unit installations of
10 MW or greater be required to have a governor(s) capable of providing immediate and
sustained response to frequency deviations.
Re bullets 9 and 10: Currently wind generation does not have governor response capability.
Due to the amount of wind integration planned in the next decade, new installations should
have a requirement for frequency responsive units. Historically, requirements have provided
incentive for manufacturers to modify machine design (low-voltage ride-through capability,
voltage control capability) to meet the requirements.
Page 16 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001373
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: We agree – the proposed standard would have assumed that each interconnection had a unique frequency response.
Regarding bullet 4, some thought would have to be given on how to measure over the entire duration of a frequency disturbance (typically up to
15 minutes for a DCS event) and how to remove AGC response from the estimate of frequency response. Suggestions are welcome.
However, the Interconnection would be able to define specific requirements.
Regarding bullet 8, WECC has the right to call FRC Surveys for WECC, as does NERC (historically through the NERC OC and Resources
subcommittee)
We agree with your comment regarding bullet 9.
Regarding wind generation, governor response is normally provided by calling on more energy from the prime mover when frequency drops.
We are unsure how this would normally be done with wind, unless the goal would be to under-utilize the wind during normal operation and then
call for full available energy when the frequency drops. Again, this standard as originally proposed, was intended to measure BA response- as
long as the pool of generation within the BA provided adequate response, it would have allowed the BA flexibility on which generators provide
that response.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators. This will allow analyses to focus on the different types of response and should, eventually, facilitate the
development of another standard that includes performance requirements aimed at providing a specified amount of frequency response.
ATC LLC (1)
Jason Shaver
January 9, 2007
9
The SAR identifies Load-Serving Entities as a function that will be affected by any
requirements that are developed from this SAR. Question three, on this comment form, goes
one step further and asked the industry if the proposed standard would be applicable to
Load-Serving Entities. ATC was unable to determine from the detailed description section
any requirements that would apply to a Load-Serving Entity. With that being said ATC
suggests that language be added to the SAR that would require the Load-Serving Entities to
be responsible for procurement of adequate frequency response.
ATC found bullet number six lacks a clear description of the standard that could be
developed. ATC recommends that this bullet be rewritten to better inform the industry of the
type of standard the SAR requestor wants developed. Is the SAR requestor requesting a
standard that will not mandate frequency response, but instead recommend a frequency
response? ATC, in general, feels that standards should require something not make
recommendation. or, Is the SAR requestor requesting that a standard be develop that would
set long-term Interconnection target levels and then require the industry to meet those targetlevels? ATC is in support of a standard that would require entities to set long-term target
levels and require other entities to meet the determined target levels. ATC is not in support
Page 17 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001374
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
of a standard that requires functions to set long-term target levels but not require other
entities to meet those levels. Lastly, this bullet should clearly identify who are the
responsible entities.
ATC is concerned that Generator Owners could be allowed to categories the same
generating units differently. A Generator Owner that aggregates their units for purposes of
determining a voltage schedule (VAR-001-1) should then not be allowed to individualize their
units for this standard to escape under the nameplate rating of 10 MW.
Response: We agree that the LSE is the ultimate beneficiary of frequency response. However, since the standard isn’t mandating a particular
amount of frequency response for individual events, it would seem inappropriate to have the LSE obtain a given amount of frequency response
for any specific event.
As originally proposed, this standard would have been primarily a technical/preparedness standard. Initially, the target levels of frequency
response would have been based on observed interconnection history.
We agree that bullet # 6 needs additional clarification for it to be understood. The long-term measure was envisioned to be an annual metric,
based on a calendar year or on a rolling 12 month basis like CPS1 that captures many events over the year to come up with a composite
estimate of performance. It was expected that the standard would allow interconnections to set their own frequency response limits. Absent
specific frequency response bounds for an interconnection, the standard would have used recent history. The standard was intended to focus
on the frequency response needs of each interconnection, and would have allocated a portion of each interconnection’s frequency response
responsibility to each of the interconnection’s Balancing Authorities.
Note that the SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once
more is known about frequency response, additional standards may be proposed with specific performance requirements for generators. This
will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
PJM Corporate Development Div.
(2)
January 9, 2007
9
The SAR is still not clear about what is to be developed in the standard. Of the ten bulleted
items several seem to show a misunderstanding between a sub-minute frequency response
obligation and Automatic Generation control. The RS must make clear what it wants to do.
Sub-minute frequency response occurs with or without frequency bias; sub-minute frequency
response is not helped or hurt by having AGC. This is a major problem with the proposal. It is
not clear and it is not definitive.
Item 1 indicates the standard will be a Report
Item 2 states the standard will be flexible (that is mandated in the Process Manual)
Item 3 seems to indicate that non-compliance will be met with a requirement to analyze the
incident (if this is standard is so important why isn't every event critical?)
Item 5 is the most unusual - the standard will not mandate a response but will provide
Page 18 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001375
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
"LONG-TERM" targets (how is it that a sub-minute response gets translated into a long-term
target?)
Item 6 is to mandate AGC. This is not related to sub-minute frequency response.
Item 7 is to mandate a post-incident survey. Again this is a good idea but it a data collection
mandate - it is not a frequency response standard. The RS has the tools to collect that
information today, without the need to resort to mandatory penalties.
Item 10 will allow generators to seek exceptions (which means that the RS will allow a
generator to opt out and still require the BA to comply. In the absurd case that all generators
opt out (let's say the BA has only nuclear units) then according to the RS, the BA is held noncompliant. This is just not a good idea.
In summary: #1 is a calculation and report on response but no measure of performance; #3
requires a BA and the RRO to perform an analysis if response is measurable (by what
amount) below the norm (which is a constantly moving value); #4 is the only possibility for
true standard; #9 generators must have governors is more a certification issue than a BA
standard. Three of the bullets are not requirements (#2, #5, and #10). Two of the bullets are
already in other standards while two of the bullets duplicate each other. The SAR team needs
to better describe exactly what is being proposed to be in the standard so that the industry
can evaluate the proposal. The industry does not need to get involved in a research project.
Response: The standard was intended to measure response within the first minute (or longer if determined it was needed by the
interconnection) following a frequency disturbance (which is prior to the timeframe when AGC contributes to frequency stabilization). Since
natural frequency response is much less than Bias for most control areas, AGC will make a contribution to frequency stabilization over a period
of time.
Regarding item 1, part of this technical/readiness standard was envisioned as a report, much as BAs are responsible to calculate and report
CPS or DCS. Refer to the NERC Reliability Standards Process Manual for the different types of standards.
Regarding item 2, thank you.
Regarding item 3, the standard would not have required analysis of single events, but rather performance over a 12-month period.
Regarding item 5, as envisioned, the BA would have calculated its response based on several events over the long term (12 months).
Interconnection performance is tracked by the Regions and NERC over years.
Item 6 refers to using a bias in AGC that is reflective of the BA’s natural frequency response. However, based on comments, the Resources
Subcommittee agrees this requirement more appropriately belongs in the AGC standard.
January 9, 2007
Page 19 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001376
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
Regarding item 10, the SAR was not proposing that generators may opt out of participation. As envisioned, generators were expected to have
governors that respond to frequency. Exceptions would have been documented. Nevertheless, the standard would have measured overall
BA response.
Note, however, that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection. Once more is known about frequency response, additional standards may be proposed with specific performance
requirements for generators. This will allow analyses to focus on the different types of response and should, eventually, facilitate the
development of another standard that includes performance requirements aimed at providing a specified amount of frequency response.
Duke Energy Carolinas (1, 3, 5,
6)
Tom Pruitt
9
9
Generally, yes, but more clarity is desired on a number of points, e.g., who decides which
generators will be granted exemptions - the BA or the RRO; who sets the criteria - BA or
RRO. In addition, I think some of the proposed requirements may conflict with each other as
details are driven out; if a number of a BA's generators applied for and were granted
exemptions from governor response, the (anticipated) 5% droop range may need to be
adjusted for the generators which do provide governor response for the BA.
Governor response is not the only equipment consideration at the plant/unit. Plant/unit control
systems also should be operated so that the desired unit response will occur and be
sustained.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
This will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
NERC Resources Subcommittee
9
Re Bullet 7 - BAs must be free to operate their automatic generation control in any method
they desire. The tie-line frequeency bias is used for complinace monitoring, but should not
be a requirement for the actual automatic generation algorithm. Recommend this be
modified to state : Balancing authorities will calculate an Area Control Error for compliance
reporting purposes using tie-line frequency bias.
Response: Based on comments, the Resources Subcommittee recommends this requirement more appropriately belongs in the AGC
standard.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
ITC Transmission (1)
Jim Cyrulewski
January 9, 2007
9
However some bullets need further clarification
Bullet 2: The standards process allows for regional differences. What more flexibility is
needed?
Page 20 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001377
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Beth Howell
Mike Moltane
Van Greening
Yes
No
Comment
Bullet 6: Keep this bullet simple by simply stating target levels will be set for BAs and RROs
to take actions cited. Also a sub-bullet needs to be added on what are options to get
additional frequency response; specifically for the BAs. In particular what can the BAs do if
the Generation Owners do not provide adequate response. The BAs don't have generation
interconnection agreements, the transmission owners do.
Response: As originally envisioned, the primary differences would have been at the Interconnection level. For example, it was envisioned that
there might be more than one authorized method that could be used by a BA to calculate response.
We agree that transmission owners have interconnection agreements that provide leverage to get generators to perform through “good utility
practices” provisions.
The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. Once more is
known about frequency response, additional standards may be proposed with specific performance requirements for generators. This will
allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that includes
performance requirements aimed at providing a specified amount of frequency response.
Midwest Reliability Organization
(2)
9
In particular we agree that generator owners have an obligation to have working governors or
provide explanations why not. The 10 MW requirement should be evaluated for consistency
with other standards. This should not hold up the progress of the SAR, but should be
evaluated by the ultimate standard drafting team.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
Once more is known about frequency response, additional standards may be proposed with specific performance requirements for generators.
This will allow analyses to focus on the different types of response and should, eventually, facilitate the development of another standard that
includes performance requirements aimed at providing a specified amount of frequency response.
With respect to the 10 MW threshold - As each new standard is developed, greater attention will be paid on the ‘applicability’. The threshold of
’10 MW’ will need to be reviewed from a reliability-related perspective rather than ‘consistency across all standards’ perspective.
Southern Company Transm. (1)
January 9, 2007
9
Page 21 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001378
Consideration of Comments on Second Draft of Frequency Response SAR
3. Do you agree that the proposed standard(s) would be applicable to the Reliability Coordinator, Balancing Authority,
Generator Owner, and Load-serving Entity?
Summary Consideration: Although most commenters agreed with the proposed applicability, the drafting team has reduced the scope of the
proposed standard, and the proposed applicability has been changed. The revised SAR shows that, in addition to the functional entities listed
above, the Generator Operator may have some requirements in the proposed standard.
Commenter
Yes
No
9
Tri-State G&T (1)
Bruce Sembeck
Comment
Since the standard is concerned with governor regulated frequency response of generating
units that applicability should also apply to the Generator Operator (currently this box is not
checked). It will ultimately be the Generator Operators responsibility to ensure frequency
responsiveness of the units, e.g. ensuring that the unit is not operating in Valve Wide Open
mode.
Response: Note that the SAR was revised and will address only the collection of data needed to model frequency response in each
interconnection.
We will include generator operator as an applicable entity.
9
PJM Corporate Development
Div. (2)
This question would require an assumption of what the standard would be. If the standard is to
provide sub-minute frequency response, then the only entity should be the generator owner.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
9
IESO. (2)
Ron Falsetti
Not having a good handle on what the standard is intended to achieve and stipulate, we are
unable to comment on whom the standard should apply to. Among the ones included in the
question, we are unclear on the role of the RC in requiring anyone to install devices or take
actions to improve frequency response in day to day operation.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
We expect the Reliability Coordinator’s role to be limited (most likely only alerting other Reliability Coordinators of generation or load events
causing significant frequency excursions)
9
Duke Energy Midwest (1, 3, 6)
Jeff Baker
IESO (1)
Anita Lee
January 9, 2007
9
9
The Generator Operator may also have some responsibilities, such as the selection of control
modes.
We're not sure what the LSE can do regarding the standard. They cannot control response
from load. The exception may be coordination of frequency response with UFLS.
Planners may have some responsibilities with regard to new interconnections and also using
observed frequency response in models as opposed to theoretical response.
Page 22 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001379
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The LSE does need to provide some of this data and is listed as an applicable entity in the revised SAR.
BPA (1, 3, 5, 6)
9
9
The only portion we can think of that would applicable to the Load-serving entity is for the
load-serving entity to report their underfrequency load shedding settings. We believe LSEs
should be removed as applicable entities.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The LSE does need to provide some of this data and is listed as an applicable entity in the revised SAR.
Duke Energy Carolinas (1, 3, 5,
6)
Tom Pruitt
9
However, the standard applies to each entity in different ways. The lion's share of
responsibility lies with the BA to insure that the aggregate of the Gen Owners responses
provide the response needed.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
WECC Reliability Coordination
Subc.
9
The only portion we can think of that would applicable to the Load-serving entity is for the
load-serving entity to report their underfrequency load shedding settings. We believe LSEs
should be removed as applicable entities.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
ATC LLC (1)
Jason Shaver
9
Please see comment in questions two about the Load-serving Entity.
Response: Please see the response to your comment on question 2.
Midwest Reliability Organization
(2)
9
The Generator Operator may also have some responsibilities, such as the selection of control
modes.
We're not sure what the LSE can do regarding the standard. They cannot control response
from load. The exception may be coordination of frequency response with UFLS.
Planners may have some responsibilities with regard to new interconnections and also using
observed frequency response in models as opposed to theoretical response.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
NERC Resources
Subcommittee
9
The proposed standards may apply to LSEs when demand side resources are utilized for
frequency control, but will not apply to many of the LSEs. There may also be cases where
Generator Operators have obligations under the standard.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
Energy Mark, Inc. (8)
January 9, 2007
9
The requirements applicable to the Generator Owner and Load-serving Entity may only
Page 23 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001380
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Howard F. Illian
Yes
No
Comment
include requirements for measurement processes, not necessairly requirements to provide
any frequency response.
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection.
The Load-serving Entity does need to provide some of this data and is listed as an applicable entity in the revised SAR.
NPCC CP9 Reliability
Standards Working Group
9
If required.
9
Also pertains to Generator Operator.
Response: Thank you.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
Response: The SAR was revised and will address only the collection of data needed to model frequency response in each interconnection. In
the revised SAR, the Generator Operator is responsible for providing data when the BA’s performance is below an Interconnection target.
Southern Company Transm. (1)
January 9, 2007
9
Page 24 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001381
Consideration of Comments on Second Draft of Frequency Response SAR
4. The current standard on Bias requires a Balancing Authority to carry a minimum bias equal to 1% of peak load. As
an example, in the Eastern Interconnection, this value is double current natural frequency response. Should the
standard provide an incentive, such that a Balancing Authority can use a bias equal to their natural response, but
less than 1% of peak, if the response is above an acceptable target?
Summary Consideration: While most commenters supported this suggestion, there was not consensus on the scope of the proposed
requirements, and the drafting team revised the SAR to focus solely on collecting data needed to model frequency response in each of the
interconnections. The drafting team will forward these comments to the Director of Standards Development so that they can be addressed by the
Balance Resources and Demand standard drafting team or another drafting team. This shall serve as a summary response to all comments
provided.
Commenter
Yes
IESO. (2)
Ron Falsetti
BPA (1, 3, 5, 6)
January 9, 2007
9
No
Comment
9
(i) The question seems to get the sub-minute and longer-term targets intertwined. We are
unclear on which "standard be provided an incentive". Is it the proposed sub-minute
standard which has yet to be determined or the current standard on Bias? If it is the
former, then this question seems a bit premature as we don't even know what the
performance target for sub-minute response should be. If it's the latter, then the issue
belongs to other BAL standards.
9
The RS again is avoiding the issue of what sub-minute frequency response it MUST
mandate. The 1% is related to the frequency bias setting (basically a long term average
response). The BRD deals with the longer term issue of frequency response - this
standard was designed for the shorter-term response.
If the RS is willing to accept under-biased systems then it would seem to be going against
conventional wisdom, and should explain why it would even consider such an idea. If the
real intent of this frequency SAR is to establish a minimum frequency response value
then the SAR needs to state that.
Perhaps the SAR should establish a minimum 1 minute response for every generator (if
they can't provide it they are obligated to contract for it from another unit) and maybe a 1
minute average over a week, month, or year if a longer term value is needed. However,
since the SAR authors state the problem is sub-minute response, it is suggested that the
long term response is better be addressed by the BRD standard.
In addition the SAR does not adequately address the load portion of the frequency
response. The standard seems to presuppose the solution is having governors.
9
The standard should not provide an incentive, but the standard should provide a
methodology that would allow a Balancing Authority to calculate a bias based on their
natural response, provided that response is above an acceptable target.
Page 25 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001382
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
Southern Company Transm. (1)
9
The 1% minimum frequency bias is obsolete and does not take into account the changes
in interconnection frequency response over recent years. If not modified, it will lead to
increased frequency oscillations within the interconnections and needless maneuvering of
generating assets with associated wear and tear on these assets.
IESO(1)
Anita Lee
9
There should be a safeguard in place, such that if frequency performance declines, the
industry reverts to the 1% minimum.
Midwest Reliability Organization (2)
9
There should be a safeguard in place, such that if frequency performance declines, the
industry reverts to the 1% minimum.
Energy Mark, Inc. (8)
Howard F. Illian
9
There is a minimum frequency response below which the interconnection will be less
reliable than acceptable. We currently do not know what this value is but we do know
that a value exists. We also know that this value is less than the 1% of peak load
specificed in the current standards. A standard that arbitrairly requires a 1% of peak load
response without a technical justification based on reliability cannot be called a reliabiltiy
standard. However, even though we do not know the minimum frequency response
below which the interconnection will be less reliable than acceptable, we can perform the
work necessary to estimate a reasonable value for a minimum frequency response and
assign responsibility for that response among the Balancing Authorities on an
interconnection. A Frequency Response Standard without this characteristic cannot
maintain reliability of the interconnection.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
9
I believe that an incentive should be included in the standard.
Duke Energy Carolinas (1, 3, 5, 6)
Tom Pruitt
9
Calculation of each BA's bias should be based on a rigorous analysis which demonstrates
that the BA can provide the expected response, regardless of peak load. This is
consistent with the proposed requirements - 'technically-sound calculation and report of
frequency response' and 'Will not mandate a given amount of frequency response'.
ATC LLC (1)
Jason Shaver
9
Although ATC is in support of this recommendation, we feel that it should be classified as
an "allowable exemption" not an "incentive".
NERC Resources Subcommittee
9
The 1% minimum frequency bias should be evaluated to take into account the reliability
requirements of the interconnections. frequency response over recent years. We suggest
that the minimum bias be addressed during the development of the Frequency Response
Standard. It is unclear what the word "incentive" means above.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
9
However this requirement still does not address the need for enough frequency response
on the system.
January 9, 2007
Page 26 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001383
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Mike Moltane
Van Greening
January 9, 2007
Yes
No
Comment
Page 27 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001384
Consideration of Comments on Second Draft of Frequency Response SAR
5. Several commenters suggested response should be measured for an extended period after a frequency excursion,
up to the point where automatic generation control (AGC) would take over. This was to ensure initial response
wasn’t withdrawn prematurely. Should the standard measure out to 60 seconds following an excursion?
Summary Consideration: There was not consensus on the scope of the proposed requirements, and the drafting team revised the SAR to
focus solely on collecting data needed to model frequency response in each of the interconnections. The drafting team modified the SAR to
specify that data will be collected to measure response over a period up to 5 minutes. This window may be reduced during the standard drafting
phase. This should provide sufficient data to analyze frequency response and should help identify the window of time where frequency response
appears to be masked by Automatic Generation Control action.
Commenter
Yes
No
Comment
I did not provide an answer but believe that this is a decision that could be made over time
and not necessarily with the inception of the standard.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
Response: We agree.
Arizona Public Service Co. (1, 5)
Baj Agrawal
9
Most of the frequency recovery happens in first 30 seconds. Thus anything more than 30
seconds is unnecessary. It is also seen that the response of a unit varies greatly within that
30 seconds period. Thus, it is very important that the measured response be the average
response over the 30 seconds period and not be the response at 30 seconds.
Response: We agree that frequency response should be measured over a period of time (as opposed to a measure for a single event).
Southern Company Transm. (1)
9
AGC response begins within only a few seconds after the disturbance with a maximum ramp
rate achieved within three to five minutes. Governor response and load frequency response
typically peak within 30 seconds. There is some logic to monitoring governor respone for
sustainability past its initial peak, but we have not seen anything about that in this SAR.
Response: There was no consensus on this matter. The drafting team modified the SAR to specify that data will be collected to measure
response over a period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window
of time where frequency response appears to be masked by AGC action.
9
The standard should measure out to when the frequency recovers. This could be up to the 15
minute DCS limit. AGC control may or may not kick in within 60 seconds depending on
deadbands, etc. However, generators on setpoint control may hold for between 10 and 60
seconds then drop back off prior to AGC pulses reaching the generator. In order to see the
full response of a BA it is necessary to see data for the full event rather than just the first
minute. Rather than overlapping the BRD standard, this will work hand-in-hand with this
standard.
Response: There was no consensus on this matter. The drafting team modified the SAR to specify that data will be collected to measure
response over a period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window
January 9, 2007
Page 28 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001385
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
of time where frequency response appears to be masked by AGC action.
9
NPCC CP9 Reliability Standards
Working Group
Comment
This question is not clear. AGC control pulses generation every 5 seconds, therefore, the
measurement should be based on the amount of time it takes to restore the generation load
balance.
Response: In general, following a unit trip, frequency will not recover until the contingent BA has replaced the energy that was lost. This
typically takes up to 15 minutes. Unless over-biased, a non-contingent BA will not contribute AGC response to a frequency event.
9
PJM Corporate Development Div.
(2)
Unsure as to what is being suggested here. The SAR drafters need to be specific about what
requirements are needed and how they will be measured. The details contained in the white
paper are supporting information but they do not define the standard that is being proposed.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections.
NERC Resources Subcommittee
9
9
AGC response begins within only a few seconds after the disturbance with a maximum ramp
rate achieved within three to five minutes. Governor response and load frequency response
typically peak within 30 seconds. There is logic to monitoring governor response for
sustainability past its initial peak and this should be investigated during standard
development.
Response: We agree with this comment. The drafting team modified the SAR to specify that data will be collected to measure response over a
period up to 5 minutes. This should provide sufficient data to analyze frequency response and should help identify the window of time where
frequency response appears to be masked by AGC action.
IESO(1)
Anita Lee
9
Sixty seconds is a reasonable balance to capture the period prior to AGC response.
Response: Agree – However, several commenters indicated there may be value in analyzing response for several minutes and the drafting
team modified the SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient
data to analyze frequency response and should help identify the window of time where frequency response appears to be masked by AGC
action.
IESO. (2)
Ron Falsetti
9
This should cover the entire spectrum of immediate response before AGC kicks in.
Response: Agree However, several commenters indicated there may be value in analyzing response for several minutes and the drafting team
modified the SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to
analyze frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Energy Mark, Inc. (8)
Howard F. Illian
January 9, 2007
9
There are two issues associated with this question. The first is that the change in
instantaneous frequency be limited to within a range that limits the risk of a cascading outage
on the interconnection. The second is that each generation technology provides a different
response characteristic within the first minute after a sudden frequency excursion. Work
Page 29 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001386
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes
No
Comment
performed at NIPSCo and published by IEEE indicated that a measurement interval of one to
two minutes worked well for the measurement of frequency response. Without specific
knowledge of the nature of the individual responses that make up the sustained frequency
response to an excursion, it may be difficult to justify the selection of a measurement interval
shorter than one-minute that might put some generation technologies at a disadvantage with
respect to the measurement method. This is a subject that the drafting team should
technically evaluate before including a specific measurement period in the standard.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Duke Energy Carolinas (1, 3, 5, 6)
Tom Pruitt
9
At least. Based on the words in the SAR Purpose statement, 'this proposed standard
coordinates with and complements the Balance Resources and Demand standards, which
addresses Interconnection frequency control generally 5 minutes and longer', it seems that
this standard should cover out to the 5 minute mark of an event. AGC actions will commence
at the first scan cylcle or two after the event (5 -15 secs), but the actual generation response
may not settle out for several minutes, depending on the type and amount of generation on
AGC at the time.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
Midwest Reliability Organization
(2)
9
This is a significant issue, because if the governor system withdraws the unit's support prior to
the recovery of frequency, this does have a problematic impact. A period of at least 60
seconds should be considered, and 60 seconds may not be adequate as often frequency
recovery of the interconnection extends beyond the initial 60 seconds.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action.
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
9
Needs to be verified with a field trial.
Response: Several commenters indicated there may be value in analyzing response for several minutes and the drafting team modified the
SAR to specify that data will be collected to measure response over a period up to 5 minutes. This should provide sufficient data to analyze
frequency response and should help identify the window of time where frequency response appears to be masked by AGC action. Note that the
January 9, 2007
Page 30 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001387
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Yes No
Comment
drafting team modified the scope of the entire SAR to focus solely on collecting data needed to model frequency response in each of the
interconnections.
ATC LLC (1)
Jason Shaver
January 9, 2007
9
Page 31 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001388
Consideration of Comments on Second Draft of Frequency Response SAR
6. Do you have other comments on the SAR?
Commenter
ITC Transmission (1)
Jim Cyrulewski
Beth Howell
Mike Moltane
Van Greening
Comment
Reliability and Market Interface Principles 3, 5 and 6 should be checked as well.
Response: We made this change.
PJM Corporate Development Div. (2)
Please be clear about the terminology. Frequency response comes in many flavors - sub-minute;
several minutes; and hours. The RS seems to touch on all of them in this proposal.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. The data collection will include data to model and analyze
frequency response up to five minutes.
Southern Company Transm. (1)
In our opinion, this SAR, or one like it, is required to ensure that the primary frequency response of the
interconnections and the BAs do not deteriorate to a point where 1) the interconnection can not
adequately respond to major generator trips (including potential multiple contingencies which, though
rare, do happen) and 2) primary frequency response of the BAs is inadequate to support islanding
during severe local disturbances, thus allowing local disturbances to cascade into regional or
interconnection wide disturbances. Primary frequency response is declining in at least the Eastern and
Western Interconnections. WECC has taken a proactive approach to addressing this problem, but
there is no similar work being done in the Eastern Interconnection. This SAR, or one like it, is needed
to take the best practices in the industry, wherever they may be found, and utilize them to protect the
interconnections from disturbances that could be avoided if we take action now rather than waiting until
the problems actually occur.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. Your support is very much appreciated.
IESO. (2)
Ron Falsetti
January 9, 2007
(i) The SAR does not address the load portion of the frequency response but it indicates that the
standard would apply to the LSEs as well. Please clarify or eliminate LSE from the Reliability Function
check list.
(ii) We feel that the SAR needs to be very clear on what the proposed standard is intended and what
will be included. Conducting calculation, measuring and report on frequency excursion events followed
by analysis would help to ascertain whether or not poor performance exists. However, the
determination of poor performance also relies on having a minimally acceptable level to gauge. If the
standard is to provide requirements for calculation, reporting and conducting analysis only, then there
Page 32 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001389
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
Comment
needs to be some general guideline on the threshold for reporting and analyzing, which in turn begs the
question of should this "guideline" be included as the initial standard, whose compliance would not be
enforced until sufficient experience has been gained and field test conducted, with possible revision as
experience and field test so suggest. Absent a minimum performance level, the requirements for
governor setting would be difficult to determine.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. The Load-serving Entity will need to provide some of the
data needed to model frequency response.
Energy Mark, Inc. (8)
Howard F. Illian
The current measurement methods for determining individual Balancing Authority Frequency Response
may not be reliable. This is because the current measurement methods only capture a small sample of
the frequency responses provided limited to only several minutes per year. The metering methods we
currently use on the interconnection can shed some light on this problem. Since the each BA
measures its Tie Line Error with common metering with adjancent BAs, the sum of the Tie Line Errors
over the total interconnection must equal zero at all times. Each tie line has a positive error for one BA
and a negative error of equal value to the other BA that the tie line connects. If the errors must sum to
zero, then the change in errors must also sum to zero between any two points in time. Since the
Frequency on an interconnection is the same throughtout the interconnection at any point in time for
the purpose of the frequency response measurement, the change in frequency between two points in
time must also be the same throughout the interconnection. Therefore, the change in tie-line error
divided by the change in frequency must indicate a total frequency response for the interconnection as
measured by the sum of the individual BA frequency responses must be equal to zero. In other words,
there is a BA or a set of BAs that cause each frequency response on the interconnection. Only
knowledge of the distribution of individual frequency responses among BAs will provide the necessary
information to determine whether or not the frequency response indicated by current measurement
methods will maintain adequate reliablity. It may not be the average frequency response to large
events that indicates interconnection reliability, but the distribution of frequency responses among BAs
including both the positive and negative responses. Therefore, the measurement methods included in
the standard should have the goal of capturing the distribution of both positive and negative frequency
responses over the entire range of frequency operation should be a goal of standard. The
measurement methods suggested will not accomplish this goal.
Response: We agree with the concerns on errors induced in the measurement process. The standard will be designed to capture enough
events to provide a statistically-sound estimate of Balancing Authority response. We also agree that the distribution of responses needs to be
considered.
Duke Energy Midwest (1, 3, 6)
Jeff Baker
I believe we have to address the frequency issue, but feel that it can be developed over time proactivly.
Response: The revised SAR focuses solely on the collection of data needed to model frequency response. The data can be analyzed and
additional standards can be developed that build on the results of those analyses. This supports your suggestion that the standard(s) be
January 9, 2007
Page 33 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001390
Consideration of Comments on Second Draft of Frequency Response SAR
Commenter
developed proactively over time.
Comment
NERC Resources Subcommittee
In our opinion, this SAR, or one like it, is required to ensure that the primary frequency response of the
interconnections and the BAs do not deteriorate to a point where 1) the interconnection can not
adequately respond to major generator trips (including potential multiple contingencies which, though
rare, do happen) and 2) primary frequency response of the BAs is inadequate to support islanding
during severe local disturbances, thus allowing local disturbances to cascade into regional or
interconnection wide disturbances. Primary frequency response is declining in all Interconnections,
Eastern, Western and ERCOT. WECC and ERCOT have taken a proactive approach to addressing
this problem, but there is no similar work being done in the Eastern Interconnection. This SAR, or one
like it, is needed.
Response: There was no consensus on the scope of the proposed requirements, and the drafting team revised the SAR to focus solely on
collecting data needed to model frequency response in each of the interconnections. Your support is very much appreciated.
January 9, 2007
Page 34 of 34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001391
Consideration of Comments on Second Draft of Frequency Response SAR
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001392
Standard Authorization Request Form
Title of Proposed Standard
Revised:
Frequency Response Draft 3
12/06/06
SAR Type (Put an ‘x’ in front of one of
these selections)
SAR Requestor Information
Name
Terry Bilke
x
Primary Contact Terry Bilke
Telephone
(317) 249-5463
Fax
(317) 249-5994
E-mail
[email protected]
New Standard
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
Purpose/Industry Need
Frequency Response, a measure of an Interconnection’s ability to stabilize
frequency immediately following the sudden loss of generation or load, is a
critical component to the reliable operation of the bulk power system,
particularly during disturbances and restoration. The proposed standard’s
intent is to collect data needed to accurately model existing Frequency
Response. There is evidence of continuing decline in Frequency Response in
the three Interconnections over the past 10 years, but no confirmed reason for
the apparent decline. The proposed standard requires entities to provide data
so that Frequency Response in each of the Interconnections can be modeled, and
the reasons for the decline in Frequency Response can be identified. Once the
reasons for the decline in Frequency Response are confirmed, requirements can
be written to control Frequency Response to within defined reliability
parameters.
SAR-1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001393
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within its metered boundary and supports system
frequency in real time
Interchange
Authority
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced
interchange schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a long-term (>1year) plan for the resource adequacy of specific
loads within its portion of a Planning Coordinator Area.
Transmission
Planner
Develops a (>one year) plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within
a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and related reliability-related
services) to serve the End-use Customer.
SAR-2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001394
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric systems
shall be trained, qualified and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk electric systems shall be assessed, monitored and
maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with that
Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR-3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001395
Detailed Description (Provide enough detail so that an independent entity familiar with
the industry could draft, modify, or withdraw a Standard based on this description.)
The proposed technical/preparedness standard will require or provide
the following:
1. Each Balancing Authority shall collect and provide data [scan rate tie
deviation and frequency for up to 5* minutes per event] needed to model
its sub-minute Frequency Response to loss of large generating units and
load.
2. Each Balancing Authority shall report each loss of generation or load
greater than the respective Interconnection reporting threshold to its
Reliability Coordinator.
3. Each Reliability Coordinator shall relay Frequency Response Standard
(FRS) event information to other Reliability Coordinators in its
Interconnection. The Interconnection Time Monitor will maintain a log
of FRS events.
4. NERC shall annually post a list of FRS events. These events shall be
used by Balancing Authorities to calculate and report their annual
Frequency Response and Bias.
5. NERC, in conjunction with the respective Regions, shall establish a
Target Frequency Response for each Interconnection. Absent an
agreement, the observed Frequency Response in the first year of the FRS
shall be used as a target.
6. Balancing Authorities with less than [75%]* of their share of Target
Frequency Response shall provide generation-level data to their Region
for use by Transmission Planners and Planning Coordinators.
a. Each Generator Operator that operates a generator larger than [10
MW]*, shall provide data to its Balancing Authority, as required
in item 6, to support this standard and for use in developing
models of Frequency Response in the associated Interconnection.
b. Load Serving Entities shall provide data, as required in item 6,
to their BA and Region to support the standard.
*These values are representative and will be refined based on
stakeholder input during the standard drafting phase.
Related Standards
Standard No.
Explanation
BAL-001-0
through BAL006-0
Balancing Standards, version 0
Balance
Resources
and Demand
draft
standards
Balancing Resources and Demand BAL-007 through BAL-011 draft
standards, are in standards development process
MOD-013-0
The proposed standard would enable better input data to the
SAR-4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001396
modeling standards.
Related SARs
SAR ID
Explanation
Frequency
Response
SAR, version
0
Original Frequency Response SAR
MOD-027
Verification and Status of Generator Frequency Response. The
proposed standard would provide a mechanism to validate
compliance with MOD-027. The proposed standard could also
provide a means to achieve MOD-027 (if the Balancing Authority
implements on on-line measurement of generator frequency using
SCADA data).
Regional Differences
Region
Explanation
ECAR
ERCOT
Single Balancing Authority Interconnections calculate Frequency
Response based on the change in generation (or load) rather
than Tie-Line deviation (ERCOT).
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
SAR-5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Maureen E. 001397
Long
Standards Process Manager
February 8, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for three SARs
System Restoration and Blackstart SAR (February 8–March 9, 2007)
The second draft of the System Restoration and Blackstart SAR has been posted for a 30-day
comment period from February 8 through March 9, 2007. The SAR calls for the modification of
the following standards:
EOP-005 — System Restoration Plans
EOP-006 — Reliability Coordination – System Restoration
EOP-007 — Establish, Maintain, and Document a Regional Blackstart Capability Plan
EOP-009 — Documentation of Blackstart Generating Unit Test Results
This project involves upgrading the overall quality of the four standards; eliminating some gaps
in the requirements, ambiguity, and “fill-in-the-blank” components.
The development may include other improvements to the standards deemed appropriate by the
drafting team, with the consensus of stakeholders, consistent with establishing high-quality,
enforceable, and technically sufficient bulk power system reliability standards.
Please use the comment form to provide comments on this SAR.
Underfrequency Load Shedding SAR (February 8–March 9, 2007)
The second draft of the Underfrequency Load Shedding SAR has been posted for a 30-day
comment period from February 8 through March 9, 2007. The SAR calls for the modification of
the following standards:
PRC-006 — Development and Documentation of Regional Reliability Organizations’
Underfrequency Load Shedding Programs
PRC-007 — Assuring Consistency with Regional UFLS Programs
PRC-009 — UFLS Performance Following an Underfrequency Event
This project involves upgrading the overall quality of the four standards; eliminating some gaps
in the requirements, ambiguity, and “fill-in-the-blank” components.
The development may include other improvements to the standards deemed appropriate by the
drafting team, with the consensus of stakeholders, consistent with establishing high-quality,
enforceable, and technically sufficient bulk power system reliability standards.
Please use the comment form to provide comments on this SAR.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001398
REGISTERED BALLOT BODY
February 8, 2007
Page Two
Frequency Response SAR (February 8–March 9, 2007)
The third draft of the Frequency Response SAR has been posted for a 30-day comment period
from February 8 through March 9, 2007. The SAR calls for the collection of data needed to
model each interconnection’s frequency response.
Please use the comment form to provide comments on this SAR.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001399
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001400
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Bonneville Power Administration
Lead Contact:
Bart McManus
Contact Organization:
Bonneville Power Administration
Contact Segment:
1
Contact Telephone:
360-418-2309
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
James Murphy
Bonneville Power
Administration
WECC
1
John Anasis
Bonneville Power
Administration
WECC
1
Brenda Anderson
Bonneville Power
Administration
WECC
6
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001401
Comment Form for Draft 3 of the Frequency Response SAR
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001402
Comment Form for Draft 3 of the Frequency Response SAR
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001403
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: With the caveat that more data may be collected if the need arises (out to
10 or 15 minutes)
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: BPA does not believe a field trial is needed for this standard. The standard
should be written and implemented with the levels of noncompliance structured around
data submittal.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: BPA agrees with the necessity of a frequency response standard. BPA
highly encourages that this effort be implemented as soon as possible.
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001404
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001405
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
PJM
Lead Contact:
Albert DiCaprio
Contact Organization:
PJM
Contact Segment:
2
Contact Telephone:
610-666-8854
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Tom Bowe
PJM
RFC
2
Alicia Daughtery
PJM
RFC
2
Joseph Willson
PJM
RFC
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001406
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001407
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001408
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: The primary objective of this SAR is to collect data; to analyze the data;
and only then to recommend a performance value. The SAR DT insists that collecting
data is a Technical Standard. The RSDP states:
"Technical standards…will contain Measures (not measuring - AMD) of physical
parameters…" At this point this SAR proposal does not contain such a measure, it does
not even assert that the measure is really needed (hence the need to analyze the
data).
Page 19 (of 43) of the RSPM states “The drafting team may recommend the scope of
the standard be reduced to allow the effort to move forward, while still remaining
within the scope of the SAR. Reducing the scope of the SAR is acceptable if the drafting
team finds, for instance, THAT ADDITIONAL TECHNICAL RESEARCH IS NEEDED PRIOR
TO DEVELOPING (emphasis added) a portion of the standard or issues need to be
resolved before consensus can be achieved on a portion of the standard. “The
highlighted section applies directly to the scope of this SAR. The SAR Team recognizes
work is needed. There is no question about that. The Team should do that work
BEFORE proposing a mandatory standard.
PJM supports the concept of doing such a study, and would encourage NERC to assign a
group to do such a study, but PJM does not agree that collecting data rises to the level
of a valid NERC reliability standard.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: The proposal as written appears to be headed towards mandating a given
unit response. As such there would be an obligation on the Generator Operator - there
does not seem to be any requirements that would apply to the Generator Owner unless of course the requestor includes a requirement to install a governor (this has, to
date, be an implied obligation just as having a turbine has been an implied obligation).
If the requestor does intend to assert an obligation on the Generator Owner to install a
governor then the question arises should that be a standard or should that be a part of
the Certification of a GO?
It is not clear what the LSE requirements are in this proposal.
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001409
Comment Form for Draft 3 of the Frequency Response SAR
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: As noted above PJM does not consider collecting data in order to decide
what a requirement should be as grounds for a standard. Thus the sampling period
which is outside of a NERC standard, can be defined in whatever way the group doing
the sampling desires.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: There are field trials for standards (which this question is directed) and
there are field trials for good ideas. This proposed SAR would seem to fall into the
second category; and while posting events is interesting, it does not rate being a NERC
standard. Collecting and posting data can be effected without a standard.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: PJM would also note that the proposal references two distinct parameters the Natural response of a BA; and the natural response of a unit. It is not clear how the
requestor intends to link the two parameters. The sum of the units' natural responses
will not equal the natural response of the BA. Does the requestor intend to link the two,
or to keep them separate? As written it appears that the requestor intends for the BA
to be held responsible for an annual measured value. The SAR DT does not recognize
that during different times there are different number of units opperating and available
to respond. The SAR DT makes no mention of whether or not a BA(?) would have to
shed load to maintain such frequency response (for those periods when all units are at
full load). The SAR DT makes no mention of distance from an event. An event in NE will
effect more response in NE then in Florida - how will that be addressed? PJM would ask
for clarification on what the requestor would intend to mandate.
FERC has recognized the need to include suppliers that use load control - how does this
SAR intend to address such 'natural response suppliers'?
As written this proposal becomes an ambiguous standard as it obligates a BA to get
data from a generator ( as opposed to directly obligating generators to supply the data
to the analysis team - this is important from the perspective of who would be noncompliant if the data were not supplied - the BA or the GO?).
PJM would suggest that NERC create a Frequency Project, budget the project through
its members rather then create a standard and risk imposing non-compliance penalities
for what potentially could be a non-issue. Deal with this for what it is - a research
activity.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001410
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001411
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southwest Power Pool Operating Reliability Working Group
Lead Contact:
Wayne Galli
Contact Organization:
Southwest Power Pool
Contact Segment:
RTO
Contact Telephone:
501-614-3344
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Pete Kuebeck
Oklahoma Gas and Electric
SPP
1
Jim Useldinger
Kansas City Power and Light
SPP
1
Bill Grant
Southwestern Public Service
SPP
1
Jason Atwood
Kelson Energy
SPP
4
Steve Massey
Westar Energy
SPP
5
Mike Crouch
Western Farmers Electric Coop
SPP
1
Dan Boezio
American Electric Power
SPP
1
Wayne Galli
Southwest Power Pool
SPP
10
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001412
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001413
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001414
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: Do not agree with the notion in point 5 regarding the need for a Target
Frequency Response for each interconnection at this time. It is beyond the scope of
this technical SAR to propose anything other than collection of data to support the
study.
Do not agree with point 6 of the description. In order to get a handle on what is really
going on, all Balancing Authorities should be required to produce data valid to the
study. Also the language in point 6 is poorly worded compared to the right wording in
6a and 6b. 6a and 6b should be included in the SAR and 6 should be removed.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: A standard can not be imposed on the response of load to frequency. Load
Serving Entities can only provide data.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: The 5 minute time is adaquate, but it lacks substance. Small changes in
load and generation due to frequency response are very difficult to separate from
normal load changes and AGC action on generation units (as was pointed out). It is
important to include in the description of data collection that the 5 minutes should
include 1 minute of data prior to a study event and 4 minutes after a study event. It is
also important to include a sample rate, such as 4 seconds (obviously, faster samples
are better, but may not be practicle).
The SAR, as written, lacks specifics on what data is required to perform a valid study.
Some examples of necessary data may include, but are not limited to, AGC pulses,
special protection systems, generator MW, tie line MW, frequency, etc.
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001415
Comment Form for Draft 3 of the Frequency Response SAR
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: The reasoning for this technical standard is based on the perception that
the frequency response of the electrical system is declining and a concern that the
interconnect's ability to arrest significant system disturbances is slowly being
compromised. Although it is not disagreeable that a study be conducted to determine if
an actual decline in frequency response is occuring and then to determine cause, it is
diagreeable to propose a potential remedy for a problem that may not exist or,
dependent on the findings, in inappropriate remedy.
Types of generating units online (e.g., wind generation, combined cycle, etc) and their
subsequent loading will have an influence on the frequency response of the system. As
long as Balancing Authorities are maintaining their reserve obligations, even large
contingencies should be manageable. However, over the years because of the trend to
get more out of invested generation resources, it would give the appearance of a
decline in frequency response since most frequency degradations are a result of losses
of generation and a resultant decline in system frequency and those are what is studied
and scrutinized. The August 14, 2003 disturbance was an opportunity to study the
frequency response of all on-line generating units due to the frequency event resulting
in a high frequency. High frequency is the only event where all on-line generating units
will respond.
Proposing the establishment of a Target Frequency Response for the interconnect
before concluding if an actual decline in frequency response is occuring and the
cause(s) for the decline is finding a solution before defining the problem. Any
standards involving frequency response need to also consider the role system reserves
play in the interconnect as well as the frequency response of generators and system
load to frequency. As long as generating reserve obligations are being met in
accordance with current Reliability Standards and Regional Operating Criteria there
may not be a need to go further dependent on the outcome of the study proposed by
this SAR.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001416
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jason Shaver
Organization: American Transmission Co.
Telephone:
262 506 6885
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001417
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001418
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001419
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001420
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: ATC does not see the need to identify the Load Serving Entity in the
Applicability section. The SDT should provide an explanation as to the reasoning
behind the selection of Load Serving Entities.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001421
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brent Kingsford
Organization: CAISO
Telephone:
916-608-1100
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001422
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001423
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001424
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001425
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001426
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Gildea
Organization: Constellation Generation
Telephone:
410.230.4901
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001427
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001428
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001429
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001430
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Specific to the Requirement 6 a which states:
Each Generator Operator that operates a generator larger than [10
MW]*, shall provide data to its Balancing Authority, as required
in item 6, to support this standard and for use in developing
models of Frequency Response in the associated Interconnection.
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001431
Comment Form for Draft 3 of the Frequency Response SAR
Balancing Authorities may seek Speed Droop characteristics for our generators. Speed
Droop is a design characteristic of the steam turbine (or the prime mover's governor
response in the case of a combustion turbine or diesel) .
Our concern is the only data we may be able to provide would be turbine manufacturer
design data. For our older units where turbine control systems have been retrofitted
and upgraded with more modern controls, we may not really know the speed droop
characteristic of the unit. Collecting performance data to demonstrate the speed droop
is extremely difficult if not impossible on a large unit. (Requires the grid connection
frequency be allowed to "droop" as the generator is loaded). Hence, as now written,
Constellation Generation is not clear how we could comply.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001432
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Howard F. Illian
Organization: Energy Mark, Inc.
Telephone:
847-913-5491
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001433
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001434
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001435
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001436
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: At this time information is not available that would provide a sound
technical basis for the development of a performance standard. However, with the
recent increased interest in Frequency Response, new data and analysis could become
available at any time that would change the focus from a technical standard to a
performance standard. If new information and analysis becomes available during the
development of the technical standard, consideration should be given to how the
development of the technical standard could delay the development and
implementation of a performance standard. Must the technical standard be completed
and approved before work can start on a performance standard?
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: I agree that the proposed list includes those entities that would be affected
by a technical standard. However, there are many questions that must be resolved
before any standard that affects the Generation Owner, Generation Operator or Loadserving Entity can be implemented. These questions relate to how a performance
standard can or should be implemented. If there is no reasonable expectation that
they would be included in a future performance standard, it would be unreasonable to
implement a technical standard that requires these three functional entities to provide
data. In a fair market that allows voluntary participation by Generation Owners,
Generation Operators and Load-serving Entities, the direct application of a Frequency
Response Performance Standard to these entities is not currently possible without
creating unreasonable inequities in the market. Any standard applied directly to one
generator but not another will create unreasonble inequities in a market. Since each
generation technology has different Frequency Response capabilities, only a solution
that provides Frequency Response through a market based mechanism can be fairly
implimented in a market. Under these conditions, the measurement methods and data
collection for a technical standard should only be applied to those entities that would
have resposibilities under a performance standard. The correct alternative for
collecting data from these entities is to collect it indirectly through the Balancing
Authority or Reliability Coordinator that would be directly affected by a performance
standard. The inclusion of Generation Owner, Generation Operator, and Load-serving
Entity directly in the data collection will lead to the development of data collection
systems that will need to be replaced, if and when, a performance standard is
developed. This is an inefficient way to develop the technology for a new standard.
Page 5 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001437
Comment Form for Draft 3 of the Frequency Response SAR
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: I agree with the concept of measuring Frequency Response for an
extended period after a disturbance, but I do not agree that the reason is related to
masking by AGC action. If the Frequency Bias for a Balancing Authority is set to a
value that approximates the actual Frequency Response, the AGC action will always
provide the correct response for reliable interconnection performance. The Frequency
Response should be measured for an extended period after a disturbance to identify
entities that are prematurely withdrawing their expected frequency response support
from the interconnection. This has been demonstrated for entities that have outer loop
control that only includes scheduled deliveries without adjustment for frequency
response.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: This would be a good way to insure that every entity select a similar set of
events for calculation of their Frequency Response, but it will not insure conformity of
the results. The difficulty with any method for selecting a common set of events is that
each of those events is caused by a disturbance within one or more of the Balancing
Authorities on the interconnection. Those entities that cause the disturbance will
experience a different frequency response than those entities that are responding. The
net effect is that the sum of the responses for all of the entities on the interconnection
must sum to zero. This means that each entity must eliminate those disturbances for
which they are the cause, from the set of disturbances they use to estimate their
response. The real advantage is an entity cannot influence the results of the
measurement through selection of the events they choose to include in the calculation.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: One of my concerns is a majority of entities in NERC must agree that there
is a need for a standard before the standard process moves forward. This could have
undesirable long-term results with respect to the quality of the standards that are
developed. This standard provides a good example of this problem. From what I have
observed, both the Texas and Western Interconnections have concluded that there is a
reliability need for a Frequency Response Standard on their interconnections.
Unfortunately, reasonable opposition from the Eastern Interconnection will prevent the
development of a common standard for those two interconnections. The only
alternative will be for the Texas and Western Interconnections to each develop their
own standards for Frequency Response without considering ways of making those two
standards similar to each other. If the Eastern Interconnection, after a few years, finds
that it needs a Frequency Response Standard, it will then become necessary for a new
Page 6 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001438
Comment Form for Draft 3 of the Frequency Response SAR
standard to be developed that applies to all three interconnections. If each
interconnection has a different Frequency Response Standard, it means there is no
standard at all, but three different rules for NERC. The next logical step is to develop a
common standard for all three interconnections requiring the first two standards
developed by the Texas and Western Interconnections separately be modified to
conform to a North American Standard on Frequency Response. Combining these three
separate needs into a single standard will result in a natural opposition to change by
those interconnections that have already implemented an interconnection standard that
meets their individual needs. This will make it very difficult to gain the support
necessary to enact a common standard for NERC. This multi-step development can
only be avoided by having all three interconnections participate and contribute to
standards identified and developed by individual interconnections. I believe that NERC
needs to find a way to address this problem. If they do not, the standard development
and approval process will lead to fractured standards and an unacceptable fractured
standard process for NERC. One alternative might be to find a way for all
interconnections to participate in the solution of individual interconnection problems as
part of the standard development process.
Page 7 of 7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001439
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Steve Myers
Organization: ERCOT
Telephone:
512-248-3077
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001440
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001441
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001442
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001443
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: This time frame should be sufficient for determination of frequency
response. If it is intended that this data should also be useful for evaluating generating
unit governor functioning, a longer time may be appropriate.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: A field trial would be beneficial to ensure that no gaps in the need for data
exist. This could relate to whether other data is needed or whether data for a longer
time is needed.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001444
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie (HQT)
Telephone:
514 289-2211, X2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001445
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001446
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001447
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001448
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: HQT believe there might be other means than Reliability Standards to
accomplish this data collection.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: We question the need to include the applicability to the LSEs in this SAR
and requests the drafting team to explain the purpose.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: We requests clarification as to what data and at what periodicity will be
collected from the identitified entities.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: Being a single Balancing Authority Interconnection, there might be a need
for a «regional»difference for the Québec Interconnection when specific value will be
established. Same as ERCOT, frequency response will be based on the change in
generation (or load) rather than Tie-Line deviation.
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001449
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001450
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001451
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001452
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001453
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
We do not agree with the reduced scope of this SAR. It does not require a standard to
enable a data collection task(s). Data collection procedures and processes, charged by
a standing committee, e.g. the OC, or respective working groups, would be more than
sufficient.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
For the purpose of data collection, assigning responsibility to the Balancing Authority,
Generator Operator and Load-serving Entity would suffice.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: A field test is a must and would definitely provide useful information on the
types of event that would necessiate such data collection (The threshold needs to be
clarified though - e.g. should it be >10MW loss of generator or some other threshold?),
and any specific areas that need to be worked on in order to ensure that all relevant
and required data is collected.
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001454
Comment Form for Draft 3 of the Frequency Response SAR
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
While we felt that the previous SAR was unclear on the intent, this SAR has such a
reduced scope that the intended task does not require a reliability standard to achieve .
A task team charged by a standing committee (the OC), would suffice. The
requirements proposed in the SAR can be set as conditions for completing the data
collection effort by the task team.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001455
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001456
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001457
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001458
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001459
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: ISO New England does not see a need to include the applicability to the
LSEs in this SAR and requests the drafting team to explain this.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: ISO New England requests clarification as to what data and at what
periodicity will be collected.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001460
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Gammon
Organization: Kansas City Power & Light
Telephone:
816-654-1242
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001461
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001462
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001463
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001464
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: Do not agree with the notion in point 5 regarding the need for a Target
Frequency Response for each interconnection at this time. It is presumptuous to
advance a remedy prior to determining cause of the perceived decline in frequency
response. Allow the techincal SAR to perform its function to determine cause. Any
appropriate remedy in operating standards should become apparent.
Do not agree with point 6 of the description. In order to get a handle on what is really
going on, all Balancing Authorities should be required to produce data valid to the
study. Also the language in point 6 is poorly worded compared to the right wording in
6a and 6b. 6a and 6b should be included in the SAR and 6 should be removed.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: The 5 minute time is adaquate, but it lacks substance. Small changes in
load and generation due to frequency response are very difficult to separate from
normal load changes and AGC action on generation units (as was pointed out). It is
important to include in the description of data collection that the 5 minutes should
include 1 minute of data prior to a study event and 4 minutes after a study event. It is
also important to include a sample rate, such as 4 seconds (obviously, faster samples
are better, but may not be practicle).
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001465
Comment Form for Draft 3 of the Frequency Response SAR
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: The reasoning for this technical standard is based on the perception that
the frequency response of the electrical system is declining and a concern that the
interconnect's ability to arrest significant system disturbances is slowly being
compromised. Although it is not disagreeable that a study be conducted to determine if
an actual decline in frequency response is occuring and then to determine cause, it is
diagreeable to propose a potential remedy for a problem that may not exist or,
dependent on the findings, in inappropriate remedy.
One reason a decline in frequency response may be perceived occuring is a result of
more on-line generating units being fully loaded. That means when a frequency decline
occurs there are less units able to respond because they are already loaded. That does
not mean the interconnection is at risk. As long as Balancing Authorities are
maintaining their reserve obligations, even large contingencies should be manageable.
However, over the years because of the trend to get more out of invested generation
resources, it would give the appearance of a decline in frequency response since most
frequency degradations are a result of losses of generation and a resultant decline in
system frequency and those are what is studied and scrutinized. The August 14, 2003
disturbance was an opportunity to study the frequency response of all on-line
generating units due to the frequency event resulting in a high frequency. High
frequency is the only event where all on-line generating units will respond.
Proposing the establishment of a Target Frequency Response for the interconnect
before concluding if an actual decline in frequency response is occuring and the
subsequent cause(s) for the decline is finding a solution before defining the problem.
Any standards involving frequency response needs to also consider the role system
reserves play in the interconnect as well as the frequency response of generators and
system load to frequency. As long as generating reserve obligations are being met to
meet current Reliability Standards and Regional Operating Criteria there may not be a
need to go further dependent on the outcome of the study proposed by this SAR.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001466
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Robert Coish
Organization: Manitoba Hydro
Telephone:
204-487-5479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001467
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001468
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001469
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001470
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: Ten minutes might be more useful, especially in any areas where it appears
to take a long time to settle down after a frequency deviation event. This could be left
up to the discretion of operators and balancing authorities in any areas where slow or
bumpy returns to normal frequency levels are experienced.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: Only if field trials are deemed to have very high probability of not causing
significant difficulties on overly sensitive network area.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001471
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Alan R Oneal
Organization: MidAmerican Energy Company
Telephone:
515-252-6449
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001472
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001473
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001474
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001475
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: This standard would be a start, at least, at bringing to light where and why
response is being lost. It may well be that exposure and peer pressure, as well as the
tiered reporting requirements, will keep plant and operations personnel abreast of their
obligations for providing reserves of all types.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: This is not a new concept. I support institution of the standard as written
so a start can be made to identify and, with luck, remediate the decline in frequency
response.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: I have concern about the "shall"s in the standard, in that there is no
apparent enforcement behind the requirements for data submittals. If I'm wrong in
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001476
Comment Form for Draft 3 of the Frequency Response SAR
this, then I would be comfortable with the effectiveness possible. If I'm right, what is
to be done with an entity which finds it convenient not to report?
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001477
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001478
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest ISO and individual stakeholders
Lead Contact:
Jason Marshall
Contact Organization:
Midwest ISO
Contact Segment:
2
Contact Telephone:
(317) 249-5494
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Doug Hils
Duke Energy
RFC
1
Brian F. Thumm
ITC
RFC
1
Jim Cyrulewski
JDRJC Associates
RFC
8
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001479
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001480
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001481
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: Five minutes is acceptable. There may be merit in collecting 15 minutes of
data to cover the DCS window. The data should be readily available since the BAs are
already examining this data to determine their compliance with the DCS standard. The
final decision can be made during the standards drafting phase.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: This should not be a problem as BAs should already be performing this
calculation in the annual determination of their frequency bias.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001482
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001483
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC CP9, Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
Northeast Power Coordinating Council
Contact Segment:
10
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Roger Champagne
TransEnergie HydroQuebec
NPCC
1
Ed Thompson
ConEd
NPCC
1
Al Adamson
New York St. Reliability Council
NPCC
10
Kathleen Goodman
ISO-New England
NPCC
2
Bill Shemley
ISO-New England
NPCC
2
Greg Campoli
New York ISO
NPCC
2
Don Nelson
MA Dept. of Tele. and Energy
NPCC
9
Ron Falsetti
The IESO, Ontario
NPCC
2
Bruno Jesus
Hydro One Networks
NPCC
1
Randy McDonald
New Brunswick Sys. Operator
NPCC
2
Guy V. Zito
Northeast Power Coor. Council
NPCC
10
Herb Schrayshuen
National Grid US
NPCC
1
Jerad Barnhart
NStar
NPCC
1
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001484
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001485
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001486
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: Many of NPCC's participating members believe there are other means to
accomplish this phase of the initiative and that appropriate revisions to existing
standard(s) may address the issue determined by the data analysis could be proposed.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: NPCC participating members question the need to include the applicability
to the LSEs in this SAR and requests the drafting team to explain this.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: It is not clear what type of data is going to be collected from this
requirement. AGC response is continuous. What is the justification for the specific
"five minutes" reffered to? Since AGC control is every 4 seconds, five minutes appears
to be too long a period to collect this data. Imposing this requirement will require the
installation of local data storage retention facilities & telemetering equipment that may
not be necessary and NPCC participating members would like the drafting team to
explain why 5 minutes is necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001487
Comment Form for Draft 3 of the Frequency Response SAR
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001488
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Sydney L. Niemeyer
Organization: NRG Texas, Qualified Scheduling Entity (QSE)
Telephone:
713-795-6108
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001489
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001490
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001491
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001492
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: A field trial may indicate the need for more or different data for the proper
calculation of a BAs Frequency Response.
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: Frequency Response of Resources is vital to the reliability of an
interconnection. Large differences between the measured Frequency Response of a BA,
its Bias setting and the models of Frequency Response may indicate a reliability risk.
Updating the models with accurate Frequency Response data will improve the
evaluation of this reliability risk. Please implement this process as soon as possible.
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001493
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Calimano
Organization: New York Independent System Operator
Telephone:
518-356-6129
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001494
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001495
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001496
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001497
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: The NYISO is uncertain if this is the appropriate means to require data
collection for purposes of developing models. A review should be made to be certain
that this proposed scope meets the criteria for a standard.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: It is not clear what type of data is going to be collected from this
requirement. AGC response is continuous. What is the justification for the specific
"five minutes" reffered to? Since AGC control is every 4 seconds, five minutes appears
to be too long a period to collect this data. Imposing this requirement will require the
installation of local data storage retention facilities & telemetering equipment that may
not be necessary and NPCC participating members would like the drafting team to
explain why 5 minutes is necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001498
Comment Form for Draft 3 of the Frequency Response SAR
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001499
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Theodore Papaps
Organization: New York State Relaibility Council
Telephone:
516-545-4007
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001500
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001501
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001502
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001503
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: Explain the applicability of the SAR to LSEs
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: It is not clear what type of data is going to be collected from this
requirement. AGC response is continuous. What is the justification for the specific
"five minutes" reffered to? Since AGC control is every 4 seconds, five minutes appears
to be too long a period to collect this data. Imposing this requirement will require the
installation of local data storage retention facilities & telemetering equipment that may
not be necessary.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: The results of the data collection efforts should be used to develop a
standard governing frequency response.
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001504
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001505
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Jim Busbin
Contact Organization:
Southern Company Services, Inc.
Contact Segment:
1
Contact Telephone:
205-257-6357
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Marc Butts
Southern Company Services
SERC
1
J. T. Wood
Southern Company Services
SERC
1
Roman Carter
Southern Company Services
SERC
1
Raymond Vice
Southern Company Services
SERC
1
Jim Viikinsalo
Southern Company Services
SERC
1
Tom Higgins
Southern Company Services
SERC
5
Terry Crawley
Southern Company Services
SERC
5
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001506
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001507
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001508
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: Frequency response and its dynamic behavior is a complex issue that
requires detailed analysis and study to understand. This in turn requires sufficient high
quality data be obtained to support the development of models and concepts. The data
could be collected voluntarily, but without the force of NERC standards behind it not
many people are going to devote the resources required to collect the data. We
strongly support this effort.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments: Currently BAs in the Eastern Interconnection have little, if any, way to
actually calculate their frequency responses. As a result, most default to the one
percent minimum. A good database of disturbance events will provide the information
to calculate BA frequency response more accurately while at the same time allowing
the NERC OC/RS to determine if the one percent minimum is appropriate in the EI
today.
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001509
Comment Form for Draft 3 of the Frequency Response SAR
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: This SAR starts the process toward understanding frequency behavior,
particularly in the Eastern Interconnection. In our opinion this is a necessary first step
in determining whether we need frequency response allocations or other measures to
ensure the sustained frequency performance that is required for reliable operations.
Wherever possible, the scope and extent of data collection required for generators,
their dynamic models including all associated control devices, and any other system
data parameters covered under this SAR be limited such that it should not duplicate or
exceed system modeling data requirements of any other NERC standard. One
important system modeling parameter not emphasized in this SAR is the characteristic
behavior of load at each substation (constant power, constant current, etc.), which
would seem to have a significant effect on overall frequency response of the
interconnected system. It is quite possible that advancements in consumer appliances
and electronics, and their proliferation of use, have collectively changed the overall
characteristics of system load to a composite state that is significantly different from
modeling assumptions made within the previous few years.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001510
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Pfeister
Organization: Salt River Project
Telephone:
602-236-3970
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001511
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001512
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001513
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001514
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: Ultimately there may be some impact to the Planning Coordinator and/or
Resource Planner if a frequency response requirement is specified. Could there be an
extreme scenario where an entity would have to consider shedding load to meet some
frequency reserve criteria?
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: The SAR includes some requirement language pertaining to generators
greater than 10 MW. Old NERC Policy included language requiring frequency responsive
governors "unless restricted by regulatory mandates". This makes sense for most
nuclear facilities. Another type of restriction on governors involves small hydro units
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001515
Comment Form for Draft 3 of the Frequency Response SAR
that are dependent on water order. For this type of unit there truly is no governor
response yet the unit capabilities may exceed 10 MWs. Please consider these types of
exemptions as work progresses on this SAR and resulting standard.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001516
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Beck
Organization: Southwestern Power Administration
Telephone:
417-891-2639
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001517
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001518
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001519
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001520
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: The scope of this SAR is for data collection, and should not include
establishing a Target Frequency Response as stated in Paragraph #5.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: Load serving entities should not be included due to the characteristics of
load and frequency. Load Serving Entities should contribute data to determine FRC.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: Need more specific information regarding sample rates. The 5-minutes of
frequency response should identify time periods prior to and after the event.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: Data collection and FRC assessments should also take into account loss of
load, not just loss of generation. If load is lost, causing a high frequency excursion,
FRC should be observed on heavily loaded generators.
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001521
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
David Lemmons
Organization: Xcel Energy Services
Telephone:
303-308-6120
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001522
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
Greg Pieper
Xcel Energy
MRO
1
Michael Ibold
Xcel Energy
MRO
3
Steve Beuning
Xcel Energy
MRO
5
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001523
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001524
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001525
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: We agree with the proposed scope except that items 5 and 6 do not deal
specifically with data collection and therefore are beyond the scope of the SAR. We are
concerned over establishing a Target Frequency Response. This is presumptious in that
it advances a proposed remedy before first meeting the intent of the SAR-determining
the cause for the percieved decline in frequency response. We support Items 6a. and
6b. if referenced to item 4 as modified as follows: Modify 4 to require generator level
reporting when the Frequency Response for a BA is less than [75]* percent of the
Previous Years observed Frequency Response. Delete items 5 and 6.
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: To the extent information is needed from these entities, they are
appropriate to list. It is possible that the LSE is not required.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: Further clarification is needed around the time period for which data will be
collected. It important to note that description of the 5 minutes data collection period
should include 1 minute before and 4 minutes after the event.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
Page 5 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001526
Comment Form for Draft 3 of the Frequency Response SAR
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments: Establishing a Target Frequency Response is premature. It advances a
proposed remedy in advance of first meeting the intent of the SAR-determining the
cause for the percieved decline in frequency response. It is our view that the percieved
decline of frequency response, if that turns out to be the confirmed as a true decline, of
itself does not necessarily indicate an significantly increased threat to reliability. As long
as generating reserve obligations are being met to meet Reliability Standards and the
real time regulating reserves are being carried, also to meet Standards, there may not
be a need to go further depending on the outcome of the study proposed by the SAR.
Page 6 of 6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001527
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian Thumm
Organization: ITC Holdings
Telephone:
248-374-7846
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001528
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001529
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001530
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001531
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments:
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments: Five minutes of data seems arbitrary. If the collection period were
extended to 15 minutes, it would coincide with the Disturbance Control period.
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001532
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
James H. Sorrels, Jr.
Organization: American Electric Power
Telephone:
(614) 716-2370
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001533
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001534
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001535
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001536
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments:
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: The role of the load serving entity in item 6b is unclear.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001537
Comment Form for Draft 3 of the Frequency Response SAR
Please use this form to submit comments on the third draft of the Frequency Response
SAR. Comments must be submitted by March 9, 2007. You may submit the completed
form by e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
If you have questions please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Richard Kafka
Organization: Pepco Holdings, Inc.
Telephone:
301-469-5274
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
8 — Small Electricity End Users
NA – Not
Applicable
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001538
Comment Form for Draft 3 of the Frequency Response SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001539
Comment Form for Draft 3 of the Frequency Response SAR
Background Information:
The original SAR on Frequency Response was submitted in large part due to a study that
showed a 10+% decline in Eastern Interconnection Frequency Response over a 5-year
period, when response should be increasing over time as the Interconnection grows. Other
Interconnections were observing similar declines. The drafting team posted a white paper
along with the SAR to outline the need for a standard.
The NERC Resources Subcommittee recently updated their estimate of Eastern
Interconnection Frequency Response and found it still trending downward. Response in
2006 was on the order of 2,800 MW/0.1Hz (compared to 3,750 MW/0.1Hz in 1994).
Frequency Response for larger events (greater than 35 mHz) in 2006 may be as low as
2,600 MW/0.1Hz. Below is an independently calculated estimate of the trend in Eastern
Interconnection Frequency Response provided by the New York ISO. Note: Response is
stated in engineering terms (MW/mHz) as opposed to the traditional MW/01.Hz.
The proposed Frequency Response standard (FRS) is a technical standard. Technical
standards are described in the Reliability Standards Development Procedure. The FRS is
not proposed to be a performance standard and does not propose a minimum Frequency
Response, below which penalties are applied.
Industry commenters agreed there is a reliability need for the FRS. Comments varied on
the technical details of the standard. Because of the divergent views on the details of the
FRS SAR, the NERC Standards Committee (SC) directed the SAR drafting team to revise
the SAR to focus only on the data collection needed to support the development of
accurate models of Frequency Response in North America.
The SAR drafting team has tried to meet the Standards Committee’s directive with this
third version of the SAR.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001540
Comment Form for Draft 3 of the Frequency Response SAR
The Version 3 of the Frequency Response SAR represents the changes requested by the
NERC Standards Committee, while still meeting the June 2006 direction of the NERC
Operating Committee. Specifically, the Operating Committee endorsed developing a
Frequency Response standard that includes the following goals and objectives:
•
Improving Interconnection Frequency Response event cataloging and
benchmarking.
•
Calculating balancing authority Frequency Response and requiring balancing
authorities to analyze those cases where the response is significantly below the
norm.
•
Establishing time limits to complete the analyses.
•
Tabulating non-responsive generators.
•
Measuring generator response (those units on line).
•
Including regional participation and review.
This revised SAR was reviewed and supported by the NERC Resources Subcommittee on
December 4, 2006. The major changes between Draft 2 and Draft 3 include:
•
Clarification on the role of the Load-serving Entity and Generator Operator.
•
Inclusion of the applicability of Reliability Principles 3, 5, and 6.
•
Reduced the scope to address only the collection of data needed to model
Frequency Response in North America.
•
Clarified that the data collected to model frequency response over a period of up to
5 minutes per event to help identify the window of time where frequency response
appears to be masked by AGC action.
Note that because the changes to the SAR were quite significant, no redline showing the
changes from Version 2 to Version 3 will be posted.
Please review the revised SAR and then answer the questions on the following page.
Comments must be submitted by March 9, 2007. You may submit the completed form by
e-mail to [email protected] with the words “FR SAR Draft 3” in the subject line.
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001541
Comment Form for Draft 3 of the Frequency Response SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?
Yes
No
Comments: Data collection will provide the background for any new performance
standard
2. The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard?
Yes
No
Comments: In some cases, it is likely that the BA and GOP will have all the information
required.
3. The SAR drafting team modified the SAR to clarify that data will be collected to model
up to 5 minutes of frequency response. This should help identify the window of time
where frequency response appears to be masked by AGC action. Do you agree with
this clarification?
Yes
No
Comments:
4. Should a field trial be initiated, whereby a set of events for each Interconnection is
posted throughout the year, to be used by BAs to calculate their 2007 Frequency
Response?
Yes
No
Comments:
5. Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001542
Consideration of Comments on 3rd Posting of Frequency Response SAR
The Frequency Response SAR Requesters thank all commenters who submitted comments on
Draft 3 of the Frequency Response SAR. This SAR was posted for a 30-day public comment
period from February 8 through March 9, 2007. The requesters asked stakeholders to provide
feedback on the standard through a special standard Comment Form. There were 26 sets of
comments, including comments from more than 59 different people from 39 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team did not make any changes to the SAR
(except to update the descriptions of the Reliability Functions to match the latest version of the
Functional Model) and is recommending that the Standards Committee authorize moving this
SAR forward to standard drafting.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001543
Consideration of Comments on 3rd Posting of Frequency Response SAR
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Dan Boezio (G8)
AEP
9
2.
Jason Shaver
American Transmission Co.
9
3.
Bart McManus
Bonneville Power
Administration
9
4.
James Murphy
Bonneville Power
Administration
9
5.
John Anasis
Bonneville Power
Administration
9
6.
Brenda Anderson
Bonneville Power
Administration
9
7.
Brent Kingsford
California ISO
2
3
4
5
6
7
8
9
9
9
8.
Ed Thompson
(G2)
ConEd
9.
Michael Gildea
Constellation Generation
10.
Doug Hils (G3)
Duke Energy
11.
Howard F. Illian
Energy Mark, Inc.
12.
Steve Myers (G1)
ERCOT
9
9
9
9
13.
Bruno Jesus (G2)
Hydro One Networks
9
14.
Roger
Champagne (G1)
Hydro Québec
TransÉnergie
9
15.
Ron Falsetti (G1)
IESO
9
16.
Kathleen
Goodman (G1)
ISO-NE
9
17.
Bill Shemley (G2)
ISO-NE
9
18.
Brian Thumm
(G3)
ITC Transmission
19.
Jim Cyrulewski
(G3)
JDRJC Associates
20.
Michael Gammon
Kansas City Power & Light
9
21.
Jim Useldinger
KCPL
9
9
9
Page 2 of 31
June 30, 2007
10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001544
Consideration of Comments on 3rd Posting of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
(G8)
22.
Jason Atwood
(G8)
Kelson Energy
23.
Don Nelson (G2)
MA Dept. of Tele. And
Energy
24.
Robert Coish
Manitoba Hydro
25.
Alan R. Oneal
MidAmerican Energy Co.
26.
Jason Marshall
(G3)
Midwest ISO Stakeholders
Standards Collaboration
Participants
27.
Herb
Schrayshuen
National Grid
28.
Randy McDonald
(G2)
NBSO
29.
Guy V. Zito (G2)
NPCC
9
9
9
9
9
9
9
9
9
9
9
30.
Sydney Niemeyer
NRG Texas, Qualified
Scheduling Entity
31.
Jerad Barnhart
NStar
32.
Mike Calimano
(G1)
NYISO
9
33.
Greg Campoli
(G1)
NYISO
9
34.
Ralph Rufrano
(G2)
NYPA
35.
Theodore Papaps
NYSRC
36.
Al Adamson (G2)
NYSRC
9
9
9
9
9
37.
Pete Kuebeck
(G8)
OG&E
38.
Al DiCaprio
PJM
9
39.
Alicia Daughtery
PJM
9
40.
Joseph Willson
PJM
9
41.
Tom Bowe
PJM
9
42.
Mike Pfeister
Salt River Project
9
43.
Jim Busbin (G6)
Southern Company
Services, Inc.
9
44.
Marc Butts (G6)
Southern Company
Services, Inc.
9
45.
J.T. Wood (G6)
Southern Company
Services, Inc.
9
46.
Roman Carter
Southern Company
Services, Inc.
9
47.
Raymond Vice
Southern Company
Services, Inc.
9
Page 3 of 31
June 30, 2007
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001545
Consideration of Comments on 3rd Posting of Frequency Response SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
48.
Jim Viikinsalo
Southern Company
Services, Inc.
49.
Tom Higgins
Southern Company
Services, Inc.
9
50.
Terry Crawley
Southern Company
Services, Inc.
9
51.
Ron Beck
Southwestern Power
Administration
9
52.
Bill Grant (G8)
Southwestern Public
Service
9
53.
Wayne Galli (G8)
SPP
54.
Steve Massey
(G8)
Westar Energy
55.
Mich Crouch (G8)
Western Farmers
9
56.
Greg Pieper
Xcel Energy Services
9
57.
Michael Ibold
Xcel Energy Services
58.
Steve Beuning
Xcel Energy Services
59.
David Lemmons
Xcel Energy Services
6
7
8
9
10
9
9
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as
part of a group
G1 - IRC Standards Review Committee
G2 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G3 – Midwest ISO Stakeholders Standards Collaboration Participants (MISO SSC)
G4 – TVA
G5 – Public Service Commission of SC (PSC of SC)
G6 – Southern Company Transmission (Southern Co)
G7 – MRO
G8 – Southwest Power Pool Operating Reliability Working Group
Page 4 of 31
June 30, 2007
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001546
Index to Questions, Comments, and Responses
1.
Do you agree with the reduced scope of this SAR — focusing only on the data collection
needed to support the development of accurate models of Frequency Response in North
America?..............................................................................................................6
2.
The proposed standard would have requirements for the following functional entities:
Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and
Load-serving Entity. Do you agree that these are the right functional entities for the
proposed standard? ............................................................................................. 12
3.
The SAR drafting team modified the SAR to clarify that data will be collected to model up
to 5 minutes of frequency response. This should help identify the window of time where
frequency response appears to be masked by AGC action. Do you agree with this
clarification? ....................................................................................................... 17
4.
Should a field trial be initiated, whereby a set of events for each Interconnection is posted
throughout the year, to be used by BAs to calculate their 2007 Frequency Response? ... 22
5.
Please provide any other comments (that you have not already provided in response to
the first three questions on this form) that you have on the revised SAR. .................... 26
Page 5 of 31
June 30, 2007
001547
1. Do you agree with the reduced scope of this SAR — focusing only on the data collection needed to support the
development of accurate models of Frequency Response in North America?
Summary Consideration:
The majority of the comments agreed with the reduced scope of the SAR, which now focuses only on the data collection that is
needed to support the development of accurate models of Frequency Response in North America. For most of the commenters
that did not support the reduced scope, the SAR Drafting Team believes there may be a misunderstanding with respect to the
use of the Target Frequency Response. The SAR Drafting Team explained to those commenters that the Target Frequency
Response does not set a minimum for any particular Balancing Authority. Rather it sets a benchmark, beyond which additional
data is needed from the Balancing Authority.
Question #1
Commenter
SWPA
Yes
No
Comment
The
scope
of
this
SAR
is
for
data
collection,
should not include establishing a Target
; Frequency Response as stated in Paragraph and
#5.
Response: The SAR Drafting Team appreciates your input, but disagrees with your conclusion. There should always be a
purpose for going to the trouble and expense of capturing and analyzing data. The SAR Drafting Team considers the
establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and
one of the two fundamental reasons why this SAR was initially drafted. The SAR Drafting Team believes there may be a
misunderstanding with respect to Target Frequency Response, which does not set a minimum for any particular Balancing
Authority. The Target Frequency Response sets a benchmark, beyond which additional data is needed from the Balancing
Authority.
Xcel Energy Services
agree with the proposed scope except that items 5 and 6 do not deal specifically with
; We
data collection and therefore are beyond the scope of the SAR. We are concerned over
establishing a Target Frequency Response. This is presumptious in that it advances a
proposed remedy before first meeting the intent of the SAR-determining the cause for
the percieved decline in frequency response. We support Items 6a. and 6b. if referenced
to item 4 as modified as follows: Modify 4 to require generator level reporting when the
Frequency Response for a BA is less than [75]* percent of the Previous Years observed
Frequency Response. Delete items 5 and 6.
Response: In response to your first comment on Paragraph 5, the SAR Drafting Team considers the establishment of a
Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and one of the two
fundamental reasons why this SAR was drafted initially. The reason for establishing the target frequency response is to
determine the point at which additional data is needed from a given Balancing Authority.
In response to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
Page 6 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001548
Question #1
Commenter
Yes No
Comment
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them.
PJM
primary objective of this SAR is to collect data; to analyze the data; and only then
; The
to recommend a performance value. The SAR DT insists that collecting data is a
Technical Standard. The RSDP states:
"Technical standards…will contain Measures (not measuring - AMD) of physical
parameters…" At this point this SAR proposal does not contain such a measure, it does
not even assert that the measure is really needed (hence the need to analyze the data).
Page 19 (of 43) of the RSPM states “The drafting team may recommend the scope of the
standard be reduced to allow the effort to move forward, while still remaining within the
scope of the SAR. Reducing the scope of the SAR is acceptable if the drafting team finds,
for instance, THAT ADDITIONAL TECHNICAL RESEARCH IS NEEDED PRIOR TO
DEVELOPING (emphasis added) a portion of the standard or issues need to be resolved
before consensus can be achieved on a portion of the standard. “The highlighted section
applies directly to the scope of this SAR. The SAR Team recognizes work is needed.
There is no question about that. The Team should do that work BEFORE proposing a
mandatory standard.
PJM supports the concept of doing such a study, and would encourage NERC to assign a
group to do such a study, but PJM does not agree that collecting data rises to the level of
a valid NERC reliability standard.
Response: NERC’s Reliability Standards Development Plan: 2007 - 2009 describes the characteristics of a Reliability
Standard as follows: “ Although reliability standards have a common format and process, several types of reliability standards
may exist, each with a different approach to measurement:
Technical standards related to the provision, maintenance, operation, or state of bulk power systems will likely contain
measures of physical parameters and will often be technical in nature.
Performance standards related to the actions of entities providing for or impacting the reliability of the bulk power
systems will likely contain measures of the result of such actions, or the nature of the performance of such actions”.
Collecting, correlating and analyzing data on a continental scale is not a simple matter. The SAR Drafting Team believes that
the scale of this project and the potential importance of the conclusions to be developed per the specifications in Paragraphs
5 and 6 more than warrant the use of the NERC Reliability Standards Process to address them. Directed research can be
Page 7 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001549
Question #1
Commenter
Yes No
Comment
investigated during the standard development effort.
IESO
do not agree with the reduced scope of this SAR. It does not require a standard to
; We
enable a data collection task(s). Data collection procedures and processes, charged by a
standing committee, e.g. the OC, or respective working groups, would be more than
sufficient.
Response: The SAR Drafting Team believes that the scale of this project, the ongoing nature, and the potential importance
of the conclusions to be developed per the specifications in Paragraphs 5 and 6 more than warrant the use of the NERC
Reliability Standards Process to address them. We believe the Standing Committees would play a vital role in evaluating the
initial results of the standard.
SPP ORWG
not agree with the notion in point 5 regarding the need for a Target Frequency
; Do
Response for each interconnection at this time. It is beyond the scope of this technical
SAR to propose anything other than collection of data to support the study.
Do not agree with point 6 of the description. In order to get a handle on what is really
going on, all Balancing Authorities should be required to produce data valid to the study.
Also the language in point 6 is poorly worded compared to the right wording in 6a and
6b. 6a and 6b should be included in the SAR and 6 should be removed.
Response: The SAR Drafting Team appreciates your input, but disagrees with your conclusion. The SAR Drafting Team
considers the establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the
Interconnections and one of the two fundamental reasons why this SAR was drafted initially. The reason for establishing the
target frequency response is to determine the point at which additional data is needed from a given Balancing Authority.
With respect to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them. The intent of the Target Frequency Response is to determine the point where additional data is required. The SAR
Drafting Team does not recognize the specific wording that you are referring to in Paragraph 6 and request clarification.
KCP&L
not agree with the notion in point 5 regarding the need for a Target Frequency
; Do
Response for each interconnection at this time. It is presumptuous to advance a remedy
prior to determining cause of the perceived decline in frequency response. Allow the
techincal SAR to perform its function to determine cause. Any appropriate remedy in
operating standards should become apparent.
Do not agree with point 6 of the description. In order to get a handle on what is really
Page 8 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Yes
001550
No
Comment
going on, all Balancing Authorities should be required to produce data valid to the study.
Also the language in point 6 is poorly worded compared to the right wording in 6a and
6b. 6a and 6b should be included in the SAR and 6 should be removed.
Response: We appreciate your input, but disagree with your conclusion. The SAR Drafting Team considers the
establishment of a Target Frequency Response for each Interconnection as vital for the reliability of the Interconnections and
one of the two fundamental reasons why this SAR was drafted initially. The reason for establishing the target frequency
response is to determine the point at which additional data is needed from a given Balancing Authority.
In response to your comment on Paragraph 6, the SAR Drafting Team does not view the provisions of Paragraph 6 as
presumptive or proscriptive, but as a necessary step in identifying and understanding potential frequency response variations
within a given Interconnection. No specific action is required by the Balancing Authority or the Generation Owner at this
point in the process beyond supplying the data needed for NERC to understand why variations in Frequency Response occur
in different regions and to determine if further actions are required, via the NERC Reliability Standards Process, to address
them. The intent of the Target Frequency Response is to determine the point where additional data is required. The SAR
Drafting Team does not recognize the specific wording that you are referring to in Paragraph 6 and request clarification.
Hydro Québec
believe there might be other means than Reliability Standards to accomplish this
; ; HQT
TransÉnergie
data collection.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate.
NPCC CP9
of NPCC's participating members believe there are other means to accomplish this
; ; Many
phase of the initiative and that appropriate revisions to existing standard(s) may address
the issue determined by the data analysis could be proposed.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate.
NYISO
NYISO is uncertain if this is the appropriate means to require data collection for
; ; The
purposes of developing models. A review should be made to be certain that this
proposed scope meets the criteria for a standard.
Response: The SAR Drafting Team agrees that there may be methods other than the use of the NERC Reliability Standards
Process to address this issue. However, due to the scale of this project and the potential importance of the conclusions to be
developed per the specifications in Paragraphs 5 and 6, the SAR Drafting Team believes that the use of the NERC Reliability
Standards Process is appropriate. Note that the NERC Standards Committee and the industry as a whole are currently
performing just such a review, as you request, by commenting on this draft SAR.
Page 9 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Energy Mark, Inc.
Yes
001551
No
Comment
At
this
time
information
is
not
available
that would provide a sound technical basis for
;
the development of a performance standard. However, with the recent increased
interest in Frequency Response, new data and analysis could become available at any
time that would change the focus from a technical standard to a performance standard.
If new information and analysis becomes available during the development of the
technical standard, consideration should be given to how the development of the
technical standard could delay the development and implementation of a performance
standard. Must the technical standard be completed and approved before work can start
on a performance standard?
Response: The SAR Drafting Team agrees that there may be technical issues which may allow the Standard Drafting Team
to accomplish the functional purpose of this SAR differently than anticipated by the SAR Drafting Team. This is allowed for in
the NERC Reliability Standards Process Manual, page 19, as noted by PJM above.
It is anticipated by the SAR Drafting Team that the work set forth in the SAR will aid in determining if a Performance
Standard is required and, if so, how the standard should be structured. A SAR for a Frequency Response Performance
Standard can be written and submitted to the NERC Standards Committee at any time.
This standard would be a start, at least, at bringing to light where and why response is
MidAmerican Energy
;
being lost. It may well be that exposure and peer pressure, as well as the tiered
Co.
reporting requirements, will keep plant and operations personnel abreast of their
obligations for providing reserves of all types.
Response: The SAR Drafting Team appreciates your support.
Southern
Frequency response and its dynamic behavior is a complex issue that requires detailed
;
analysis and study to understand. This in turn requires sufficient high quality data be
obtained to support the development of models and concepts. The data could be
collected voluntarily, but without the force of NERC standards behind it not many people
are going to devote the resources required to collect the data. We strongly support this
effort.
Response: The SAR Drafting Team appreciates your support.
ISO New England
;
Bonneville Power
Administration
American
Transmission Co.
CAISO
ERCOT
;
;
;
;
Page 10 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #1
Commenter
Manitoba Hydro
MISO
NRG Texas
NYSRC
Salt River Project
American Electric
Power
ITC Transco
Yes
No
Comment
;
;
;
;
;
;
;
Page 11 of 31
001552
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001553
2. The proposed standard would have requirements for the following functional entities: Reliability Coordinator,
Balancing Authority, Generator Owner, Generator Operator, and Load-serving Entity. Do you agree that these are the
right functional entities for the proposed standard?
Summary Consideration:
The majority of the commenters supported the functional entities for which the proposed standard would be applicable,
specifically the Reliability Coordinator, Balancing Authority, Generator Owner, Generator Operator, and Load-Serving Entity. All
commenters that responded that they did not agree to the proposed functional entities requested clarification on the
applicability to a Load-serving Entity (LSE).
The SAR Drafting Team explained that the LSE functional entity was added in response to stakeholder comments received on
the first draft of the SAR. The SAR Drafting Team also explained to commenters that various industry experts estimate that as
much as 1/3 of the total Interconnection Frequency Response may be supplied by Load Frequency Response (the other 2/3 is
supplied from Turbine Governor Support). Thus information from the LSE concerning the composition and variations of load
served within the Interconnection can be critical in understanding total Interconnection Frequency Response.
One commenter suggested that if there is a future performance standard, it would be unreasonable to implement a technical
standard that requires functional entities to provide data. The SAR Drafting Team does not see the linkage between requiring
data from entities in order to qualify and quantify Frequency Response with the interconnections and NOT including all these
entities in a Frequency Response Performance Standard.
Question #2
Commenter
PJM
Yes
No
;
Comment
The proposal as written appears to be headed towards mandating a given unit response.
As such there would be an obligation on the Generator Operator - there does not seem
to be any requirements that would apply to the Generator Owner - unless of course the
requestor includes a requirement to install a governor (this has, to date, be an implied
obligation just as having a turbine has been an implied obligation). If the requestor does
intend to assert an obligation on the Generator Owner to install a governor then the
question arises should that be a standard or should that be a part of the Certification of
a GO?
It is not clear what the LSE requirements are in this proposal.
Response: The stated purpose of this SAR is to collect and analyze data in order to determine the Frequency Response for
each Interconnection, recommend a target Frequency Response for each Interconnection and determine the cause of any
significant variations in Frequency Response within each of the Interconnections.
In response to your comment on applicability to LSEs, various industry experts estimate that as much as 1/3 of the total
Interconnection Frequency Response may be supplied by Load Frequency Response (the other 2/3 is supplied from Turbine
Page 12 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001554
Question #2
Commenter
Yes No
Comment
Governor Support). Thus information from the LSE concerning the composition and variations of load served within the
Interconnection can be critical in understanding total Interconnection Frequency Response. The applicability to LSEs was
added at the specific request of commenters in a previous version of the SAR.
SWPA
serving entities should not be included due to the characteristics of load and
; Load
frequency. Load Serving Entities should contribute data to determine FRC.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR. Note that your two statements seem to contradict each other.
NPCC CP9
participating members question the need to include the applicability to the LSEs in
; NPCC
this SAR and requests the drafting team to explain this.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
NYSRC
; Explain the applicability of the SAR to LSEs.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
SPP ORWG
standard can not be imposed on the response of load to frequency. Load Serving
; AEntities
can only provide data.
Response: The SAR Drafting Team agrees that the role of the LSE will primarily be to supply data concerning the
composition and variations of load served within the Interconnection. There is nothing in the SAR imposing a response
requirement on any of the functional entities.
Hydro Québec
question the need to include the applicability to the LSEs in this SAR and requests
; We
TransÉnergie
the drafting team to explain the purpose.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
Page 13 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #2
Commenter
IESO
Yes
No
001555
Comment
For
the
purpose
of
data
collection,
assigning
responsibility to the Balancing Authority,
; Generator Operator and Load-serving Entity would
suffice.
Response: Most of the data will be collected from the entities you list. However, the SAR Drafting Team believes the other
entities included in the SAR have some of the data that is needed for this standard. For example the Generator Owner might
have relevant data that may not be available from the Generator Operator.
ISO New England
New England does not see a need to include the applicability to the LSEs in this SAR
; ISO
and requests the drafting team to explain this.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
American
does not see the need to identify the Load Serving Entity in the Applicability section.
; ATC
Transmission Co.
The SDT should provide an explanation as to the reasoning behind the selection of Load
Serving Entities.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
Energy Mark, Inc.
agree that the proposed list includes those entities that would be affected by a
; ; Itechnical
standard. However, there are many questions that must be resolved before
any standard that affects the Generation Owner, Generation Operator or Load-serving
Entity can be implemented. These questions relate to how a performance standard can
or should be implemented. If there is no reasonable expectation that they would be
included in a future performance standard, it would be unreasonable to implement a
technical standard that requires these three functional entities to provide data. In a fair
market that allows voluntary participation by Generation Owners, Generation Operators
and Load-serving Entities, the direct application of a Frequency Response Performance
Standard to these entities is not currently possible without creating unreasonable
inequities in the market. Any standard applied directly to one generator but not another
will create unreasonble inequities in a market. Since each generation technology has
different Frequency Response capabilities, only a solution that provides Frequency
Response through a market based mechanism can be fairly implimented in a market.
Under these conditions, the measurement methods and data collection for a technical
standard should only be applied to those entities that would have resposibilities under a
Page 14 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #2
Commenter
Yes
001556
No
Comment
performance standard. The correct alternative for collecting data from these entities is
to collect it indirectly through the Balancing Authority or Reliability Coordinator that
would be directly affected by a performance standard. The inclusion of Generation
Owner, Generation Operator, and Load-serving Entity directly in the data collection will
lead to the development of data collection systems that will need to be replaced, if and
when, a performance standard is developed. This is an inefficient way to develop the
technology for a new standard.
Response: The SAR Drafting Team appreciates your input, but disagrees with some of your conclusions.
The SAR Drafting team does not see the linkage between requiring data from entities in order to qualify and quantify
Frequency Response with the interconnections and NOT including all these entities in a Frequency Response Performance
Standard.
Available Frequency Response and its distribution within an Interconnection may require that certain generators be treated
differently than others due to their location and electrical characteristics. How this difference is compensated is neither
within the scope of this SAR nor within NERC’s authority.
The SAR drafting team agrees with your statement about the data collection being performed in the most efficient manner.
Salt River Project
Ultimately there may be some impact to the Planning Coordinator and/or Resource
;
Planner if a frequency response requirement is specified. Could there be an extreme
scenario where an entity would have to consider shedding load to meet some frequency
reserve criteria?
Response: The SAR Drafting Team does not anticipate that the standard resulting from this SAR will contain any
requirement for specific Frequency Responses from the Interconnections or the Balancing Authorities. Future standards are
beyond the scope of this SAR. The SAR Drafting Team would expect that in any standard (whether dealing with transmission,
dynamics or reserves) load shedding only makes sense if the entity cannot withstand the next contingency.
Xcel Energy Services
To the extent information is needed from these entities, they are appropriate to list. It
;
is possible that the LSE is not required.
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
American Electric
The role of the load serving entity in item 6b is unclear.
;
Power
Response: Various industry experts estimate that as much as 1/3 of the total Interconnection Frequency Response may be
supplied by Load Frequency Response (the other 2/3 is supplied from Turbine Governor Support). Thus information from the
Page 15 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001557
Question #2
Commenter
Yes No
Comment
LSE concerning the composition and variations of load served within the Interconnection can be critical in understanding total
Interconnection Frequency Response. The applicability to LSEs was added at the specific request of commenters in a
previous version of the SAR.
ERCOT
;
CAISO
Bonneville Power
Administration
KCP&L
Manitoba Hydro
MidAmerican Energy
Co.
MISO
NRG Texas
NYISO
Southern
ITC Transco
;
;
;
;
;
;
;
;
;
;
Page 16 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001558
3. The SAR drafting team modified the SAR to clarify that data will be collected to model up to 5 minutes of frequency
response. This should help identify the window of time where frequency response appears to be masked by AGC
action. Do you agree with this clarification?
Summary Consideration:
Most comments agreed that the clarification helped to identify the window of time when frequency response appears to be
masked by AGC action. Several commenters requested more specific information on the sample rates and the specific data that
would be collected. The SAR Drafting Team explained that this type of information will be developed in the standard
development process and not captured in the SAR. The SAR drafting team agreed to forward these comments to the Director
of Standards Development so that they can be addressed by the Frequency Response Standard Drafting Team.
Question #3
Commenter
SWPA
Yes
No
Comment
Need
more
specific
information
regarding
rates. The 5-minutes of frequency
; response should identify time periods priorsample
to and after the event.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
SPP ORWG
5 minute time is adequate, but it lacks substance. Small changes in load and
; The
generation due to frequency response are very difficult to separate from normal load
changes and AGC action on generation units (as was pointed out). It is important to
include in the description of data collection that the 5 minutes should include 1 minute of
data prior to a study event and 4 minutes after a study event. It is also important to
include a sample rate, such as 4 seconds (obviously, faster samples are better, but may
not be practical).
The SAR, as written, lacks specifics on what data is required to perform a valid study.
Some examples of necessary data may include, but are not limited to, AGC pulses,
special protection systems, generator MW, tie line MW, frequency, etc.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Drafting Team. We expect the data sampling rate to
Page 17 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Yes No
be on existing SCADA periodicity.
Xcel Energy Services
001559
Comment
Further clarification is needed around the time period for which data will be collected. It
important to note that description of the 5 minutes data collection period should include
1 minute before and 4 minutes after the event.
Response: In response to your first comment, the SAR Drafting Team agrees with the comment. Specific information, such
as sampling rate and specific data requirements, will be developed in the standard development process and not captured in
the SAR. The five minute period was proposed based on comments to a prior version of the SAR. Some commenters were
concerned that governors were withdrawing response shortly after the initial excursion. The SAR drafting team will forward
these comments to the Director of Standards so that they can be addressed by the Frequency Response Standard Drafting
Team. We expect the data sampling rate to be on existing SCADA periodicity.
;
In response to your second comment, the SAR Drafting team agrees that data is required both before and after the
contingency to be analyzed.
ITC Transco
minutes of data seems arbitrary. If the collection period were extended to 15
; Five
minutes, it would coincide with the Disturbance Control period.
Response: Thank you for your comment. The SAR Drafting Team agrees with the comment. Specific information, such as
sampling rate and specific data requirements, will be developed in the standard development process and not in the SAR.
The five minute period was proposed based on comments to a prior version of the SAR. Some commenters were concerned
that governors were withdrawing response shortly after the initial excursion. The SAR drafting team will forward these
comments to the Director of Standards so that they can be addressed by the Frequency Response Drafting Team. We expect
the data sampling rate to be on existing SCADA periodicity.
PJM
noted above PJM does not consider collecting data in order to decide what a
; As
requirement should be as grounds for a standard. Thus the sampling period which is
outside of a NERC standard, can be defined in whatever way the group doing the
sampling desires.
Response: Specific information, such as sampling rate and specific data requirements, will be developed in the standard
development process and not captured in the SAR. The five minute period was proposed based on comments to a prior
version of the SAR.
NYSRC
is not clear what type of data is going to be collected from this requirement. AGC
; It
response is continuous. What is the justification for the specific "five minutes" reffered
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
Page 18 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001560
Question #3
Commenter
Yes No
Comment
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
NPCC CP9
is not clear what type of data is going to be collected from this requirement. AGC
; It
response is continuous. What is the justification for the specific "five minutes" referred
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary and
NPCC participating members would like the drafting team to explain why 5 minutes is
necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not in the SAR. The five minute period was
proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
KCP&L
5 minute time is adequate, but it lacks substance. Small changes in load and
; The
generation due to frequency response are very difficult to separate from normal load
changes and AGC action on generation units (as was pointed out). It is important to
include in the description of data collection that the 5 minutes should include 1 minute of
data prior to a study event and 4 minutes after a study event. It is also important to
include a sample rate, such as 4 seconds (obviously, faster samples are better, but may
not be practical).
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Energy Mark, Inc.
with the concept of measuring Frequency Response for an extended period after
; ; Ia agree
disturbance, but I do not agree that the reason is related to masking by AGC action. If
the Frequency Bias for a Balancing Authority is set to a value that approximates the
actual Frequency Response, the AGC action will always provide the correct response for
Page 19 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Yes
No
001561
Comment
reliable interconnection performance. The Frequency Response should be measured for
an extended period after a disturbance to identify entities that are prematurely
withdrawing their expected frequency response support from the interconnection. This
has been demonstrated for entities that have outer loop control that only includes
scheduled deliveries without adjustment for frequency response.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Hydro Québec
requests clarification as to what data and at what periodicity will be collected from
; ; We
TransÉnergie
the identified entities.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
ISO New England
New England requests clarification as to what data and at what periodicity will be
; ; ISO
collected.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
MISO
minutes is acceptable. There may be merit in collecting 15 minutes of data to cover
; ; Five
the DCS window. The data should be readily available since the BAs are already
examining this data to determine their compliance with the DCS standard. The final
decision can be made during the standards drafting phase.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
Page 20 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001562
Question #3
Commenter
Yes No
Comment
sampling rate to be on existing SCADA periodicity.
NYISO
is not clear what type of data is going to be collected from this requirement. AGC
; ; It
response is continuous. What is the justification for the specific "five minutes" reffered
to? Since AGC control is every 4 seconds, five minutes appears to be too long a period to
collect this data. Imposing this requirement will require the installation of local data
storage retention facilities & telemetering equipment that may not be necessary and
NPCC participating members would like the drafting team to explain why 5 minutes is
necessary.
Also, when requesting data from a generator what is expected scan-rate/exception
reporting clarity of the data?
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
ERCOT
This time frame should be sufficient for determination of frequency response. If it is
;
intended that this data should also be useful for evaluating generating unit governor
functioning, a longer time may be appropriate.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not captured in the SAR. The five minute period
was proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards so that they can be addressed by the Frequency Response Standard Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Manitoba Hydro
Ten minutes might be more useful, especially in any areas where it appears to take a
;
long time to settle down after a frequency deviation event. This could be left up to the
discretion of operators and balancing authorities in any areas where slow or bumpy
returns to normal frequency levels are experienced.
Response: The SAR Drafting Team agrees with the comment. Specific information, such as sampling rate and specific data
requirements, will be developed in the standard development process and not in the SAR. The five minute period was
proposed based on comments to a prior version of the SAR. Some commenters were concerned that governors were
withdrawing response shortly after the initial excursion. The SAR drafting team will forward these comments to the Director
of Standards Development so that they can be addressed by the Frequency Response Drafting Team. We expect the data
sampling rate to be on existing SCADA periodicity.
Page 21 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #3
Commenter
Salt River Project
Southern
NRG Texas
MidAmerican Energy
Co.
IESO
Bonneville Power
Administration
CAISO
American Electric
Power
Yes
No
Comment
;
;
;
;
;
;
;
;
Page 22 of 31
001563
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001564
4. Should a field trial be initiated, whereby a set of events for each Interconnection is posted throughout the year, to be
used by BAs to calculate their 2007 Frequency Response?
Summary Consideration:
Most commenters indicated that a field trial should be initiated whereby a set of events for each Interconnection is posted
throughout the year, to be used by Bias to calculate their 2007 Frequency Response.
Question #4
Commenter
Yes
No
Comment
Only if field trials are deemed to have very high probability of not causing significant
difficulties on overly sensitive network area.
Response: The SAR Drafting Team agrees that no field trial should adversely impact the reliability of the Bulk Power System.
is not a new concept. I support institution of the standard as written so a start can
MidAmerican Energy
; This
Co.
be made to identify and, with luck, remediate the decline in frequency response.
Response: Thank you for your support.
Bonneville Power
does not believe a field trial is needed for this standard. The standard should be
; BPA
Administration
written and implemented with the levels of noncompliance structured around data
submittal.
Response: Thank you for your support.
PJM
are field trials for standards (which this question is directed) and there are field
; There
trials for good ideas. This proposed SAR would seem to fall into the second category;
and while posting events is interesting, it does not rate being a NERC standard.
Collecting and posting data can be effected without a standard.
Response: Thank you for your comment.
NYSRC
;
;
;
Manitoba Hydro
Energy Mark, Inc.
This would be a good way to insure that every entity select a similar set of events for
calculation of their Frequency Response, but it will not insure conformity of the results.
The difficulty with any method for selecting a common set of events is that each of those
events is caused by a disturbance within one or more of the Balancing Authorities on the
interconnection. Those entities that cause the disturbance will experience a different
frequency response than those entities that are responding. The net effect is that the
sum of the responses for all of the entities on the interconnection must sum to zero.
This means that each entity must eliminate those disturbances for which they are the
cause, from the set of disturbances they use to estimate their response. The real
advantage is an entity cannot influence the results of the measurement through
selection of the events they choose to include in the calculation.
Page 23 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001565
Question #4
Commenter
Yes No
Comment
Response: Thank you for your comment. The SAR drafting team will forward these comments to the Director of Standards
so that they can be addressed by the Frequency Response Standard Drafting Team.
MISO
This should not be a problem as BAs should already be performing this calculation in the
;
annual determination of their frequency bias.
Response: Thank you for your comment.
NRG Texas
A field trial may indicate the need for more or different data for the proper calculation of
;
a BAs Frequency Response.
Response: Thank you for your comment.
ERCOT
A field trial would be beneficial to ensure that no gaps in the need for data exist. This
;
could relate to whether other data is needed or whether data for a longer time is
needed.
Response: Thank you for your comment.
IESO
A field test is a must and would definitely provide useful information on the types of
;
event that would necessiate such data collection (The threshold needs to be clarified
though - e.g. should it be >10MW loss of generator or some other threshold?), and any
specific areas that need to be worked on in order to ensure that all relevant and required
data is collected.
Response: Thank you for your comment. The SAR Drafting Team agrees with the comment. Specific information, such as
sampling rate and specific data requirements, will be developed in the standard development process and not in the SAR.
The SAR drafting team will forward these comments to the Director of Standards so that they can be addressed by the
Frequency Response Standard Drafting Team. We expect the data sampling rate to be on existing SCADA periodicity.
Southern
Currently BAs in the Eastern Interconnection have little, if any, way to actually calculate
;
their frequency responses. As a result, most default to the one percent minimum. A
good database of disturbance events will provide the information to calculate BA
frequency response more accurately while at the same time allowing the NERC OC/RS to
determine if the one percent minimum is appropriate in the EI today.
Response: Thank you for your comment.
Hydro Québec
;
TransÉnergie
CAISO
;
ISO New England
KCP&L
NPCC CP9
;
;
;
Page 24 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #4
Commenter
NYISO
SPP ORWG
Salt River Project
Xcel Energy Services
American Electric
Power
ITC Transco
SWPA
Yes
No
Comment
;
;
;
;
;
;
;
Page 25 of 31
001566
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001567
5. Please provide any other comments (that you have not already provided in response to the first three questions on this
form) that you have on the revised SAR.
Question #5
Commenter
Comment
Bonneville Power
BPA agrees with the necessity of a frequency response standard. BPA highly encourages that this
Administration
effort be implemented as soon as possible.
Response: Thank you for your support.
Constellation
Specific to the Requirement 6 a which states:
Each Generator Operator that operates a generator larger than [10 MW]*, shall provide data
to its Balancing Authority, as required in item 6, to support this standard and for use in
developing models of Frequency Response in the associated Interconnection.
Balancing Authorities may seek Speed Droop characteristics for our generators. Speed Droop is a
design characteristic of the steam turbine (or the prime mover's governor response in the case of a
combustion turbine or diesel) .
Our concern is the only data we may be able to provide would be turbine manufacturer design data.
For our older units where turbine control systems have been retrofitted and upgraded with more
modern controls, we may not really know the speed droop characteristic of the unit. Collecting
performance data to demonstrate the speed droop is extremely difficult if not impossible on a large
unit. (Requires the grid connection frequency be allowed to "droop" as the generator is loaded).
Hence, as now written, Constellation Generation is not clear how we could comply.
Response: The SAR Drafting Team anticipates that Frequency Response information will be collected directly from measured
quantities on the grid or the generator bus. We do not anticipate using design curves or other archival data.
Energy Mark, Inc.
One of my concerns is a majority of entities in NERC must agree that there is a need for a standard
before the standard process moves forward. This could have undesirable long-term results with
respect to the quality of the standards that are developed. This standard provides a good example of
this problem. From what I have observed, both the Texas and Western Interconnections have
concluded that there is a reliability need for a Frequency Response Standard on their
interconnections. Unfortunately, reasonable opposition from the Eastern Interconnection will prevent
the development of a common standard for those two interconnections. The only alternative will be
for the Texas and Western Interconnections to each develop their own standards for Frequency
Response without considering ways of making those two standards similar to each other. If the
Eastern Interconnection, after a few years, finds that it needs a Frequency Response Standard, it will
then become necessary for a new standard to be developed that applies to all three interconnections.
Page 26 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
001568
Comment
If each interconnection has a different Frequency Response Standard, it means there is no standard
at all, but three different rules for NERC. The next logical step is to develop a common standard for
all three interconnections requiring the first two standards developed by the Texas and Western
Interconnections separately be modified to conform to a North American Standard on Frequency
Response. Combining these three separate needs into a single standard will result in a natural
opposition to change by those interconnections that have already implemented an interconnection
standard that meets their individual needs. This will make it very difficult to gain the support
necessary to enact a common standard for NERC. This multi-step development can only be avoided
by having all three interconnections participate and contribute to standards identified and developed
by individual interconnections. I believe that NERC needs to find a way to address this problem. If
they do not, the standard development and approval process will lead to fractured standards and an
unacceptable fractured standard process for NERC. One alternative might be to find a way for all
interconnections to participate in the solution of individual interconnection problems as part of the
standard development process.
Response: Thank you for your comment. We believe the Standards Development Procedure provides the solution you are
seeking. The proposed SAR sets the foundation for a technical standard for a common way to measure and evaluate
frequency response. Should a Region or Interconnection determine they need a more stringent, performance-based
standard, there is a means to pursue a difference.
Hydro Québec
Being a single Balancing Authority Interconnection, there might be a need for a «regional» difference
TransÉnergie
for the Québec Interconnection when specific value will be established. Same as ERCOT, frequency
response will be based on the change in generation (or load) rather than Tie-Line deviation.
Response: We agree with this comment. The SAR Drafting Team anticipates that specific regional differences will be
addressed in the Standard and not in the SAR.
IESO
While we felt that the previous SAR was unclear on the intent, this SAR has such a reduced scope that
the intended task does not require a reliability standard to achieve . A task team charged by a
standing committee (the OC), would suffice. The requirements proposed in the SAR can be set as
conditions for completing the data collection effort by the task team.
Response: The SAR Drafting Team disagrees and believes that the scale of this project, the ongoing nature, and the
potential importance of the conclusions to be developed per the specifications in Paragraphs 5 and 6 are sufficiently important
to warrant the use of the NERC Reliability Standards Process.
KCP&L
The reasoning for this technical standard is based on the perception that the frequency response of
the electrical system is declining and a concern that the interconnect's ability to arrest significant
system disturbances is slowly being compromised. Although it is not disagreeable that a study be
conducted to determine if an actual decline in frequency response is occuring and then to determine
cause, it is diagreeable to propose a potential remedy for a problem that may not exist or, dependent
on the findings, in inappropriate remedy.
Page 27 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
001569
Comment
One reason a decline in frequency response may be perceived occuring is a result of more on-line
generating units being fully loaded. That means when a frequency decline occurs there are less units
able to respond because they are already loaded. That does not mean the interconnection is at risk.
As long as Balancing Authorities are maintaining their reserve obligations, even large contingencies
should be manageable. However, over the years because of the trend to get more out of invested
generation resources, it would give the appearance of a decline in frequency response since most
frequency degradations are a result of losses of generation and a resultant decline in system
frequency and those are what is studied and scrutinized. The August 14, 2003 disturbance was an
opportunity to study the frequency response of all on-line generating units due to the frequency event
resulting in a high frequency. High frequency is the only event where all on-line generating units will
respond.
Proposing the establishment of a Target Frequency Response for the interconnect before concluding if
an actual decline in frequency response is occuring and the subsequent cause(s) for the decline is
finding a solution before defining the problem. Any standards involving frequency response needs to
also consider the role system reserves play in the interconnect as well as the frequency response of
generators and system load to frequency. As long as generating reserve obligations are being met to
meet current Reliability Standards and Regional Operating Criteria there may not be a need to go
further dependent on the outcome of the study proposed by this SAR.
Response: The SAR Drafting Team agrees with you speculations, but strongly believes that actual field data must be
collected and analyzed to determine the specific processes impacting Frequency Response. It may well be that no further
action will be required, but that is beyond the scope of this SAR.
I have concern about the "shall"s in the standard, in that there is no apparent enforcement behind
MidAmerican Energy
the requirements for data submittals. If I'm wrong in this, then I would be comfortable with the
Co.
effectiveness possible. If I'm right, what is to be done with an entity which finds it convenient not to
report?
Response: The SAR Drafting Team anticipates that the Standard that evolves from this SAR will have measures for such
things as failure to report and other practical details.
NRG Texas
Frequency Response of Resources is vital to the reliability of an interconnection. Large differences
between the measured Frequency Response of a BA, its Bias setting and the models of Frequency
Response may indicate a reliability risk. Updating the models with accurate Frequency Response data
will improve the evaluation of this reliability risk. Please implement this process as soon as possible.
Response: The SAR Drafting Team agrees and thanks you for your support.
NYSRC
The results of the data collection efforts should be used to develop a standard governing frequency
response.
Page 28 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001570
Question #5
Commenter
Comment
Response: The SAR Drafting Team agrees and thanks you for your support.
Southern
This SAR starts the process toward understanding frequency behavior, particularly in the Eastern
Interconnection. In our opinion this is a necessary first step in determining whether we need
frequency response allocations or other measures to ensure the sustained frequency performance
that is required for reliable operations.
Wherever possible, the scope and extent of data collection required for generators, their dynamic
models including all associated control devices, and any other system data parameters covered under
this SAR be limited such that it should not duplicate or exceed system modeling data requirements of
any other NERC standard. One important system modeling parameter not emphasized in this SAR is
the characteristic behavior of load at each substation (constant power, constant current, etc.), which
would seem to have a significant effect on overall frequency response of the interconnected system.
It is quite possible that advancements in consumer appliances and electronics, and their proliferation
of use, have collectively changed the overall characteristics of system load to a composite state that
is significantly different from modeling assumptions made within the previous few years.
Response: The SAR Drafting Team agrees and thanks you for your support.
SPP ORWG
The reasoning for this technical standard is based on the perception that the frequency response of
the electrical system is declining and a concern that the interconnect's ability to arrest significant
system disturbances is slowly being compromised. Although it is not disagreeable that a study be
conducted to determine if an actual decline in frequency response is occuring and then to determine
cause, it is diagreeable to propose a potential remedy for a problem that may not exist or, dependent
on the findings, in inappropriate remedy.
Types of generating units online (e.g., wind generation, combined cycle, etc) and their subsequent
loading will have an influence on the frequency response of the system. As long as Balancing
Authorities are maintaining their reserve obligations, even large contingencies should be manageable.
However, over the years because of the trend to get more out of invested generation resources, it
would give the appearance of a decline in frequency response since most frequency degradations are
a result of losses of generation and a resultant decline in system frequency and those are what is
studied and scrutinized. The August 14, 2003 disturbance was an opportunity to study the frequency
response of all on-line generating units due to the frequency event resulting in a high frequency.
High frequency is the only event where all on-line generating units will respond.
Proposing the establishment of a Target Frequency Response for the interconnect before concluding if
an actual decline in frequency response is occuring and the cause(s) for the decline is finding a
solution before defining the problem. Any standards involving frequency response need to also
Page 29 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
001571
Question #5
Commenter
Comment
consider the role system reserves play in the interconnect as well as the frequency response of
generators and system load to frequency. As long as generating reserve obligations are being met in
accordance with current Reliability Standards and Regional Operating Criteria there may not be a
need to go further dependent on the outcome of the study proposed by this SAR.
Response: The SAR Drafting Team disagrees and believes that a fundamental understanding of frequency response in each
of the Interconnections is necessary to ensure reliability of the Bulk Power System. This is particularly important as new,
untested technologies are integrated into the Bulk Power System with potentially unanticipated outcomes. Although no follow
up Standards may be required after the Frequency Response Standard is developed, there is a potential risk to
Interconnection reliability unless we do implement this SAR and Standard and develop a firm understanding of specifically
how Frequency Response operates.
It appears that there is a misunderstanding of the Target Frequency Response in that this does not set a minimum for any
particular Balancing Authority. The Target Frequency Response sets a benchmark, beyond which additional data is needed
from the Balancing Authority.
Salt River Project
The SAR includes some requirement language pertaining to generators greater than 10 MW. Old NERC
Policy included language requiring frequency responsive governors "unless restricted by regulatory
mandates". This makes sense for most nuclear facilities. Another type of restriction on governors
involves small hydro units that are dependent on water order. For this type of unit there truly is no
governor response yet the unit capabilities may exceed 10 MWs. Please consider these types of
exemptions as work progresses on this SAR and resulting standard.
Response: Your comments are good and will be provided to the Standard Drafting Team as it wrestles with the specific
details of this project. The SAR does not propose to set a mandatory level of governor response for each generator. The
proposed standard requires data and an identification of which generators are not providing response should the Balancing
Authority be below the Target Response.
Xcel Energy Services
Establishing a Target Frequency Response is premature. It advances a proposed remedy in advance
of first meeting the intent of the SAR-determining the cause for the percieved decline in frequency
response. It is our view that the percieved decline of frequency response, if that turns out to be the
confirmed as a true decline, of itself does not necessarily indicate an significantly increased threat to
reliability. As long as generating reserve obligations are being met to meet Reliability Standards and
the real time regulating reserves are being carried, also to meet Standards, there may not be a need
to go further depending on the outcome of the study proposed by the SAR.
Response: The SAR Drafting Team does not anticipate that a Target Frequency Response will be developed until such time
that it can be technically supported as required by the NERC Reliability Standards Process.
PJM
PJM would also note that the proposal references two distinct parameters - the Natural response of a
BA; and the natural response of a unit. It is not clear how the requestor intends to link the two
parameters. The sum of the units' natural responses will not equal the natural response of the BA.
Page 30 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
Question #5
Commenter
001572
Comment
Does the requestor intend to link the two, or to keep them separate? As written it appears that the
requestor intends for the BA to be held responsible for an annual measured value. The SAR DT does
not recognize that during different times there are different number of units opperating and available
to respond. The SAR DT makes no mention of whether or not a BA(?) would have to shed load to
maintain such frequency response (for those periods when all units are at full load). The SAR DT
makes no mention of distance from an event. An event in NE will effect more response in NE then in
Florida - how will that be addressed? PJM would ask for clarification on what the requestor would
intend to mandate.
FERC has recognized the need to include suppliers that use load control - how does this SAR intend to
address such 'natural response suppliers'?
As written this proposal becomes an ambiguous standard as it obligates a BA to get data from a
generator ( as opposed to directly obligating generators to supply the data to the analysis team - this
is important from the perspective of who would be non-compliant if the data were not supplied - the
BA or the GO?).
PJM would suggest that NERC create a Frequency Project, budget the project through its members
rather then create a standard and risk imposing non-compliance penalities for what potentially could
be a non-issue. Deal with this for what it is - a research activity.
Response: The SAR Drafting Team appreciates your thoughtful comments but does not agree with your conclusions. Many
of the details you are concerned about will be worked out as part of the details addressed by the Standards Drafting Team.
The SAR Drafting Team does not anticipate that this SAR will mandate any specific frequency response. The stated purpose
of this SAR is to collect and analyze data in order to determine the Frequency Response for each Interconnection, recommend
a target Frequency Response for each Interconnection and determine the cause of any significant variations in Frequency
Response within each of the Interconnections.
In response to your suggestion to create a Frequency Project, the NERC Standards Development Procedure Manual allows for
the development of SAR/Standard to collect and analyze data as needed to ensure the reliability of Interconnections.
SWPA
Data collection and FRC assessments should also take into account loss of load, not just loss of
generation. If load is lost, causing a high frequency excursion, FRC should be observed on heavily
loaded generators.
Response: You are correct; however the collection of statistically significant load loss data has proven to be very difficult, if
not impossible, in the past. The SAR Drafting Team will forward your comments to the Director of Standards so that they can
be addressed by the Frequency Response Standard Drafting Team.
Page 31 of 31
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Consideration of Comments on 3rd Posting of Frequency Response SAR
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001573
Standard Authorization Request Form
Title of Proposed Standard
Frequency Response
Request Date
11/25/06
Revised Date
06/30/07
SAR Requestor Information
Name
Terry Bilke
Primary Contact Terry Bilke
Telephone
(317) 249-5463
Fax
(317) 249-5994
E-mail
[email protected]
SAR Type (Put an ‘x’ in front of one of
these selections)
x
New Standard
Revision to existing Standard
Withdrawal of existing Standard
Urgent Action
Purpose/Industry Need
Frequency Response, a measure of an Interconnection’s ability to stabilize
frequency immediately following the sudden loss of generation or load, is a
critical component to the reliable operation of the bulk power system,
particularly during disturbances and restoration. The proposed standard’s
intent is to collect data needed to accurately model existing Frequency
Response. There is evidence of continuing decline in Frequency Response in
the three Interconnections over the past 10 years, but no confirmed reason for
the apparent decline. The proposed standard requires entities to provide data
so that Frequency Response in each of the Interconnections can be modeled, and
the reasons for the decline in Frequency Response can be identified. Once the
reasons for the decline in Frequency Response are confirmed, requirements can
be written to control Frequency Response to within defined reliability
parameters.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001574
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
Reliability
Authority
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
interconnection frequency in real time
Interchange
Authority
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation valid and balanced Interchange
Schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >1year plan for the resource adequacy of its specific loads
within a Planning Authority area.
Transmission
Planner
Develops a >1 year plan for the reliability of the interconnected Bulk Electric
System within its portion of the Planning Coordinator Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within
a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and reliability-related services) to
serve the End-use Customer.
SAR-2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001575
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric systems
shall be trained, qualified and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk electric systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber
attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with that
Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR-3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001576
Detailed Description (Provide enough detail so that an independent entity familiar with
the industry could draft, modify, or withdraw a Standard based on this description.)
The proposed technical/preparedness standard will require or provide
the following:
1. Each Balancing Authority shall collect and provide data [scan rate tie
deviation and frequency for up to 5* minutes per event] needed to model
its sub-minute Frequency Response to loss of large generating units and
load.
2. Each Balancing Authority shall report each loss of generation or load
greater than the respective Interconnection reporting threshold to its
Reliability Coordinator.
3. Each Reliability Coordinator will relay Frequency Response Standard
(FRS) event information to other Reliability Coordinators in its
Interconnection. The Interconnection Time Monitor will maintain a log
of FRS events.
4. NERC will annually post a list of FRS events. These events will be used
by Balancing Authorities to calculate and report their annual Frequency
Response and Bias.
5. NERC, in conjunction with the respective Regions, will establish a
Target Frequency Response for each Interconnection. Absent an
agreement, the observed Frequency Response in the first year of the FRS
will be used as a target.
6. Balancing Authorities with less than [75%]* of their share of Target
Frequency Response shall provide generation-level data to their Region
for use by Transmission Planners and Planning Coordinators.
a. Each Generator Operator that operates a generator larger than [10
MW]*, shall provide data to its Balancing Authority, as required
in item 6, to support this standard and for use in developing
models of Frequency Response in the associated Interconnection.
b. Load Serving Entities shall provide data, as required in item 6,
to their BA and Region to support the standard.
*These values are representative and will be refined based on
stakeholder input during the standard drafting phase.
Related Standards
Standard No.
Explanation
BAL-001-0
through BAL006-0
Balancing Standards, version 0
Balance
Resources
and Demand
draft
standards
Balancing Resources and Demand BAL-007 through BAL-012 draft
standards, are in standards development process
SAR-4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001577
Related SARs
SAR ID
Explanation
Frequency
Response
SAR, version
0
Original Frequency Response SAR
MOD-027
Verification and Status of Generator Frequency Response. The
proposed standard would provide a mechanism to validate
compliance with MOD-027. The proposed standard could also
provide a means to achieve MOD-027 (if the Balancing Authority
implements on on-line measurement of generator frequency using
SCADA data).
Regional Variances
Region
Explanation
ECAR
ERCOT
Single Balancing Authority Interconnections calculate Frequency
Response based on the change in generation (or load) rather
than Tie-Line deviation (ERCOT).
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC
Related NERC Operating Policies or Planning Standards
ID
Explanation
MOD-013-0
The proposed standard would enable better input data to the
modeling standards.
SAR-5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001578
SAR-6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001579
Maureen E. Long
Standards Process Manager
July 17, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Nomination Periods Open for Five New Drafting Teams
The Standards Committee announces the following standards actions:
Project 2007-04 — Certifying System Operators SAR Drafting Team (July 17–30,
2007)
The Standards Committee is seeking industry experts to serve on the Certifying System
Operators SAR Drafting Team. The drafting team will work on the modification of the
following standard:
PER-003 — Operating Personnel Credentials
If you are interested in serving on this SAR drafting team, please complete this nomination form
and return it to [email protected] by July 30, 2007 with “SO Certification SAR DT” in the
subject line. For questions, please contact Linda Clarke at 610-310-7210 or [email protected].
Project 2007-05 — Balancing Authority Controls SAR Drafting Team (July 17–30,
2007)
The Standards Committee is seeking industry experts to serve on the Balancing Authority
Controls SAR Drafting Team. The drafting team will work on modifications to the following
standards:
BAL-002 — Disturbance Control Performance
BAL-004 — Time Error Correction
BAL-005 — Automatic Generation Control
BAL-006 — Inadvertent Interchange
If you are interested in serving on this SAR drafting team, please complete this nomination form
and return it to [email protected] by July 30, 2007 with “BA Controls SAR DT” in the subject
line. For questions, please contact Linda Clarke at 610-310-7210 or [email protected].
Project 2007-09 — Generator Verification Standard Drafting Team (July 17–30,
2007)
The Standards Committee is seeking industry experts to serve on the Generator Verification
Standard Drafting Team. If you are interested in serving on this team, please complete this
nomination form and return it to [email protected] with “Gen Verification SDT” in the subject
line by July 30, 2007. For questions, please contact David Taylor at 609-651-5089 or
[email protected].
The drafting team will work on finalizing the following Phase III & IV standards:
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001580
REGISTERED BALLOT BODY
July 17, 2007
Page Two
PRC-019 — Coordination of Generator Voltage Regulator Controls with Unit
Capabilities and Protection
PRC-024 — Generator Performance during Frequency and Voltage Excursions
MOD-026 — Verification of Models and Data for Generator Excitation System
Functions
MOD-027 — Verification of Generator Unit Frequency Response
The drafting team will also work on revising two existing standards that were not approved
by the FERC because of their “fill-in-the-blank” elements:
MOD-024 — Verification of Generator Gross and Net Real Power Capability
MOD-025 — Verification of Generator Gross and Net Reactive Power Capability
Project 2007-12 — Frequency Response Standard Drafting Team (July 17–30,
2007)
The Standards Committee is seeking industry experts to serve on the Frequency Response
Standard Drafting Team. The drafting team will work to develop a standard that requires entities
to provide data so that Frequency Response in each of the Interconnections can be modeled, and
the reasons for the decline in Frequency Response can be identified.
If you are interested in serving on this standard drafting team, please complete this nomination
form and return it to [email protected] by July 30, 2007 with “FR SDT” in the subject line.
For questions, please contact Linda Clarke at 610-310-7210 or [email protected].
Project 2007-23 — Violation Severity Levels Drafting Team (July 17–30, 2007)
The Standards Committee is seeking industry experts to serve on the Violation Severity Levels
SAR Drafting Team. The drafting team will work to achieve consensus on a set of criteria for
assigning Violation Severity Levels, and will work (with other existing drafting teams) to replace
“Levels of Non-compliance” with “Violation Severity Levels” in the 83 standards approved by
the FERC. FERC directed NERC to replace “Levels of Non-compliance” with “Violation
Severity Levels’ so that the ERO’s Sanctions Guidelines can be used as intended.
If you are interested in serving on this standard drafting team, please complete this nomination
form and return it to [email protected] by July 30, 2007 with “VSL DT” in the subject line.
For questions please contact Al Calafiore at 678-524-1188 or [email protected] or Stephen
Crutchfield at 609-651-9455 or [email protected].
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001581
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Single Event Frequency Response Data (SEFRD)
The individual sample of event data from a Balancing Authority which represents the change
in Net Actual Interchange (NIA), divided by the change in frequency, expressed in
MW/0.1Hz.
Frequency Response Measure (FRM)
The median of all Single Event Frequency Response Data observations reported annually on
FRS Form 1.
Frequency Response Obligation (FRO)
The Balancing Authority’s contribution to the total aggregate Frequency Response needed
for reliable operation of an Interconnection assigned by the ERO.
Frequency Bias Setting (redline showing proposed changes to approved definition)
A value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz, set
into a Balancing Authority Area Control Error algorithm equation that allows the Balancing
Authority to contribute its frequency Frequency rResponse to the Interconnection.
BAL-003-1 Dra ft 1
Fe b ru a ry 4, 2011
Page 1 of 4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001582
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored. To schedule and
provide consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.2. Reserve Sharing Group (where applicable)
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2 and R3
of this standard shall become effective the first calendar day of the first calendar
quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as
detailed in Attachment A and calculated on FRS Form 1) that is equal to or more
negative than its Frequency Response Obligation (FRO). [Risk Factor: ][Time
Horizon: Operations Assessment]
R2.
Each Balancing Authority shall implement the Frequency Bias Setting (fixed or
variable) provided by the ERO into its Area Control Error (ACE) calculation beginning
on the date specified by the ERO to ensure effective coordinated secondary control,
using the results from the calculation methodology detailed in Attachment A. [Risk
Factor: ][Time Horizon: Operations Planning]
R3.
Each Balancing Authority shall operate its Automatic Generation Control (AGC) on
Tie Line Bias, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area. [Risk Factor: ][Time Horizon: Real-time Operations]
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall increase
its Frequency Bias Setting in its ACE calculation by combining the Frequency Bias
BAL-003-1 Dra ft 1
Fe b ru a ry 4, 2011
Page 2 of 4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001583
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Settings for the entire Balancing Authority Area being controlled. [Risk Factor: }{Time
Horizon: Operations Planning}
C. Measures
Measures for each Requirement will be provided in the second posting of the proposed
standard.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
1.3. Data Retention
Data Retention periods for Requirement R1 through Requirement R4 will be
defined in the second posting of the proposed standard.
If a Balancing Authority is found non-compliant, it shall keep information related
to the non-compliance until found compliant or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
R1 Supplemental Information
Each Balancing Authority shall report its previous year’s Frequency Response
Measure (FRM) to the ERO on Form 1 by January 10 each year. If the ERO posts
the official list of events after December 10, Balancing Authorities will be given
45 days from the date the ERO posts the official list of events to submit their FRS
Form 1.
A Balancing Authority may elect to fulfill its Frequency Response Obligation by
participating as a member of a Reserve Sharing Group (RSG). If a Balancing
BAL-003-1 Dra ft 1
Fe b ru a ry 4, 2011
Page 3 of 4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001584
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Authority elects to report as an RSG, the total of the participating Balancing
Authorities’ FRO will be compared to the total of the participating Balancing
Authorities’ FRM.
R2 Supplemental Information.
Each Balancing Authority shall report its current year requested Frequency Bias
Setting and Frequency Bias type (fixed or variable) to the ERO on FRS-Form 1
by January 10 each year. If the ERO posts the official list of events after
December 10, Balancing Authorities will be given 45 days from the date NERC
posts the official list of events to submit their FRS Form 1. Once the FRM and
Frequency Bias Settings have been validated by the ERO, the ERO will
disseminate the Frequency Bias Settings Report for all Balancing Authorities in
each Interconnection along with the implementation date.
Balancing Authorities with variable Frequency Bias Settings shall calculate
monthly average Frequency Bias Settings. The previous year’s monthly averages
will be reported annually on FRS Form 1.
2.0 Violation Severity Levels (To be added later)
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
R2
R3
R4
E. Regional Variance
None
F. Associated Documents
Attachment A - Frequency Response Standard Background Document
FRS Form 1
FRS Form 1 Instructions
Field Test Document
G. Version History
Version
0
1
BAL-003-1 Dra ft 1
Fe b ru a ry 4, 2011
Date
April 1, 2005
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 4 of 4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
001585
BAL-003 - Attachment A
Background Document
Introduction
This draft document provides background to explain the requirements in the draft Frequency
Response Standard (BAL-003-1). This document will evolve on the basis of Industry comments
on the standard and is expected to become Attachment A to the standard.
Requirement 1
R1. Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as
detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative
than its Frequency Response Obligation (FRO).
Frequency Bias Setting vs. Frequency Response
The Frequency Response Measure (FRM) for the upcoming year is based on the same data
collected for the Balancing Authorities’ annual Frequency Bias Setting calculation. A final
listing of official events to be used in the calculation will be available from NERC by December
10 each year. Once a list is distributed to Balancing Authorities, each BA has one month to
assemble its data and calculate the FRM.
The ERO will use the following criteria for the selection of events to be analyzed.
1. At least 25 events will be used for the calculation of FRM. If a year occurs in which there
are not 25 events that meet the remaining criteria below, then the most recent 25 events
(as defined below) will be used for determination of an entity’s compliance with the FRM
requirement and storage of SEFRD.
2. Two limits will be used to determine if a frequency event has occurred for the purposes
of determining FRM:
a. The frequency at the arresting frequency (Point C) must exceed the frequency
deviation event threshold specified for the Interconnection. (As of 2010, the
governor deadband setting for the Eastern and Western Interconnections will be
assumed to be near or greater than 36 MHz, although there is no stated
requirement defined in NERC standards). The Point C value is the minimum of
frequency samples within 8 seconds after the start of the rapid change in
frequency.
b. The time from the start of the rapid change in frequency until the point at which
Frequency has largely stabilized should be less than 18 seconds.
3. Typically, the Point A frequency should be relatively steady and near 60.000 Hz. Point A
is computed as an average over the period from -16 seconds to 0 seconds before initial
frequency decline.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Background Document
001586
4. Any indication or evidence of a secondary event occurrence after Point C should be
reviewed for inclusion based on having sufficient information to perform a full analysis
of the event.
5. Events occurring during periods in which either significant interchange schedule ramping
or load ramping is likely, should be excluded if other events are available for
measurement purposes.
Additional events included in Frequency Response survey for interconnection analysis: The
ERO has the discretion to request a frequency survey for events that differ significantly from
criteria 3, 4, or 5. These events will not be included on FRS Form 1 used for calculation of
frequency response.
The report will be done via FRS Form 1.
Sliding of the reporting deadline from that found in previous versions of BAL-003 is due to the
increased number of samples required and is intended to avoid burdening NERC and the
Balancing Authorities with working over holiday periods for no added value to reliability.
Frequency Bias Settings and acceptable Frequency Response are negative numbers by definition.
In other words, as frequency drops, the Balancing Authority is expected to contribute MWs to
the Interconnection (or take fewer MWs in).
The current BAL-003 has a minimum Frequency Bias Setting (in MW/0.1Hz) that is in absolute
terms equal to 1% of the Balancing Authority’s projected peak. An early researcher 1 noted that
the ideal state is where the Frequency Bias Setting is exactly equal to natural Frequency
Response. Researchers have also noted that over-bias is preferable to under-bias. The current –
(1% of peak) /0.1Hz floor for the Frequency Bias Setting is significantly more negative than
most Balancing Authorities’ natural Frequency Response. This can lead to over-control ,
particularly in the Eastern Interconnection, and force the industry to require too much
secondary control resulting in degraded performance and increased operating cost compared to
requiring an appropriate balance of primary and secondary control.
Changes to the Frequency Bias Setting that move it closer to the natural Frequency Response
will improve the quality and accuracy of ACE and all ACE based systems and measures,
including: the CERTS Automatic Frequency Events Identification and Frequency Response
Evaluation System; the CPS1 measure; the CPS2 measure; the DCS measure; the BAAL
measure; and, AGC Systems in general.
1
Cohn, Nathan. Control of Generation and Power Flow on Interconnected Systems. (New York: John Wiley & Sons,
1966)
February 4, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Background Document
001587
Frequency Bias Setting Floor
The FR SDT is proposing a gradual transition to bring Frequency Bias Settings and natural
Frequency Response closer. The Frequency Response Field Test Document describes the
gradual replacement of a floor by natural Frequency Response for Frequency Bias Setting.
Frequency Response Obligation and Allocation
The SDT is initially proposing that the Interconnection Frequency Response Obligation (FRO)
be a discretely administered determination.
For this administered approach each Interconnection will have a target contingency protection
criteria based on the largest category C event (N-2). The protection criteria will assure that Point
C will not encroach on the first step UFLS.
Under development – The SDT is evaluating a risk based approach to establishing an
Interconnection Frequency Response Obligation which can be based on a probability function.
The ERO and the NERC RS will manage the administrative procedure to assign an FRO to each
BA for the upcoming year.
Each Balancing Authority will receive a proportional slice of the Interconnection’s Frequency
Response Obligation based on (peak generation + peak load)/2. The reasoning for this
allocation method is that Balancing Authorities carry differing proportions of load and
generation. In fact, some Balancing Authorities have only load with no native generation, while
others have only generation with no native load. One of the reasons for using 2010 event data as
part of a field trial of the standard is to evaluate the allocation methodology.
Methods of Obtaining Response
A Balancing Authority may elect to fulfill its Frequency Response Obligation by participating as
a member of a Reserve Sharing Group.
There are two considerations under the option of meeting compliance by participation in a
Reserve Sharing Group (RSG). First, although spinning reserve is not a part of this standard, it
should be noted that RSGs typically define the amount of spinning reserve carried by Balancing
Authorities. Second, allowing the RSG option addresses the FERC Order No. 693 directive to
define methods of obtaining frequency response.
As long as all BAs within the RSG use the same events for calculating FRM, BAs within the
RSG may allocate a portion of their FRM to another RSG participant.
The SDT is soliciting comments on methods of obtaining Frequency Response to meet the Order
693 directive (markets, incentive programs, tariff changes, interconnection agreements,
innovative technology, resource standard).
February 4, 2011
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Background Document
001588
Measure and Compliance Information
This will be added in the second posting.
Requirement 2
R2. Each Balancing Authority shall implement the Frequency Bias Setting (fixed or
variable) provided by the ERO into its Area Control Error (ACE) calculation beginning
on the date specified by the ERO to ensure effective coordinated secondary control, using
the results from the calculation methodology detailed in Attachment A.
Background and Rationale
The traditional process for implementing new Frequency Bias Settings is for Balancing
Authorities to submit their upcoming annual Frequency Bias Setting value by January 1. NERC
and the Resources Subcommittee validate Frequency Bias Setting values, perform error checking
and use these values to calculate L10 values for CPS2. Once the L10 values are validated,
NERC posts the L10 values and sends a letter to Balancing Authorities giving a date on which to
implement the new Frequency Bias Settings. This data collection and validation process can
take up to two months. It is expected NERC will send out the L10 and Frequency Bias Setting
notification generally in February for March 1 implementation.
Measure and Compliance Information
This will be added in the second posting.
Requirement 3
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on
Tie Line Bias, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.
Background and Rationale
This requirement has existed in NERC Policy 1 and BAL-003 for years. Operating out of Tie
Line Bias control can lead to uncoordinated control that may result in unreliable operations.
Measure and Compliance Information
This will be added in the second posting.
Requirement 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall
increase its Frequency Bias Setting in its ACE calculation by combining the Frequency
Bias Settings for the entire Balancing Authority Area being controlled.
Background and Rationale
February 4, 2011
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Background Document
001589
This requirement has existed in NERC Policy 1 and BAL-003 for years. Overlap regulation
service provides ACE control for compliance from another BA authority performing the overlap
service thus the frequency bias used by the BA purchasing the service needs to be added to the
providers frequency bias which will provide the ACE control for the Balancing Authority.
Supplemental service is a schedule to provide a portion of the control for another BA using a
portion of the ACE which does not require changing the frequency bias.
Measure and Compliance Information
This will be added in the second posting.
February 4, 2011
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001590
S ta n d a rd BAL-003-0 — Fre q u e n c y Re s p o n s e a n d Bia s
A.
B.
Introduction
1.
Title:
Frequency Response and Bias
2.
Number:
BAL-003-0
3.
Purpose:
This standard provides a consistent method for calculating the Frequency Bias component of
ACE.
4.
Applicability:
4.1. Balancing Authorities
5.
Effective Date:
April 1, 2005
Requirements
R1. Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year
and recalculate its setting to reflect any change in the Frequency Response of the Balancing
Authority Area.
R1.1. The Balancing Authority may change its Frequency Bias Setting, and the method used
to determine the setting, whenever any of the factors used to determine the current bias
value change.
R1.2. Each Balancing Authority shall report its Frequency Bias Setting, and method for
determining that setting, to the NERC Operating Committee.
R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as
close as practical to, or greater than, the Balancing Authority’s Frequency Response.
Frequency Bias may be calculated several ways:
R2.1. The Balancing Authority may use a fixed Frequency Bias value which is based on a
fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The
Balancing Authority shall determine the fixed value by observing and averaging the
Frequency Response for several Disturbances during on-peak hours.
R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is
based on a variable function of Tie Line deviation to Frequency Deviation. The
Balancing Authority shall determine the variable frequency bias value by analyzing
Frequency Response as it varies with factors such as load, generation, governor
characteristics, and frequency.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Frequency Bias, unless such operation is adverse to system or Interconnection reliability.
R4. Balancing Authorities that use Dynamic Scheduling or Pseudo-ties for jointly owned units
shall reflect their respective share of the unit governor droop response in their respective
Frequency Bias Setting.
R4.1. Fixed schedules for Jointly Owned Units mandate that Balancing Authority (A) that
contains the Jointly Owned Unit must incorporate the respective share of the unit
governor droop response for any Balancing Authorities that have fixed schedules (B
and C). See the diagram below.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
1 of 2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001591
S ta n d a rd BAL-003-0 — Fre q u e n c y Re s p o n s e a n d Bia s
R4.2. The Balancing Authorities that have a fixed schedule (B and C) but do not contain the
Jointly Owned Unit shall not include their share of the governor droop response in
their Frequency Bias Setting.
Jointly Owned Unit
A
C
B
R5. Balancing Authorities that serve native load shall have a monthly average Frequency Bias
Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1
Hz change.
R5.1. Balancing Authorities that do not serve native load shall have a monthly average
Frequency Bias Setting that is at least 1% of its estimated maximum generation level in
the coming year per 0.1 Hz change.
R6. A Balancing Authority that is performing Overlap Regulation Service shall increase its
Frequency Bias Setting to match the frequency response of the entire area being controlled. A
Balancing Authority shall not change its Frequency Bias Setting when performing
Supplemental Regulation Service.
C.
Measures
M1. Each Balancing Authority shall perform Frequency Response surveys when called for by the
Operating Committee to determine the Balancing Authority’s response to Interconnection
Frequency Deviations.
D.
Compliance
Not Specified.
E.
Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed "Proposed" from Effective Date
Errata
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
2 of 2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
The information in this Supplemental SAR identifies the modifications to
001592
BAL-003-0 that were originally part of Project 2007-18 – Reliabilitybased Control. The Standards Committee authorized the transfer of this
work from Project 2007-18 to Project 2007-12 during its October 13-14,
2010 meeting.
Standard Authorization Request Form
Title of Proposed Standard
BAL-003-1 Frequency Response and Frequency Bias Setting
Supplemental to SAR dated 30Jun2007
SC Approved the transfer of work identified in this SAR from Project 2007-18 to Project
2007-12 during its October 13-14, 2010 meeting.
The supplemental SAR outlining the work that was transferred was accepted by the SC EC
on February 2, 2011
SAR Type (Check a box for each one
that applies.)
SAR Requester Information
Name
Frequency Response Standard
Drafting Team
Primary Contact
Telephone
Bill Herbsleb - PJM
New Standard
X
Revision to existing Standard
610.666.8874
Withdrawal of existing Standard
[email protected]
Urgent Action
Fax
E-mail
Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
To require sufficient Frequency Response from the Balancing Authority to maintain
Interconnection Frequency within predefined bounds by arresting frequency deviations and
supporting frequency until the frequency is restored to schedule and to provide consistent
methods for measuring Frequency Response and determining the Frequency Bias Setting.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency
immediately following the sudden loss of generation or load, is a critical component to the
reliable operation of the bulk power system, particularly during disturbances and
restoration. There is evidence of continuing decline in Frequency Response in the three
Interconnections over the past 10 years, but no confirmed reason for the apparent decline.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
To provide a minimum Frequency Response Obligation for the Balancing Authority to
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001593
Standards Authorization Request Form
achieve, methods to obtain Frequency Response and provide a consistent method for
calculating the Frequency Bias Setting for a Balancing Authority. In addition, the standard
will specify the optimal periodicity of Frequency Response surveys.
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
This SAR proposes to retire BAL-003-0 when BAL-003-1 is implemented. Below are
excerpts from documents relevant to this SAR.
From FERC Order 693:
369 - With respect to the frequency of frequency response surveys, EEI states that NERC
currently conducts an annual frequency response characteristic survey that appears to
address the Commission’s concern. The Commission disagrees. The surveys that were
performed on a yearly basis are not available on NERC’s website and the ISO/RTO Council
believes that more frequent analysis after large frequency disturbances is appropriate. The
Commission understands that the last analysis was performed in 2002. Currently, Measure
M1 only requires balancing authorities to perform surveys when requested by the NERC
operating committee. As identified in Order No. 672, the Reliability Standards should be
based on actual data. Therefore, on further consideration, instead of requiring yearly
surveys as proposed in the NOPR, the Commission believes that the frequency of these
surveys should be based on the data requirements that will assist the ERO to determine if
the balancing authorities are providing adequate and equitable frequency response to
disturbances on the Bulk-Power System. Accordingly, we direct the ERO to determine the
optimal periodicity of frequency response surveys necessary to ensure that Requirement R2
and other Requirements of the Reliability Standard are being met and to modify Measure M1
based on this determination.
372 - The Commission is not persuaded by the commenters. We conclude that the
minimum frequency response needed for Reliable Operation should be defined and methods
of obtaining the frequency response identified. In addition to the ERCOT experience, EEI
provides an additional example that underscores the Commission’s concern in this area with
its discussion of the ISO-NE frequency oscillations resulting from the August 14, 2003
blackout. Severe oscillations were observed in the ISO-NE frequency when it separated
from the Eastern Interconnection during the August 14, 2003 blackout. The ISO-NE
operators acted quickly to reduce the bias setting so as to eliminate the self-induced
frequency oscillations before they affected system reliability. This apparent mismatch
between the bias and the actual frequency response might have caused the ISO-NE system
to cascade if it had not been for the quick actions of its operators. Therefore, we direct the
ERO to either modify this Reliability Standard or develop a new Reliability Standard that
defines the necessary amount of frequency response needed for Reliable Operation and
methods of obtaining and measuring that frequency response is available.
SAR–2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001594
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
X
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001595
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
X
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
X
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
X
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
X
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
X
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR–4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001596
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
BAL-001
through BAL006
Balancing Standards
Balance
Resources and
Demand draft
standards
Balancing Resources and Demand BAL-007 draft standard is in the
Standards Development Process.
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
Single Balancing Authority Interconnections calculate Frequency Response
based on the change in generation (or load) rather than Tie-Line deviation.
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001597
Balancing Authority FRS Form 1 Background and Instructions
Subsections
A. Frequency Response Characteristics and their Measurement
1. Frequency Response
2. Response to Internal and External Generation/Load Imbalances
3. Frequency Bias Setting versus Frequency Response
4. Effects of a Disturbance on all Balancing Authorities External to the Contingent Balancing
Authority
5. Effects of a Disturbance on the Contingent Balancing Authority
6. Effects of a Disturbance on the Contingent Balancing Authority with a Jointly-Owned Unit
7. Effects of a Disturbance on the Non-Contingent Balancing Authority with a Jointly-Owned Unit
B. FRS Form 1 Instructions
This document includes the purpose and description of the Frequency Response Survey (FRS) Form 1,
including specific instructions to complete the survey form.
A.
Frequency Response Characteristics and their Measurement
Disturbances can cause frequency to either increase from loss of load or decrease from loss of generation;
Frequency Response characteristics should be evaluated for both types of events.
Accurate measurement of Frequency Response for an Interconnection or for individual Balancing
Authorities is difficult unless the frequency deviation resulting from a system disturbance is significant.
Therefore, it is better to analyze response only when significant frequency deviations occur.
1.
Frequency Response — For any change in generation/load balance in the Interconnection, a
frequency change occurs. Each Balancing Authority in the Interconnection will respond to this
frequency change through:
•
•
•
A load change resulting from the load’s Frequency Response 1 that acts to arrest
frequency changes, and varies with frequency in a continuous and inverse relationship,
A generation change resulting from governor action that acts to arrest frequency changes,
and varies with frequency in a continuous and inverse relationship, and
A change in energy consumption or production from other devices resulting from the
device’s control system that acts to arrest frequency changes, and varies with frequency
in a continuous and inverse relationship.
1
Rotating (motor) and inductive loads are the dominant load response factors; resistive loads do not
change with changing frequency.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001598
Balancing Authority FRS Form 1 Background and Instructions
Frequency responsive resources (generation, load, and other devices as above described) produce
these responses. The net effect of these actions is the Balancing Authority’s response to the
frequency change, that is, its Frequency Response. The combined response of all Balancing
Authorities in the Interconnection will cause the Interconnection frequency to settle at some value
different from the pre-disturbance value and maintain it there. Frequency will remain different
until the Balancing Authority with the generation/load imbalance (referred to as the “contingent
Balancing Authority”) corrects that imbalance, thus returning the Interconnection frequency to its
pre-disturbance value.
2.
Response to Internal and External Generation/Load Imbalances — Most of a Balancing
Authority’s Frequency Response will be reflected in a change in its actual net interchange. By
monitoring frequency error (the difference between actual and scheduled frequency) and the
change in actual interchange in response to the frequency deviation, a Balancing Authority’s
automatic generation control (AGC) can determine whether the imbalance in load and generation
is internal or external to its system. If internal, the Balancing Authority’s AGC and/or
deployment of Contingency Reserve should gradually correct the imbalance. If external, the
Balancing Authority’s AGC should allow its frequency responsive resources to continue
responding (as allowed by its Frequency Bias Setting contribution in its ACE equation) until the
contingent Balancing Authority corrects its imbalance, which should return frequency to its predisturbance value.
3.
Frequency Response versus Frequency Bias Setting— If the Balancing Authority’s Frequency
Bias Setting matches its Frequency Response in its AGC ACE equation, the Balancing
Authority’s Frequency Bias Setting allowance term would exactly offset the change in tie line
flow included in the ACE that results from frequency responsive resource action countering a
frequency deviation on the Interconnection . The following sections discuss effects of Frequency
Bias Settings on control action. The discussion explains control action by all Balancing
Authorities external to the contingent Balancing Authority (the Balancing Authority that
experienced the sudden generation/load imbalance) and by the contingent Balancing Authority
itself.
While this discussion deals with loss of generation, it applies equally to loss of load, or any
sudden contingency resulting in a generation/load mismatch. Each Balancing Authority’s
Frequency Response will vary with each disturbance because generation and load characteristics
change continuously. This discussion also assumes that frequency error from 60 Hz was zero (all
ACE values were zero) just prior to the sudden generation/load imbalance.
For further explanation of the ACE equation, refer to the Area Interchange Error Training
Document.
4.
Effects of a Disturbance on all Balancing Authorities External to the Contingent Balancing
Authority — When a loss of generation occurs, Interconnection frequency declines because
machine speed must decrease to supply a portion of the energy shortfall from rotating kinetic
energy. Initially, rotating kinetic energy from all rotating machines with direct mechanical–toelectrical coupling addresses the entire shortfall by lowering machine speed, and hence
frequency, of the Interconnection 2. Over time, Balancing Authorities’ frequency responsive
2
An amount of kinetic energy proportional to the power (generation) lost will be withdrawn from
the stored energy in rotating machines with direct mechanical-to-electrical coupling throughout the
Interconnection. As the mechanical speeds are reduced, Interconnection frequency decreases
proportionally.
February 4, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001599
Balancing Authority FRS Form 1 Background and Instructions
resources should respond to frequency error and change energy to stabilize frequency
accordingly. This will cause a change in the Balancing Authorities’ actual net interchange. In
other words, the Actual Net Interchange (NIA) generally should be greater than its value before
the contingency for all but the contingent Balancing Authority, and the result should be an
increase in flow out of non-contingent Balancing Authorities (or a decrease in flow into noncontingent Balancing Authorities). The resulting tie flow error (NIA – NIS) will be counted as
Inadvertent Interchange.
If Balancing Authorities were using only tie line flow error (i.e., flat tie control ignoring the
frequency error), this non-zero ACE would cause their AGC to reduce generation until NIA was
equal to NIS; returning their ACE to zero. However, doing this would not help arrest
Interconnection frequency decline because the Balancing Authorities would not be helping to
temporarily replace some of the generation deficiency in the Interconnection. With the tie-line
bias method, the Balancing Authorities’ AGC should allow their frequency responsive resources
to continue responding to the frequency deviation until the contingent Balancing Authority
replaces the generation it has lost.
For the AGC to allow frequency responsive resource action to continue to support frequency, a
frequency bias contribution term is added to the ACE equation to offset the tie flow error. This
bias contribution term is equal in magnitude and opposite in direction to the frequency responsive
resource action and should ideally be equal to each Balancing Authority’s Frequency Response
measured in MW/0.1 Hz. Then, when multiplied by the frequency error, ideally the Frequency
Bias Setting should exactly be offset by the tie flow error portion of the ACE calculation,
allowing continued support of frequency responsive resource action to support system frequency
while maintaining ACE at zero.
The ACE equation is then:
ACE = ( NiA − NiS ) − 10 B( f A − f S ) − I ME
Where:
• The factor 10 converts the Frequency Bias Setting (B) from MW/0.1 Hz to
MW/Hz.
• IME is a meter error correction estimate; this term should normally be very small
or zero.
NOTE: Frequency Response and Frequency Bias Settings are often referred to as positive values
(such as “our bias is 50 MW/0.1 Hz”). Frequency Response and Frequency Bias Settings are
actually negative values.
If the Frequency Bias Setting is greater (as an absolute value) than the Balancing Authority’s
actual Frequency Response, then its AGC will increase generation beyond the primary frequency
responsive resource response in order to achieve ACE = 0, which further helps arrest the
frequency decline, but increases Inadvertent Interchange. Likewise, if the Frequency Bias Setting
contribution term is less (as an absolute value) than actual Frequency Response, its AGC will
reduce generation in order to achieve ACE = 0, thereby reducing the Balancing Authority’s
contribution to arresting frequency change.
February 4, 2011
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001600
Balancing Authority FRS Form 1 Background and Instructions
5.
Effects of a Disturbance on the Contingent Balancing Authority — In the contingent
Balancing Authority where the generation deficiency occurred, most of the replacement power
comes from the Interconnection over its tie lines from Frequency Response contributions by other
Balancing Authorities in the Interconnection, as allowed by Frequency Bias Settings. A small
portion will be made up internally from the contingent Balancing Authority’s own frequency
responsive resource response. In this case, the change in NIA for the contingent Balancing
Authority is much greater than its Frequency Bias Setting component. Its ACE will be negative
(if the loss is generation), and its AGC will begin to increase generation.
NIA — drops by the total generation lost less the contingent Balancing Authority’s own
frequency responsive resource response
NIS — does not change
The energy supplied from the Interconnection appears in the contingent Balancing Authority’s
inadvertent balance.
6.
Effects of a Disturbance on the Contingent Balancing Authority with a Jointly-Owned Unit 3
— When a generation deficiency occurs within a Balancing Authority on a jointly-owned unit
(with dynamically scheduled shares being exported), the effects on the tie line component (NIA –
NIS) of their ACE equation are more complicated. The NIA drops by the total amount of the
generator lost, while the NIS is reduced only by the dynamic reduction in the shares being
exported.
NIA — drops by the total generation lost less the contingent Balancing Authority’s own
frequency responsive resource response
NIS — decreases by the reduction in dynamic shares being exported
The net effect is that the tie line bias component reflects only the response by the contingent
Balancing Authority for its share of the lost generation. Most of the replacement power comes
from the Interconnection over its tie lines from Frequency Response contributions by other
Balancing Authorities in the Interconnection.
7.
Effects of a Disturbance on a Balancing Authority with a Contingent Jointly-Owned Unit 4
Geographically-Located in an External Balancing Authority — In a Balancing Authority
whose generation deficiency occurred on a jointly-owned unit in another Balancing Authority
(with dynamically scheduled shares being exported from the other BA), the effects on the tie line
component (NIA – NIS) of their ACE equations are also complicated. The NIA increases by the
Balancing Authority’s own Frequency Response, while the NIS is reduced only by the dynamic
reduction in the share the BA is importing from the unit.
NIA — increases by the Balancing Authority’s own frequency responsive resource
response
NIS — decreases by the BA’s dynamic share of the jointly-owned unit.
The net effect is that the tie line bias component reflects only the response by the contingent
Balancing Authority for its share of the lost generation. Most of the replacement power comes
from the Interconnection over its tie lines from Frequency Response contributions of other
Balancing Authorities in the Interconnection.
3 This example assumes dynamic scheduling, not the use of pseudo-ties.
4 This example assumes dynamic scheduling, not the use of pseudo-ties.
February 4, 2011
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001601
Balancing Authority FRS Form 1 Background and Instructions
B.
BAL-003 - FRS Form 1 Instructions
Fig u re 1 — Cla s s ic Fre q u e n c y Exc u rs io n a n d Re c o ve ry
A sample frequency chart is shown in Figure 1 with points A, B, and C labeled. Point A
represents the interconnected system frequency immediately before the disturbance. Point B
represents the interconnected system frequency at the point immediately after frequency stabilizes
due to Frequency Response but before the contingent Balancing Authority takes corrective AGC
action. Point C represents the interconnected system frequency at its maximum deviation. All
dynamic adjustments as cited bulleted items 4 through 6 needs to be made to NIA.
February 4, 2011
5
001602
Balancing Authority FRS Form 1 Background and Instructions
001603
Line-by-line instructions for the survey form follow:
Point "A" Information
Point "B" Information
Column B
DelFreq
Column C
Load
Column D
NAI
Column E
Load
-0.058
2869.1
-117.0
2861.2
-0.066
2553.6
-138.5
-0.040
-0.053
2838.7
2524.7
-99.2
-94.4
FRS Form 1
Date/Time
Column A
(XXXX
Prevailing)
12/20/2008
2:12
12/27/2008
4:18
1/5/2009 9:26
1/27/2009 0:39
Point A values are averages over the
period from -16 seconds to 0 seconds
before initial frequency decline.
SEFRD
Internal
Column G
(MW/0.1Hz)
Column I
Contingency
-93.8
-40.2
N
2576.9
-110.8
-41.9
N
2857.8
2522.3
-88.5
-13.8
-26.5
-153.6
N
N
Column F
NAI
Column J
Unit
Point B values are averages over the period
from 18 seconds to 52 seconds after the first
scan indicating an initial frequency decline
Data Values
The times of events are approximate; your local observations may vary in time due to the proximity to the loss of generation and SCADA scan rates. The
time skew of your observations may be several seconds and your data should be reported accordingly.
Similarly, Delta Frequency values are approximate.
Note: The following table shows the data cells for a Generation Only Balancing Authority
February 4, 2011
7
Balancing Authority FRS Form 1 Background and Instructions
001604
Modified Heading for Generation only BA
A
Date/Time
(xxxx Prevailing)
B
Del Freq
C
D
Point "A" Information
Load
Generation
Point A values are averages over the period
from -16 seconds to 0 seconds before initial
frequency decline.
E
F
Point "B" Information
Load
Generation
G
I
SEFRD
Internal
Contingency
(MW/0.1Hz)
Unit
Point B values are averages over the period from
18 seconds to 52 seconds after the first scan
indicating an initial frequency decline
Notes: Add any necessary notes to the response. Please note that Excel allows a maximum of 256 characters for a cell.
All other data on the survey form is calculated.
February 4, 2011
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001605
Balancing Authority
NERC FRS FORM 1
BA_1
Date/Time
(Central Prevailing)
DelFreq
12/20/2008 12:12 -0.058
12/27/2008 14:18 -0.066
1/5/2009 9:26 -0.040
1/27/2009 0:39 -0.053
2/1/2009 18:59 -0.071
2/19/2009 4:59 -0.052
3/24/2009 21:27 -0.058
3/26/2009 3:51 -0.076
4/1/2009 17:05 -0.056
4/2/2009 17:09 -0.057
5/3/2009 10:05 -0.052
5-21-09 16:36:04 -0.050
6/21/2009 16:50 -0.052
6-25-09 13:51:44 -0.056
7-6-09 13:35:44 -0.058
7-26-09 14:05:48 -0.049
8-4-09 19:48:12 -0.045
8-15-09 16:06:36 -0.038
9-12-09 13:30:20 -0.048
9-29-09 11:16:12 -0.056
10-19-09 9:45:52 -0.047
10-26-09 14:53:36 -0.060
11-2-09 21:40:01 -0.060
11-3-09 19:42:08 -0.051
Point "A" Information
Load
NAI
2869.1
-117.0
2553.6
-138.5
2838.7
-99.2
2524.7
-94.4
2628.6
62.3
2295.7
10.2
2438.2
-164.5
2198.8
-167.6
2447.9
-185.2
2273.1
-124.8
2010.7
-19.9
2154.9
-2.3
2104.5
7.8
2505.8
33.4
2382.0
30.9
2180.8
-51.6
2035.8
0.2
2103.3
22.0
2101.7
-49.3
2144.0
-13.3
2376.9
-103.6
2319.7
-4.1
2442.3
-154.5
2550.7
-1.8
Point "B" Information
Load
NAI
2861.2
-93.8
2576.9
-110.8
2857.8
-88.5
2522.3
-13.8
2642.9
35.4
2283.7
20.1
2465.3
-161.1
2193.6
-131.2
2436.4
-184.7
2269.5
-122.1
2012.6
-6.2
2155.4
8.8
2103.4
-12.1
2505.2
45.7
2383.3
31.7
2178.8
-49.4
2035.5
9.7
2100.4
22.4
2098.2
-47.1
2106.1
16.1
2372.8
-99.0
2322.4
-2.5
2488.2
-102.1
2549.1
32.2
SEFRD
(MW/0.1Hz)
-40.2
-41.9
-26.5
-153.6
37.9
-19.2
-5.8
-48.1
-0.9
-4.8
-26.4
-22.2
38.3
-22.0
-1.3
-4.6
-21.1
-0.9
-4.6
-52.9
-9.8
-2.7
-87.3
-66.6
Load
Contribution
34%
-84%
-179%
3%
53%
120%
-803%
14%
2346%
132%
-14%
-5%
-5%
5%
-174%
88%
3%
834%
163%
129%
89%
-171%
-88%
4%
Internal
Contingency
N
N
N
N
N
N
N
Y
N
N
Y
N
N
N
N
N
N
N
N
N
N
N
N
N
Unit
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
2010
Eastern
BA_1
3241
3882
3242
Bias Calculation Form Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
Current Year's Actual Peak
Internal Generating Capacity
Next Year's Projected Peak
2009
-15.8
Current year
2009 Frequency Requirement Obligation(FRO)
Green Valley 1
Pleasant View 2
Summary Statistics
-24.5
Average Frequency Response [all events] (MW/0.1Hz)
-20.1
Median Frequency Response [all events] (MW/0.1Hz)
-16.2
Regression Estimate of Frequency Response [all events] (MW/0.1Hz)
-23.3
-33.9
5%
-28.5
Next Year's
2010 Frequency Requirement Obligation(FRO)
2010 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak)
-14.5
2009 FRM - Median Frequency Response [external contingencies
(MW/0.1Hz)
-15.8
A
Date/Time
(Central Prevailing)
12/15/2008 15:18
B
DelFreq
-0.100
C
Modified Heading for Single BA Interconnection
D
E
F
G
Point "A" Information
Point "B" Information
Load
Contingency Load
MW
28950.0
600.0
28931.0
SEFRD
(MW/0.1Hz)
-600.0
H
Load
Contribution
3%
I
J
K
Unit
Average Frequency Response [external contingencies] (MW/0.1Hz)
Linear Regression Frequency Response [external contingencies] (MW/0.1Hz)
Median Load Contribution (%)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001606
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0 Requirements R1, R2, R3, R4 and R6 should be retired when BAL-003-1 becomes effective.
BAL-003-0 Requirement R5 should be retired as outlined in the following table.
For those Balancing Authorities that serve native load:
•
•
•
•
•
May 2011 through December 2011
January 2012 through December 2012
January 2013 through December 2013
January 2014 through December 2014
January 2015 through
-0.8% of peak/0.1 Hz
-0.6% of peak/0.1 Hz
-0.4% of peak/0.1 Hz
-0.2% of peak/0.1 Hz
-0.0% of peak/0.1 Hz
For those Balancing Authorities that do not serve native load:
•
•
•
•
•
May 2011 through December 2011
generation/0.1 Hz
January 2012 through December 2012
generation/0.1 Hz
January 2013 through December 2013
generation/0.1 Hz
January 2014 through December 2014
generation/0.1 Hz
January 2015 through
generation/0.1 Hz
-0.8% of upcoming years maximum
-0.6% of upcoming years maximum
-0.4% of upcoming years maximum
-0.2% of upcoming years maximum
-0.0% of upcoming years maximum
The FRR drafting team, NERC and the NERC Resources Subcommittee will observe the impact on
frequency and will implement a reversion plan should frequency performance decline.
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001607
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R1, R3 and R4 of this
standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R1, R3 and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R2 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required, Requirements
R2 of this standard shall become effective the first calendar day of the first calendar quarter 24
months after Board of Trustees adoption.
February 4, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001608
Unofficial Comment Form for BAL-003-1 Frequency Response and
Frequency Bias Standard
Please DO NOT use this form to submit comments on the 1st draft of BAL-003-1 –
Frequency Response and Frequency Bias Setting. Comments must be submitted by March
7, 2011. If you have questions please contact Darrel Richardson by email at
[email protected] or by telephone at 609.613.1848.
Background Information:
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency
immediately following the sudden loss of generation or load, is a critical component to the
reliable operation of the bulk power system, particularly during disturbances and
restoration. The proposed standard’s intent is to collect data needed to accurately analyze
existing Frequency Response, set a minimum Frequency Response obligation, provide a
uniform calculation of Frequency Bias Settings that transition to values closer to Frequency
Response, and encourage coordinated AGC operation. There is evidence of continuing
decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency
Response in each of the Interconnections can be analyzed, and the reasons for the decline
in Frequency Response can be identified. Once Frequency Response has been analyzed and
confirmed, requirements can be modified to maintain reliability.
The Drafting Team would like to receive industry comments on this standard. Please submit
your comments using the electronic form by March 7, 2011.
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The SDT has developed three new terms to be used with this standard.
Single Event Frequency Response Data (SEFRD)
The individual sample of event data from a Balancing Authority which
represents the change in Net Actual Interchange (NIA), divided by the change
in frequency, expressed in MW/0.1Hz.
Frequency Response Measure (FRM)
The median of all Single Event Frequency Response Data observations
reported annually on FRS Form 1.
Frequency Response Obligation (FRO)
The Balancing Authority’s contribution to the total aggregate Frequency
Response needed for reliable operation of an Interconnection assigned by the
ERO.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001609
Comment Form — BAL-003-1 Frequency Response & Frequency Bias Standard
Do you agree with the proposed definitions in this standard? If not, please explain in
the comment area.
Yes
No
Comments:
2. The SDT has modified the definition for the term Frequency Bias Setting. The new
definition is shown below in redline to show the changes proposed.
Frequency Bias Setting
A value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz,
set into a Balancing Authority Area Control Error algorithm equation that allows the
Balancing Authority to contribute its frequency Frequency rResponse to the
Interconnection.
Do you agree with this new definition for Frequency Bias Setting? If not, please explain
in the comment area.
Yes
No
Comments:
3. The proposed purpose statement in the draft standard is:
To require sufficient Frequency Response from the Balancing Authority to maintain
Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to schedule. To
provide consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Do you agree with this purpose? If not, please explain in the comment area.
Yes
No
Comments:
4. Requirement 1 identifies a minimum level of Frequency Response.
R1. Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as
detailed in Attachment A and calculated on FRS Form 1) that is equal to or more
negative than its Frequency Response Obligation (FRO).
Do you agree with the concept that a Balancing Authority should be required to achieve
a minimum level of Frequency Response and the method for measurement? If not,
please explain in the comment area.
Yes
No
Comments:
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001610
Comment Form — BAL-003-1 Frequency Response & Frequency Bias Standard
5. Requirement 2 identifies when the Balancing Authority must implement its Frequency
Bias Setting.
R2.
Each Balancing Authority shall implement the Frequency Bias Setting (fixed or
variable) provided by the ERO into its Area Control Error (ACE) calculation beginning
on the date specified by the ERO to ensure effective coordinated secondary control,
using the results from the calculation methodology detailed in Attachment A.
Do you agree with this implementation? If not, please explain in the comment area.
Yes
No
Comments:
6. Requirement 3 mandates that a Balancing Authority operate its Automatic Generation
Control (AGC) on Tie Line Bias unless it becomes adverse to the integrity of its system.
R3.
Each Balancing Authority shall operate its Automatic Generation Control
(AGC) on Tie Line Bias, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.
Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it
becomes adverse to its system? If not, please explain in the comment area below.
Yes
No
Comments:
7. Do you agree with the proposed Implementation Plan for this standard? If not, please
explain in the comment area.
Yes
No
Comments:
8. This standard proposes to eliminate the 1% minimum Frequency Bias over a period of 4
years as outlined in the Implementation Plan. Do you agree that the elimination of the
1% minimum will bring Frequency Bias closer or equal to natural Frequency Response?
If not, please explain in the comment area.
Yes
No
Comments:
9. Do you agree with the drafting team that this standard should be field tested? If not,
please explain in the comment area.
Yes
No
Comments:
10. Attachment A of the proposed standard describes the criteria for selecting events to be
analyzed. Do you agree with the criteria as described in Attached A? If not, please
explain in the comment area.
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001611
Comment Form — BAL-003-1 Frequency Response & Frequency Bias Standard
Yes
No
Comments:
11. The proposed standard has a document attached to it that describes the SDT’s reasoning
for the Requirements (Attachment A - Frequency Response Background Document). Do
you agree with the SDT that this document is useful and provides a clear understanding
of the Requirements? If not, please explain in the comment area.
Yes
No
Comments:
12. The proposed standard requires the use of FRS Form 1 for calculating a Balancing
Authority’s FRM. Do you agree with the SDT that this is the proper method to calculate
its FRM? If not, please explain in the comment area and if possible provide an alternate
method to calculate FRM.
Yes
No
Comments:
13. The proposed standard requires the use of FRS Form 1 for calculating a Balancing
Authority’s Frequency Bias Setting. Do you agree with the SDT that this is the proper
method to calculate its Frequency Bias Setting? If not, please explain in the comment
area and if possible provide an alternate method to calculate Frequency Bias Setting.
Yes
No
Comments:
14. The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS
Form 1 for calculating FRM and Frequency Bias Setting. Do you agree with the SDT that
this document provides a clear understanding of how to use the form? If not, please
explain in the comment area.
Yes
No
Comments:
15. The SDT is soliciting comments on methods of obtaining Frequency Response to meet
the FERC Order 693 directive. If possible please provide any thoughts you may have on
this subject.
Comments:
16. If you are aware of any conflicts between the proposed standard and any regulatory
function, rule order, tariff, rate schedule, legislative requirement, or agreement please
identify the conflict here.
Comments:
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001612
Comment Form — BAL-003-1 Frequency Response & Frequency Bias Standard
17. Please provide any other comments (that you have not already provided in response to
the questions above) that you have on the draft standard BAL-003-1.
Comments:
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001613
Frequency Response Standard
Field Test Document
February 2011
February 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001614
Need for a Field test
To expedite the delivery of a Frequency Response Standard 1 the draft BAL-003-1 is built upon
the traditional annual Frequency Bias Setting calculation. This approach will enable using 2010
event data as a field test of specific aspects of the standard that have never been validated
industry-wide. The proposed field test is intended to facilitate the delivery of a technically sound
standard as soon as possible. The reasoning and approach for the components of the field test are
described below. The field test will be modified if the draft standard changes on the basis of
industry comments.
Frequency Bias Setting Floor
BAL-003-1 proposes to bring Frequency Bias Settings closer to Frequency Response. The
drafting team proposes to reduce the minimum Frequency Bias Settings over a period of years.
The drafting team proposes to establish a new minimum Frequency Bias Setting in 2011 (-0.8%
of peak/0.1Hz, compared to the present -1% of peak/0.1Hz). The drafting team, NERC and the
Resources Subcommittee will observe the impact on frequency and will implement a reversion
plan as necessary.
Impact on other Balancing Standards
Changes in Frequency Bias Settings may have secondary impacts on calculated performance in
other balancing standards. For example, with a reduced bias, L10 values tighten. The drafting
team will evaluate the impact on other balancing standards.
Evaluating Other Options
The drafting team is evaluating other approaches to evaluate risk and performance obligation.
This evaluation will be done in parallel during the field test period using the same underlying
data and other data (such as ACE) that will be available without additional effort on the part of
Balancing Authorities.
Confirm Calculation and Allocation Methodologies
While the general principles of Frequency Response are understood by Balancing Authorities,
there has never been a common methodology for measuring and analyzing Frequency Response.
The drafting team will evaluate the following aspects of the standard during the field test:
•
The measurement methodology for Balancing Authorities with large amounts of nonconforming load. This is because the impact of non conforming load on NIA for a small
Balancing Authority can be an order of magnitude greater than the Balancing Authority’s
Frequency Response. The drafting team will solicit volunteer Balancing Authorities to test a
1
On March 18, 2010, FERC Ordered NERC to deliver a performance-based Frequency Response Standard within 6
months. While FERC granted rehearing to provide time for a technical conference, the Order No 693 directives on
BAL-003 must still be addressed. BAL-003-1 is one of the top priority standards for NERC in 2010.
Frequency Response Standard Field Test Document
February 2011
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001615
secondary measure that may be superior for measuring Frequency Response in these
situations.
•
The validity of the measurement methodology for the full spectrum of Balancing Authorities
(fixed vs. variable Frequency Bias Settings, large vs. small, load-only, generation-only).
•
The variability of calculated Frequency Response (load’s Frequency Response, governor
response, plus Frequency Response from other technologies).
•
Evaluate the event-selection criteria (differences in starting and settling frequency).
Frequency Response Standard Field Test Document
February 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001616
Standards Announcement
Project 2007-12 Frequency Response
Comment Period Open February 4 – March 7, 2011
Now available at: http://www.nerc.com/filez/standards/Frequency_Response.html
Formal 30-day Comment Period Open through 8 p.m. on March 7, 2011
BAL-003-1 – Frequency Response and Frequency Bias Setting, and associated documents including the required
Form 1, Instructions for Form 1, Attachment A, proposal for a field test, and implementation plan have been posted
for a 30-day formal comment period.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment form is
posted on the project page: http://www.nerc.com/filez/standards/Frequency_Response.html
Next Steps
The drafting team will consider all comments and determine whether to make additional changes to the standard.
The team will post its response to comments and, if changes are made to the standard and supporting documents,
submit the revised documents for quality review prior to the next posting.
Project Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately following the
sudden loss of generation or load, is a critical component to the reliable operation of the bulk power system,
particularly during disturbances and restoration. The proposed standard’s intent is to collect data needed to
accurately analyze existing Frequency Response, set a minimum Frequency Response obligation, provide a uniform
calculation of Frequency Bias Settings that transition to values closer to Frequency Response, and encourage
coordinated AGC operation. There is evidence of continuing decline in Frequency Response over the past 10 years,
but no confirmed reason for the apparent decline. The proposed standard requires entities to provide data so that
Frequency Response in each of the Interconnections can be analyzed, and the reasons for the decline in Frequency
Response can be identified. Once Frequency Response has been analyzed and confirmed, requirements can be
modified to maintain reliability.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our thanks to
all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001617
Individual or group. (36 Responses)
Name (21 Responses)
Organization (21 Responses)
Group Name (15 Responses)
Lead Contact (15 Responses)
Question 1 (31 Responses)
Question 1 Comments (36 Responses)
Question 2 (31 Responses)
Question 2 Comments (36 Responses)
Question 3 (33 Responses)
Question 3 Comments (36 Responses)
Question 4 (33 Responses)
Question 4 Comments (36 Responses)
Question 5 (30 Responses)
Question 5 Comments (36 Responses)
Question 6 (33 Responses)
Question 6 Comments (36 Responses)
Question 7 (29 Responses)
Question 7 Comments (36 Responses)
Group
Arizona Public Service Company
Janet Smith
Yes
Yes
Yes
Yes
What is meant by discretely administered determination, under the heading "Frequency Obligation and Allocation" of
Attachment A? Please explain.
Yes
Yes
As long as Appendix 1 interpretation remains in effect for WECC Auto Time Error Payback. WECC BAs operate in TieLine and Time.
AZPS has a few questions: 1) has frequency performance been affected by the on-going RBC field trial, 2) what steps
will be taken to isolate this field trial from the effects of the RBC field trial, 3) will the frequency bias reduction to 0.8% of
peak load include a CPS2 grace-period for thos BAs not involved in the RBC field trial?
Individual
Joe O'Brien
NIPSCO
Yes
No
Frequency Bias and Frequency Response are not the same thing and that may be why "F" & "R" were not capitalized
in the present definition. I think the word "secondary" should appear per R2 finishing something like this: "to contribute
to secondary (non-immediate)Interconnection frequency control.", removing Frequency Response altogether. (I do
understand that you are bringing the FR and Bias closer together).
No
Yes, "Interconnection frequency", small "f".
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001618
Yes and no, similar to BAL-002 I think this should read "Each Balancing Authority or Reserve Sharing Group shall .....,
With so many BA's I believe the RSGs will be play a big role in this compliance ... This comment applies to only R1,
Yes
I guess the ERO will calculate the Bias, interesting.
No
Yes, It was proposed that AGC be replaced by Automatic Resource Control (ARC) in the standards but did not pass.
The SDT may want to monitor this related effort.
No
"Effective Date" section at the top of the Standard does not match the Implementation plan; I think there is an R4
missing in the second part of 1.3 . In the implementation plan add RSG to "Compliance with the Standards" 5 year
phase-in on removing the 1% is a good idea
Individual
John Canavan
NorthWestern Energy
Yes
Yes
Yes
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing multiple events.
Frequency response during some of these events is better than others, depending on the system conditions at the time
and the amount system loading and unloaded generation online at the time of the event. Given these circumstances a
BA’s actual response could vary by event (better or worse than median), thus compliance measurement per event to a
frequency response obligation based on the median response (over multiple events) could put BA’s in non-compliant
situations unjustly.
Yes
Yes
Yes
Individual
Howard F. Illian
Energy Mark, Inc.
No
Comment 1: I agree with the definition of the Single Event Frequency Response Data. Comment 2: I do not agree that
the Frequency Response Measure should be the median of all SEFRD observations reported annually on FRS Form 1.
Comment 3: The regression values presented on FRS Form 1 have not been calculated correctly. Comment 4: Since
the FRM is going to be used to set the value for the Frequency Bias Setting and the Frequency Bias Setting represents
a straight line though the origin of zero frequency error and zero megawatt error, the best representation of the data for
setting this paramater can be achieved through the use of a regression. Comment 5: Only a regression will weight the
impact of each SEFRD correctly. The use of median or mean will not provide the best estimate for use as the
Frequency Bias Setting. Comment 6: The standard has been written to include a samlple size (25) large enough to
enable effective statistical methods of analysis. What justification is there to then ignor those well proven methods and
revert to methods designed to address problems where the sample sizes are insufficient to support sound statistical
analysis methods.
No
Comment 7: The definition should be: "A value, (either a fixed or variable Frequency Bias), usually expressed in
MW/0.1 Hz, set into a Balancing Authority Area Control Error equation that indicates to the Balancing Authority its
contribution of Frequency Response to the Interconnection. Comment 8: The Frequency Bias Setting does not allow or
disallow the Frequency Response to be contributed. The BA will contribute its natural Frequency Response to the
interconnection through the independent actions of its loads and generators. The only influence that the Frequency
Bias Setting has is that it causes the AGC System, and hopefully other outer-loop control systems, to include that
natural Frequency Response when developing control actions to implement through AGC in response to BA balancing
requirements in a time frame well after the Frequency Response has been provided by the independent actions of its
loads and generators.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001619
Yes
No
Comment 9: I agree that each BA should be required to provide a minimum level of Frequency Response to provide for
its share of the total Frequency Response required for interconnection reliability. Comment 10: I also agree with the
methods used to measure SEFRD subject to my comments on FRS Form 1. Comment 11: I do not agree that the
method suggested for setting the FRO will achieve the desired goal of maintaining interconnection reliability. The
measurement method offered only evaluates the supply of Frequency Response. It does not evaluate the demand
(need) for Frequency Response. Since frequency error is the difference between the demand and supply any effective
measure for maintaining reliability due to frequency error must include both the demand and supply parts of this
balance. As a consequence, the method will be blind to changes (good or bad) in the demand for Frequency
Response. Changes in the demand for Frequency Response will require subsequent changes in the supply for
Frequency Response that this standard fails to address until the following year and leaves the interconnection at risk
for unreliable operation. Comment 12: The requirements associated with Frequency Response as defined in this
standard will not assure interconnection reliability. Frequency Response is a two part service. The first part of this
service is the rate at which energy is supplied in proportion to frequency error. This first part is commonly represented
as the Frequency Response and the corresponding Frequency Bias Setting. The second part of the service is the
amount of capacity that the BA stands ready to supply at this stated proportion in response to frequency error. Failure
to effectively specify and measure the amount of capacity that the BA stands ready to supply at the stated proportion
could put the interconnection at reliability risk when the required amount of capacity is not included in the operating
plan.
No
Comment 13: I agree that the BA shall implement the Frequency Bias Setting provided by the ERO into it Area Control
Error (ACE) calculation beginning on the date specified by the ERO to ensure effective coordinated secondary control.
Comment 14: I do not agree that the results from the calculation methodology detailed in Attachment A will provide the
correct Frequency Bias Setting. My comments on the calculation methodology are included elsewhere in my comments
on Attachment A and FRS Form 1.
No
Comment 15: Requirement 3 as written is unenforceable because it is too difficult to define “unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area.” Comment 16: What if operation out of Tie
line Bias control does not have an Adverse Reliability Impact on the Balancing Authority’s Area, but does have an
Adverse Reliability Impact on another BA? Comment 17: A document follows that provides an initial starting justification
for the elimination of this Requirement. See following “Requirements for AGC Operation, January 25, 2011.”
Requirements for AGC Operation, January 25, 2011 Introduction: As of the date of these comments there are two
requirements in the NERC Standards that address the operation of AGC. The first is in BAL-003-0.1b – Frequency
Response and Bias, Requirement R3. R3. Each Balancing Authority shall operate its Automatic Generation Control
(AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability. The
second is in BAL-005-0.1b – Automatic Generation Control, Requirement R7. R7. The Balancing Authority shall
operate AGC continuously unless such operation adversely impacts the reliability of the Interconnection. If AGC has
become inoperative, the Balancing Authority shall use manual control to adjust generation to maintain the Net
Scheduled Interchange. These requirements are misdirected and, for compliance purposes, they are difficult to
measure effectively. This paper provides the technical basis for replacing these requirements with new requirements
that will not only achieve the intent of these requirements, but do so in a more effective and measurable manner.
Background: Automatic Generation Control (AGC) is a computer control system contained in the Control Center EMS
that performs a number of critical functions related to the balancing function necessary to maintain frequency and
associated reliability. Among the functions it performs are: 1) the collection of telemetered and local data useful for
determining the appropriate control actions, 2) the calculation of Area Control Error (ACE), 3) determination of desired
control actions that should be sent to those resources available for automatic dispatch, and 4) sending the actual
control signals to implement that dispatch. Most AGC Systems have three basic modes of operation, 1) Tie-line
Frequency Bias, 2) Constant Net Interchange and 3) Constant Frequency. The ACE Equation is the basis for all three
modes of operation. In the Tie-line Frequency Bias mode, all of the ACE Equation is used as an input to control action
determination. In the Constant Net Interchange mode, only the Tie-line Error portion of the ACE Equation is used as an
input to control action determination. The Constant Net Interchange mode would normally be used when there is no
information available to indicate interconnection frequency. In the Constant Frequency mode, only the Frequency Bias
portion of the ACE Equation is used as an input to control action determination. The Constant Frequency mode of
operation would be used when the Tie-line Error is known to be misleading, inaccurate or unavailable. It is also used
when there are no tie-lines in service as in the case of a single BA interconnection or during islanded operation. AGC
Systems have been used in the industry since before the development of digital computers. Initially AGC Systems did
little more than send instructions to generators based on evaluation of the ACE Equation. They have become more
sophisticated since their inception and implement greater complexity in their evaluations of appropriate dispatch actions
to the point that they include forecasting, reliability and economics within their algorithms. Modern AGC Systems
determine control actions based on the collection of much more data than is included in the ACE Equation. This
additional data includes: short-term load forecasts and forecast error estimates as influenced by weather; individual
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001620
non-conforming load forecasts and forecast error; forecast interchange transaction information; generating unit ramp
and response rates; generating unit economic operating points including valve position; generating unit incremental
economic costs including start-up and maintenance; Hydro unit river flow limits as related to the operation of other units
on the same waterway; energy storage capabilities and available energy; Inadvertent Interchange energy account
balances; time error; and current control performance scores. As AGC Systems have evolved, the control mode in
which they are operating, Tie-line Frequency Bias, Constant Net Interchange, or Constant Frequency, provides less
and less information about the control actions that they implement. In a modern AGC System the control mode
provides little information about how control actions are being determined and implemented. In fact, only someone
experienced in AGC programming and implementation would have the knowledge necessary to determine whether or
not an AGC System is providing reasonable control actions or control actions consistent with Tie-line Frequency Bias
Control. Even someone with the necessary experience observing the operation of a modern AGC System for a short
period of time will be incapable of determining whether or not that system is providing effective or adequate control.
Therefore, neither of the two requirements is effectively enforceable from a practical point of view. Perspective: A
couple of examples are offered to add perspective to the problem. Example 1: R3 includes the requirement, “Each
Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such
operation is adverse to system or Interconnection reliability.” There are three conditions when operation on Tie-line
Frequency Bias control may be adverse to the system or Interconnection reliability. 1. The first is when the Tie-line
Error data used in the ACE Equation is incorrect. The ACE Equation will be incorrect when there are errors in the
Actual or Scheduled Tie-line flow values. This condition will occur when there is telemetry failure of one or more tielines, when there is an unidentified scheduling error, or when there is a separation that causes a tie-line metering point
to be located on a separate island due to interconnection separation or islanding. Telemetry failure will be indicated by
the quality bits associated with the Tie-line telemetry. If AGC is disabled to identify a scheduling error, there should be
an operating log entry. If AGC is disabled because of a separation, there will also be a log entry. 2. The second is when
the actual frequency is determined to be incorrect. If measured frequency is incorrect, this condition should be
indicated by an operating log entry and transfer to the redundant frequency device to provide measured frequency.
When the actual frequency fails, this condition will be indicated by the quality bits associated with the measured
frequency value and transfer to the redundant frequency device to provide measured frequency. 3. The third is when
operation of AGC would provide control different from the desired control to address some emergency condition in the
BA or elsewhere on the interconnection. If the operation of AGC would be adverse to system or Interconnection
reliability and is disabled for this reason, this condition should be indicated by an operating log entry. In all cases, there
should be a record of the reason for the use of other than Tie-line Frequency Bias control and records indicating the
reason for the use of other control modes. In all cases, other than the third indicated above, an error in the value of
ACE is the reason for not using Tie-line Bias Control and the quality bits for ACE or ACE component data should
provide a reasonable explanation for the condition. The third case occurs with such infrequency that there should be no
need for a special rule to address this condition. Example 2: R7 includes the requirement, “…If AGC has become
inoperative, the Balancing Authority shall use manual control to adjust generation to maintain the Net Scheduled
Interchange.” Cases have been observed of an AGC System that does not perform as well as the manual dispatch
used when the AGC System is inoperative. If a BA has a CPS1 score of 120% when using AGC and a CPS1 score of
125% when performing manual dispatch, should that BA be penalized for not having its AGC continuously operating?
What is the goal? Is the goal to operate on AGC regardless of the result or is the goal to operate in a manner that
provides the best measured control? Alternatives: Since these requirements are not effectively measurable or
enforceable, can a requirement or requirements be written to provide an equivalent to the intent of the old requirements
addressing AGC operation? The industry has three alternatives to address this issue: 1. Retain requirements that are
directed at the AGC System understanding that they are effectively not measureable or enforceable. 2. Eliminate
requirements that are directed at the AGC System with the understanding that they were not contributing to reliability.
3. Determine an alternative method to evaluate, measure and enforce a requirement that will achieve a goal similar to
the goal originally intended by the implementation of the AGC System requirements. Elimination of the requirement is
an appropriate solution. However, if it is determined that a replacement measure is required, then the solution to this
problem lies with the third alternative above. Solution: There is already a requirement that effectively enforces the intent
of the above requirements. Instead of requiring the BA to control in a particular manner, CPS1, BAAL and DCS require
the BA to achieve specific results with their control actions. All three measures require the BA to calculate ACE using
Tie-line Frequency Bias for determination of their Reporting ACE. The requirements specify that at least 50% of the
data must be valid for the one-minute average data to be included in the measures. The requirements for redundant
frequency measurement devices assure that the BA will have the actual frequency data available to perform the
necessary calculations. The data retention requirements specify the data they must retain to demonstrate that their
control achieved the stated goals. Finally, this approach is consistent with the White House Executive Order on
Improving Regulation and Regulatory Review in Section 1(b)(4) stating that regulatory agencies must: “to the extent
feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that the
regulated entities must adopt;…”
No
Comment 18: The Proposed Effective Date in the implementation plan is inconsistent with the Effective Data in the
Draft Standard. Comment 19: The completion of the implementation plan does not occur until 2015. This lengthy plan
stems from a standard that only measures reliability annually and provides only an annual window for changing
parameters such as Minimum Frequency Response. Alternative methods that measure reliability more frequently could
me implemented with a shorter implementation plan.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001621
Group
Northeast Power Coordinating Council
Guy Zito
Refer to the response to Question 17.
Refer to the response to Question 17.
Refer to the response to Question 17.
Refer to the response to Question 17.
Refer to the response to Question 17.
Refer to the response to Question 17.
Refer to the response to Question 17.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
The proposed method is good to measure frequency response at point “B”. However, point “C” is not taken in
consideration in this measure. As for the FRO, a N-2 criteria is more stringent for an Interconnection with less units
than a large Interconnection. The risk associated with coincidental events is much higher in a large Interconnection. For
this reason, we believe that N-1 criteria should be considered for a small Interconnection like Quebec.
Yes
However the “Tie Line Bias” AGC mode is not appropriate for a Single Balancing Authority operating in an
Interconnection. HQT uses the Flat Frequency mode.
Individual
Isaac Read
Beacon Power Corporation
Yes
Yes
Yes
The concept of requiring each Balancing Authority to achieve some level of Frequency Response and calculate it
consistently is appropriate and necessary.
Yes
As R3 has not significantly changed, will the Interpretation of Requirement 3 from BAL-003-0.1b still be applicable to
BAL-003-1?
No
Why is it appropriate to delay implementation of this standard for over 12 months after applicable approval? This
seems an unnecessary delay considering the intent to operate under a field test. Similarly, delaying implementation of
R2 for over 2 years seems unnecessary. Based on the suggested schedule for measuring FRM and implementing
Frequency Bias Settings, there may be rationale to implement the standard on the first calendar year following
approval. However, delays beyond the beginning of the next calendar year should require conclusive justification.
Group
Southern Company
Cindy Martin
Yes
Comments: The Frequency Response Measure should be based on either the median or average of all SEFR’s as
currently defined. Due to the varied nature of frequency responsive resources online it should never be based on
meeting response on a single event.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001622
Frequency Bias Setting A value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz, set into a
Balancing Authority Area Control Error algorithm equation that allows the Balancing Authority to contribute its
frequency Frequency rResponse to the Interconnection. Comments: Not sure the word “allows” is the right word.
Perhaps use something in terms of preventing withdrawal of Primary Frequency Response with words like “…equation
that prevents the withdrawal of the Balancing Authority’s Primary Frequency Response to the Interconnection.”
Yes
No
Comments: Proposed Standard Comment 1: BAL-003-1, Requirement R1. The requirement should be made less
prescriptive by removing references to Attachment A and FRS Form 1. The responsible entity should understand the
fundamental and basic requirement – to achieve a Frequency Response Measure. Where the methodology is specified
or how the BA is supposed to achieve it should be a matter of compliance and/or implementation and not a part of the
basic requirement. Proposed language is as follows: Each Balancing Authority shall achieve a Frequency Response
Measure (FRM) that is equal to or more negative than its Frequency Response Obligation (FRO).
No
Comments: Comment 2: BAL-003-1, Requirement R2. The requirement should be made less prescriptive by removing
references to the calculation methodology and Attachment A. The responsible entity should understand the
fundamental and basic requirement – to implement the Frequency Bias Setting into its Areas Control Error calculation.
Proposed language is as follows: Each Balancing Authority shall implement the Frequency Bias Setting (fixed or
variable) provided by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO
to ensure effective coordinated secondary control. Comment 3: BAL-003-1, Requirement R2 and Section 1.4 Additional
Compliance Information. The SDT should consider whether or not the ERO has compliance obligations pursuant to the
obligations mentioned in the proposed Standard. Requirement R2, states that the ERO should provide the BA with the
Frequency Bias Setting and the specified date to begin the calculation. The R1 Supplemental Information section
states that the ERO is obligated to post the official list of events. The R2 Supplemental Information section states that
the ERO is obligated to validate the FRM and Frequency Bias Settings and disseminate the Frequency Bias Settings
Report along with the implementation date. These obligations should be confirmed and properly incorporated into
Standard if appropriate.
No
Comments: Agree only to the extent that an accurate frequency measurement is available to the BA. If not frequency
measurement is available, then that should be considered an adverse condition and thus TLB is not appropriate. In
other words, one small BA maintaining TLB may not cause the condition in the Glossary definition of Adverse Reliability
Impact but it is still not appropriate for them to stay on TLB.
Yes
We did not want to vote on Question 7, but clicked 'yes' in error.
Individual
Bryan Taggart
Westar Energy
No
For FRM, why is median used rather than average? The method in the standard for dsetermining FRM needs to allow
for excluding some events due to non-conforming loads, scan rates, intermittent resources, large interchange ramps,
etc that may cause the actual response during the 16 seconds to actually be opposite of the expected response.
No
We propose the following: A value, (either a fixed or variable), expressed in MW/0.1 Hz, set into a Balancing Authority
Area Control Error equation that allows the Balancing Authority to contribute its SECONDARY Frequency Response to
the Interconnection.
Yes
No
The lagging measure is a concern. The ERO should be required to provide an updated proposed/possible list of
frequency events monthly so BA's can determine their FRM through out the year so corrective action can be taken if
needed. Prior year events should be excluded (just to get to 25 events). This could result in begin non-compliant twice
for the same events.
Yes
Yes
Yes
Yes, if field testing validates the standard.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001623
Individual
Thomas Washburn
FMPP
Yes
Yes
Yes
No
The proposed Requirement 1 states: Each Balancing Authority shall achieve a Frequency Response Measure (FRM)
(as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative than its Frequency
Response Obligation (FRO). Attachment A states that if a year occurs in which there are not 25 events that meet the
remaining criteria below, then the most recent 25 events (as defined below) will be used for determination of an entity’s
compliance with the FRM requirement and storage of SEFRD. Problem – by using events from last year to determine
an entity’s compliance with a Requirement for this year puts the entity in double jeopardy for last year’s events, which
were already used for compliance for last year.
Yes
Yes
Group
Santee Cooper
Terry L. Blackwell
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing Authority for a
specific frequency excursion event as identified by the ERO (or NERC). As a comment, how frequency response is
calculated needs to be defined and may not always be the Net Actual Interchange (NIa) divided by the change in
frequency expressed in hertz. For example, the NIa may need to be adjusted for known generation and load changes
that do not represent frequency response for the period being measured such as known generation and load ramp
changes. Change in frequency needs to be more specific, such as the frequency difference between B and A
measured at B. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be:
The Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total…..” The review team
is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs will be held
accountable. Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used
to determine the FRO value. Should the definition of Frequency Response Measure be a median or mean value?
No
We suggest the following changes to the definition: A value, fixed or variable, expressed in MW/0.1 hertz, as part of a
Balancing Authority’s Area Control Error (ACE) equation that influences its Automatic Generation Control (AGC) to
provide frequency response without secondary control action withdrawing the response.
Yes
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25 events are
identified; it is a lagging indicator. The BA may have to ensure it measures all frequency excursions and develops its
own leading indicator to ensure compliance following year end.
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the BA’s prior
year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming year maximum
generation? What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b, Requirement 6
requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to
determine the Balancing Authority’s ACE. We suggest that Requirement 3 be restated to “shall operate its Automatic
Generation Control (AGC) on Tie Line Frequency Bias, unless ........” Tie Line bias is the (Ia-Is) term and frequency
bias is the -10B(Fa-Fs) term.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001624
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5 over
several years. Perhaps these dates should not be specific but tied to months following regulatory approval. Attachment
A should be modified to match what is in the proposed standard. The values currently shown as percent “of peak/0.1
Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz change. For BAs that do not serve
native load, percent “of upcoming years maximum generation/0.1 Hz should be changed to percent of its estimated
maximum generation level in the coming year/0.1 Hz change.
Individual
Chris Adams
EKPC
No
These definitions should be revised to include specifics on how to calculate each term. The FRM calculation method
should take into account large non-conforming loads. A median will not reflect the true nature of the system.
No
"Frequency Bias” should not be used in the definition. "Usually" can be omitted.
Yes
No
The method for measurement is not detailed. Also, the method indicates a lagging indicator. Hows is the BA to ensure
its compliance through the year?
No
The method is not clear in Attachment A.
No
Tie line bias is calculated using (NAI-NSI) while frequency bias is -10B(FA-FS).
No
Specific dates should be tied to regulatory approval.
Individual
Kathleen Goodman
ISO New Engand Inc.
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be developed or
promulgated until the Field Trial has accomplished its purpose and the performance criteria and measures have been
determined. The standard should be put into place later; it is premature at this time. Since this is to be a data gathering
process to be used to determine appropriate performance parameters, the purpose statement of the Field Trial should
be changed to read as follows: To determinerequire sufficient Frequency Response arranged by from the Balancing
Authority to maintain Interconnection Frequency within predefined bounds by responding to and arresting frequency
deviations and supporting frequency until the frequency is restored to schedule. To identify and establishprovide
consistent methods for measuring Frequency Response and determining the Frequency Bias Setting and Frequency
Response Obligation. We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon Field Trial
results. Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting frequency
deviations. When there is a sudden and sizable change to system resource or demand, the first response to a
frequency deviation caused by this change would be the generators’ governors. This will provide a mitigating effect for
the immediate seconds up to minutes. The frequency bias setting will then kick in to supplement the mitigation need.
The governors are owned by the Generator Owners; the BAs do not own these facilities and hence can do little to
address frequency response during this initial period. To hold only the BA responsible for maintaining interconnection
frequency and arresting frequency deviations would be inappropriate. The industry needs to have a discussion to
determine who should be held responsible for providing governor responses immediately following an event, and by
what mechanism, and for implementing additional measures thereafter. We suggest that BAL-003 development be
withheld until this discussion takes place and a decision is made on who and how the governor response shall be
provided.
No
We have a difficulty seeing the BA being the only entity held responsible for maintaining interconnection frequency and
arresting frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will provide a
mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick in to supplement the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001625
mitigation need. The governors are owned by the Generator Owners; the BAs do not own these facilities and hence
can do little to address frequency response during this initial period.
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to accommodate this
or regional variances should be written by the SDT to address existing differences. In addition this requirement, as
written, does not provide for momentary cessation of AGC for any reason, nor for reasonable system maintenance,
repair, or updates. As written, it seems to say that any duration of operation off Tie Line Bias is unacceptable and, thus,
would be a violation.
No
We do not agree that a meaningful Implementation Plan can be developed until such time as the data gathering/field
testing is completed. Therefore, we believe this Standard may be premature.
Individual
Hao Li
Seattle City Light
Yes
Yes
Yes
Yes
No
Currently a Balancing Authority has only about one month over holiday periods(December 10 to January 10) to
assemble its data and calculate the Frequency Response Measure (FRM). Further, Attachment A requires the ERO to
use at least 25 events for the calculation of FRM. Seattle City Light (SCL) believes that one month is insufficient time
given the number of events required. So SCL recommends additional time, such as two months or to reduce the
number of events to be included in annual reviews.
Yes
Yes
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Yes
Yes
The new more likely improved method of measuring Frequency Response is welcome. This should be an improvement
over the existing methods of using 1% of projected peak load, or average of DCS events. Calculating projected peaks
leave lots of room for error and limiting calculations to only DCS events likely does not reflect accurate BIAS.
Yes
Yes
The implementation schedule seems reasonable.
Yes
Yes
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001626
No
For Frequency Response Measure, the drafting team should consider using average rather than median. Because
median is literally the middle value, a Balancing Authority could have 12 really bad Single Event Frequency Response
Data and still comply. Average values would prevent this from happening. Should FRM be clear that it includes at least
25 events in the definition? While that can be garnered from Attachment A, it is not specified in the Form 1 instructions.
We are concerned that the regulators may argue that 25 events do not apply because an attachment is not part of the
standard.
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably be
changed to “maintain”. The goal is to ensure AGC does not withdraw frequency response and that it is maintained
while frequency is depressed. We are not sure if Frequency Response has a precise enough definition and it is part of
the definition of Frequency Bias Setting. The definition of Frequency Response really just reflects how it is measured. It
does not define what it really is which is the dynamic response of load, generation, and other frequency responsive
devices to a perturbation in frequency. The drafting team should also consider resolving the definition of Frequency
Bias. Is it needed? It is often confused with Frequency Bias Setting and is often used interchangeably with Frequency
Response even though the meanings are slightly different.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency Response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis based on the field trial, based on the Frequency Response Initiative Work Plan
that NERC filed in response to the Commission’s September 23 technical conference and based on the plan outlined in
NERC’s October 25, 2010 compliance filing.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis based on the field trial, based on the Frequency Response Initiative Work Plan
that NERC filed in response to the Commission’s September 23 technical conference and based on the plan outline in
NERC’s October 25, 2010 compliance filing. The effects of the nonconforming load should be considered in the
calculation of the frequency response obligation in order to get accurate results.
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better to allow
the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible for identifying
Frequency Bias Setting is being removed from the Balancing Authority. There is an implied obligation that the ERO will
determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are left wondering who has the
responsibility for determining the Frequency Bias Setting. Frequency Response of the interconnection is constantly
changing. As a result, the Frequency Bias Setting will never match the Frequency Response exactly. It is better to
overbias than underbias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for frequency
bias setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some margin in the
frequency bias setting to ensure that the bias setting is overbiased.
Yes
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it because
it will take several years to assess the impact. We recommend a wording change to the implementation plan. Please
change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following table,” to “BAL-003-0.1b Requirement
5 should be phased out by reducing the minimum frequency bias setting per the table.” It is not clear if the minimum
frequency bias setting can be modified without modifying the existing BAL-003-0.1b standard. Is this being
accomplished through the field trial? The implementation plan makes no mention of a field trial. It should. Please
change all BAL-003-0 to BAL-003-0.1b.
Group
LG&E and KU Energy
Brent Ingebrigtson
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing Authority for a
specific frequency excursion event as identified by the ERO (or NERC). As a comment, how frequency response is
calculated needs to be defined and may not always be the Net Actual Interchange (NIa) divided by the change in
frequency expressed in hertz. For example, the NIa may need to be adjusted for known generation and load changes
that do not represent frequency response for the period being measured such as known generation and load ramp
changes. Change in frequency needs to be more specific, such as the frequency difference between two physical
locations B and A measured at B. Frequency deviation used in the calculation needs to be the deviation observed by
the BA performing the calculation. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001627
definition should be: The Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC).
The word “contribution” should be considered to be replaced with “the balancing authority piece of the total…..” The
standard does not explain who will determine the value of each BA’s FRO nor the method used to determine the FRO
value. Should the definition of Frequency Response Measure be a median or mean value?
No
We suggest the following changes to the definition: 1. Delete the word “usually” 2. Replace “set into” with “as part of”. 3.
Replace the remainder of the sentence following “Area Control Error equation” with “that influences its Automatic
Generation Control (AGC) to provide its frequency response while Interconnection frequency is not at its scheduled
value” – (The frequency bias does not allow a BA to contribute its frequency response to the Interconnection. The
frequency bias term only affects the AGC response of the BA, which is part of its frequency response usually minutes
after the initial event and is dependent upon generation units being on AGC control and capable of responding.) 4. The
suggested changes would result in the following definition: A value, (either a fixed or variable Frequency Bias),
expressed in MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not at its
scheduled value.
No
The proposed purpose statement as provided in this question is not the same as the purpose statement for BAL-003-1
as posted on the Project 2007-12 page of the NERC website. The posted purpose on the NERC website is: To require
sufficient Frequency Response from the Balancing Authority to maintain Interconnection Frequency within predefined
bounds by arresting frequency deviations and supporting frequency until the frequency is restored. To schedule and
provide consistent methods for measuring Frequency Response and determining the Frequency Bias Setting. The
version posted in the question appears to correct errors in the last sentence of the purpose statement given in the
project page. We do not agree with the purpose statement as posted on the project page. In addition, we suggest the
following edits to what appears to be a corrected purpose statement as provided in this question: To require sufficient
Frequency Response from the Balancing Authority to maintain Interconnection Frequency within predefined bounds by
arresting frequency deviations due to contingencies on the interconnected BES and supporting frequency until the
frequency is restored to schedule. To provide consistent methods for measuring Frequency Response and determining
the Frequency Bias Setting. As NERC/FERC has differentiated Frequency Response from Frequency Regulation, the
standards addressing Frequency Response should clearly be related to unplanned contingencies occurring on the
interconnected BES.
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25 events are
identified; it is a lagging indicator. The BA may have to ensure it measures all frequency excursions and develops its
own leading indicator to ensure compliance following year end. A sample CPS bounds report should be considered,
perhaps based on 2010 numbers, to demonstrate how FRM submitted would translate to FRO frequency bias settings
and how it will affect the L10 values
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the BA’s prior
year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming year maximum
generation? What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b, Requirement 6
requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to
determine the Balancing Authority’s ACE. We suggest that Requirement 3 be restated to “shall operate its Automatic
Generation Control (AGC) on Tie Line Frequency Bias, unless ........” Tie Line bias is the (Ia-Is) term and frequency
bias is the -10B(Fa-Fs) term. This should be coordinated with BARCSDT modifications to BAL-005.
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5 over
several years. Perhaps these dates should not be specific but tied to months following regulatory approval. Attachment
A should be modified to match what is in the proposed standard. The values currently shown as percent “of peak/0.1
Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz change. For BAs that do not serve
native load, percent “of upcoming years maximum generation/0.1 Hz should be changed to percent of its estimated
maximum generation level in the coming year/0.1 Hz change
Group
Progress Energy
James Eckelkamp
No
The proposed definition for SEFRD assumes that there is no change in the Net Scheduled Interchange (NIS) as a
result of the event. However, a dynamic schedule for load or generation based on data obtained with a two second
scan rate will impact the NIS, and therefore the corresponding load or generation response will offset the change to
NIA. Therefore, the definition of SEFRD should replace "NIA" with "change in NIA minus NIS".
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001628
No
A bias, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority's Area Control Error
equation to account for the Balancing Authority's Frequency Response contribution to the interconnection, and prevent
response withdrawal through secondary control systems. The changes suggested are to clarify that biasing of the ACE
equation "allow[s]" primary frequency response to continue beyond the initial event window by accounting for it in the
ACE input to secondary control systems (i.e. AGC). It's important to note that Primary Frequency Response will occur
no matter what the Bias value is set to in the ACE equation, and biasing "supports" the response until the frequency is
restored".
Yes
No
Progress Energy believes the Eastern Interconnection does not have the same issues with frequency experienced in
the other two interconnections, and that load response is significant enough in the interconnection to arrest and
stabilize frequency as long as BAs do not withdraw that effect (accurate biasing of the ACE equation). We also believe
this standard should reference standrd PRC-024 related to accurate relay settings to allow out of bounds operations
related to frequency and voltage deviations.
Yes
Yes
No
We agree with the graduated implementation for the FRO portion of the standard, but feel NERC needs to losen the
minimum frequency bias requirement immediately so that it matches the newly required frequency response. There are
also other areas within the EMS the besides BA's frequency bias that should be addressed such as secondary
frequency response systems that should also be included in this standard. Additionally, if the industry was truly
concerned with matching bias values to actual response, they would swich to variable frequency bias. Variable bias
requires additional up front work along with general maintenance, but it truly is the best way to accurately bias the ACE
equation.
Individual
JC Culberson
ERCOT
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI for
frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange and does not
really reflect the frequency response of a contingent BA. Either the definition needs to be changed to accommodate
single BA Interconnections (such as ERCOT and Hydro Quebec), or regional variances for them need to be written by
the SDT. A BA’s frequency response is composed of load frequency response, governor response, and, for BAs
external to the resource loss, change in Net Interchange. Some approximation may be achieved by recognizing that the
magnitude of frequency deviation is attenuated by load frequency response and governor response (or frequency
activated demand response to reduce load). The definition of FRM specifies the median of all SEFRD observations
reported annually. What is the technical basis for selecting the median rather than the mean? The definition of FRO
raises questions. The discretely administered determination of FRO described in the draft Attachment A sets too
stringent a requirement; particularly for the smaller Interconnections which may also have large size generation
resources just as do the larger Interconnections. To “assure that Point C will not encroach on the first step UFLS” is
significantly more stringent than existing and historical performance for those smaller Interconnections. Such
assurance will assuredly prove to be very expensive. In fact, we question the need to define FRM and FRO since they
can easily be stipulated in the standard requirements. Having them defined and added to the ever-growing NERC
glossary creates unnecessary work to maintain the glossary, unless these terms are used by other NERC standards for
which consistent meaning need to be established. For example, R1 can easily be reworded as: “R1: Each Balancing
Authority shall achieve a median of all Single Event Frequency Response Data observations reported annually on FRS
Form 1 that is equal to or more negative than its contribution obligation to the total aggregate Frequency Response
needed for reliable operation of an Interconnection assigned by the ERO.” Similar wording changes can be made to the
FRS Form 1 to eliminate the need to define these two terms. Further, the Attachment A states that the SDT is
evaluating a risk based approach to establishing an Interconnection Frequency Response Obligation which can be
based on a probability function. If the N-2 criteria is established, it will be unlikely to be possible to change that if the
new approach is viewed as a reduction in required performance. As an example, in the ERCOT Interconnection, it is
recognized that the present level of required frequency responsive reserve cannot in all scenarios assure that Point C
will not encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the minimum
load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in ten years based
upon actual history. The cost of precluding such an event would be astronomical.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001629
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the context of these
requirements? Should it be Frequency Bias Setting, instead? “Fixed” seems to be straightforward, but what is
“variable”? How often must Frequency Bias Setting change in order to be considered to be “variable”?
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be developed or
promulgated until the Field Trial has accomplished its purpose and the performance criteria and measures have been
determined. We request that the results of the Field Trial should be published and discussed BEFORE any changes
are made. The standard should be put into place later; it is premature at this time. Since this is to be a data gathering
process to be used to determine appropriate performance parameters, the purpose statement of the Field Trial should
be changed to read as follows: To determine require sufficient Frequency Response arranged by from the Balancing
Authority to maintain Interconnection Frequency within predefined bounds by responding to and arresting frequency
deviations and supporting frequency until the frequency is restored to schedule. To identify and establish provide
consistent methods for measuring Frequency Response and determining the Frequency Bias Setting and Frequency
Response Obligation. We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon Field Trial
results. Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting frequency
deviations. When there is a sudden and sizable change to system resource or demand, the first response to a
frequency deviation caused by this change would be the generators’ governors. This will provide a mitigating effect for
the immediate seconds up to minutes. The frequency bias setting will then kick in to supplement the mitigation need.
The governors are owned by the Generator Owners; the BAs do not own these facilities and hence can do little to
address frequency response during this initial period. To hold only the BA responsible for maintaining interconnection
frequency and arresting frequency deviations would be inappropriate. The industry needs to have a discussion to
determine who should be held responsible for providing governor responses immediately following an event, and by
what mechanism, and for implementing additional measures thereafter. We suggest that BAL-003 development be
withheld until this discussion takes place and a decision is made on who and how the governor response shall be
provided.
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be achieved.
However, the measure as described does not apply to all Interconnections. It does not apply to single BA
Interconnections such as ERCOT and Hydro Quebec. This requirement should be added later—not included now; and
it should clarify what the BA must do and what the response providers must do. BAs do not own and operate the
resources. An entity which does own or operate the resources may also be registered as a BA, but an entity which
does not own or operate resources may also be registered as a BA. Therefore, it is important to detail what a BA must
do and also to detail what the resource owner or operator must do. The resource owner may be registered as a GO or
a TO or even a DP. The resource operator may be registered as a GOP, a TOP, or a LSE. The BA must establish an
operations plan, using data provided to it by the resource owners and or operators, that will meet the performance
requirements. The BA must then deploy the proper amount of response through AGC or verbal instructions to
supplement the automatic responses that the resources will provide, must calculate the actual responses after-the-fact,
and report the performance as required. The resources must, as standards already provide, comply with the
deployments and instructions provided by the BA. However, if an entity which is functioning as a BA does not own its
resources, nor does it directly operate those resources, the BA cannot ensure the achievement. The standard must not
create an organizational or contractual arrangement that dictates how the compliance is provided. It should state what
must be done, not how. If entities choose to write and enter into such arrangements, that should be permissible, but not
required. Specific to R1, the wording does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not seem to
correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. It should not be
necessary for the ERO to do the determination for all the Interconnections. There are already in place methods for this
by the existing ERCOT and WECC Interconnections. The SRC suggests that the ERO may not be the appropriate
technical entity. The ERO may be the appropriate entity to serve as the receiver of the forms and analyze results for
the Eastern Interconnection, but existing processes are already in place elsewhere. It should be sufficient that those
processes continue and submit copies of Form 1 to the ERO. This may also be appropriate for Hydro Quebec. In
addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the BAs to
implement the settings. The proposed language says only that the BA shall implement it on the date specified, but it
doesn’t address the need for that date to include some implementation time.
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to accommodate this
or regional variances should be written by the SDT to address existing differences. In addition this requirement, as
written, does not provide for momentary cessation of AGC for any reason, nor for reasonable system maintenance,
repair, or updates. As written, it seems to say that any duration of operation off Tie Line Bias is unacceptable and, thus,
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001630
would be a violation.
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier than the
schedule shown could result in the unintended consequence of non-compliance enforcement for performance that is
caused by the change rather than by the non-performance of the functional entity. Also, the effective dates given in the
Implementation differ from those in the draft standard. Different requirement numbers are expressed in each. Some of
the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as early as May 2011.
We do not believe that the BAL-003-1 standard will be approved by the industry or the NERC BoT at that time and that
does not even take into account regulatory approval (or 12 months after BoT adoption in those jurisdictions where no
regulatory approval is required). How can a standard begins to phase out while the successor standard is not anywhere
near becoming effective? If the SDT wants to propose a gradual replacement of the current R5, we would suggest that
the phase-out steps be tied to the date that the standard becomes effective.
Individual
Howard Rulf
We Energies
No
For Frequency Response Measure, the drafting team should consider using average rather than median. Because
median is literally the middle value, a Balancing Authority could have 12 really bad Single Event Frequency Response
Data points and still comply. Average values would prevent this from happening. Should FRM be clear that it includes
at least 25 events in the definition? While that can be garnered from Attachment A, it is not specified in the Form 1
instructions. We are concerned that the regulators may argue that 25 events do not apply because an attachment is not
part of the standard.
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably be
changed to “maintain.” The goal is to ensure AGC does not withdraw frequency response and that it is maintained
while frequency is depressed. We are not sure if Frequency Response has a precise enough definition and it is part of
the definition of Frequency Bias Setting. The current NERC Glossary definition of Frequency Response really just
reflects how it is measured, it does not define Frequency Response. Frequency Response is the dynamic real power
response of load, generation, and other devices to a perturbation in frequency. The drafting team should also consider
resolving the definition of Frequency Bias. Is it needed? It is often confused with Frequency Bias Setting and is often
used interchangeably with Frequency Response even though the meanings are slightly different.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency Response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis, field trial data, the Frequency Response Initiative Work Plan that NERC filed in
response to the Commission’s September 23 technical conference, and the plan outlined in NERC’s October 25, 2010
compliance filing.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis, field trial data, the Frequency Response Initiative Work Plan that NERC filed in
response to the Commission’s September 23 technical conference, and the plan outline in NERC’s October 25, 2010
compliance filing.
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better to allow
the ERO to specify the date to allow some flexibility in implementation. It appears that the responsibility for identifying
Frequency Bias Setting is being removed from the Balancing Authority. There is an implied obligation that the ERO will
determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are left wondering who has the
responsibility for determining the Frequency Bias Setting. Frequency Response of the interconnection is constantly
changing. As a result, the Frequency Bias Setting will never match the Frequency Response exactly. It is better to
over–bias than under–bias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for
frequency bias setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some
margin in the frequency bias setting to ensure that the bias setting is over–biased.
Yes
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it because
it will take several years to assess the impact. We recommend a wording change to the implementation plan. Please
change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following table,” to “BAL-003-0.1b Requirement
5 should be phased out by reducing the minimum frequency bias setting per the table.” It is not clear if the minimum
frequency bias setting can be modified without modifying the existing BAL-003-0.1b standard. Is this being
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001631
accomplished through the field trial? The implementation plan makes no mention of a field trial. It should. Please
change all BAL-003-0 to BAL-003-0.1b
Group
Midwest ISO Standards Collaborators
Jason Marshall
No
For Frequency Response Measure, the drafting team should consider using average rather than median. Because
median is literally the middle value, a Balancing Authority could have 12 really bad Single Event Frequency Response
Data and still comply. Average values would prevent this from happening. Should FRM be clear that it includes at least
25 events in the definition? While that can be garnered from Attachment A, it is not specified in the Form 1 instructions.
We are concerned that the regulators may argue that 25 events do not apply because an attachment is not part of the
standard.
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably be
changed to “maintain”. The goal is to ensure AGC does not withdraw frequency response and that it is maintained
while frequency is depressed. We are not sure if Frequency Response has a precise enough definition and it is part of
the definition of Frequency Bias Setting. The definition of Frequency Response really just reflects how it is measured. It
does not define what it really is which is the dynamic response of load, generation, and other frequency responsive
devices to a perturbation in frequency. The drafting team should also consider resolving the definition of Frequency
Bias. Is it needed? It is often confused with Frequency Bias Setting and is often used interchangeably with Frequency
Response even though the meanings are slightly different.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency Response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis based on the field trial, based on the Frequency Response Initiative Work Plan
that NERC filed in response to the Commission’s September 23 technical conference and based on the plan outlined in
NERC’s October 25, 2010 compliance filing.
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency response
performance level. However, we caution the drafting team that the minimum level established needs to be determined
based on an extensive data analysis based on the field trial, based on the Frequency Response Initiative Work Plan
that NERC filed in response to the Commission’s September 23 technical conference and based on the plan outline in
NERC’s October 25, 2010 compliance filing.
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better to allow
the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible for identifying
Frequency Bias Setting is being removed from the Balancing Authority. There is an implied obligation that the ERO will
determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are left wondering who has the
responsibility for determining the Frequency Bias Setting. Frequency Response of the interconnection is constantly
changing. As a result, the Frequency Bias Setting will never match the Frequency Response exactly. It is better to
overbias than underbias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for frequency
bias setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some margin in the
frequency bias setting to ensure that the bias setting is overbiased.
Yes
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it because
it will take several years to assess the impact. We recommend a wording change to the implementation plan. Please
change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following table,” to “BAL-003-0.1b Requirement
5 should be phased out by reducing the minimum frequency bias setting per the table.” It is not clear if the minimum
frequency bias setting can be modified without modifying the existing BAL-003-0.1b standard. Is this being
accomplished through the field trial? The implementation plan makes no mention of a field trial. It should. Please
change all BAL-003-0 to BAL-003-0.1b.
Group
FirstEnergy
Sam Ciccone
Yes
For the definition of FRM, we are not clear as to the rationale for choosing the median value instead of the mean.
Yes
Although we support the definition, we suggest the word “contribute” be changed to “maintain”.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001632
Yes
No
We cannot agree at this time since Attachment A of the materials posted do not include sufficient details regarding the
calculations used. Furthermore, there is no obligation imposed on the ERO to provide neither a reasonable time frame
for implementation of the Frequency Bias Setting nor a requirement for the ERO to follow the methodology detailed in
Attachment A. The team should consider adding a requirement for the ERO or clarifying where this obligation is
covered in NERC’s Rules of Procedure.
Yes
Although we mostly agree with the requirement, we believe it can be improved. We suggest that the team add wording
in the requirement to allow for brief periods where meters or communication channels fail and trip the AGC off Tie Line
Bias. In most areas, if merely one BA trips off bias it would not have an adverse affect on BES reliability and
furthermore, the BA can take alternative measures for these periods such as manual AGC. We suggest the team add
wording similar to the second sentence of requirement R7 of BAL-005 which states: “If AGC has become inoperative,
the Balancing Authority shall use manual control to adjust generation to maintain the Net Scheduled Interchange.”
No
We believe that the implementation plan should include information regarding the field trial and how it fits in with the
phase-in implementation. It appears as though the field trial is being conducted based on 2010 data and will be
concluded upon completion of the development of the standard but we think this could be clarified. Furthermore, as
stated in the process manual, a field test “should include at a minimum the data collection and analysis or field test
plan, the implementation schedule, and an expectation for periodic updates of the results.” The field test information
posted is not clear on the implementation schedule of the field test as well as when and how periodic updates will be
available.
Group
Bonneville Power Administration
Denise Koehn
No
FRO definition – BPA feels uncomfortable supporting this standard when the ERO is given a blank check to FRO. The
methodology for determining the FRO must be spelled out in detail in order to allow all entities an opportunity to
comment on that methodology.
Yes
Yes
No
BPA agrees that there should be a minimum level of Frequency Response, but disagree with the way the measure is
obtained in the requirement. • R1 – BPA suggests replacing “achieve” with “calculate”. Achieve: indicates it is a
performance. • R1 – BPA does not agree with the requirements in Attachment A not being in the standard. These
should not be modified without full review and voting by members. • R1 – BPA believes that there should be more
description on Variable Bias. What variable bias number should we use: average, minimum, peak for the event? BPA
feels that the peak bias of each event would be appropriate.
No
R2 – BPA believes that the ERO should not be providing the BA the Frequency Bias Settings for the BA. R2 points to
Attachment A as having the calculation methodology, but there is no methodology spelled out in Attachment A, there
are simply data requirements, delta frequency that will be included in surveys, tools to be used, etc. The statement
‘natural frequency response’ is in Attachment A many times, but it is never spelled out. What is meant by this phrase.
This differs dramatically depending on when the event occurs due to different generating patterns, different types of
load (frequency responsive versus not frequency responsive), etc. The methodology needs to spell out how this will be
taken into account when calculating the correct frequency bias. Secondly, how would this be done for variable bias?
No
R3. BPA does not believe this standard should dictate the control mode for AGC. That is better suited to be in BAL-001
and should not be repeated in this standard – the ACE used for reporting is spelled out in BAL-001 R1 and is also
discussed in BAL-005 R6. R3 should be removed from this standard, not modified to fit with what is stated in BAL-001
or BAL-005.
No
From a compliance perspective, it is administratively very burdensome to have portions of two different versions of a
standard applicable at the same time, as specified in the Implementation Plan for BAL-003-1. This type of structure
adds an additional layer of complexity to all parts of the compliance administration process, as necessary to distinguish
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001633
between the separate versions of the standard. Rather than create and prolong this type of situation over a 4 year time
period, BPA asks that BAL-003-0 be retired in its entirety and that the contents of BAL-003-1 be expanded to also
include R5, as specified in BAL-003-0. This change resolves the identified issues while also ensuring that all
requirements of BAL-005 are in effect, as originally intended. The Implementation Plan for BAL-003-1 also includes a
proposal to modify the specified limiting percentage of Native Load on a sliding scale over a 4 year time period. BAL003-3 R5, as approved, explicitly specifies 1% as a minimum value for monthly average Frequency Bias Setting. As
such, changing this value results in a change in the requirement itself. Instead of being done through an
Implementation Plan, these types of changes should be made as specific modifications to the requirement in question.
To resolve this issue, BPA asks that the sliding scale specified for percentage of peak load specified in the
Implementation Plan be incorporated directly into BAL-003-1 as a part of the specified text of R5. This change meets
the intended goal of applying a sliding scale to this value over time while assuring that the underlying change is
implemented as a change to the requirement through the Standards Development Process.
Individual
Thad Ness
American Electric Power
Yes
No
If “the proposed standard’s intent is to collect data needed to accurately analyze existing Frequency Response, set a
minimum Frequency Response obligation, provide a uniform calculation of Frequency Bias Settings that transition to
values closer to Frequency Response, and encourage coordinated AGC operation”, it appears the current and stated
definition is precluding the process for determination of the Frequency Bias Setting itself. I believe it is too early to state
in definition the frequency bias setting to be based on MW/0.1 Hz, when this appears to be more of the expected
response. Using the word usually does not appear to be defining anything. To eventually get to an acceptable
performance measure with reliability basis the project needs to be expanded to also address associated governor
droop issues, which inherently affect response. When the current definition references using “either a fixed or variable
Frequency Bias”, it does not state whether or not to be applied in the calculation to either load or generation. The
current Standard uses 1% of yearly estimated peak demand for BAs that serve load, when the actual load at time of
disturbance could be greatly different. Response is more directly related to the amount of Generation on-line and active
AGC within the BA at time of trip. MW/0.1 Hz states more of expected result of response than defining Frequency Bias
Setting.
No
AEP believes the statement should read “To require sufficient Frequency Response from governors and AGC of
Generators within the Balancing Authority to maintain Interconnection Frequency within predefined bounds by arresting
frequency deviations and supporting frequency until the frequency is restored to schedule.To provide consistent
methods for measuring Frequency Response from governors and AGC of Generators within the Balancing Authority for
determining the overall Frequency Bias Setting threshold. Since Generators are directly responsible for response,
applicability must be added to Generator Operators.
No
Between the definition and the requirement in Attachment A, it is unclear if FRM is a reliability-supported, performancebased measure, or instead, if it is a calculated number based on previous performance. As written, it is unclear if this is
a performance-based requirement, or simply a calculation that should be utilized in some way. In any event, the
requirement needs to be re-written to clarify its intent.
No
It appears this standard deviates from past practice for calculating frequency bias. It is unclear how this might affect the
CPS Bounds L10 calculation.
Yes
No
It is unprecedented that an implementation plan would require following some (but not all) requirement(s) within
multiple versions of the same standard. This would make following the standard very difficult. Having to piece together
multiple documents into a coherent requirement would be very difficult to achieve. There needs to be a definitive start
and stop date for each version, rather than a phase in and phase out across multiple versions. We disagree with setting
preselected dates beginning months away. Timing should be driven by applicable regulatory approval, as opposed to
dates which appear to be arbitrarily selected. Going from 100% of the load-based, frequency bias calculation to 0% is
unclear without correlating it to something else being phased in over time. It is very hard to follow how BAL-003-0 R5
relates to BAL-003-1. More work needs to be done by the SDT to explain how these relate to one another.
Individual
Greg Rowland
Duke Energy
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001634
No
The definition of SEFRD would conflict with any alternative measurement of frequency response. The SEFRD makes
no provision for the impacts of generation loss experienced by a contingent BA, impacts of non-conforming loads, or
impacts of schedule ramps. The FRM also makes no such provisions. The resulting FRM for a BA experiencing one or
more of these impacts for one or more SEFRDs will be skewed and completely miss the intended measurement of the
BA’s response to frequency excursions. In addition, as it is not yet clear how provision of Frequency Response by one
BA to meet a portion of another BA’s requirement would be achieved, Duke Energy cannot say that a simple measure
of the NIA against the frequency deviation will capture the net of the response desired. Regarding the definition of
FRO, the industry should agree on the methodology which would be used for the ERO to determine the response
desired for the Interconnection that is used for allocation of the FRO, and not leave it as a parameter subject to change
outside of the standards process. The definition is only acceptable if the assignment by the ERO is based upon a
methodology supported by the industry and subject to change only through the standards process.
No
Duke Energy would suggest not using “Frequency Bias” in the definition of “Frequency Bias Setting”. In addition, Duke
Energy would like to point out that ACE does not allow Frequency Response; response will occur with or without the
ACE equation. The Frequency Bias Setting is needed so that the AGC does not negate what may be provided in
frequency response. The bias component of ACE provides the feedback so that a BA may sustain the intended amount
of response with secondary control as long as Actual Frequency deviates from Scheduled Frequency. Duke Energy
would suggest the following: “A fixed or variable value usually expressed in MW/0.1 Hz, set into a Balancing Authority
Area Control Error equation to bias the control of resources so that Interconnection frequency is driven toward the
Scheduled Frequency.”
Yes
No
Duke Energy agrees that a BA should be required to achieve a minimum level of Frequency Response, however Duke
Energy believes the method for measurement needs improvement – please see comments to 1 and 2 above. Duke
Energy agrees with the concept that a Balancing Authority should be required to achieve a minimum level of Frequency
Response however the method for measurement should also allow exclusion of certain events, such as when the
frequency deviation is associated with the BA’s contingent loss of generation, or when an event is coincident with a
significant change in ramped interchange. It is not clear how the FRO will be determined – Duke Energy believes that
the industry should agree on the methodology which would be used for the ERO to determine the response desired for
the Interconnection and how the allocation for the FRO would be determined for each Balancing Authority. The
calculation of FRO allocation (in Attachment 1) is not clear on whether the peak load and generation data used is
historic data or forecasted data. It is also not clear how the assignment of the FRO would accommodate a mid-year
change in Balancing Authority size or other attribute that could change the calculated response. Duke Energy
questions if a BA providing better response than its allocated FRO in any year should be held to achieving that in the
following year – Duke Energy believes that should be the decision of the BA if it chooses to achieve more than the
minimum requirement applied to others.
No
Duke Energy believes that this needs to be restated. Will the ERO perform the calculations to determine each BA’s
Bias? Will the ERO provide ample time between publication of the settings and the date of implementation? If effective
coordinated secondary control is desired, other related operational parameters (e.g., L10) need to be set at the same
time. Since measurement and reporting of operational performance is primarily on a monthly basis (e.g., CPS1/CPS2),
the implementation date should be on or near the first of a month, but during normal working hours (so that adequate
support personnel are available).
No
Duke Energy agrees to the simple statement posed in the question; however, the requirement goes beyond that by
using a defined term, Adverse Reliability Impact, which has a relatively narrow focus on extreme conditions. If a single
BA lost a significant amount of its tie-line telemetry or its frequency sources, cascading outages and/or grid separation
would not necessarily be imminent but it would be imprudent to remain in Tie Line Bias mode. Go back to the original
language for the requirement – “Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie
Line Frequency Bias, unless such operation is adverse to system or Interconnection reliability.”
No
Duke Energy does not agree with having prescribed dates for the gradual reduction of the minimum Frequency Bias
Setting, as the implementation may drive significant issues which could delay, or halt the implementation at a certain
level. It is not clear what process would be used to give the “go-ahead” to move to the next level (agree?).
Group
SPP Standards Development
Robert Rhodes
No
In the past tie line flow changes that did not have the expected response for the given frequency deviation have been
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001635
excluded from the determination of Frequency Bias. It appears that this exclusion does not carry forth in the
determination of Frequency Response Measure. Therefore, non-conforming loads, intermittent resources and other
events/issues within a Balancing Authority could very well mask its natural frequency repsonse thereby setting the
Balancing Authority's Frequency Bias and its Frequency Response Obligation incorrectly. Then the Balancing Authority
is obligated to respond and will be measured for compliance against an incorrect value. This being the case, we can
support the definition of Single Event Frequency Response Data but have reservations about Frequency Response
Measure and Frequency Response Obligation.
No
We would suggest inserting 'secondary' in front of Frequency Response at the end of the sentence and delete
'Frequency Bias' following 'variable' at the beginning of the sentence.
Yes
Yes
No
We would suggest ending the sentence at the second ERO, deleting the phrase '…to ensure effective coordinated
secondary control, using the results from the calculation methodology detailed in Attachment A.' This phrase is more of
an explanation of why this is being done rather than a part of an actual requirement.
Yes
Yes
Individual
LeRoy Patterson
Patterson Consulting, Inc.
No
SEFRD: From the definition, it is not clear whether SEFRD is a Balancing Authority's 1) data collected for each
frequency event, 2) calculated Frequency Response for a selected event, 3) Net Actual Interchange divided by the
change in frequency for a selected event, or 4) some combination of these interpretations. If the SDT determines that
adjustments to Net Actual Interchange should be made such as adjustments for joint-owned generation and nonconforming loads as suggested in the field test document, then since this definition requires Frequency Response to be
determined from Net Actual Interchange, this definition would require changing to allow those adjustments. I suggest
defining SEFRD as "The individual sample of event data from a Balancing Authority that is necessary to calculate its
Frequency Response on FRS Form 1, expressed in MW/0.1Hz." FRM: This definition and its calculation in FRS Form 1
do not match. FRS Form 1 calculates FRM as "The median of Single Event Frequency Response Data observations
reported annually on FRS Form 1 [for events external to the Balancing Authority]." (Brackets added for emphasis.) The
FRS Form 1 calculation appears more appropriate based on data collected, since data are not reported and
calculations are not adjusted to compensate for contingencies within the Balancing Authority. Regardless, the
difference between definition and calculation makes it impossible for a Balancing Authority to know the expected
performance measure. FRO: The definition should be changed to remove the opposing concepts of performance and
obligation. For example: FRO is defined to be "The Balancing Authority's contribution to the total aggregate Frequency
Response…" FRM, not FRO, is the Balancing Authority's contribution toward the aggregated Frequency Response.
FRO is "The Balancing Authority's allocation of the interconnection's required Frequency Response…" or "The
Balancing Authority's required Frequency Response needed for reliable operation of an Interconnection …”
Yes
No
The purpose should not expect Frequency Response to maintain frequency beyond a few minutes, perhaps 15 minutes
for example. This purpose statement suggests the requirements will be "…to maintain Interconnection Frequency
within predefined bounds by arresting frequency deviations and support frequency until the frequency is restored to
schedule…" The phrase "until the frequency is restored to schedule" is problematic since regulation must bring
frequency to schedule. Frequency Response, and the associated requirements, should not be expected to substitute
for poor regulation beyond the first few minutes.
No
Requiring a Balancing Authority to provide Frequency Response and measuring that Frequency Response
consistently, is critical to maintaining reliability. The requirement is long overdue and the concept is a good one. The
method for measurement in FRS Form 1 is not consistent with the definition of FRM. The desired "averaging" of input
data over specific time ranges by the Balancing Authority as it completes FRS Form 1 appears only in the background
and instructions for FRS Form 1. Since this "instruction" document will not be a part of the standard, it is not obvious
that Balancing Authority's will be compelled to provide consistent data. Therefore, the standard will fail to achieve the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001636
stated purpose of providing "…consistent methods for measuring Frequency Response…". Attachment A, other than
the section providing guidance regarding event selection, appears to be explanatory, contextual, and instructional in
content. These aspects are important, but should not be requirements. Attachment A should include only the event
selection process and calculations associated with requirements, including an explanation of what is necessary if
variable Frequency Bias Settings are implemented. If other "requirements" are included in Attachment A, they should
be moved to the standard. FRS Form 1 should be an attachment to the standard as this form contains and performs
the required calculations. The remaining information in Attachment A should become either a standalone (technical)
document, or be combined with information such as "FRS Form 1 Background and Instructions" and renamed. As
further clarification regarding the ambiguity identified in the previous paragraph, Attachment A could be interpreted as
additional requirements on the Balancing Authority, ERO, or both. The language and scope is not sufficiently clear to
identify whether statements are informative or requirements. This lack of clarity makes it impossible for entities to
identify requirements, acquire appropriate tools and resources related to requirements, and to provide suitable
performance to meet requirements. For example, the statement "A final listing of official events to be used in the
calculation will be available from NERC by December 10 each year." may be intended as a requirement rather than a
statement suggesting a typical schedule. Further, if the previous statement is a typical schedule, then the statement
"The ERO will use the following criteria for the selection of events to be analyzed." could be interpreted as merely the
typical process to be used, but not a binding one.
No
The concept of requiring a Balancing Authority to implement its Frequency Bias Setting at a specific time and using a
specific calculation is meaningful. This requirement is not clearly worded, however. If the intent of Requirement 2 is to
identify "…when the Balancing Authority must implement its Frequency Bias Setting…" the requirement should stop
after "…on the date specified by the ERO." The remaining portion of the requirement explains the need for the
requirement and should be moved to supporting material. Attachment A does not have a "calculation methodology"
associated with the Frequency Bias Setting unless the language describing historical practice and the benefits of
moving a Frequency Bias Setting closer to a Balancing Authority's natural Frequency Response are intended to
constitute a "calculation methodology." FRS Form 1 has the "calculation methodology" of using the minimum (since the
value is negative) of last year's FRM, next year's FRO, and percentage of next year's peak load or generation.
Attachment A does not mention this methodology and the requirement does not mention FRS Form 1. The clause "…,
using the results from the calculation methodology detailed in Attachment A." appears to place an obscure requirement
on the ERO since the ERO is the entity providing the Frequency Bias Setting to be implemented by the Balancing
Authority. If the ERO is intended to use the value from FRS Form 1, after verifying data and calculations, then state that
expectation explicitly and clearly. Otherwise, the ERO could set Frequency Bias Settings in another manner after
observing the Form 1 values. The requirement for the ERO to provide a Frequency Bias Setting to each Balancing
Authority begs the question of how variable bias will be implemented. Historically, the Balancing Authority implements
its algorithm with oversight from NERC (Resources Subcommittee). The manner and expectation for providing data
and algorithms related to variable bias are inadequate.
No
While this requirement is in the existing standard, it places a significant reporting burden on a Balancing Authority to
demonstrate compliance during audits for little reliability gain. In addition for single Balancing Authority
interconnections, operating in this AGC mode is functionally equivalent to operating in flat frequency mode. This may
cause some interconnections to seek a variance, just to avoid compliance complications. Perhaps this requirement
could be replaced with a requirement for Balancing Authorities to contribute to frequency performance as well as
balance commitments and resources, or to calculate the ACE it uses to report in other standards in a specific manner.
As written, it could be interpreted to create a violation when AGC suspends or is offline.
No
The implementation plan should address implementing these requirements at the same time for all Balancing
Authorities within an interconnection, regardless of regulatory approvals. The present implementation plan will require
some Balancing Authorities within an interconnection to operate to the new standard while other Balancing Authorities
operate to the old standard if multiple regulatory jurisdictions exist as they do within two interconnections. This could
lead to uncoordinated and unreliable operation within an interconnection.
Group
IRC Standards Review Committee
Albert DiCaprio
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI for
frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange and does not
really reflect the frequency response of a contingent BA. Either the definition needs to be changed to accommodate
single BA Interconnections (such as ERCOT and Hydro Quebec), or regional variances for them need to be written by
the SDT. A BA’s frequency response is composed of load frequency response, governor response, and, for BAs
external to the resource loss, change in Net Interchange. Some approximation may be achieved by recognizing that the
magnitude of frequency deviation is attenuated by load frequency response and governor response (or frequency
activated demand response to reduce load). The definition of FRM specifies the median of all SEFRD observations
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001637
reported annually. What is the technical basis for selecting the median rather than the mean? The definition of FRO
raises questions. The discretely administered determination of FRO described in the draft Attachment A sets too
stringent a requirement; particularly for the smaller Interconnections which may also have large size generation
resources just as do the larger Interconnections. To “assure that Point C will not encroach on the first step UFLS” is
significantly more stringent than existing and historical performance for those smaller Interconnections. Such
assurance will assuredly prove to be very expensive. In fact, we question the need to define FRM and FRO since they
can easily be stipulated in the standard requirements. Having them defined and added to the ever-growing NERC
glossary creates unnecessary work to maintain the glossary, unless these terms are used by other NERC standards for
which consistent meaning need to be established. For example, R1 can easily be reworded as: “R1: Each Balancing
Authority shall achieve a median of all Single Event Frequency Response Data observations reported annually on FRS
Form 1 that is equal to or more negative than its contribution obligation to the total aggregate Frequency Response
needed for reliable operation of an Interconnection assigned by the ERO.” Similar wording changes can be made to the
FRS Form 1 to eliminate the need to define these two terms. Further, the Attachment A states that the SDT is
evaluating a risk based approach to establishing an Interconnection Frequency Response Obligation which can be
based on a probability function. If the N-2 criteria is established, it will be unlikely to be possible to change that if the
new approach is viewed as a reduction in required performance. As an example, in the ERCOT Interconnection, it is
recognized that the present level of required frequency responsive reserve cannot in all scenarios assure that Point C
will not encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the minimum
load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in ten years based
upon actual history. The cost of precluding such an event would be astronomical.
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the context of these
requirements? Should it be Frequency Bias Setting, instead? “Fixed” seems to be straightforward, but what is
“variable”? How often must Frequency Bias Setting change in order to be considered to be “variable”?
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be developed or
promulgated until the Field Trial has accomplished its purpose and the performance criteria and measures have been
determined. We request that the results of the Field Trial should be published and discussed BEFORE any changes
are made. The standard should be put into place later; it is premature at this time. Since this is to be a data gathering
process to be used to determine appropriate performance parameters, the purpose statement of the Field Trial should
be changed to read as follows: To determine require sufficient Frequency Response arranged by from the Balancing
Authority to maintain Interconnection Frequency within predefined bounds by responding to and arresting frequency
deviations and supporting frequency until the frequency is restored to schedule. To identify and establish provide
consistent methods for measuring Frequency Response and determining the Frequency Bias Setting and Frequency
Response Obligation. We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon Field Trial
results. Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting frequency
deviations. When there is a sudden and sizable change to system resource or demand, the first response to a
frequency deviation caused by this change would be the generators’ governors. This will provide a mitigating effect for
the immediate seconds up to minutes. The frequency bias setting will then kick in to supplement the mitigation need.
The governors are owned by the Generator Owners; the BAs do not own these facilities and hence can do little to
address frequency response during this initial period. To hold only the BA responsible for maintaining interconnection
frequency and arresting frequency deviations would be inappropriate. The industry needs to have a discussion to
determine who should be held responsible for providing governor responses immediately following an event, and by
what mechanism, and for implementing additional measures thereafter. We suggest that BAL-003 development be
withheld until this discussion takes place and a decision is made on who and how the governor response shall be
provided.
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be achieved.
However, the measure as described does not apply to all Interconnections. It does not apply to single BA
Interconnections such as ERCOT and Hydro Quebec. This requirement should be added later—not included now; and
it should clarify what the BA must do and what the response providers must do. BAs do not own and operate the
resources. An entity which does own or operate the resources may also be registered as a BA, but an entity which
does not own or operate resources may also be registered as a BA. Therefore, it is important to detail what a BA must
do and also to detail what the resource owner or operator must do. The resource owner may be registered as a GO or
a TO or even a DP. The resource operator may be registered as a GOP, a TOP, or a LSE. The BA must establish an
operations plan, using data provided to it by the resource owners and or operators, that will meet the performance
requirements. The BA must then deploy the proper amount of response through AGC or verbal instructions to
supplement the automatic responses that the resources will provide, must calculate the actual responses after-the-fact,
and report the performance as required. The resources must, as standards already provide, comply with the
deployments and instructions provided by the BA. However, if an entity which is functioning as a BA does not own its
resources, nor does it directly operate those resources, the BA cannot ensure the achievement. The standard must not
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001638
create an organizational or contractual arrangement that dictates how the compliance is provided. It should state what
must be done, not how. If entities choose to write and enter into such arrangements, that should be permissible, but not
required. Specific to R1, the wording does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not seem to
correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. Please clarify. Also, it
should not be necessary for the ERO to do the determination for all the Interconnections. There are already in place
methods for this by the existing ERCOT and WECC Interconnections. The SRC suggests that the ERO may not be the
appropriate technical entity. The ERO may be the appropriate entity to serve as the receiver of the forms and analyze
results for the Eastern Interconnection, but existing processes are already in place elsewhere. It should be sufficient
that those processes continue and submit copies of Form 1 to the ERO. This may also be appropriate for Hydro
Quebec. In addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the
BAs to implement the settings. The proposed language says only that the BA shall implement it on the date specified,
but it doesn’t address the need for that date to include some implementation time.
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to accommodate this
or regional variances should be written by the SDT to address existing differences. In addition this requirement, as
written, does not provide for momentary cessation of AGC for any reason, nor for reasonable system maintenance,
repair, or updates. As written, it seems to say that any duration of operation off Tie Line Bias is unacceptable and, thus,
would be a violation.
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier than the
schedule shown could result in the unintended consequence of non-compliance enforcement for performance that is
caused by the change rather than by the non-performance of the functional entity. Also, the effective dates given in the
Implementation differ from those in the draft standard. Different requirement numbers are expressed in each. Some of
the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as early as May 2011.
We do not believe that the BAL-003-1 standard will be approved by the industry or the NERC BoT at that time and that
does not even take into account regulatory approval (or 12 months after BoT adoption in those jurisdictions where no
regulatory approval is required). How can a standard begins to phase out while the successor standard is not anywhere
near becoming effective? If the SDT wants to propose a gradual replacement of the current R5, we would suggest that
the phase-out steps be tied to the date that the standard becomes effective.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing Authority for a
specific frequency excursion event as identified by the ERO (or NERC). As a comment, how frequency response is
calculated needs to be defined and may not always be the Net Actual Interchange (NIa) divided by the change in
frequency expressed in hertz. For example, the NIa may need to be adjusted for known generation and load changes
that do not represent frequency response for the period being measured such as known generation and load ramp
changes. Change in frequency needs to be more specific, such as the frequency difference between B and A
measured at B. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be:
The Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total…..” The review team
is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs will be held
accountable. Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used
to determine the FRO value. Should the definition of Frequency Response Measure be a median or mean value? May
need to clarify what FRS stands for.
We suggest the following changes to the definition: 1. Delete “Frequency Bias” in the parenthetical expression –
(“Frequency Bias” should not be used to define Frequency Bias) 2. Delete the word “usually” 3. Replace “set into” with
“as part of” as defined in BAL-001. 4. Replace the remainder of the sentence following “Area Control Error equation”
with “that influences its Automatic Generation Control (AGC) to provide its frequency response while Interconnection
frequency is not at its scheduled value” – (The frequency bias does not allow a BA to contribute its frequency response
to the Interconnection. The frequency bias term only affects the AGC response of the BA, which is part of its frequency
response usually minutes after the initial event and is dependent upon generation units being on AGC control and
capable of responding.) 5. The suggested changes would result in the following definition” A value, fixed or variable,
expressed in MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not at its
scheduled value.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001639
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25 events are
identified; it is a lagging indicator. The BA may have to ensure it measures all frequency excursions and develops its
own leading indicator to ensure compliance following year end. A sample CPS bounds report should be considered,
perhaps based on 2010 numbers, to demonstrate how FRM submitted would translate to FRO frequency bias settings
and how it will affect the L10 values.
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the BA’s prior
year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming year maximum
generation? What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
We suggest defining the date as by the end of the first business day following the deadline for Frequency Bias Setting
implementation.
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b, Requirement 6
requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to
determine the Balancing Authority’s ACE. We suggest that Requirement 3 be restated to “shall operate its Automatic
Generation Control (AGC) on Tie Line Frequency Bias, unless ........” Tie Line bias is the (Ia-Is) term and frequency
bias is the -10B(Fa-Fs) term. This should be coordinated with BARCSDT modifications to BAL-005.
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5 over
several years. Perhaps these dates should not be specific but tied to months following regulatory approval. Attachment
A should be modified to match what is in the proposed standard. The values currently shown as percent “of peak/0.1
Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz change. For BAs that do not serve
native load, percent “of upcoming years maximum generation/0.1 Hz should be changed to percent of its estimated
maximum generation level in the coming year/0.1 Hz change.
Group
ENBALA Power Networks
Rob Coulbeck
Yes
No
: ENBALA would modify the above as follows: A value, (either a fixed or variable Frequency Bias), usually expressed in
MW/0.1 Hz, set into a Balancing Authority Area Control Error algorithm equation that allows the Balancing Authority
AGC System to ignore the export or import caused by the Primary Frequency Response.
Yes
ENBALA strongly agrees that a Frequency Response standard is necessary to ensure reliable operation of the bulk
power system. We fully support all efforts to understand the declining trend, and the development of accurate models,
of Frequency Response in each Interconnection.
Yes
ENBALA does believe that a BA should be responsible for a minimum level of Frequency Response as calculated on
Form 1 and reflected in its FRO. Furthermore, we feel that additional data collected on the frequency nadir, such as the
metric suggested in the recent Lawrence Berkeley National Laboratory of nadir-based frequency response, would be
useful in assessing the current inertial response capabilities and level of risk for under-frequency load shedding.
Yes
Yes
Yes
Individual
Todd Bennett
Associated Electric Cooperative, Inc.
No
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is actually an
internally calculated value derived from a set of event sample data, and not really a “sample” value at all. So, I believe
the SEFRD definition needs further work. 2) FRM is defined by undefined terms “FRS” and “FRS Form 1”. 3) FRO –
fine 4) FRS – “Frequency Response Survey”
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001640
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is actually an
internally calculated value derived from a set of event sample data, and not really a “sample” value at all. So, I believe
the SEFRD definition needs further work.
Yes
Yes
Yes
Individual
Mark Thompson
Alberta Electric System Operator
No
The frequency response has 2 aspects: arresting frequency deviation (Point C) and deviation where frequency has
settled (Point B). The proposed SEFRD and FRM seem all based on the Point B, however the intention in purpose
statement is towards Point C... It is not clear to AESO that these proposed SEFRD and FRM based on settled
frequency deviation (Point B) are technically sufficient to address the concern of arresting frequency deviation (Point
C).
Yes
Yes
The purpose statement mentioned arresting deviation, restored to schedule and frequency bias setting, which are all at
different time frames. The AESO suggests that NERC provide some clarification of the relationships for the different
time frames.
Yes
The AESO agrees that there should be certain minimum requirement(s) of Frequency Response. In Attachment A, it
mentioned that it will be based on the protection criteria and Point C, and the FRM is determined based on the settled
deviation. The AESO suggests that the SDT describe how the FRM be related with the FRO as they are determined by
different time frames. The AESO suggests NERC investigate the measure and method of separate FRM / FRO for
different time frames, or provide technical evidence that the proposed FRM / FRO can also address the technical
concerns in different time frames.
Yes
The AESO suggests that the standard should provide a description on how the ERO would determine the frequency
bias setting and the relation to the FRO.
Yes
Individual
Dan Rochester
Independent Electricity System Operator
No
We concur with the definitions for SEFRD, FRM and FRO but do not believe that the latter two terms (FRM and FRO)
need to be defined since they can easily be stipulated in the standard requirements. Having them defined and added to
the ever-growing NERC glossary creates unnecessary work to maintain the glossary, unless these terms are used by
other NERC standards for which consistent meaning need to be established. For example, R1 can easily be reworded
as: “R1: Each Balancing Authority shall achieve a median of all Single Event Frequency Response Data observations
reported annually on FRS Form 1 that is equal to or more negative than its contribution obligation to the total aggregate
Frequency Response needed for reliable operation of an Interconnection assigned by the ERO.” Similar wording
changes can be made to the FRS Form 1 to eliminate the need to define these two terms.
Yes
No
We do not have any issue with the general intent of the scope statement, but have a difficulty in seeing the BA being
the only entity held responsible for maintaining interconnection frequency and arresting frequency deviations. When
there is a sudden and sizable change to system resource or demand, the system frequency will change. The first
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001641
response to such deviation would be the generators’ governors. This will provide a mitigating effect for the immediate
seconds up to minutes. The frequency bias setting will then kick in to supplement the mitigation need. To hold only the
BA responsible for maintaining interconnection frequency arresting frequency deviations would be only part of the
solution. The industry needs to have a discussion to determine who should be held responsible for providing governor
responses, and by what mechanism. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Yes
We agree with the BA being one of the responsible entities to achieve a minimum level of FR, and the method of
measurement. However, R1 does not correspond to the figures shown in the FRS (Form 1) in that the FRM (the
median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not seem to
correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
Yes
Yes
No
We have a difficulty understanding the basis for some of the dates in the implementation plan. Some of the
implementation steps (retiring R5 of BAL-003-0) start as early as May 2011. We do not believe that the BAL-003-1
standard will be approved by the industry or the NERC BoT at that time and that does not even take into account
regulatory approval (or 12 months after BoT adoption in those jurisdictions where no regulatory approval is required).
How can a standard begins to phase out while the successor standard is not anywhere near becoming effective? If the
SDT wants to propose a gradual replacement of the current R5, we would suggest that the phase-out steps be tied to
the date that the standard becomes effective.
Individual
Alice Ireland
Xcel Energy
Group
SERC OC Standards Review Group
Gerald Beckerle
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing Authority for a
specific frequency excursion event as identified by the ERO (or NERC). As a comment, how frequency response is
calculated needs to be defined and may not always be the Net Actual Interchange (NIa) divided by the change in
frequency expressed in hertz. For example, the NIa may need to be adjusted for known generation and load changes
that do not represent frequency response for the period being measured such as known generation and load ramp
changes. Change in frequency needs to be more specific, such as the frequency difference between B and A
measured at B. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be:
The Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total…..” The review team
is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs will be held
accountable. Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used
to determine the FRO value. Should the definition of Frequency Response Measure be a median or mean value?
No
We suggest the following changes to the definition: 1. Delete “Frequency Bias” in the parenthetical expression –
(“Frequency Bias” should not be used to define Frequency Bias) 2. Delete the word “usually” 3. Replace “set into” with
“as part of” as defined in BAL-001. 4. Replace the remainder of the sentence following “Area Control Error equation”
with “that influences its Automatic Generation Control (AGC) to provide its frequency response while Interconnection
frequency is not at its scheduled value” – (The frequency bias does not allow a BA to contribute its frequency response
to the Interconnection. The frequency bias term only affects the AGC response of the BA, which is usually minutes after
the initial event and is dependent upon generation units being on AGC control and capable of responding.) 5. The
suggested changes would result in the following definition” A value, fixed or variable, expressed in MW/0.1 hertz as
part of a Balancing Authority’s Area Control Error (ACE) equation that influences its Automatic Generation Control
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001642
(AGC) to continue to provide its frequency response while Interconnection frequency is not at its scheduled value.
Yes
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25 events are
identified; it is a lagging indicator. The BA may have to ensure it measures all frequency excursions and develops its
own leading indicator to ensure compliance following year end. A sample CPS bounds report should be considered,
perhaps based on 2010 numbers, to demonstrate how FRM submitted would translate to FRO frequency bias settings
and how it will affect the L10 values.
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the BA’s prior
year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming year maximum
generation? What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b, Requirement 6
requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to
determine the Balancing Authority’s ACE. We suggest that Requirement 3 be restated to “shall operate its Automatic
Generation Control (AGC) on Tie Line Frequency Bias, unless ........” Tie Line bias is the (Ia-Is) term and frequency
bias is the -10B(Fa-Fs) term. This should be coordinated with BARCSDT modifications to BAL-005.
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5 over
several years. Perhaps these dates should not be specific but tied to months following regulatory approval. Attachment
A should be modified to match what is in the proposed standard. The values currently shown as percent “of peak/0.1
Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz change. For BAs that do not serve
native load, percent “of upcoming years maximum generation/0.1 Hz should be changed to percent of its estimated
maximum generation level in the coming year/0.1 Hz change.
Group
Kansas City Power & Light
Michael Gammon
Yes
Yes
No
This purpose statement presumes that each Balancing Authority (BA) will have generation online to meet a
predetermined frequency response obligation. There are many small BA’s that do not have any generation online and
rely on load regulation agreements and energy agreements to provide their energy needs during parts of the year. This
purpose statement would not allow a BA to operate without generation online.
No
This requirement presumes that each Balancing Authority (BA) will have generation online to meet a predetermined
frequency response obligation. There are many small BA’s that do not have any generation online and rely on load
regulation agreements and energy agreements to provide their energy needs during parts of the year. This requirement
would not allow a BA to operate without generation online. Under Requirement 1, item 2a in Attachment A suggests
governor deadband as 36MHz (Megahertz). Suggest what is intended is 36mHz (millihertz). The Frequency Response
Obligation determination for the interconnection as described in Attachment A is a crude method and will result in
obligations that will exceed the FRO that is intended. This will result in additional cost to BA’s that is unnecessary to
achieve the purpose of maintaining sufficient generation online to arrest frequency degradation events caused by loss
of generating resources. The current NERC method for calculating a BA’s actual frequency response are inaccurate
and provide misleading guidance in the actual frequency response of a BA. These methods need considerable
improvement before any attempts to hold a BA to an expected level of frequency response as this proposal has stated.
No
The Frequency Response Obligation determination for the interconnection as described in Attachment A is a crude
method and will result in obligations that will exceed the FRO that is intended. This will result in additional cost to BA’s
that is unnecessary to achieve the purpose of maintaining sufficient generation online to arrest frequency degradation
events caused by loss of generating resources. The current NERC method for calculating a BA’s actual frequency
response are inaccurate and provide misleading guidance in the actual frequency response of a BA. These methods
need considerable improvement before any attempts to hold a BA to an expected level of frequency response as this
proposal has stated.
No
The impact of operating in an inappropriate AGC control mode is bigger than the BA’s own balancing area. The control
of the area affects other BA’s around a BA and if enough BA’s are involved, can affect an interconnection. Recommend
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001643
the requirement be modified to consider the reliability impact on its own balancing area, the balancing areas of adjacent
BA’s and the interconnection.
No
How can hard dates for the phasing out of the current R5 be in the implementation plan for a standard under
development? The concept of phasing out R5 and phasing in R2 could be done, however, this would take considerable
thought as to how to implement that. This current proposed implementation plan should be carefully reconsidered.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001644
Consideration of Comments
BAL-003-1 – Frequency Response and Frequency Bias Setting
Project 2007-12 - 1st Draft
There are a few places where the team missed
providing a comment in response to a
The Frequency Response and Frequency Bias Setting
suggestion – these are highlighted in yellow.
Drafting Team thanks all commenters who submitted
In general, the team did a good job of
comments on the 1st draft of BAL-003-1 – Frequency
responding!
Response and Frequency Bias Setting. This standard
was posted for a 30-day public comment period from
February 4, 2011 through March 7, 2011. The stakeholders were asked to provide feedback on the
standards through a special electronic comment form. There were 36 sets of comments, including
comments from more than 139 different people from approximately 86 companies representing 10 of
the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received the drafting team made the following changes to the proposed
Standard:
•
Removed the Single Event Frequency Response Data (SEFRD) definition from the standard.
•
Modified the definitions for Frequency Response Measure (FRM) and Frequency Response
Obligation (FRO).
•
Modified the proposed definition of Frequency Bias Setting.
•
Modified FRS Form 1 to correct errors, allow for adjustments and provide clarity.
•
Separated Attachment A Background Document into two documents; 1) Attachment A – Supporting
Document detailing the methodology to be followed for calculations, and 2) Background Document
detailing the rational for the development of the requirements.
•
Created Attachment B – Process for Adjusting Bias Setting Floor to clarify the methodology to be
used in reducing the present 1% minimum Frequency Bias Setting.
•
Added measures, VRFs and VSLs.
There were a couple of minority issues that the team was unable to resolve, including the following:
•
A few stakeholders requested the SDT to consider a standard for generators to support the
Balancing Authority in achieving the targeted level of Frequency Response. The team stated that
this was outside the scope of the industry approved SAR. The SDT further stated that any entity
could submit a SAR addressing this issue to the SC for consideration and that the SDT supported this
option.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001645
•
A couple of comments stated they believed that the standard should support the development of a
market for supporting a Balancing Authority in achieving the target Frequency Response. The SDT
explained that this standard would provide for the metrics for Frequency Response while the
market would define itself. The SDT further stated a market could be created by a region, subregion, ISO, RTO or other entity as appropriate to facilitate compliance however the NERC
Reliability Standards do not establish markets.
In this “Consideration of Comments” document stakeholder comments have been organized so that it
is easier to see the responses associated with each question. All comments received can be viewed in
their original format at:
http://www.nerc.com/filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001646
Index to Questions, Comments, and Responses
1.
The SDT has developed three new terms to be used with this standard.
•
Single Event Frequency Response Data (SEFRD) The individual sample of event data from a
Balancing Authority which represents the change in Net Actual Interchange (NIA), divided by
the change in frequency, expressed in MW/0.1Hz.
•
Frequency Response Measure (FRM) The median of all Single Event Frequency Response Data
observations reported annually on FRS Form 1.
•
Frequency Response Obligation (FRO) The Balancing Authority’s contribution to the total
aggregate Frequency Response needed for reliable operation of an Interconnection assigned
by the ERO.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area?.................................................................................................................................. 12
2.
The SDT has modified the definition for the term Frequency Bias Setting. The current definition
and revised definition are shown below to show the changes proposed. Do you agree with this
new definition for Frequency Bias Setting? If not, please explain in the comment area…………….. 25
3.
The proposed purpose statement in the draft standard is: To require sufficient Frequency
Response from the Balancing Authority to maintain Interconnection Frequency within predefined
bounds by arresting frequency deviations and supporting frequency until the frequency is restored
to schedule. To provide consistent methods for measuring Frequency Response and determining
the Frequency Bias Setting. Do you agree with this purpose? If not, please explain in the comment
area. ……. ............................................................................................................. ………35
4.
Requirement 1 identifies a minimum level of Frequency Response. R1. Each Balancing Authority
shall achieve a Frequency Response Measure (FRM) (as detailed in Attachment A and calculated
on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO).
Do you agree with the concept that a Balancing Authority should be required to achieve a
minimum level of Frequency Response and the method for measurement? If not, please explain in
the comment area. .......................................................................................................44
5.
Requirement 2 identifies when the Balancing Authority must implement its Frequency Bias Setting.
R2. Each Balancing Authority shall implement the Frequency Bias Setting (fixed or variable)
provided by the ERO into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effective coordinated secondary control, using the results from the
calculation methodology detailed in Attachment A.
Do you agree with this implementation? If not, please explain in the comment area.…. .............56
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001647
6.
Requirement 3 mandates that a Balancing Authority operate its Automatic Generation Control
(AGC) on Tie Line Bias unless it becomes adverse to the integrity of its system.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Bias, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s
Area.
Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it becomes
adverse to its system? If not, please explain in the comment area below.…. ............................67
7.
Do you agree with the proposed Implementation Plan for this standard? If not, please explain in
the comment area.…. ....................................................................................................79
8.
This standard proposes to eliminate the 1% minimum Frequency Bias over a period of 4 years as
outlined in the Implementation Plan. Do you agree that the elimination of the 1% minimum will
bring Frequency Bias closer or equal to natural Frequency Response? If not, please explain in the
comment area.. ............................................................................................................90
9.
Do you agree with the drafting team that this standard should be field tested? If not, please
explain in the comment area.…. ......................................................................................99
10. Attachment A of the proposed standard describes the criteria for selecting events to be analyzed.
Do you agree with the criteria as described in Attached A? If not, please explain in the comment
area.…. ..................................................................................................................... 105
11. The proposed standard has a document attached to it that describes the SDT’s reasoning for the
Requirements (Attachment A - Frequency Response Background Document). Do you agree with
the SDT that this document is useful and provides a clear understanding of the Requirements? If
not, please explain in the comment area.…. ..................................................................... 115
12. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s FRM.
Do you agree with the SDT that this is the proper method to calculate its FRM? If not, please
explain in the comment area and if possible provide an alternate method to calculate FRM.…. . 127
13. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s
Frequency Bias Setting. Do you agree with the SDT that this is the proper method to calculate its
Frequency Bias Setting? If not, please explain in the comment area and if possible provide an
alternate method to calculate Frequency Bias Setting.…. ................................................... 135
14. The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS Form 1 for
calculating FRM and Frequency Bias Setting. Do you agree with the SDT that this document
provides a clear understanding of how to use the form? If not, please explain in the comment
area.…. ..................................................................................................................... 142
15. The SDT is soliciting comments on methods of obtaining Frequency Response to meet the FERC
Order 693 directive. If possible please provide any thoughts you may have on this subject.….... 149
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001648
16. If you are aware of any conflicts between the proposed standard and any regulatory function, rule
order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.…. ..................................................................................................................... 126
17. Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1.…. .................................... 131
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001649
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Kurtis Chong
Independent Electricity System Operator
NPCC
2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5. Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC
NA
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC
1
7. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8. Brian D. Evans-Mongeon Utility Services
NPCC
8
9. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
10. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
2
3
4
5
6
7
8
9
10
X
001650
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Kathleen Goodman
ISO - New England
NPCC
2
12. David Kiguel
Hydro One Networks Inc.
NPCC
1
13. Michael R. Lombardi
Northeast Utilities
NPCC
1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC
1
15. Bruce Metruck
New York Power Authority
NPCC
6
16. Chantel Haswell
FPL Group, Inc.
NPCC
5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
18. Robert Pellegrini
The United Illuminating Company
NPCC
1
19. Saurabh Saksena
National Grid
NPCC
1
20. Michael Schiavone
National Grid
NPCC
1
21. Wayne Sipperly
New York Power Authority
NPCC
5
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC
3
2.
Group
Terry L. Blackwell
Santee Cooper
X
2
3
X
4
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Glenn Stephens
Santee Cooper
SERC
1
3. Rene Free
Santee Cooper
SERC
1
4. Wayne Ahl
Santee Cooper
SERC
1
5. Jim Peterson
Santee Cooper
SERC
1
3.
Group
Additional Member
Carol Gerou
MRO's NERC Standards Review
Subcommittee
Additional Organization
X
Region Segment Selection
1. Mahmood Safi
Omaha Public Utility District
MRO
1, 3, 5, 6
2. Chuck Lawrence
American Transmission Company
MRO
1
3. Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4. Jason Marshall
Midwest ISO Inc.
MRO
2
5. Jodi Jenson
Western Area Power Administration
MRO
1, 6
6. Ken Goldsmith
Alliant Energy
MRO
4
7. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
8. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001651
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
10. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
11. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
12. Scott Nickels
Rochester Public Utilties
MRO
4
13. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
14. Richard Burt
Minnkota Power Cooperative, Inc.
MRO
1, 3, 5, 6
4.
Brent Ingebrigtson
Group
Additional Member
LG&E and KU Energy
Additional Organization
Region
PPL Electric Utilities Corporation NA - Not Applicable 1
2. Annette Bannon
PPL Generation LLC
NA - Not Applicable 5
3. Mark Heimbach
PPL Energy Plus
NA - Not Applicable 6
Group
Jason Marshall
Additional Member
1, 3
2. Terry Harbour
Midamerican Energy
MRO
1
3. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
4. Mike Moltane
ITC Holdings
RFC
1
Group
Sam Ciccone
5
6
7
8
9
10
X
Region Segment Selection
1. Robert Thomasson Big Rivers Electric Cooperative SERC
6.
4
X
Midwest ISO Standards Collaborators
Additional Organization
3
Segment Selection
1. Brenda Truhe
5.
2
FirstEnergy
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Dave Folk
FE
RFC
1, 3, 4, 5, 6
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
7.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
Region Segment Selection
1. Jamie Murphy
BPA, Transmission Technical Operations WECC 1
2. Bart McManus
BPA, Transmission Technical Operations WECC 1
3. Dave Kirsch
BPA, Transmission Technical Operations WECC 1
4. Deanna Phillips
BPA, FERC Compliance Office
8.
Group
Additional Member
1. John Allen
Robert Rhodes
WECC 1, 3, 5, 6
SPP Standards Development
Additional Organization
City Utilities of Springfield, MO
Region Segment Selection
SPP
1, 4
8
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001652
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Michelle Corley
Cleco
SPP
1, 3, 5
3. Lisa Duffey
Cleco
SPP
1, 3, 5
4. Jeff Elting
Nebraska Public Power District
MRO
1, 3, 5
5. Denney Fales
Kansas City Power & Light
SPP
1, 3, 5, 6
6. Louis Guidry
Cleco
SPP
1, 3, 5
7. Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
8. Rick Koch
Nebraska Public Power District
MRO
1, 3, 5
9. Errol Ortego
Louisiana Energy and Power Authority SPP
10
10. David Pham
Empire District Electric
SPP
1, 3, 5, 6
11. Don Schmit
Nebraska Public Power District
MRO
1, 3, 5
12. John Stephens
City Utililties of Springfield, MO
SPP
1, 4
13. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
14. Jim Useldinger
Kansas City Power & Light
SPP
1, 3, 5, 6
15. Barry Warren
Empire District Electric
SPP
1
16. Bryn Wilson
Empire District Electric
SPP
1
9.
Albert DiCaprio
Group
IRC Standards Review Committee
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Patrick Brown
PJM
RFC
2
2. Matt Goldberg
ISO-NE
NPCC
2
3. Dan Rochester
IESO
NPCC
2
4. Steve Myers
ERCOT
ERCOT 2
5. Mark Thompson
AESO
WECC 2
6. Greg Van Pelt
CAISO
WECC 2
7. Charles Yeung
SPP
SPP
2
8. Terry Bilke
Midwest ISO
RFC
2
9. Greg Campoli
NYISO
NPCC
2
10. Kathleen Goodman ISO-NE
NPCC
2
11. Ben Li
IESO
NPCC
2
12. Jason Marshall
Midwest ISO
RFC
2
13. Don Weaver
NBSO
NPCC
2
10.
Gerald Beckerle
Group
SERC OC Standards Review Group
X
X
9
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001653
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. John Neagle
AECI
SERC
1, 3, 5
2. Larry Akens
TVA
SERC
1, 3, 5, 9
3. Chris Adams
EKPC
SERC
3, 5, 9, 1
4. Joel Wise
TVA
SERC
1, 3, 5, 9
5. Ron Wyble
CWLD
SERC
1, 5, 9
6. Andy Burch
EEI
SERC
1, 5
7. Rene' Free
Santee Cooper
SERC
1, 3, 5, 9
8. Glenn Stephens
Santee Cooper
SERC
1, 3, 5, 9
9. Robert Thomasson
BREC
SERC
1, 3, 5, 9
10. Gene Delk
SCE&G
SERC
1, 3, 5
11. Mike Oatts
Southern
SERC
1, 3, 5
12. Sam Holeman
Duke
SERC
1, 3, 5
13. Marc Butts
Southern
SERC
1, 3, 5
14. Melinda Montgomery Entergy
SERC
1, 3
15. Ron Carlsen
Southern
SERC
1, 3, 5
16. Tim Hattaway
PowerSouth
SERC
1, 3, 5, 9
17. John Troha
SERC
SERC
10
11.
Michael Gammon
Group
Additional Member
Kansas City Power & Light
X
X
X
X
X
X
Additional Organization Region Segment Selection
1. Jennifer Flandermeyer Kansas City Power & Light SPP
1, 3, 5, 6
2. Denney Fales
Kansas City Power & Light SPP
1, 3, 5, 6
12.
Individual
Janet Smith
Arizona Public Service Company
X
X
13.
Individual
Cindy Martin
Southern Company
X
X
14.
Individual
James Eckelkamp
Progress Energy
X
X
X
X
15.
Individual
Rob Coulbeck
ENBALA Power Networks
16.
Individual
Joe O'Brien
NIPSCO
X
X
X
X
17.
Individual
John Canavan
NorthWestern Energy
X
18.
Individual
Howard F. Illian
Energy Mark, Inc.
19.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
X
X
10
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001654
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
20.
Individual
Isaac Read
Beacon Power Corporation
21.
Individual
Bryan Taggart
Westar Energy
22.
Individual
Thomas Washburn
FMPP
23.
Individual
Chris Adams
EKPC
24.
Individual
Kathleen Goodman
ISO New Engand Inc.
25.
Individual
Hao Li
Seattle City Light
X
X
26.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
27.
Individual
JC Culberson
ERCOT
28.
Individual
Howard Rulf
We Energies
29.
Individual
Thad Ness
American Electric Power
X
X
X
X
30.
Individual
Greg Rowland
Duke Energy
X
X
X
X
31.
Individual
LeRoy Patterson
Patterson Consulting, Inc.
32.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
33.
Individual
Todd Bennett
Associated Electric Cooperative, Inc.
X
X
X
X
34.
Individual
Mark Thompson
Alberta Electric System Operator
X
35.
Individual
Dan Rochester
Independent Electricity System Operator
X
36.
Individual
Alice Ireland
Xcel Energy
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001655
1. The SDT has developed three new terms to be used with this standard.
• Single Event Frequency Response Data (SEFRD) The individual sample of event data from a Balancing Authority which
represents the change in Net Actual Interchange (NIA), divided by the change in frequency, expressed in MW/0.1Hz.
• Frequency Response Measure (FRM) The median of all Single Event Frequency Response Data observations reported
annually on FRS Form 1.
• Frequency Response Obligation (FRO) The Balancing Authority’s contribution to the total aggregate Frequency
Response needed for reliable operation of an Interconnection assigned by the ERO.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment area?
Summary Consideration: The majority of the commenters disagreed with the proposed definitions for this standard. The primary
concerns cited are the definitions, and the calculations and methodology associated with the definitions, are not clear.
Many commenters expressed concern that the FRM methodology did not allow exclusion of events that, if included, would mask true
frequency response. Commenters also indicated that the ‘average’ and not the ‘median’ should be used for the FRM calculation. Other
observations include inconsistency between the FRM definition and its calculation on FRS Form 1; that proposed language allows the ERO
to unilaterally change FRO value; and that definitions seem more focused on the frequency excursion curve point B value and not point C
value. Suggestions for improving the standard include making it clear that 25 events are used for determining FRM; that definitions should
specify how to calculate each term; and that FRM should take into account nonconforming load.
In response to industry comments, the SDT has deleted the SEFRD definition from the standard; revised the FRO and FRM definitions; and
also improved the calculations. With regards to use of the median for calculating FRM, in general, statisticians use the median as the best
measure of central tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less
influenced by noise in the measurement process. FRS Form 1 has been modified to allow for adjustments to the load and generation. To
allay industry concern over the ERO’s role, the SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to
perform the tasks specified in the standard is necessary.
In regards to concerns over the frequency excursion curve point B value, the SDT explained that while point B measurements have some
data quality challenges to be mastered, point C measurements are not practical at this time for Balancing Authorities in an Interconnection
with more than one Balancing Authority. The SDT intends to study point B and point C relationships of each Interconnection with more
than one Balancing Authority to address this issue during the field trial.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the
BAs. The SDT is evaluating a probabilistic method during the field trial.
Organization
Yes or No
Question 1 Comment
12
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001656
Organization
Patterson Consulting, Inc.
Yes or No
No
Question 1 Comment
From the definition, it is not clear whether SEFRD is a Balancing Authority's 1) data collected for each
frequency event, 2) calculated Frequency Response for a selected event, 3) Net Actual Interchange divided by
the change in frequency for a selected event, or 4) some combination of these interpretations. If the SDT
determines that adjustments to Net Actual Interchange should be made such as adjustments for joint-owned
generation and nonconforming loads as suggested in the field test document, then since this definition requires
Frequency Response to be determined from Net Actual Interchange, this definition would require changing to
allow those adjustments. I suggest defining SEFRD as
"The individual sample of event data from a Balancing Authority that is necessary to calculate its
Frequency Response on FRS Form 1, expressed in MW/0.1Hz."
FRM: This definition and its calculation in FRS Form 1 do not match. FRS Form 1 calculates FRM as "The
median of Single Event Frequency Response Data observations reported annually on FRS Form 1 [for events
external to the Balancing Authority]." (Brackets added for emphasis.) The FRS Form 1 calculation appears more
appropriate based on data collected, since data are not reported and calculations are not adjusted to
compensate for contingencies within the Balancing Authority. Regardless, the difference between definition and
calculation makes it impossible for a Balancing Authority to know the expected performance measure.
FRO: The definition should be changed to remove the opposing concepts of performance and obligation. For
example: FRO is defined to be "The Balancing Authority's contribution to the total aggregate Frequency
Response…" FRM, not FRO, is the Balancing Authority's contribution toward the aggregated Frequency
Response. FRO is
"The Balancing Authority's allocation of the interconnection's required Frequency Response…" or "The
Balancing Authority's required Frequency Response needed for reliable operation of an Interconnection
…”
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT has modified the definition for FRM to read “The median of all the Frequency Response observations reported annually on FRS Form 1.”
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
Santee Cooper
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes.
Change in frequency needs to be more specific, such as the frequency difference between B and A measured
at B. If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
13
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001657
Organization
Yes or No
Question 1 Comment
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs
will be held accountable. Also, the definitions do not explain who will determine the value of each BA’s FRO
and the method used to determine the FRO value.Should the definition of Frequency Response Measure be a
median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
LG&E and KU Energy
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between two physical locations B and A measured at B. Frequency
deviation used in the calculation needs to be the deviation observed by the BA performing the calculation.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
standard does not explain who will determine the value of each BA’s FRO nor the method used to determine
the FRO value.
Should the definition of Frequency Response Measure be a median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
14
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001658
Organization
SERC OC Standards Review
Group
Yes or No
No
Question 1 Comment
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between B and A measured at B.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”The
review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the BAs
will be held accountable.
Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used to
determine the FRO value.
Should the definition of Frequency Response Measure be a median or mean value?
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
The ERO is the responsible party for determining a BA’s FRO. The explanation of who determines the BA’s FRO as-well-as how the BA’s FRO
is determined is now contained in the revised Attachment A.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
South Carolina Electric and Gas
No
We suggest the SDT consider defining SEFRD as: The calculated frequency response by a Balancing
Authority for a specific frequency excursion event as identified by the ERO (or NERC). As a comment, how
frequency response is calculated needs to be defined and may not always be the Net Actual Interchange
(NIa) divided by the change in frequency expressed in hertz. For example, the NIa may need to be adjusted
for known generation and load changes that do not represent frequency response for the period being
measured such as known generation and load ramp changes. Change in frequency needs to be more
specific, such as the frequency difference between B and A measured at B.
If Frequency Response Obligation (FRO) is a targeted value, then perhaps the definition should be: The
Balancing Authority’s annual median frequency response as assigned by the ERO (or NERC). The word
15
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001659
Organization
Yes or No
Question 1 Comment
“contribution” should be considered to be replaced with “the balancing authority piece of the total.....”
The review team is concerned that the FRO and FRM definitions do not contain enough clarity as to how the
BAs will be held accountable.
Also, the definitions do not explain who will determine the value of each BA’s FRO and the method used to
determine the FRO value.
Should the definition of Frequency Response Measure be a median or mean value? May need to clarify what
FRS stands for.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
The ERO is the responsible party for determining a BA’s FRO. The explanation of who determines the BA’s FRO as-well-as how the BA’s FRO
is determined is now contained in the revised Attachment A.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
MRO's NERC Standards Review
Subcommittee
No
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data and still comply. Average values would prevent this from happening.
Should FRM be clear that it includes at least 25 events in the definition? While that can be garnered from
Attachment A, it is not specified in the Form 1 instructions. We are concerned that the regulators may argue
that 25 events do not apply because an attachment is not part of the standard.
Response: Based on analysis of data the SDT has determined that the median value is the proper method to be used in defining FRM.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of
Requirement.
Midwest ISO Standards
Collaborators
No
that
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data and still comply. Average values would prevent this from happening.
Should FRM be clear that it includes at least 25 events in the definition? While that can be garnered from
Attachment A, it is not specified in the Form 1 instructions. We are concerned that the regulators may argue
16
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001660
Organization
Yes or No
Question 1 Comment
that 25 events do not apply because an attachment is not part of the standard.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
Requirement.
We Energies
No
For Frequency Response Measure, the drafting team should consider using average rather than median.
Because median is literally the middle value, a Balancing Authority could have 12 really bad Single Event
Frequency Response Data points and still comply. Average values would prevent this from
happening.Should FRM be clear that it includes at least 25 events in the definition? While that can be
garnered from Attachment A, it is not specified in the Form 1 instructions. We are concerned that the
regulators may argue that 25 events do not apply because an attachment is not part of the standard.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
Requirement.
Westar Energy
No
For FRM, why is median used rather than average?
The method in the standard for dsetermining FRM needs to allow for excluding some events due to nonconforming loads, scan rates, intermittent resources, large interchange ramps, etc that may cause the actual
response during the 16 seconds to actually be opposite of the expected response.
Response: With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
Bonneville Power Administration
No
FRO definition - BPA feels uncomfortable supporting this standard when the ERO is given a blank check to
FRO. The methodology for determining the FRO must be spelled out in detail in order to allow all entities an
opportunity to comment on that methodology.
Response: The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is
17
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001661
Organization
Yes or No
Question 1 Comment
No
In the past tie line flow changes that did not have the expected response for the given frequency deviation
have been excluded from the determination of Frequency Bias. It appears that this exclusion does not carry
forth in the determination of Frequency Response Measure. Therefore, non-conforming loads, intermittent
resources and other events/issues within a Balancing Authority could very well mask its natural frequency
repsonse thereby setting the Balancing Authority's Frequency Bias and its Frequency Response Obligation
incorrectly. Then the Balancing Authority is obligated to respond and will be measured for compliance against
an incorrect value. This being the case, we can support the definition of Single Event Frequency Response
Data but have reservations about Frequency Response Measure and Frequency Response Obligation.
necessary.
SPP Standards Development
Response: The SDT agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
Note that based on other stakeholder concerns, the definition of SEFRD has been deleted.
IRC Standards Review
Committee
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI
for frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange
and does not really reflect the frequency response of a contingent BA. Either the definition needs to be
changed to accommodate single BA Interconnections (such as ERCOT and Hydro Quebec), or regional
variances for them need to be written by the SDT. A BA’s frequency response is composed of load frequency
response, governor response, and, for BAs external to the resource loss, change in Net Interchange. Some
approximation may be achieved by recognizing that the magnitude of frequency deviation is attenuated by
load frequency response and governor response (or frequency activated demand response to reduce load).
The definition of FRM specifies the median of all SEFRD observations reported annually. What is the
technical basis for selecting the median rather than the mean?
The definition of FRO raises questions. The discretely administered determination of FRO described in the
draft Attachment A sets too stringent a requirement; particularly for the smaller Interconnections which may
also have large size generation resources just as do the larger Interconnections.
To “assure that Point C will not encroach on the first step UFLS” is significantly more stringent than existing
and historical performance for those smaller Interconnections. Such assurance will assuredly prove to be
very expensive.In fact, we question the need to define FRM and FRO since they can easily be stipulated in
18
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001662
Organization
Yes or No
Question 1 Comment
the standard requirements. Having them defined and added to the ever-growing NERC glossary creates
unnecessary work to maintain the glossary, unless these terms are used by other NERC standards for which
consistent meaning need to be established. For example, R1 can easily be reworded as:”R1: Each Balancing
Authority shall achieve a median of all Single Event Frequency Response Data observations reported
annually on FRS Form 1 that is equal to or more negative than its contribution obligation to the total
aggregate Frequency Response needed for reliable operation of an Interconnection assigned by the ERO.\
”Similar wording changes can be made to the FRS Form 1 to eliminate the need to define these two
terms.Further, the Attachment A states that the SDT is evaluating a risk based approach to establishing an
Interconnection Frequency Response Obligation which can be based on a probability function. If the N-2
criteria is established, it will be unlikely to be possible to change that if the new approach is viewed as a
reduction in required performance. As an example, in the ERCOT Interconnection, it is recognized that the
present level of required frequency responsive reserve cannot in all scenarios assure that Point C will not
encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the
minimum load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in
ten years based upon actual history. The cost of precluding such an event would be astronomical.
Response: The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the
definitions in the standard so they can be added to the approved NERC Glossary of Terms.
The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the BAs. The SDT is
evaluating a probabilistic approach during the field trial.
ERCOT
No
The definition of SEFRD will not work as described for a single BA Interconnection. There is no change in NI
for frequency deviations. Similarly, the definition assumes all response is provided by change in Interchange
and does not really reflect the frequency response of a contingent BA. Either the definition needs to be
changed to accommodate single BA Interconnections (such as ERCOT and Hydro Quebec), or regional
variances for them need to be written by the SDT. A BA’s frequency response is composed of load frequency
response, governor response, and, for BAs external to the resource loss, change in Net Interchange. Some
approximation may be achieved by recognizing that the magnitude of frequency deviation is attenuated by
19
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001663
Organization
Yes or No
Question 1 Comment
load frequency response and governor response (or frequency activated demand response to reduce load).
The definition of FRM specifies the median of all SEFRD observations reported annually. What is the
technical basis for selecting the median rather than the mean?
The definition of FRO raises questions. The discretely administered determination of FRO described in the
draft Attachment A sets too stringent a requirement; particularly for the smaller Interconnections which may
also have large size generation resources just as do the larger Interconnections. To “assure that Point C will
not encroach on the first step UFLS” is significantly more stringent than existing and historical performance for
those smaller Interconnections. Such assurance will assuredly prove to be very expensive.
In fact, we question the need to define FRM and FRO since they can easily be stipulated in the standard
requirements. Having them defined and added to the ever-growing NERC glossary creates unnecessary work
to maintain the glossary, unless these terms are used by other NERC standards for which consistent meaning
need to be established. For example, R1 can easily be reworded as:”R1: Each Balancing Authority shall
achieve a median of all Single Event Frequency Response Data observations reported annually on FRS Form
1 that is equal to or more negative than its contribution obligation to the total aggregate Frequency Response
needed for reliable operation of an Interconnection assigned by the ERO.”
Similar wording changes can be made to the FRS Form 1 to eliminate the need to define these two
terms.Further, the Attachment A states that the SDT is evaluating a risk based approach to establishing an
Interconnection Frequency Response Obligation which can be based on a probability function. If the N-2
criteria is established, it will be unlikely to be possible to change that if the new approach is viewed as a
reduction in required performance. As an example, in the ERCOT Interconnection, it is recognized that the
present level of required frequency responsive reserve cannot in all scenarios assure that Point C will not
encroach the first step of UFLS. The system conditions that exist for the encroachment to occur represent a
small likelihood and would require the N-2 contingency to occur on something like the minimum hour of the
minimum load day of the year. It has occurred one time in the history of ERCOT. Thus, it is less than once in
ten years based upon actual history. The cost of precluding such an event would be astronomical.
Response: The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the
definitions in the standard so they can be added to the approved NERC Glossary of Terms.
The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The SDT also agrees with your concern regarding the definition of FRO and has revised the definition to read “The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.”
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
The SDT has chosen the deterministic approach detailed in Attachment A as the method to use to allocate the Interconnection FRO to the BAs. The SDT is
20
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001664
Organization
Yes or No
Question 1 Comment
evaluating a probabilistic approach during the field trial.
Progress Energy
No
The proposed definition for SEFRD assumes that there is no change in the Net Scheduled Interchange (NIS)
as a result of the event. However, a dynamic schedule for load or generation based on data obtained with a
two second scan rate will impact the NIS, and therefore the corresponding load or generation response will
offset the change to NIA. Therefore, the definition of SEFRD should replace "NIA" with "change in NIA minus
NIS".
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
Energy Mark, Inc.
No
Comment 1: I agree with the definition of the Single Event Frequency Response Data.
Comment 2: I do not agree that the Frequency Response Measure should be the median of all SEFRD
observations reported annually on FRS Form 1.
Comment 3: The regression values presented on FRS Form 1 have not been calculated correctly.
Comment 4: Since the FRM is going to be used to set the value for the Frequency Bias Setting and the
Frequency Bias Setting represents a straight line though the origin of zero frequency error and zero megawatt
error, the best representation of the data for setting this paramater can be achieved through the use of a
regression.
Comment 5: Only a regression will weight the impact of each SEFRD correctly. The use of median or mean
will not provide the best estimate for use as the Frequency Bias Setting.
Comment 6: The standard has been written to include a samlple size (25) large enough to enable effective
statistical methods of analysis. What justification is there to then ignor those well proven methods and revert
to methods designed to address problems where the sample sizes are insufficient to support sound statistical
analysis methods.
Response: (1) The SDT thanks you for your affirmative response, however several other stakeholders disagreed with the definition of SEFRD and the drafting
team has removed the proposed definition from the revised standard.
(2, 4, 5) With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central
tendency when a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in
the measurement process.
(3) The SDT has corrected FRS Form 1.
(6) Research conducted by the Frequency Response Standard Drafting Team (FR SDT) indicated that a Balancing Authority’s FRM will
converge to a reasonably stable value with 20 to 25 samples. The FR SDT as well as the NERC Frequency Response Initiative is evaluating
other methods of FRM. The SDT is not ignoring methods of proven statistical design and the chosen method does require at least 25
21
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001665
Organization
Yes or No
Question 1 Comment
samples.
EKPC
No
These definitions should be revised to include specifics on how to calculate each term.
The FRM calculation method should take into account large non-conforming loads.
A median will not reflect the true nature of the system.
Response: The SDT does not believe the definition should include the specific calculation and therefore has incorporated the calculation methodology in
Attachment A.
The FRM calculation, using FRS Form 1, has been modified to now include adjustments.
Based on analysis of data the SDT has determined that the median value is the proper method to be used in defining FRM.
Duke Energy
No
The definition of SEFRD would conflict with any alternative measurement of frequency response. The SEFRD
makes no provision for the impacts of generation loss experienced by a contingent BA, impacts of nonconforming loads, or impacts of schedule ramps.
The FRM also makes no such provisions. The resulting FRM for a BA experiencing one or more of these
impacts for one or more SEFRDs will be skewed and completely miss the intended measurement of the BA’s
response to frequency excursions. In addition, as it is not yet clear how provision of Frequency Response by
one BA to meet a portion of another BA’s requirement would be achieved, Duke Energy cannot say that a
simple measure of the NIA against the frequency deviation will capture the net of the response desired.
Regarding the definition of FRO, the industry should agree on the methodology which would be used for the
ERO to determine the response desired for the Interconnection that is used for allocation of the FRO, and not
leave it as a parameter subject to change outside of the standards process. The definition is only acceptable if
the assignment by the ERO is based upon a methodology supported by the industry and subject to change
only through the standards process.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
The methodology that the ERO will use for determining the FRO is now outlined in the new Attachment A.
methodology in the balloting phase of the standard.
Associated Electric Cooperative,
Inc.
No
The industry will either accept or reject this
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is
actually an internally calculated value derived from a set of event sample data, and not really a “sample” value
at all. So, I believe the SEFRD definition needs further work.
22
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001666
Organization
Yes or No
Question 1 Comment
2) FRM is defined by undefined terms “FRS” and “FRS Form 1”.
3) FRO – fine
4) FRS - “Frequency Response Survey”
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
FRS Form 1 is the name of the form to be used for calculating FRM.
Alberta Electric System Operator
No
The frequency response has 2 aspects: arresting frequency deviation (Point C) and deviation where
frequency has settled (Point B). The proposed SEFRD and FRM seem all based on the Point B, however the
intention in purpose statement is towards Point C... It is not clear to AESO that these proposed SEFRD and
FRM based on settled frequency deviation (Point B) are technically sufficient to address the concern of
arresting frequency deviation (Point C).
Response: The SDT recognizes that point C is the primary reliability concern. However, while Point B measurements have some data quality challenges to be
mastered, point C measurements are not practical at this time for Balancing Authorities in an Interconnection with more than one Balancing Authority. The SDT
intends to study point B and point C relationships of each Interconnection with more than one Balancing Authority to address this issue.
Independent Electricity System
Operator
No
We concur with the definitions for SEFRD, FRM and FRO but do not believe that the latter two terms (FRM
and FRO) need to be defined since they can easily be stipulated in the standard requirements. Having them
defined and added to the ever-growing NERC glossary creates unnecessary work to maintain the glossary,
unless these terms are used by other NERC standards for which consistent meaning need to be established.
For example, R1 can easily be reworded as:”R1: Each Balancing Authority shall achieve a median of all
Single Event Frequency Response Data observations reported annually on FRS Form 1 that is equal to or
more negative than its contribution obligation to the total aggregate Frequency Response needed for reliable
operation of an Interconnection assigned by the ERO.”Similar wording changes can be made to the FRS
Form 1 to eliminate the need to define these two terms.
Response: Several stakeholders indicated concerns with the definition of SEFRD and the team has removed this definition from the revised standard.
The SDT believes that the FRO and FRM definitions will be used in later revisions to the BAL group of standards and therefore is keeping the definitions in the
standard so they can be added to the approved NERC Glossary of Terms.
FirstEnergy
Yes
For the definition of FRM, we are not clear as to the rationale for choosing the median value instead of the
mean.
Response: The SDT thanks you for your affirmative response and clarifying comment.
23
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001667
Organization
Yes or No
Question 1 Comment
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
Southern Company
Yes
Comments: The Frequency Response Measure should be based on either the median or average of all
SEFR’s as currently defined. Due to the varied nature of frequency responsive resources online it should
never be based on meeting response on a single event.
Response: The SDT thanks you for your affirmative response and clarifying comment.
With regards to use of the median for calculating FRM, in general, statisticians use the median as the best measure of central tendency when
a population has outliers. Two independent reviews by the FR SDT have shown the Median to be less influenced by noise in the measurement
process.
Seattle City Light
Yes
Manitoba Hydro
Yes
ENBALA Power Networks
Yes
NIPSCO
Yes
NorthWestern Energy
Yes
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
FMPP
Yes
American Electric Power
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
24
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001668
2. The SDT has modified the definition for the term Frequency Bias Setting. The current definition and revised definition
are shown below to show the changes proposed.
Frequency Bias Setting
Current Definition in NERC Glossary: A value, usually expressed in MW/0.1 Hz, set into a Balancing Authority ACE
algorithm, that allows the Balancing Authority to contribute its frequency response to the Interconnection.
Revised Definition: A value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz, set into a
Balancing Authority Area Control Error equation that allows the Balancing Authority to contribute its Frequency
Response to the Interconnection.
Do you agree with this new definition for Frequency Bias Setting? If not, please explain in the comment area.
Summary Consideration: Many of the commenters did not agree with the new definition proposed for Frequency Bias Setting. Several
commenters recommend revising the Frequency Bias Setting definition and have offered suggestions for the SDT to consider. In response,
the SDT has revised the Frequency Bias Setting definition to better address concerns raised by industry.
The revised definition is:
Frequency Bias Setting: A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal through secondary
control systems.
Some commenters also questioned if the definition of Frequency Response also needed to be revised, however in reviewing the current
definition of Frequency Response the SDT believes that the current definition is both accurate and appropriate. Concern was also raised
regarding what constitutes variable bias. - Fixed bias is a value approved by the ERO whereas variable bias is a methodology for
determining the Frequency Bias Setting approved by the ERO.
Organization
Santee Cooper
Yes or No
No
Question 2 Comment
We suggest the following changes to the definition: A value, fixed or variable, expressed in MW/0.1 hertz, as
part of a Balancing Authority’s Area Control Error (ACE) equation that influences its Automatic Generation
Control (AGC) to provide frequency response without secondary control action withdrawing the response.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
ENBALA Power Networks
No
: ENBALA would modify the above as follows: A value, (either a fixed or variable Frequency Bias), usually
25
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001669
Organization
Yes or No
Question 2 Comment
expressed in MW/0.1 Hz, set into a Balancing Authority Area Control Error algorithm equation that allows the
Balancing Authority AGC System to ignore the export or import caused by the Primary Frequency Response.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
Westar Energy
No
We propose the following:A value, (either a fixed or variable), expressed in MW/0.1 Hz, set into a Balancing
Authority Area Control Error equation that allows the Balancing Authority to contribute its SECONDARY
Frequency Response to the Interconnection.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
EKPC
No
"Frequency Bias” should not be used in the definition."Usually" can be omitted.
Response: The SDT has modified the definition and “frequency bias” is not used in the revised definition. The definition now reads “A number, either fixed or
variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency
Response contribution to the Interconnection, and discourage response withdrawal through secondary control systems.”
LG&E and KU Energy
No
We suggest the following changes to the definition:
1. Delete the word “usually”
2. Replace “set into” with “as part of”.
3. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is part of its
frequency response usually minutes after the initial event and is dependent upon generation units being on
AGC control and capable of responding.)
4. The suggested changes would result in the following definition:A value, (either a fixed or variable
Frequency Bias), expressed in MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE)
equation that influences its Automatic Generation Control (AGC) to provide its frequency response while
Interconnection frequency is not at its scheduled value.
Response: The SDT did adopt the suggestion to remove, “set into” and replaced this phrase with, “included”, however the team did not adopt the suggestion to
26
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001670
Organization
Yes or No
Question 2 Comment
delete the word, ‘usually’ as the inclusion of this word recognizes that there may be rare instances when the Frequency Bias Setting could be expressed in other
than MW/0.1 Hz. The SDT did not adopt the third proposed change because it can cause confusion since primary Frequency Response cannot be delivered by
AGC.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.”
SERC OC Standards Review
Group
No
We suggest the following changes to the definition:
1. Delete “Frequency Bias” in the parenthetical expression - (“Frequency Bias” should not be used to define
Frequency Bias)
2. Delete the word “usually”
3. Replace “set into” with “as part of” as defined in BAL-001.
4. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is usually minutes
after the initial event and is dependent upon generation units being on AGC control and capable of
responding.)
5. The suggested changes would result in the following definition”A value, fixed or variable, expressed in
MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to continue to provide its frequency response while Interconnection
frequency is not at its scheduled value.
Response: The SDT has modified the definition and “frequency bias” is not used in the revised definition and the phase, “set into” was replaced with “included”.
The SDT did not adopt the suggestion to delete the word, ‘usually’ because there may be rare instances when the Frequency Bias Setting is expressed in other
than MW/0.1 Hz. The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in
a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and
discourage response withdrawal through secondary control systems.”
Midwest ISO Standards
Collaborators
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably
be changed to “maintain”. The goal is to ensure AGC does not withdraw frequency response and that it is
maintained while frequency is depressed. We are not sure if Frequency Response has a precise enough
definition and it is part of the definition of Frequency Bias Setting. The definition of Frequency Response
really just reflects how it is measured. It does not define what it really is which is the dynamic response of
load, generation, and other frequency responsive devices to a perturbation in frequency.
27
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001671
Organization
Yes or No
Question 2 Comment
The drafting team should also consider resolving the definition of Frequency Bias. Is it needed? It is often
confused with Frequency Bias Setting and is often used interchangeably with Frequency Response even
though the meanings are slightly different.
Response: The SDT has modified the definition of Frequency Bias Setting. The definition now reads “A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the
term “contribution” better describes the action that has taken place.
The SDT has reviewed the current definition of Frequency Response and believes that the current definition is both accurate and appropriate.
We Energies
No
Given that frequency response is “contributed” long before AGC has an impact, “contribute” should probably
be changed to “maintain.” The goal is to ensure AGC does not withdraw frequency response and that it is
maintained while frequency is depressed. We are not sure if Frequency Response has a precise enough
definition and it is part of the definition of Frequency Bias Setting. The current NERC Glossary definition of
Frequency Response really just reflects how it is measured, it does not define Frequency Response.
Frequency Response is the dynamic real power response of load, generation, and other devices to a
perturbation in frequency.
The drafting team should also consider resolving the definition of Frequency Bias. Is it needed? It is often
confused with Frequency Bias Setting and is often used interchangeably with Frequency Response even
though the meanings are slightly different.
Response: The SDT has modified the definition of Frequency Bias Setting. The definition now reads “A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the
term “contribution” better describes the action that has taken place.
The SDT has reviewed the current definition of Frequency Response and believes that the current definition is both accurate and appropriate.
SPP Standards Development
No
We would suggest inserting 'secondary' in front of Frequency Response at the end of the sentence and delete
'Frequency Bias' following 'variable' at the beginning of the sentence.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the modified definition is more appropriate than the recommended change. The
SDT does not believe it is necessary to differentiate between primary and secondary Frequency Response in the definition.
IRC Standards Review
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the
28
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001672
Organization
Yes or No
Committee
Question 2 Comment
context of these requirements? Should it be Frequency Bias Setting, instead?
“Fixed” seems to be straightforward, but what is “variable”?
How often must Frequency Bias Setting change in order to be considered to be “variable”?
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
If the ERO provides the Frequency Bias Setting then it is considered fixed. If the ERO accepts a methodology for determining the Frequency Bias Setting then it is
considered variable.
ERCOT
No
The definition appears to be accurate, but where is “fixed” and “variable” Frequency Bias defined in the
context of these requirements? Should it be Frequency Bias Setting, instead? “Fixed” seems to be
straightforward, but what is “variable”? How often must Frequency Bias Setting change in order to be
considered to be “variable”?
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
If the ERO provides the Frequency Bias Setting then it is considered fixed. If the ERO accepts a methodology for determining the Frequency Bias Setting then it is
considered variable.
Progress Energy
No
A bias, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority's Area
Control Error equation to account for the Balancing Authority's Frequency Response contribution to the
interconnection, and prevent response withdrawal through secondary control systems.
The changes suggested are to clarify that biasing of the ACE equation "allow[s]" primary frequency response
to continue beyond the initial event window by accounting for it in the ACE input to secondary control systems
(i.e. AGC). It's important to note that Primary Frequency Response will occur no matter what the Bias value is
set to in the ACE equation, and biasing "supports" the response until the frequency is restored".
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the revised definition agrees with your comment related to supporting the
response until frequency is restored. The SDT also believes that it is impossible to “prevent” withdrawal and that you can only try to discourage withdrawal.
NIPSCO
No
Frequency Bias and Frequency Response are not the same thing and that may be why "F" & "R" were not
29
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001673
Organization
Yes or No
Question 2 Comment
capitalized in the present definition.
I think the word "secondary" should appear per R2 finishing something like this: "to contribute to secondary
(non-immediate)Interconnection frequency control.", removing Frequency Response altogether.(I do
understand that you are bringing the FR and Bias closer together).
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.” The SDT believes that the modified definition is more appropriate than the recommended change. The
SDT does not believe it is necessary to differentiate between primary and secondary Frequency Response in the definition.
Energy Mark, Inc.
No
Comment 7: The definition should be:"A value, (either a fixed or variable Frequency Bias), usually expressed
in MW/0.1 Hz, set into a Balancing Authority Area Control Error equation that indicates to the Balancing
Authority its contribution of Frequency Response to the Interconnection.
Comment 8: The Frequency Bias Setting does not allow or disallow the Frequency Response to be
contributed. The BA will contribute its natural Frequency Response to the interconnection through the
independent actions of its loads and generators. The only influence that the Frequency Bias Setting has is
that it causes the AGC System, and hopefully other outer-loop control systems, to include that natural
Frequency Response when developing control actions to implement through AGC in response to BA
balancing requirements in a time frame well after the Frequency Response has been provided by the
independent actions of its loads and generators.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”
The SDT agrees with comment #8.
American Electric Power
No
If “the proposed standard’s intent is to collect data needed to accurately analyze existing Frequency
Response, set a minimum Frequency Response obligation, provide a uniform calculation of Frequency Bias
Settings that transition to values closer to Frequency Response, and encourage coordinated AGC operation”,
it appears the current and stated definition is precluding the process for determination of the Frequency Bias
Setting itself.
I believe it is too early to state in definition the frequency bias setting to be based on MW/0.1 Hz, when this
appears to be more of the expected response.
Using the word usually does not appear to be defining anything.To eventually get to an acceptable
performance measure with reliability basis the project needs to be expanded to also address associated
30
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001674
Organization
Yes or No
Question 2 Comment
governor droop issues, which inherently affect response.
When the current definition references using “either a fixed or variable Frequency Bias”, it does not state
whether or not to be applied in the calculation to either load or generation. The current Standard uses 1% of
yearly estimated peak demand for BAs that serve load, when the actual load at time of disturbance could be
greatly different. Response is more directly related to the amount of Generation on-line and active AGC within
the BA at time of trip.MW/0.1 Hz states more of expected result of response than defining Frequency Bias
Setting.
Response: The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.”The “MW/0.1 Hz” term represents the units of Frequency Bias and is not intended to reference
magnitude.
Issues dealing with governor droop are outside of the scope of the industry approved SAR.
The SDT agrees with the last comment which is why the SDT also supports using a variable bias where appropriate.
Duke Energy
No
Duke Energy would suggest not using “Frequency Bias” in the definition of “Frequency Bias Setting”.
In addition, Duke Energy would like to point out that ACE does not allow Frequency Response; response will
occur with or without the ACE equation. The Frequency Bias Setting is needed so that the AGC does not
negate what may be provided in frequency response. The bias component of ACE provides the feedback so
that a BA may sustain the intended amount of response with secondary control as long as Actual Frequency
deviates from Scheduled Frequency. Duke Energy would suggest the following:”A fixed or variable value
usually expressed in MW/0.1 Hz, set into a Balancing Authority Area Control Error equation to bias the control
of resources so that Interconnection frequency is driven toward the Scheduled Frequency.”
Response: The term Frequency Bias has been removed from the definition.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.”
Associated Electric Cooperative,
Inc.
No
SEFRD - I had to read this definition several times because “The individual sample of event data” is actually
an internally calculated value derived from a set of event sample data, and not really a “sample” value at all.
So, I believe the SEFRD definition needs further work.
Response: The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
31
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001675
Organization
Yes or No
MRO's NERC Standards Review
Subcommittee
No
Southern Company
Yes
Question 2 Comment
Frequency Bias SettingA value, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1 Hz,
set into a Balancing Authority Area Control Error algorithm equation that allows the Balancing Authority to
contribute its frequency Frequency rResponse to the Interconnection.
Comments: Not sure the word “allows” is the right word. Perhaps use something in terms of preventing
withdrawal of Primary Frequency Response with words like “...equation that prevents the withdrawal of the
Balancing Authority’s Primary Frequency Response to the Interconnection.”
Response: The SDT thanks you for your affirmative response and clarifying comments. The revised definition does not use the word, “allows.”
The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to
account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal through secondary control
systems.”
FirstEnergy
Yes
Although we support the definition, we suggest the word “contribute” be changed to “maintain”.
Response: The SDT thanks you for your affirmative response and clarifying comments.
The SDT has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response
withdrawal through secondary control systems.” The SDT believes that based on the modified definition, the use of the term “contribution” better describes the
action that has taken place.
Patterson Consulting, Inc.
Yes
Beacon Power Corporation
Yes
NorthWestern Energy
Yes
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
Bonneville Power Administration
Yes
32
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001676
Organization
Yes or No
Alberta Electric System Operator
Yes
Independent Electricity System
Operator
Yes
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
South Carolina Electric and Gas
Question 2 Comment
We suggest the following changes to the definition: 1. Delete “Frequency Bias” in the parenthetical expression
- (“Frequency Bias” should not be used to define Frequency Bias)
2. Delete the word “usually”
3. Replace “set into” with “as part of” as defined in BAL-001.
4. Replace the remainder of the sentence following “Area Control Error equation” with “that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value” - (The frequency bias does not allow a BA to contribute its frequency response to the
Interconnection. The frequency bias term only affects the AGC response of the BA, which is part of its
frequency response usually minutes after the initial event and is dependent upon generation units being on
AGC control and capable of responding.)
5. The suggested changes would result in the following definition”A value, fixed or variable, expressed in
MW/0.1 hertz as part of a Balancing Authority’s Area Control Error (ACE) equation that influences its
Automatic Generation Control (AGC) to provide its frequency response while Interconnection frequency is not
at its scheduled value.
Response: The term, “Frequency Bias” was deleted, the phrase, “set into” was replaced with, “included in”. The other suggestions were not adopted. The SDT
has modified the definition. The definition now reads “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s
Area Control Error equation to account for the Balancing Authority’s Frequency Response contribution to the Interconnection, and discourage response withdrawal
through secondary control systems.” The SDT believes that the modified definition addresses your concerns but provides for additional clarity as to the action
that has taken place.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
33
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001677
Organization
Yes or No
Question 2 Comment
Response: Please refer to the SDT response to Question 17.
34
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001678
3. The proposed purpose statement in the draft standard is: To require sufficient Frequency Response from the Balancing
Authority to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and
supporting frequency until the frequency is restored to schedule. To provide consistent methods for measuring Frequency
Response and determining the Frequency Bias Setting.
Do you agree with this purpose? If not, please explain in the comment area.
Summary Consideration: Several of the commenters agree with the purpose statement of the draft standard as written. Most of the
feedback received disagreeing with the purpose statement reflects general comments and suggestions for the SDT to consider. A major
concern identified is that the minimum level of Frequency Bias Setting established needs to be determined based on extensive data
analysis of field trial results. Some commenters even stated that the standard should not be revised until the field trial is completed,
performance criteria and measures determined, and results vetted by industry. Several commenters expressed concern with making the
Balancing Authority the only entity responsible for maintaining interconnection frequency and arresting frequency decline; with an
observation that the purpose statement presumes that each Balancing Authority must have generation online to meet a predetermined
frequency response obligation. It was pointed out that on occasion small Balancing Authorities may not have generation online and instead
rely on load regulation and energy agreements to meet their energy needs. Another commenter indicated that since NERC and FERC have
differentiated Frequency Response from Frequency Regulation, the standard should only apply to unplanned contingencies that occur.
In response to these general comments the SDT notes that the minimum Frequency Response level used during the field trial uses a
deterministic approach and the actual level of Frequency Response required in the final version of the draft standard will be based on field
trial results. Issues involving governor droop, dead-band settings, and governor operation are outside the scope of the project’s approved
SAR. The purpose statement does not mandate generation dispatch for Frequency Response. This standard only prescribes a minimum
Frequency Response obligation for reliable BES operation. Each entity must determine how to meet its Frequency Response obligation
using existing resources and agreements.
Another commenter noted that the purpose statement addresses several concepts that do not share a common timeframe. In response,
the SDT has revised Attachment A to explain the relationship for the different time frames associated with these concepts.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 3 Comment
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012
35
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001679
Organization
Yes or No
Question 3 Comment
Modifications to this schedule require both NERC and FERC approval.
Midwest ISO Standards
Collaborators
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
We Energies
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum Frequency
Response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis, field trial data, the Frequency Response
Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical conference,
and the plan outlined in NERC’s October 25, 2010 compliance filing.
Response: The SDT thanks you for your comment. For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of
response required may be established in the final version of the standard using field trial information obtained.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
LG&E and KU Energy
No
The proposed purpose statement as provided in this question is not the same as the purpose statement for
BAL-003-1 as posted on the Project 2007-12 page of the NERC website. The posted purpose on the NERC
website is:To require sufficient Frequency Response from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the
frequency is restored. To schedule and provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.The version posted in the question appears to correct errors in the
last sentence of the purpose statement given in the project page.
We do not agree with the purpose statement as posted on the project page.In addition, we suggest the
following edits to what appears to be a corrected purpose statement as provided in this question:To require
sufficient Frequency Response from the Balancing Authority to maintain Interconnection Frequency within
predefined bounds by arresting frequency deviations due to contingencies on the interconnected BES and
supporting frequency until the frequency is restored to schedule. To provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting.
As NERC/FERC has differentiated Frequency Response from Frequency Regulation, the standards
36
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001680
Organization
Yes or No
Question 3 Comment
addressing Frequency Response should clearly be related to unplanned contingencies occurring on the
interconnected BES.
Response: The SDT believes adequate Frequency Response is important during both normal and emergency operations however it is easier to measure
Frequency Response during a contingency which is why the SDT favors this rationale.
IRC Standards Review
Committee
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. We request that the results of the Field Trial should be published and
discussed BEFORE any changes are made. The standard should be put into place later; it is premature at
this time. Since this is to be a data gathering process to be used to determine appropriate performance
parameters, the purpose statement of the Field Trial should be changed to read as follows:To determine
require sufficient Frequency Response arranged by from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by responding to and arresting frequency deviations and supporting
frequency until the frequency is restored to schedule. To identify and establish provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting and Frequency Response
Obligation.We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon
Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
37
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001681
Organization
Yes or No
Question 3 Comment
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
ISO New Engand Inc.
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. The standard should be put into place later; it is premature at this time.
Since this is to be a data gathering process to be used to determine appropriate performance parameters, the
purpose statement of the Field Trial should be changed to read as follows:To determinerequire sufficient
Frequency Response arranged by from the Balancing Authority to maintain Interconnection Frequency within
predefined bounds by responding to and arresting frequency deviations and supporting frequency until the
frequency is restored to schedule. To identify and establishprovide consistent methods for measuring
Frequency Response and determining the Frequency Bias Setting and Frequency Response Obligation.We
should not write the new standard and its requirements until this Field Trial work has been accomplished; to
do so possibly would result in difficulty changing the standard requirements based upon Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
38
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001682
Organization
Yes or No
Question 3 Comment
Modifications to this schedule require both NERC and FERC approval.
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
ERCOT
No
If this is really intended to be a Field Trial, it should be written as such and the standard should not be
developed or promulgated until the Field Trial has accomplished its purpose and the performance criteria and
measures have been determined. We request that the results of the Field Trial should be published and
discussed BEFORE any changes are made. The standard should be put into place later; it is premature at
this time. Since this is to be a data gathering process to be used to determine appropriate performance
parameters, the purpose statement of the Field Trial should be changed to read as follows:To determine
require sufficient Frequency Response arranged by from the Balancing Authority to maintain Interconnection
Frequency within predefined bounds by responding to and arresting frequency deviations and supporting
frequency until the frequency is restored to schedule. To identify and establish provide consistent methods for
measuring Frequency Response and determining the Frequency Bias Setting and Frequency Response
Obligation.We should not write the new standard and its requirements until this Field Trial work has been
accomplished; to do so possibly would result in difficulty changing the standard requirements based upon
Field Trial results.
Further, while we do not have any issue with the general intent of the scope statement, we have a difficulty
seeing the BA being the only entity held responsible for maintaining interconnection frequency and arresting
frequency deviations. When there is a sudden and sizable change to system resource or demand, the first
response to a frequency deviation caused by this change would be the generators’ governors. This will
provide a mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick
in to supplement the mitigation need. The governors are owned by the Generator Owners; the BAs do not
own these facilities and hence can do little to address frequency response during this initial period.To hold
only the BA responsible for maintaining interconnection frequency and arresting frequency deviations would
be inappropriate. The industry needs to have a discussion to determine who should be held responsible for
providing governor responses immediately following an event, and by what mechanism, and for implementing
additional measures thereafter. We suggest that BAL-003 development be withheld until this discussion takes
place and a decision is made on who and how the governor response shall be provided.
Response: The original SAR was for data collection. The SDT developed a supplemental SAR to address the FERC directives.
The project schedule adopted for the development of the BAL-003 standard has been approved by the FERC and includes filing a standard by May, 2012.
Modifications to this schedule require both NERC and FERC approval.
39
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001683
Organization
Yes or No
Question 3 Comment
The purpose of the standard is to establish a minimum Frequency Response threshold that prevents unreliable BES operation.
This issue concerning the BA being the only entity being held responsible has been discussed and the SDT understands your concern. However, governor droop
requirements, dead-band settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification
standards will help address these concerns. The SDT encourages entities to develop a SAR to address generators.
Kansas City Power & Light
No
This purpose statement presumes that each Balancing Authority (BA) will have generation online to meet a
predetermined frequency response obligation. There are many small BA’s that do not have any generation
online and rely on load regulation agreements and energy agreements to provide their energy needs during
parts of the year. This purpose statement would not allow a BA to operate without generation online.
Response: The purpose statement does not mandate generation dispatch for Frequency Response. This standard only prescribes a minimum Frequency
Response obligation for reliable BES operations. Each entity must determine how to meet this obligation using existing resources and agreements.
NIPSCO
No
Yes, "Interconnection frequency", small "f".
Response: The SDT thanks you for this comment and has corrected the error.
American Electric Power
No
AEP believes the statement should read “To require sufficient Frequency Response from governors and AGC
of Generators within the Balancing Authority to maintain Interconnection Frequency within predefined bounds
by arresting frequency deviations and supporting frequency until the frequency is restored to schedule.To
provide consistent methods for measuring Frequency Response from governors and AGC of Generators
within the Balancing Authority for determining the overall Frequency Bias Setting threshold.Since
Generators are directly responsible for response, applicability must be added to Generator Operators.
Response: The drafting team disagrees with this recommendation because the FERC Order 693 requires a technology neutral performance standard for the purpose
of providing Frequency Response.
Patterson Consulting, Inc.
No
The purpose should not expect Frequency Response to maintain frequency beyond a few minutes, perhaps
15 minutes for example. This purpose statement suggests the requirements will be "...to maintain
Interconnection Frequency within predefined bounds by arresting frequency deviations and support frequency
until the frequency is restored to schedule..." The phrase "until the frequency is restored to schedule" is
problematic since regulation must bring frequency to schedule. Frequency Response, and the associated
requirements, should not be expected to substitute for poor regulation beyond the first few minutes.
Response: The focus of the standard is to establish sustainable primary frequency control which can seamlessly coordinate with secondary frequency control for
maintaining system frequency.
40
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001684
Organization
Independent Electricity System
Operator
Yes or No
Question 3 Comment
No
We do not have any issue with the general intent of the scope statement, but have a difficulty in seeing the
BA being the only entity held responsible for maintaining interconnection frequency and arresting frequency
deviations. When there is a sudden and sizable change to system resource or demand, the system frequency
will change. The first response to such deviation would be the generators’ governors. This will provide a
mitigating effect for the immediate seconds up to minutes. The frequency bias setting will then kick in to
supplement the mitigation need. To hold only the BA responsible for maintaining interconnection frequency
arresting frequency deviations would be only part of the solution. The industry needs to have a discussion to
determine who should be held responsible for providing governor responses, and by what mechanism.
We suggest that BAL-003 development be withheld until this discussion takes place and a decision is made
on who and how the governor response shall be provided.
Response: The SDT thanks you for your comment. This issue concerning the BA being the only entity being held responsible has been discussed and the SDT
understands your concern. However, governor droop requirements, dead-band settings and governor operation are outside the scope of the project approved
SAR. The SDT believes that the Generator Verification standards will help address these concerns. The SDT encourages entities to develop a SAR to address
generators.
For the field trial, the minimum level of response needed uses a deterministic approach. The actual level of response required may be established in the final
version of the standard using field trial information obtained.
The SDT does not agree with your comment concerning withholding the development of a standard addressing Frequency Response. The development of a
standard addressing Frequency Response was identified in FERC Order 693. FERC further directed the ERO to finalize a standard addressing Frequency Response
in an order in February 2010 within six (6) months which they later granted an extension. The project schedule adopted for the development of the BAL-003
standard has been approved by the FERC and includes filing a standard by May, 2012. Modifications to this schedule would require both NERC and FERC
approval.
ENBALA Power Networks
Yes
ENBALA strongly agrees that a Frequency Response standard is necessary to ensure reliable operation of
the bulk power system. We fully support all efforts to understand the declining trend, and the development of
accurate models, of Frequency Response in each Interconnection.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Manitoba Hydro
Yes
The new more likely improved method of measuring Frequency Response is welcome. This should be an
improvement over the existing methods of using 1% of projected peak load, or average of DCS events.
Calculating projected peaks leave lots of room for error and limiting calculations to only DCS events likely
does not reflect accurate BIAS.
41
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001685
Organization
Yes or No
Question 3 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Alberta Electric System Operator
Yes
The purpose statement mentioned arresting deviation, restored to schedule and frequency bias setting,
which are all at different time frames. The AESO suggests that NERC provide some clarification of the
relationships for the different time frames.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Refer to Attachment A for clarification of the relationships for the different time frames.
Duke Energy
Yes
Seattle City Light
Yes
Santee Cooper
Yes
FirstEnergy
Yes
Bonneville Power Administration
Yes
SPP Standards Development
Yes
SERC OC Standards Review
Group
Yes
Arizona Public Service Company
Yes
Southern Company
Yes
Progress Energy
Yes
NorthWestern Energy
Yes
Energy Mark, Inc.
Yes
Beacon Power Corporation
Yes
42
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001686
Organization
Yes or No
Westar Energy
Yes
FMPP
Yes
EKPC
Yes
South Carolina Electric and Gas
Yes
Associated Electric Cooperative,
Inc.
Yes
Northeast Power Coordinating
Council
Question 3 Comment
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
43
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001687
4. Requirement 1 identifies a minimum level of Frequency Response.
R1. Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO).
Do you agree with the concept that a Balancing Authority should be required to achieve a minimum level of Frequency
Response and the method for measurement? If not, please explain in the comment area.
Summary Consideration: Most commenters supported the concept however a significant majority did not agree with the method for
measurement. In general commenters indicated the sample size of 25 events for determining FRM is too small; insufficient information
was provided to address the use of variable bias; the FRM and FRO definitions were unclear with questionable determination methods; and
the standard should reference Reserve Sharing Groups. Some commenters also indicated that the measure may not apply to a single BA
interconnection; that the draft standard dictated how compliance is provided with respect to Attachment A and FRS Form 1 references;
that requirements would not allow a BA to operate without generation online; and expressed concern that the BA may not own and operate
resources yet will still have the compliance obligation.
The SDT is currently evaluating a probabilistic method for determining the FRO. After consideration of industry comments, the SDT
converted Attachment A into two documents - a calculation methodology included with the standard, and a separate supporting document
providing requirement rationale. The SDT revised the definitions for FRO & FRM; incorporated Reserve Sharing Groups into the draft
standard; modified FRS Form 1 to allow for adjustments; and clarified how an entity is to show compliance. The SDT also provided an
explanation addressing the use of Variable Bias and provided an administrative procedure for the ERO’s FRO determination.
R1. Each Balancing Authority or Reserve Sharing Group (RSG) shall achieve an annual Frequency Response Measure (FRM) (as detailed in Attachment
A and calculated on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each BA or RSG to maintain an adequate level of Frequency Response in the Interconnection.
Organization
Santee Cooper
Yes or No
No
Question 4 Comment
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
LG&E and KU Energy
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
44
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001688
Organization
Yes or No
Question 4 Comment
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
SERC OC Standards Review
Group
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
South Carolina Electric and Gas
No
The concept seems reasonable but since the measure of compliance (FRM) is determined only after the 25
events are identified; it is a lagging indicator. The BA may have to ensure it measures all frequency
excursions and develops its own leading indicator to ensure compliance following year end.
A sample CPS bounds report should be considered, perhaps based on 2010 numbers, to demonstrate how
FRM submitted would translate to FRO frequency bias settings and how it will affect the L10 values.
Response: The SDT agrees that the measure is a lagging indicator and recommends that the list of reportable events be posted on a quarterly basis.
The SDT will provide samples to illustrate the interaction of FRO, FRM, and frequency bias settings at the conclusion of the field trial.
MRO's NERC Standards Review
Subcommittee
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outline in NERC’s October 25, 2010 compliance filing.
The effects of the nonconforming load should be considered in the calculation of the frequency response
obligation in order to get accurate results.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
45
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001689
Organization
Yes or No
Question 4 Comment
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the project
schedule will require both NERC and FERC approval.
The deterministic allocation method does not consider the effects of nonconforming load.
Midwest ISO Standards
Collaborators
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis based on the field trial, based on the Frequency
Response Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical
conference and based on the plan outline in NERC’s October 25, 2010 compliance filing.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the project
schedule will require both NERC and FERC approval.
We Energies
No
In general, we don’t have significant issues with a standard that attempts to establish a minimum frequency
response performance level. However, we caution the drafting team that the minimum level established
needs to be determined based on an extensive data analysis, field trial data, the Frequency Response
Initiative Work Plan that NERC filed in response to the Commission’s September 23 technical conference,
and the plan outline in NERC’s October 25, 2010 compliance filing.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial.
The SDT is using a FERC approved project schedule to develop the BAL-003 standard and includes filing a standard by May, 2012.. Any modification to the
project schedule will require both NERC and FERC approval.
Bonneville Power Administration
No
BPA agrees that there should be a minimum level of Frequency Response, but disagree with the way the
measure is obtained in the requirement.
o R1 - BPA suggests replacing “achieve” with “calculate”. Achieve: indicates it is a performance.
o R1 - BPA does not agree with the requirements in Attachment A not being in the standard. These should
not be modified without full review and voting by members.
o R1 - BPA believes that there should be more description on Variable Bias. What variable bias number
should we use: average, minimum, peak for the event? BPA feels that the peak bias of each event would be
appropriate.
Response: The SDT believes the intent of the standard is for each BA to “achieve” its Frequency Response Obligation.
46
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001690
Organization
Yes or No
Question 4 Comment
The SDT is not incorporating additional standard requirements by means of Attachment A information however the SDT recognizes the need to convert
Attachment A into two documents. The first document will remain part of the standard as Attachment A and describe the calculation methodology utilized. The
second document will explain the rationale for the requirements as supplemental standard information.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT agrees Variable Bias
requires more description and will review this concern during the field trial.
IRC Standards Review
Committee
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be
achieved. However, the measure as described does not apply to all Interconnections. It does not apply to
single BA Interconnections such as ERCOT and Hydro Quebec.
This requirement should be added later-not included now; and it should clarify what the BA must do and what
the response providers must do. BAs do not own and operate the resources. An entity which does own or
operate the resources may also be registered as a BA, but an entity which does not own or operate resources
may also be registered as a BA. Therefore, it is important to detail what a BA must do and also to detail what
the resource owner or operator must do. The resource owner may be registered as a GO or a TO or even a
DP. The resource operator may be registered as a GOP, a TOP, or a LSE. The BA must establish an
operations plan, using data provided to it by the resource owners and or operators, that will meet the
performance requirements. The BA must then deploy the proper amount of response through AGC or verbal
instructions to supplement the automatic responses that the resources will provide, must calculate the actual
responses after-the-fact, and report the performance as required. The resources must, as standards already
provide, comply with the deployments and instructions provided by the BA. However, if an entity which is
functioning as a BA does not own its resources, nor does it directly operate those resources, the BA cannot
ensure the achievement. The standard must not create an organizational or contractual arrangement that
dictates how the compliance is provided. It should state what must be done, not how. If entities choose to
write and enter into such arrangements, that should be permissible, but not required.
Specific to R1, the wording does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not
seem to correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
Response: This standard is intended to apply to all Interconnections. The SDT has modified the definition for FRO to read, “The Balancing Authority’s share of
the required Frequency Response needed for the reliable operation of an Interconnection.”
The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must determine how to
meet this minimum obligation.
FRS Form 1 has been revised to allow for adjustments.
ERCOT
No
The SRC agrees that a Frequency Response of some minimum level for each Interconnection should be
achieved. However, the measure as described does not apply to all Interconnections. It does not apply to
47
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001691
Organization
Yes or No
Question 4 Comment
single BA Interconnections such as ERCOT and Hydro Quebec. This requirement should be added later-not
included now; and it should clarify what the BA must do and what the response providers must do. BAs do
not own and operate the resources. An entity which does own or operate the resources may also be
registered as a BA, but an entity which does not own or operate resources may also be registered as a BA.
Therefore, it is important to detail what a BA must do and also to detail what the resource owner or operator
must do. The resource owner may be registered as a GO or a TO or even a DP. The resource operator may
be registered as a GOP, a TOP, or a LSE. The BA must establish an operations plan, using data provided to
it by the resource owners and or operators, that will meet the performance requirements. The BA must then
deploy the proper amount of response through AGC or verbal instructions to supplement the automatic
responses that the resources will provide, must calculate the actual responses after-the-fact, and report the
performance as required. The resources must, as standards already provide, comply with the deployments
and instructions provided by the BA. However, if an entity which is functioning as a BA does not own its
resources, nor does it directly operate those resources, the BA cannot ensure the achievement. The
standard must not create an organizational or contractual arrangement that dictates how the compliance is
provided. It should state what must be done, not how. If entities choose to write and enter into such
arrangements, that should be permissible, but not required. Specific to R1, the wording does not correspond
to the figures shown in the FRS (Form 1) in that the FRM (the median) is -14.5 whereas the FRO is -15.8. The
FRO is more negative than the FRM, which does not seem to correspond to what’s stipulated in R1 (FRM to
be equal or more negative than its FRO).
Response: This standard is intended to apply to all Interconnections. The SDT has modified the definition for FRO to read, “The Balancing Authority’s share of
the required Frequency Response needed for the reliable operation of an Interconnection.”
The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must determine how to
meet this minimum obligation.
FRS Form 1 has been revised to allow for adjustments.
Kansas City Power & Light
No
This requirement presumes that each Balancing Authority (BA) will have generation online to meet a
predetermined frequency response obligation. There are many small BA’s that do not have any generation
online and rely on load regulation agreements and energy agreements to provide their energy needs during
parts of the year. This requirement would not allow a BA to operate without generation online.
Under Requirement 1, item 2a in Attachment A suggests governor deadband as 36MHz (Megahertz).
Suggest what is intended is 36mHz (millihertz).
The Frequency Response Obligation determination for the interconnection as described in Attachment A is a
crude method and will result in obligations that will exceed the FRO that is intended. This will result in
additional cost to BA’s that is unnecessary to achieve the purpose of maintaining sufficient generation online
to arrest frequency degradation events caused by loss of generating resources.
48
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001692
Organization
Yes or No
Question 4 Comment
The current NERC method for calculating a BA’s actual frequency response are inaccurate and provide
misleading guidance in the actual frequency response of a BA. These methods need considerable
improvement before any attempts to hold a BA to an expected level of frequency response as this proposal
has stated.
Response: The standard does not dictate a particular generation dispatch strategy. The standard only prescribes a minimum obligation. The entity must
determine how to meet this minimum obligation.
The SDT has removed the reference to governor deadband.
The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of the draft
standard may be based on analysis of data obtained from the field trial. The SDT is also evaluating a probabilistic method for determining the FRO.
The SDT has modified FRS Form 1 to correctly calculate Frequency Response.
Southern Company
No
Comments: Proposed Standard
Comment 1: BAL-003-1, Requirement R1. The requirement should be made less prescriptive by removing
references to Attachment A and FRS Form 1. The responsible entity should understand the fundamental and
basic requirement - to achieve a Frequency Response Measure. Where the methodology is specified or how
the BA is supposed to achieve it should be a matter of compliance and/or implementation and not a part of
the basic requirement. Proposed language is as follows: Each Balancing Authority shall achieve a Frequency
Response Measure (FRM) that is equal to or more negative than its Frequency Response Obligation (FRO).
Response: The SDT believes that Requirement 1 needs to reference FRS Form 1 in order for the calculation methodology to be consistent for all interconnections
and has removed the reference to Attachment A. The SDT has also revised FRS Form 1 to correctly calculate Frequency Response and to allow for adjustments.
Progress Energy
No
Progress Energy believes the Eastern Interconnection does not have the same issues with frequency
experienced in the other two interconnections, and that load response is significant enough in the
interconnection to arrest and stabilize frequency as long as BAs do not withdraw that effect (accurate biasing
of the ACE equation).
We also believe this standard should reference standrd PRC-024 related to accurate relay settings to allow
out of bounds operations related to frequency and voltage deviations.
Response: Under certain system conditions the response of frequency sensitive load to a frequency excursion may be sufficient to arrest and stabilize frequency
following an event. The eastern interconnection may also demonstrate greater stability as compared to the other interconnections. However, frequency stability
is not assured to be achieved in this manner for all system conditions, even for the eastern interconnection irrespective of Frequency Bias setting accuracy.
The intent of BAL-003 is independent of PRC-024 intent. Specifically the purpose of BAL-003 is to better match a Balancing Authority’s Frequency Bias Setting to
its Frequency Response Characteristic, which should also reduce the probability for UFLS activation. The purpose of PRC-024 is to ensure generation remains
49
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001693
Organization
Yes or No
Question 4 Comment
connected during a tolerable frequency or voltage excursion. Furthermore, consideration of voltage deviations is outside the scope of the approved project.
NIPSCO
No
Yes and no, similar to BAL-002 I think this should read "Each Balancing Authority or Reserve Sharing Group
shall ....., With so many BA's I believe the RSGs will be play a big role in this compliance ... This comment
applies to only R1,
Response: The SDT has revised Requirement R1 to reference Reserve Sharing Groups.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The SDT agrees that compliance should not be based on an individual event but based on a series of events.
Energy Mark, Inc.
No
Comment 9: I agree that each BA should be required to provide a minimum level of Frequency Response to
provide for its share of the total Frequency Response required for interconnection reliability.
Comment 10: I also agree with the methods used to measure SEFRD subject to my comments on FRS Form
1.
Comment 11: I do not agree that the method suggested for setting the FRO will achieve the desired goal of
maintaining interconnection reliability. The measurement method offered only evaluates the supply of
Frequency Response. It does not evaluate the demand (need) for Frequency Response. Since frequency
error is the difference between the demand and supply any effective measure for maintaining reliability due to
frequency error must include both the demand and supply parts of this balance. As a consequence, the
method will be blind to changes (good or bad) in the demand for Frequency Response. Changes in the
demand for Frequency Response will require subsequent changes in the supply for Frequency Response that
this standard fails to address until the following year and leaves the interconnection at risk for unreliable
operation.
Comment 12: The requirements associated with Frequency Response as defined in this standard will not
assure interconnection reliability. Frequency Response is a two part service. The first part of this service is
the rate at which energy is supplied in proportion to frequency error. This first part is commonly represented
as the Frequency Response and the corresponding Frequency Bias Setting. The second part of the service
is the amount of capacity that the BA stands ready to supply at this stated proportion in response to frequency
error. Failure to effectively specify and measure the amount of capacity that the BA stands ready to supply at
the stated proportion could put the interconnection at reliability risk when the required amount of capacity is
50
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001694
Organization
Yes or No
Question 4 Comment
not included in the operating plan.
Response: Comment 11 - The FRO provides a target for ensuring robust frequency response is achieved by all Balancing Authorities. Both FRO and FRM values
are considered by the algorithm determining the Frequency Bias Setting for the next year. While there is mutual dependence between supply and demand with
respect to frequency response, the resultant frequency deviation is more important than the cause as it is the effect on system operations realized that
determines the magnitude of control response required for reliability. It is expected robust frequency control will yield smaller frequency deviations during events
and in turn require less incremental control response than currently realized for maintaining frequency.
Comment 12 – Capacity is an important yet independent consideration. First, responsive robust control is necessary. Next, the Frequency Bias Setting must
better approximate the Frequency Response Characteristic for improved control response. Adequate capacity is an implicit assumption for reliable grid operation.
Hydro-Quebec TransEnergie
No
The proposed method is good to measure frequency response at point “B”. However, point “C” is not taken in
consideration in this measure.
As for the FRO, a N-2 criteria is more stringent for an Interconnection with less units than a large
Interconnection. The risk associated with coincidental events is much higher in a large Interconnection. For
this reason, we believe that N-1 criteria should be considered for a small Interconnection like Quebec.
Response: The SDT agrees that the size of an Interconnection can make a difference in Frequency Response. This standard is intended to apply to all
Interconnections. The SDT has modified the definition for FRO. The definition now reads “The Balancing Authority’s share of the required Frequency Response
needed for the reliable operation of an Interconnection.” A smaller Interconnection can and should request a variance if needed.
Westar Energy
No
The lagging measure is a concern. The ERO should be required to provide an updated proposed/possible list
of frequency events monthly so BA's can determine their FRM through out the year so corrective action can
be taken if needed.Prior year events should be excluded (just to get to 25 events). This could result in begin
non-compliant twice for the same events.
Response: The SDT recommends posting selected events quarterly to give BAs time to evaluate their compliance. The SDT has evaluated the method for
assessing compliance and has determined compliance is best demonstrated on a quarterly basis using a rolling 12 months data period.
FMPP
No
The proposed Requirement 1 states: Each Balancing Authority shall achieve a Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative than its
Frequency Response Obligation (FRO).Attachment A states that if a year occurs in which there are not 25
events that meet the remaining criteria below, then the most recent 25 events (as defined below) will be used
for determination of an entity’s compliance with the FRM requirement and storage of SEFRD.
Problem - by using events from last year to determine an entity’s compliance with a Requirement for this year
puts the entity in double jeopardy for last year’s events, which were already used for compliance for last year.
51
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001695
Organization
Yes or No
Question 4 Comment
Response: The SDT recommends posting selected events quarterly to give BAs time to evaluate their compliance. The SDT has evaluated the method for
assessing compliance and has determined compliance is best demonstrated on a quarterly basis using a rolling 12 months data period.
EKPC
No
The method for measurement is not detailed.
Also, the method indicates a lagging indicator. Hows is the BA to ensure its compliance through the year?
Response: FRS Form 1 now details the measurement method.
An entity can use the Criteria for Selecting Events to confirm compliance during the year. The SDT recommends posting selected events quarterly to give BAs
time to evaluate their compliance.
ISO New Engand Inc.
No
We have a difficulty seeing the BA being the only entity held responsible for maintaining interconnection
frequency and arresting frequency deviations. When there is a sudden and sizable change to system
resource or demand, the first response to a frequency deviation caused by this change would be the
generators’ governors. This will provide a mitigating effect for the immediate seconds up to minutes. The
frequency bias setting will then kick in to supplement the mitigation need. The governors are owned by the
Generator Owners; the BAs do not own these facilities and hence can do little to address frequency response
during this initial period.
Response: While the SDT has described possible methods for obtaining Frequency Response compliance with this standard, the SDT is not prescribing a
particular method for entities to implement. Governor operation is outside the scope of the approved project SAR. Any entity may submit a SAR request to
modify or create a standard.
American Electric Power
No
Between the definition and the requirement in Attachment A, it is unclear if FRM is a reliability-supported,
performance-based measure, or instead, if it is a calculated number based on previous performance. As
written, it is unclear if this is a performance-based requirement, or simply a calculation that should be utilized
in some way. In any event, the requirement needs to be re-written to clarify its intent.
Response: The SDT has modified the definition of FRM to read “The median of all the Frequency Response observations reported annually on FRS Form 1.”
Duke Energy
No
Duke Energy agrees that a BA should be required to achieve a minimum level of Frequency Response,
however Duke Energy believes the method for measurement needs improvement - please see comments to 1
and 2 above.Duke Energy agrees with the concept that a Balancing Authority should be required to achieve a
minimum level of Frequency Response however the method for measurement should also allow exclusion of
certain events, such as when the frequency deviation is associated with the BA’s contingent loss of
generation, or when an event is coincident with a significant change in ramped interchange.
It is not clear how the FRO will be determined - Duke Energy believes that the industry should agree on the
methodology which would be used for the ERO to determine the response desired for the Interconnection and
52
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001696
Organization
Yes or No
Question 4 Comment
how the allocation for the FRO would be determined for each Balancing Authority.
The calculation of FRO allocation (in Attachment 1) is not clear on whether the peak load and generation data
used is historic data or forecasted data.
It is also not clear how the assignment of the FRO would accommodate a mid-year change in Balancing
Authority size or other attribute that could change the calculated response.
Duke Energy questions if a BA providing better response than its allocated FRO in any year should be held to
achieving that in the following year - Duke Energy believes that should be the decision of the BA if it chooses
to achieve more than the minimum requirement applied to others.
Response: The FRS Form 1 has been modified to allow for adjustments (not exclusions) to the load and generation.
The Industry will agree on the methodology for determining the FRO by submitting approval ballots on the standard.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and describe the
calculation methodology utilized. The second document will explain the rationale for the requirements as supplemental standard information.
The FR SDT agrees that mid-year changes need to be addressed and will review this issue during the field trial.
A BA’s FRO is not based on the previous year’s compliance. FRO is determined using the methodology described in Attachment A.
Patterson Consulting, Inc.
No
Requiring a Balancing Authority to provide Frequency Response and measuring that Frequency Response
consistently, is critical to maintaining reliability. The requirement is long overdue and the concept is a good
one. The method for measurement in FRS Form 1 is not consistent with the definition of FRM.
The desired "averaging" of input data over specific time ranges by the Balancing Authority as it completes
FRS Form 1 appears only in the background and instructions for FRS Form 1. Since this "instruction"
document will not be a part of the standard, it is not obvious that Balancing Authority's will be compelled to
provide consistent data. Therefore, the standard will fail to achieve the stated purpose of providing
"...consistent methods for measuring Frequency Response...".
Attachment A, other than the section providing guidance regarding event selection, appears to be
explanatory, contextual, and instructional in content. These aspects are important, but should not be
requirements. Attachment A should include only the event selection process and calculations associated with
requirements, including an explanation of what is necessary if variable Frequency Bias Settings are
implemented. If other "requirements" are included in Attachment A, they should be moved to the standard.
FRS Form 1 should be an attachment to the standard as this form contains and performs the required
calculations. The remaining information in Attachment A should become either a standalone (technical)
document, or be combined with information such as "FRS Form 1 Background and Instructions" and
renamed. As further clarification regarding the ambiguity identified in the previous paragraph, Attachment A
53
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001697
Organization
Yes or No
Question 4 Comment
could be interpreted as additional requirements on the Balancing Authority, ERO, or both. The language and
scope is not sufficiently clear to identify whether statements are informative or requirements. This lack of
clarity makes it impossible for entities to identify requirements, acquire appropriate tools and resources
related to requirements, and to provide suitable performance to meet requirements. For example, the
statement "A final listing of official events to be used in the calculation will be available from NERC by
December 10 each year." may be intended as a requirement rather than a statement suggesting a typical
schedule. Further, if the previous statement is a typical schedule, then the statement "The ERO will use the
following criteria for the selection of events to be analyzed." could be interpreted as merely the typical process
to be used, but not a binding one.
Response: The SDT has modified FRS Form 1 to allow for adjustments.
The SDT has modified the Attachment A documentation to clarify the calculation methodology.
The SDT has modified the Requirements and added measures to clarify how an entity is to show compliance.
Alberta Electric System Operator
Yes
The AESO agrees that there should be certain minimum requirement(s) of Frequency Response. In
Attachment A, it mentioned that it will be based on the protection criteria and Point C, and the FRM is
determined based on the settled deviation. The AESO suggests that the SDT describe how the FRM be
related with the FRO as they are determined by different time frames. The AESO suggests NERC investigate
the measure and method of separate FRM / FRO for different time frames, or provide technical evidence that
the proposed FRM / FRO can also address the technical concerns in different time frames.
Response: The FRO is a determined value providing a target for ensuring robust frequency response is achieved by all Balancing Authorities. The FRM is the
medium value of observations for the time period. The intent is for FRM to always be equal or more negative than the FRO, signifying robust control resulting in
proper frequency response. As such, the determination timeframes does not have to be the same for each value.
Independent Electricity System
Operator
Yes
We agree with the BA being one of the responsible entities to achieve a minimum level of FR, and the method
of measurement. However, R1 does not correspond to the figures shown in the FRS (Form 1) in that the FRM
(the median) is -14.5 whereas the FRO is -15.8. The FRO is more negative than the FRM, which does not
seem to correspond to what’s stipulated in R1 (FRM to be equal or more negative than its FRO).
Response: FRS Form 1 has been modified to correct calculations and to allow for adjustments (not exclusions) to the load and generation.
Arizona Public Service Company
Yes
What is meant by discretely administered determination, under the heading "Frequency Obligation and
Allocation" of Attachment A? Please explain.
Response: The SDT has provided an administrative procedure for the ERO to follow in Attachment A.
54
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001698
Organization
ENBALA Power Networks
Yes or No
Question 4 Comment
Yes
ENBALA does believe that a BA should be responsible for a minimum level of Frequency Response as
calculated on Form 1 and reflected in its FRO. Furthermore, we feel that additional data collected on the
frequency nadir, such as the metric suggested in the recent Lawrence Berkeley National Laboratory of nadirbased frequency response, would be useful in assessing the current inertial response capabilities and level of
risk for under-frequency load shedding.
Response: The FRO is a determined value providing a target for ensuring robust frequency response is achieved by all Balancing Authorities. The FRM is the
medium value of observations for the time period. The intent is for FRM to always be equal or more negative than the FRO, signifying robust control resulting in
proper frequency response. As such, the determination timeframes does not have to be the same for each value.
Beacon Power Corporation
Yes
The concept of requiring each Balancing Authority to achieve some level of Frequency Response and
calculate it consistently is appropriate and necessary.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SPP Standards Development
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
Associated Electric Cooperative,
Inc.
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
55
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001699
5.
Requirement 2 identifies when the Balancing Authority must implement its Frequency Bias Setting.
R2. Each Balancing Authority shall implement the Frequency Bias Setting (fixed or variable) provided by the ERO into its Area Control Error
(ACE) calculation beginning on the date specified by the ERO to ensure effective coordinated secondary control, using the results from the
calculation methodology detailed in Attachment A.
Do you agree with this implementation? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters did not agree with the implementation plan specified in Requirement R2.
Many of the comments received echo concerns raised in comments for question 4 such as the Attachment A calculation methodology is not
clear; there was insufficient information provided to address the use of variable bias, and FRO determination was questionable. Several
commenters were concerned with the role assigned to the ERO, questioning how the ERO will use the FRM to determine the required BA
Frequency Bias Setting and if the ERO was the correct entity to perform this action. Commenters also expressed concerns with performing
an FRM analysis at the end of the year over the holiday period, suggesting the implementation time should be increased from one month to
two months. Some commenters also expressed concern that CPS and L10 compliance may be adversely affected by the requirements
proposed for calculating the Frequency Bias Setting.
In response to the comments received from industry, the SDT has revised Attachment A to clarify the calculation methodology; revised
Requirement R2 to clarify how an entity implements the Frequency Bias Setting provided by the ERO; and also modified FRS Form 1 to
allow for adjustments. Regarding FRO determination, the SDT is using a deterministic approach and also evaluating a probabilistic
method. With respect to ERO actions, the SDT is evaluating whether modifications to the NERC Rules of Procedure are necessary to ensure
the ERO provides the necessary support. The SDT also will develop a second draft standard attachment, Attachment B, to define the
methodology for lowering the minimum Frequency Bias Setting required, including maintaining a safety margin.
R2. Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable)
validated by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively coordinated
Tie Line Bias.
Organization
Santee Cooper
Yes or No
No
Question 5 Comment
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation?
What does “provided by the ERO” mean? Perhaps it should be verified or approved by the ERO (NERC).
56
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001700
Organization
Yes or No
Question 5 Comment
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
LG&E and KU Energy
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
SERC OC Standards Review
Group
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
effectively coordinated Tie Line Bias control.”
South Carolina Electric and Gas
No
It is not clear what the methodology (should be method) is in Attachment A. Is the frequency bias setting the
BA’s prior year FRM with a minimum value being a percentage of estimated yearly peak load or upcoming
year maximum generation? What does “provided by the ERO” mean? Perhaps it should be verified or
approved by the ERO (NERC).
We suggest defining the date as by the end of the first business day following the deadline for Frequency Bias
Setting implementation.
Response: Attachment A has been revised to clarify the calculation methodology.
Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the
Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure
57
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001701
Organization
Yes or No
Question 5 Comment
effectively coordinated Tie Line Bias control.”
The SDT does not believe the suggestion to define the date is necessary since there is language in the standard stating the ERO will allow sufficient time to
implement the Frequency Bias Setting.
MRO's NERC Standards Review
Subcommittee
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible
for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is an implied
obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are
left wondering who has the responsibility for determining the Frequency Bias Setting.
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias than underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is overbiased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
Midwest ISO Standards
Collaborators
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the responsible
for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is an implied
obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly. Thus, we are
left wondering who has the responsibility for determining the Frequency Bias Setting.
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias than underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is overbiased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
58
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001702
Organization
Yes or No
Question 5 Comment
No
Flexibility established in the date is better than the existing currently defined date in the standards. It is better
to allow the ERO to specify the date to allow some flexibility in implementation. It appears that the
responsibility for identifying Frequency Bias Setting is being removed from the Balancing Authority. There is
an implied obligation that the ERO will determine the Frequency Bias Setting but it is not stated explicitly.
Thus, we are left wondering who has the responsibility for determining the Frequency Bias Setting.
and provide a safety margin.
We Energies
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to over-bias than under-bias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for frequency bias setting was chosen to
ensure that BAs are always over-biased. The standard needs to allow some margin in the frequency bias
setting to ensure that the bias setting is over-biased.
Response: The SDT has modified the language in Requirement R2 to provide further clarity. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
FirstEnergy
No
We cannot agree at this time since Attachment A of the materials posted do not include sufficient details
regarding the calculations used. Furthermore, there is no obligation imposed on the ERO to provide neither a
reasonable time frame for implementation of the Frequency Bias Setting nor a requirement for the ERO to
follow the methodology detailed in Attachment A. The team should consider adding a requirement for the
ERO or clarifying where this obligation is covered in NERC’s Rules of Procedure.
Response: Attachment A has been revised to clarify the calculation methodology.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary.
Bonneville Power Administration
No
R2 - BPA believes that the ERO should not be providing the BA the Frequency Bias Settings for the BA.
R2 points to Attachment A as having the calculation methodology, but there is no methodology spelled out in
Attachment A, there are simply data requirements, delta frequency that will be included in surveys, tools to be
used, etc.
The statement ‘natural frequency response’ is in Attachment A many times, but it is never spelled out. What
is meant by this phrase. This differs dramatically depending on when the event occurs due to different
generating patterns, different types of load (frequency responsive versus not frequency responsive), etc.
59
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001703
Organization
Yes or No
Question 5 Comment
The methodology needs to spell out how this will be taken into account when calculating the correct frequency
bias.
Secondly, how would this be done for variable bias?
Response: Requirement R2 has been revised for clarity and now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
Attachment A has been revised to clarify the calculation methodology.
The SDT agrees that over-bias is better than under-bias and has added Attachment B to define the methodology to lower the minimum Frequency Bias Setting
and provide a safety margin.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT will provide
additional and sufficient direction related to variable bias after review of this issue during the field trial.
The term “natural frequency response” is no longer in Attachment A but it is used in the new Background Document. The SDT believes that this term is
describing the response for any individual event and if calculated the statistical summation of multiple events. This term is more a work of art and not science
and therefore is not capitalized or defined.
SPP Standards Development
No
We would suggest ending the sentence at the second ERO, deleting the phrase '...to ensure effective
coordinated secondary control, using the results from the calculation methodology detailed in Attachment A.'
This phrase is more of an explanation of why this is being done rather than a part of an actual requirement.
Response: The SDT believes this language provides additional clarity and should remain as is. The SDT has removed the reference to Attachment A.
IRC Standards Review
Committee
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. Please clarify.
Also, it should not be necessary for the ERO to do the determination for all the Interconnections. There are
already in place methods for this by the existing ERCOT and WECC Interconnections. The SRC suggests
that the ERO may not be the appropriate technical entity. The ERO may be the appropriate entity to serve as
the receiver of the forms and analyze results for the Eastern Interconnection, but existing processes are
already in place elsewhere. It should be sufficient that those processes continue and submit copies of Form 1
to the ERO. This may also be appropriate for Hydro Quebec.
In addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the
BAs to implement the settings. The proposed language says only that the BA shall implement it on the date
specified, but it doesn’t address the need for that date to include some implementation time.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
60
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001704
Organization
Yes or No
Question 5 Comment
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common methodology applicable
to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
ERCOT
No
It is not clear how the ERO uses the FRM to determine the required Frequency Bias Settings. It should not
be necessary for the ERO to do the determination for all the Interconnections. There are already in place
methods for this by the existing ERCOT and WECC Interconnections. The SRC suggests that the ERO may
not be the appropriate technical entity. The ERO may be the appropriate entity to serve as the receiver of the
forms and analyze results for the Eastern Interconnection, but existing processes are already in place
elsewhere. It should be sufficient that those processes continue and submit copies of Form 1 to the ERO.
This may also be appropriate for Hydro Quebec.
In addition, whichever entity determines the Frequency Bias Setting must provide implementation time for the
BAs to implement the settings. The proposed language says only that the BA shall implement it on the date
specified, but it doesn’t address the need for that date to include some implementation time.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common methodology applicable
to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Kansas City Power & Light
No
The Frequency Response Obligation determination for the interconnection as described in Attachment A is a
crude method and will result in obligations that will exceed the FRO that is intended. This will result in
additional cost to BA’s that is unnecessary to achieve the purpose of maintaining sufficient generation online
to arrest frequency degradation events caused by loss of generating resources.
The current NERC method for calculating a BA’s actual frequency response are inaccurate and provide
misleading guidance in the actual frequency response of a BA. These methods need considerable
improvement before any attempts to hold a BA to an expected level of frequency response as this proposal
61
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001705
Organization
Yes or No
Question 5 Comment
has stated.
Response: The minimum level of response selected for the field trial uses a deterministic approach. The actual level of response specified in the final version of
the draft standard may be based on analysis of data obtained from the field trial. The SDT is also evaluating a probabilistic method to determine the FRO.
FRS Form 1 has been modified to correctly calculate Frequency Response.
Southern Company
No
Comments: Comment 2: BAL-003-1, Requirement R2. The requirement should be made less prescriptive by
removing references to the calculation methodology and Attachment A. The responsible entity should
understand the fundamental and basic requirement - to implement the Frequency Bias Setting into its Areas
Control Error calculation. Proposed language is as follows: Each Balancing Authority shall implement the
Frequency Bias Setting (fixed or variable) provided by the ERO into its Area Control Error (ACE) calculation
beginning on the date specified by the ERO to ensure effective coordinated secondary control.
Comment 3: BAL-003-1, Requirement R2 and Section 1.4 Additional Compliance Information. The SDT
should consider whether or not the ERO has compliance obligations pursuant to the obligations mentioned in
the proposed Standard. Requirement R2, states that the ERO should provide the BA with the Frequency Bias
Setting and the specified date to begin the calculation. The R1 Supplemental Information section states that
the ERO is obligated to post the official list of events. The R2 Supplemental Information section states that
the ERO is obligated to validate the FRM and Frequency Bias Settings and disseminate the Frequency Bias
Settings Report along with the implementation date. These obligations should be confirmed and properly
incorporated into Standard if appropriate.
Response: The SDT disagrees that the standard should independently address each Interconnection, and believes it is necessary to have a common
methodology applicable to each Interconnection. An entity can request a variance and justify why deviation from the methodology adopted is necessary.
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Energy Mark, Inc.
No
Comment 13: I agree that the BA shall implement the Frequency Bias Setting provided by the ERO into it
Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effective
coordinated secondary control.
Comment 14: I do not agree that the results from the calculation methodology detailed in Attachment A will
provide the correct Frequency Bias Setting. My comments on the calculation methodology are included
elsewhere in my comments on Attachment A and FRS Form 1.
Response: Comment 13 – The SDT thanks you for your affirmative comment. Note that based on comments from other stakeholders, the language in
Requirement R2 was modified to state, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) “validated” by the ERO, into its Area Control Error (ACE) calculation . . .”
62
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001706
Organization
Yes or No
Question 5 Comment
Comment 14 - Please see the SDT response to your Attachment A and FRS Form 1 comments.
EKPC
No
The method is not clear in Attachment A.
Response: Attachment A has been revised to clarify the calculation methodology.
Seattle City Light
No
Currently a Balancing Authority has only about one month over holiday periods(December 10 to January 10)
to assemble its data and calculate the Frequency Response Measure (FRM). Further, Attachment A requires
the ERO to use at least 25 events for the calculation of FRM. Seattle City Light (SCL) believes that one month
is insufficient time given the number of events required. So SCL recommends additional time, such as two
months or to reduce the number of events to be included in annual reviews.
Response: The SDT recommends posting the selected events on a quarterly basis which should provide ample time for BAs to provide the information.
American Electric Power
No
It appears this standard deviates from past practice for calculating frequency bias. It is unclear how this might
affect the CPS Bounds L10 calculation.
Response: The Frequency Bias Setting calculation remains the same. The SDT is only modifying the “minimum Frequency Bias Setting” threshold. The SDT
understands reducing the minimum Frequency Bias Setting will affect L10 and ACE values which is why the SDT proposes monitoring these parameters and
undoing the modification if adverse results are realized.
Duke Energy
No
Duke Energy believes that this needs to be restated. Will the ERO perform the calculations to determine each
BA’s Bias?
Will the ERO provide ample time between publication of the settings and the date of implementation?
If effective coordinated secondary control is desired, other related operational parameters (e.g., L10) need to
be set at the same time.
Since measurement and reporting of operational performance is primarily on a monthly basis (e.g.,
CPS1/CPS2), the implementation date should be on or near the first of a month, but during normal working
hours (so that adequate support personnel are available).
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
63
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001707
Organization
Yes or No
Question 5 Comment
also define implementation timing.
The SDT understands reducing the minimum Frequency Bias Setting will affect L10 and ACE values which is why the SDT proposes monitoring these parameters
and undoing the modification if adverse results are realized.
The SDT is not proposing to change the methodology presently used to set the timing of the implementation of the Frequency Bias Setting.
Patterson Consulting, Inc.
No
The concept of requiring a Balancing Authority to implement its Frequency Bias Setting at a specific time and
using a specific calculation is meaningful. This requirement is not clearly worded, however. If the intent of
Requirement 2 is to identify "...when the Balancing Authority must implement its Frequency Bias Setting..." the
requirement should stop after "...on the date specified by the ERO." The remaining portion of the requirement
explains the need for the requirement and should be moved to supporting material.
Attachment A does not have a "calculation methodology" associated with the Frequency Bias Setting unless
the language describing historical practice and the benefits of moving a Frequency Bias Setting closer to a
Balancing Authority's natural Frequency Response are intended to constitute a "calculation methodology."
FRS Form 1 has the "calculation methodology" of using the minimum (since the value is negative) of last
year's FRM, next year's FRO, and percentage of next year's peak load or generation. Attachment A does not
mention this methodology and the requirement does not mention FRS Form 1. The clause "..., using the
results from the calculation methodology detailed in Attachment A." appears to place an obscure requirement
on the ERO since the ERO is the entity providing the Frequency Bias Setting to be implemented by the
Balancing Authority. If the ERO is intended to use the value from FRS Form 1, after verifying data and
calculations, then state that expectation explicitly and clearly. Otherwise, the ERO could set Frequency Bias
Settings in another manner after observing the Form 1 values.
The requirement for the ERO to provide a Frequency Bias Setting to each Balancing Authority begs the
question of how variable bias will be implemented. Historically, the Balancing Authority implements its
algorithm with oversight from NERC (Resources Subcommittee). The manner and expectation for providing
data and algorithms related to variable bias are inadequate.
Response: The SDT has modified the language in Requirement R2 to clarify the role of the ERO. The Requirement now reads “Each Balancing Authority not
participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
Attachment A has been revised to clarify the calculation methodology.
FRS Form 1 has been modified to correctly calculate Frequency Response and to allow for adjustments (not exclusions) to the load and generation.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT will provide
64
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001708
Organization
Yes or No
Question 5 Comment
additional and sufficient direction related to variable bias after review of this issue during the field trial.
Alberta Electric System Operator
Yes
The AESO suggests that the standard should provide a description on how the ERO would determine the
frequency bias setting and the relation to the FRO.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
The SDT is evaluating if a modification to the NERC Rules of Procedure to obligate the ERO to perform the tasks identified in the standard is necessary and will
also define implementation timing.
NIPSCO
Yes
I guess the ERO will calculate the Bias, interesting.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to clarify the
role of the ERO. The Requirement now reads, “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias
Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
Manitoba Hydro
Yes
The implementation schedule seems reasonable.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Westar Energy
Yes
FMPP
Yes
Progress Energy
Yes
ENBALA Power Networks
Yes
NorthWestern Energy
Yes
Independent Electricity System
Operator
Yes
65
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001709
Organization
Arizona Public Service Company
Northeast Power Coordinating
Council
Yes or No
Question 5 Comment
Yes
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
66
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001710
6.
Requirement 3 mandates that a Balancing Authority operate its Automatic Generation Control (AGC) on Tie Line Bias unless it becomes
adverse to the integrity of its system.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Bias, unless such operation would have an
Adverse Reliability Impact on the Balancing Authority’s Area.
Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it becomes adverse to its system? If not, please
explain in the comment area below.
Summary Consideration: Approximately half of the comments received agreed that a Balancing Authority should operate its AGC in Tie
Line Bias unless an Adverse Reliability Impact occurs. Many of the dissenters were concerned with the apparent conflict with BAL-005.1b
Requirement R6, efforts of the Balancing Authority Reliability-based Controls (BARC) SDT with modifying BAL-005, and concern that the
draft standard should not dictate an AGC operating control mode. Other commenters indicated the language of Requirement R3 needed to
be revised for clarity and that the requirement could place a reporting burden on the Balancing Authorities. It was also noted that a single
BA Interconnection does not operate AGC using Tie Line Bias mode.
In response to industry comments received, the SDT has revised Requirement R3 by adding Overlap Regulation Service language and
allowing the AGC operating mode to be changed for an Adverse Reliability Impact.
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode
to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.
Organization
Santee Cooper
Yes or No
No
Question 6 Comment
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE. We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
67
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001711
Organization
LG&E and KU Energy
Yes or No
No
Question 6 Comment
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
SERC OC Standards Review
Group
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
South Carolina Electric and Gas
No
BAL-003-0, Requirement 3 requires operation of AGC on Tie Line Frequency Bias. BAL-005-0.1b,
Requirement 6 requires the BA to compare total Net Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing Authority’s ACE.We suggest that Requirement 3 be
restated to “shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless
........”Tie Line bias is the (Ia-Is) term and frequency bias is the -10B(Fa-Fs) term.
This should be coordinated with BARCSDT modifications to BAL-005.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
68
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001712
Organization
Yes or No
Question 6 Comment
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Bonneville Power Administration
No
R3. BPA does not believe this standard should dictate the control mode for AGC. That is better suited to be
in BAL-001 and should not be repeated in this standard - the ACE used for reporting is spelled out in BAL-001
R1 and is also discussed in BAL-005 R6. R3 should be removed from this standard, not modified to fit with
what is stated in BAL-001 or BAL-005.
Response: This standard is proposed to go into effect prior to implementation of the BARC draft standard. A determination of which reliability standard should
specify the AGC control mode used for system operations can be made once development of the BARC draft standard is completed.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
IRC Standards Review
Committee
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
ISO New Engand Inc.
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
69
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001713
Organization
Yes or No
Question 6 Comment
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
ERCOT
No
Single BA Interconnections do not operate on Tie Line Bias. The requirement should be modified to
accommodate this or regional variances should be written by the SDT to address existing differences.
In addition this requirement, as written, does not provide for momentary cessation of AGC for any reason, nor
for reasonable system maintenance, repair, or updates. As written, it seems to say that any duration of
operation off Tie Line Bias is unacceptable and, thus, would be a violation.
Response: The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has
been revised to clarify this situation.
The SDT disagrees that the Requirement does not allow for instances of not operating in Tie Line Bias mode. The revised Requirement states “Each Balancing
Authority not receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
Kansas City Power & Light
No
The impact of operating in an inappropriate AGC control mode is bigger than the BA’s own balancing area.
The control of the area affects other BA’s around a BA and if enough BA’s are involved, can affect an
interconnection. Recommend the requirement be modified to consider the reliability impact on its own
balancing area, the balancing areas of adjacent BA’s and the interconnection.
Response: The SDT agrees and has modified Requirement R3 to read, “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
Southern Company
No
Comments: Agree only to the extent that an accurate frequency measurement is available to the BA. If not
frequency measurement is available, then that should be considered an adverse condition and thus TLB is
not appropriate. In other words, one small BA maintaining TLB may not cause the condition in the Glossary
definition of Adverse Reliability Impact but it is still not appropriate for them to stay on TLB.
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
70
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001714
Organization
NIPSCO
Yes or No
No
Question 6 Comment
Yes, It was proposed that AGC be replaced by Automatic Resource Control (ARC) in the standards but did
not pass. The SDT may want to monitor this related effort.
Response: The SDT is using approved definitions listed in the NERC Glossary of Terms. Changes to current NERC Glossary of Terms definition language not
used in this standard would need to occur as a separate project.
Energy Mark, Inc.
No
Comment 15: Requirement 3 as written is unenforceable because it is too difficult to define “unless such
operation would have an Adverse Reliability Impact on the Balancing Authority’s Area.”
Comment 16: What if operation out of Tie line Bias control does not have an Adverse Reliability Impact on
the Balancing Authority’s Area, but does have an Adverse Reliability Impact on another BA?
Comment 17: A document follows that provides an initial starting justification for the elimination of this
Requirement. See following “Requirements for AGC Operation, January 25, 2011.”Requirements for AGC
Operation, January 25, 2011
Introduction:As of the date of these comments there are two requirements in the NERC Standards that
address the operation of AGC.
•
•
The first is in BAL-003-0.1b - Frequency Response and Bias, Requirement R3.R3. Each Balancing
Authority shall operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such
operation is adverse to system or Interconnection reliability.
The second is in BAL-005-0.1b - Automatic Generation Control, Requirement R7.R7. The Balancing
Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the
Interconnection. If AGC has become inoperative, the Balancing Authority shall use manual control to
adjust generation to maintain the Net Scheduled Interchange.
These requirements are misdirected and, for compliance purposes, they are difficult to measure effectively.
This paper provides the technical basis for replacing these requirements with new requirements that will not
only achieve the intent of these requirements, but do so in a more effective and measurable manner.
Background:
Automatic Generation Control (AGC) is a computer control system contained in the Control Center EMS that
performs a number of critical functions related to the balancing function necessary to maintain frequency and
associated reliability. Among the functions it performs are:
1) the collection of telemetered and local data useful for determining the appropriate control actions,
2) the calculation of Area Control Error (ACE),
3) determination of desired control actions that should be sent to those resources available for
automatic dispatch, and
71
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001715
Organization
Yes or No
Question 6 Comment
4) sending the actual control signals to implement that dispatch.
Most AGC Systems have three basic modes of operation,
1) Tie-line Frequency Bias,
2) Constant Net Interchange and
3) Constant Frequency.
The ACE Equation is the basis for all three modes of operation.
•
•
•
In the Tie-line Frequency Bias mode, all of the ACE Equation is used as an input to control action
determination.
In the Constant Net Interchange mode, only the Tie-line Error portion of the ACE Equation is used as
an input to control action determination. The Constant Net Interchange mode would normally be
used when there is no information available to indicate interconnection frequency.
In the Constant Frequency mode, only the Frequency Bias portion of the ACE Equation is used as an
input to control action determination. The Constant Frequency mode of operation would be used
when the Tie-line Error is known to be misleading, inaccurate or unavailable. It is also used when
there are no tie-lines in service as in the case of a single BA interconnection or during islanded
operation.AGC Systems have been used in the industry since before the development of digital
computers.
Initially AGC Systems did little more than send instructions to generators based on evaluation of the ACE
Equation. They have become more sophisticated since their inception and implement greater complexity in
their evaluations of appropriate dispatch actions to the point that they include forecasting, reliability and
economics within their algorithms. Modern AGC Systems determine control actions based on the collection of
much more data than is included in the ACE Equation. This additional data includes: short-term load
forecasts and forecast error estimates as influenced by weather; individual non-conforming load forecasts and
forecast error; forecast interchange transaction information; generating unit ramp and response rates;
generating unit economic operating points including valve position; generating unit incremental economic
costs including start-up and maintenance; Hydro unit river flow limits as related to the operation of other units
on the same waterway; energy storage capabilities and available energy; Inadvertent Interchange energy
account balances; time error; and current control performance scores.
As AGC Systems have evolved, the control mode in which they are operating, Tie-line Frequency Bias,
Constant Net Interchange, or Constant Frequency, provides less and less information about the control
actions that they implement. In a modern AGC System the control mode provides little information about how
control actions are being determined and implemented. In fact, only someone experienced in AGC
programming and implementation would have the knowledge necessary to determine whether or not an AGC
System is providing reasonable control actions or control actions consistent with Tie-line Frequency Bias
Control. Even someone with the necessary experience observing the operation of a modern AGC System for
72
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001716
Organization
Yes or No
Question 6 Comment
a short period of time will be incapable of determining whether or not that system is providing effective or
adequate control. Therefore, neither of the two requirements is effectively enforceable from a practical point
of view.
Perspective:A couple of examples are offered to add perspective to the problem.
Example 1:R3 includes the requirement, “Each Balancing Authority shall operate its Automatic Generation
Control (AGC) on Tie Line Frequency Bias, unless such operation is adverse to system or Interconnection
reliability.” There are three conditions when operation on Tie-line Frequency Bias control may be adverse to
the system or Interconnection reliability.
1. The first is when the Tie-line Error data used in the ACE Equation is incorrect. The ACE Equation
will be incorrect when there are errors in the Actual or Scheduled Tie-line flow values. This condition
will occur when there is telemetry failure of one or more tie-lines, when there is an unidentified
scheduling error, or when there is a separation that causes a tie-line metering point to be located on a
separate island due to interconnection separation or islanding. Telemetry failure will be indicated by
the quality bits associated with the Tie-line telemetry. If AGC is disabled to identify a scheduling error,
there should be an operating log entry. If AGC is disabled because of a separation, there will also be a
log entry.
2. The second is when the actual frequency is determined to be incorrect. If measured frequency is
incorrect, this condition should be indicated by an operating log entry and transfer to the redundant
frequency device to provide measured frequency. When the actual frequency fails, this condition will
be indicated by the quality bits associated with the measured frequency value and transfer to the
redundant frequency device to provide measured frequency.
3. The third is when operation of AGC would provide control different from the desired control to
address some emergency condition in the BA or elsewhere on the interconnection. If the operation of
AGC would be adverse to system or Interconnection reliability and is disabled for this reason, this
condition should be indicated by an operating log entry.In all cases, there should be a record of the
reason for the use of other than Tie-line Frequency Bias control and records indicating the reason for
the use of other control modes. In all cases, other than the third indicated above, an error in the value
of ACE is the reason for not using Tie-line Bias Control and the quality bits for ACE or ACE component
data should provide a reasonable explanation for the condition. The third case occurs with such
infrequency that there should be no need for a special rule to address this condition.
Example 2:R7 includes the requirement, “...If AGC has become inoperative, the Balancing Authority shall use
manual control to adjust generation to maintain the Net Scheduled Interchange.” Cases have been observed
of an AGC System that does not perform as well as the manual dispatch used when the AGC System is
inoperative. If a BA has a CPS1 score of 120% when using AGC and a CPS1 score of 125% when
performing manual dispatch, should that BA be penalized for not having its AGC continuously operating?
What is the goal? Is the goal to operate on AGC regardless of the result or is the goal to operate in a manner
73
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001717
Organization
Yes or No
Question 6 Comment
that provides the best measured control?
Alternatives:Since these requirements are not effectively measurable or enforceable, can a requirement or
requirements be written to provide an equivalent to the intent of the old requirements addressing AGC
operation?The industry has three alternatives to address this issue:
1. Retain requirements that are directed at the AGC System understanding that they are effectively not
measureable or enforceable.
2. Eliminate requirements that are directed at the AGC System with the understanding that they were
not contributing to reliability.
3. Determine an alternative method to evaluate, measure and enforce a requirement that will achieve a
goal similar to the goal originally intended by the implementation of the AGC System requirements.
Elimination of the requirement is an appropriate solution. However, if it is determined that a replacement
measure is required, then the solution to this problem lies with the third alternative above.
Solution:There is already a requirement that effectively enforces the intent of the above requirements.
Instead of requiring the BA to control in a particular manner, CPS1, BAAL and DCS require the BA to achieve
specific results with their control actions. All three measures require the BA to calculate ACE using Tie-line
Frequency Bias for determination of their Reporting ACE. The requirements specify that at least 50% of the
data must be valid for the one-minute average data to be included in the measures. The requirements for
redundant frequency measurement devices assure that the BA will have the actual frequency data available
to perform the necessary calculations. The data retention requirements specify the data they must retain to
demonstrate that their control achieved the stated goals.
Finally, this approach is consistent with the White House Executive Order on Improving Regulation and
Regulatory Review in Section 1(b)(4) stating that regulatory agencies must: “to the extent feasible, specify
performance objectives, rather than specifying the behavior or manner of compliance that the regulated
entities must adopt;...”
Response: Comment 15 & 16: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service
shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an
Adverse Reliability Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Comment 17: The SDT recognizes that from a compliance perspective it can be difficult to ascertain if an Adverse Reliability Impact exists. Nonetheless, the SDT
is very concerned with adversely affecting primary Frequency Response when operating without AGC. The SDT believes revised language using NERC glossary
defined terms will support proper compliance enforcement. It is expected entities will provide an explanation each time AGC Tie Line Bias mode is not used for
74
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001718
Organization
Yes or No
Question 6 Comment
the compliance auditor to assess.
EKPC
No
Tie line bias is calculated using (NAI-NSI) while frequency bias is -10B(FA-FS).
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
Duke Energy
No
Duke Energy agrees to the simple statement posed in the question; however, the requirement goes beyond
that by using a defined term, Adverse Reliability Impact, which has a relatively narrow focus on extreme
conditions. If a single BA lost a significant amount of its tie-line telemetry or its frequency sources, cascading
outages and/or grid separation would not necessarily be imminent but it would be imprudent to remain in Tie
Line Bias mode. Go back to the original language for the requirement - “Each Balancing Authority shall
operate its Automatic Generation Control (AGC) on Tie Line Frequency Bias, unless such operation is
adverse to system or Interconnection reliability.”
Response: The SDT has revised Requirement R3 language and believes the use of NERC glossary defined terms in the Requirement provides necessary clarity
for compliance.
Patterson Consulting, Inc.
No
While this requirement is in the existing standard, it places a significant reporting burden on a Balancing
Authority to demonstrate compliance during audits for little reliability gain.
In addition for single Balancing Authority interconnections, operating in this AGC mode is functionally
equivalent to operating in flat frequency mode. This may cause some interconnections to seek a variance, just
to avoid compliance complications. Perhaps this requirement could be replaced with a requirement for
Balancing Authorities to contribute to frequency performance as well as balance commitments and resources,
or to calculate the ACE it uses to report in other standards in a specific manner. As written, it could be
interpreted to create a violation when AGC suspends or is offline.
Response: The SDT has taken into consideration the reporting burden on the Balancing Authority to demonstrate compliance.
provide an explanation each time AGC Tie Line Bias mode is not used for the compliance auditor to assess.
It is expected that entities will
The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has been revised
to clarify this situation.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
75
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001719
Organization
Yes or No
Question 6 Comment
standard will take into account the work completed on this standard.
FirstEnergy
Yes
Although we mostly agree with the requirement, we believe it can be improved. We suggest that the team add
wording in the requirement to allow for brief periods where meters or communication channels fail and trip the
AGC off Tie Line Bias. In most areas, if merely one BA trips off bias it would not have an adverse affect on
BES reliability and furthermore, the BA can take alternative measures for these periods such as manual AGC.
We suggest the team add wording similar to the second sentence of requirement R7 of BAL-005 which states:
“If AGC has become inoperative, the Balancing Authority shall use manual control to adjust generation to
maintain the Net Scheduled Interchange.”
Response: Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Arizona Public Service Company
Yes
As long as Appendix 1 interpretation remains in effect for WECC Auto Time Error Payback. WECC BAs
operate in Tie-Line and Time.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Hydro-Quebec TransEnergie
Yes
However the “Tie Line Bias” AGC mode is not appropriate for a Single Balancing Authority operating in an
Interconnection. HQT uses the Flat Frequency mode.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT agrees that a single BA Interconnection does not operate using Tie Line Bias mode. The “Additional Compliance Information” section has been revised
to clarify this situation.
Requirement R3 has been revised for clarity and now reads “Each Balancing Authority not receiving Overlap Regulation Service shall operate its Automatic
Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control, unless such operation would have an Adverse Reliability Impact on the
Balancing Authority’s Area.”
This standard is scheduled to be completed and filed with FERC prior to the BARC standard being completed. The SDT anticipates that work on the BARC
standard will take into account the work completed on this standard.
Beacon Power Corporation
Yes
As R3 has not significantly changed, will the Interpretation of Requirement 3 from BAL-003-0.1b still be
applicable to BAL-003-1?
76
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001720
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
When this standard is approved and implemented it will replace all previous standards and interpretations.
Westar Energy
Yes
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
We Energies
Yes
American Electric Power
Yes
SPP Standards Development
Yes
Midwest ISO Standards
Collaborators
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
Yes
Independent Electricity System
Operator
Yes
NorthWestern Energy
Yes
Progress Energy
Yes
ENBALA Power Networks
Yes
Northeast Power Coordinating
Council
Refer to the response to Question 17.
77
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001721
Organization
Yes or No
Question 6 Comment
Response: Please refer to our response to Question 17.
78
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001722
7.
Do you agree with the proposed Implementation Plan for this standard? If not, please explain in the comment area.
Summary Consideration: The majority of the comments received stated that they did not agree with the proposed implementation plan
for this standard. The main concerns were that the implementation plan would take several years to fully implement, that adjustment to
the Frequency Bias Setting could not occur without first modifying the existing BAL-003-0.1b standard, and a preference for aligning
implementation plan effective dates with the regulatory approval date. Several commenters expressed concern regarding the accuracy and
clarity of Attachment A and how field testing efforts integrated into the implementation plan. One commenter observed that it would be
ideal for the standard to require the use of variable bias.
In response to industry comments the SDT has revised Attachment A for correctness and clarity; changed all references in the standard
and associated documents for BAL-003 to read “BAL-003-0.1b”; and removed the table showing the annual reduction schedule for the
minimum bias setting. The SDT has provided a revised plan for reducing the minimum Frequency Bias Setting - the ERO will monitor the
results of the reductions and make necessary corrections. Details for the reduction plan have been provided as Attachment B to the
standard.
Organization
Santee Cooper
Yes or No
No
Question 7 Comment
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard.
The values currently shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly
peak demand per 0.1 Hz change. For BAs that do not serve native load, percent “of upcoming years
maximum generation/0.1 Hz should be changed to percent of its estimated maximum generation level in the
coming year/0.1 Hz change.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval which is why the implementation plan specifies reducing the bias setting on an annual basis.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
LG&E and KU Energy
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change
79
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001723
Organization
Yes or No
Question 7 Comment
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
South Carolina Electric and Gas
No
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT deleted the section of the Implementation Plan that referenced “of peak/0.1 Hz”.
MRO's NERC Standards Review
Subcommittee
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
plan makes no mention of a field trial. It should.
Please change all BAL-003-0 to BAL-003-0.1b.
Response: The SDT did change all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Midwest ISO Standards
Collaborators
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
80
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001724
Organization
Yes or No
Question 7 Comment
plan makes no mention of a field trial. It should.
Please change all BAL-003-0 to BAL-003-0.1b.
Response: The SDT has changed all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
We Energies
No
We agree with the plan to phase out BAL-003-0.1b R5 over a period of years rather than abruptly terminate it
because it will take several years to assess the impact. We recommend a wording change to the
implementation plan. Please change ‘BAL-003-0 Requirement 5 should be retired as outlined in the following
table,” to “BAL-003-0.1b Requirement 5 should be phased out by reducing the minimum frequency bias
setting per the table.”It is not clear if the minimum frequency bias setting can be modified without modifying
the existing BAL-003-0.1b standard. Is this being accomplished through the field trial? The implementation
plan makes no mention of a field trial. It should.Please change all BAL-003-0 to BAL-003-0.1b
Response: The SDT has changed all references in the implementation plan for BAL-003-1 to read “BAL-003-0.1b.”
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
FirstEnergy
No
We believe that the implementation plan should include information regarding the field trial and how it fits in
with the phase-in implementation. It appears as though the field trial is being conducted based on 2010 data
and will be concluded upon completion of the development of the standard but we think this could be clarified.
Furthermore, as stated in the process manual, a field test “should include at a minimum the data collection
and analysis or field test plan, the implementation schedule, and an expectation for periodic updates of the
results.” The field test information posted is not clear on the implementation schedule of the field test as well
as when and how periodic updates will be available.
Response: The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the Field Trial. The SDT has removed
the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another method for reducing the minimum Frequency Bias Setting
in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
Bonneville Power Administration
No
From a compliance perspective, it is administratively very burdensome to have portions of two different
versions of a standard applicable at the same time, as specified in the Implementation Plan for BAL-003-1.
81
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001725
Organization
Yes or No
Question 7 Comment
This type of structure adds an additional layer of complexity to all parts of the compliance administration
process, as necessary to distinguish between the separate versions of the standard. Rather than create and
prolong this type of situation over a 4 year time period, BPA asks that BAL-003-0 be retired in its entirety and
that the contents of BAL-003-1 be expanded to also include R5, as specified in BAL-003-0. This change
resolves the identified issues while also ensuring that all requirements of BAL-005 are in effect, as originally
intended.
The Implementation Plan for BAL-003-1 also includes a proposal to modify the specified limiting percentage
of Native Load on a sliding scale over a 4 year time period. BAL-003-3 R5, as approved, explicitly specifies
1% as a minimum value for monthly average Frequency Bias Setting. As such, changing this value results in
a change in the requirement itself. Instead of being done through an Implementation Plan, these types of
changes should be made as specific modifications to the requirement in question. To resolve this issue, BPA
asks that the sliding scale specified for percentage of peak load specified in the Implementation Plan be
incorporated directly into BAL-003-1 as a part of the specified text of R5. This change meets the intended
goal of applying a sliding scale to this value over time while assuring that the underlying change is
implemented as a change to the requirement through the Standards Development Process.
Response: The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias
Setting. The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is
proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary
correction. Please refer to Attachment B for reduction plan details.
IRC Standards Review
Committee
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier
than the schedule shown could result in the unintended consequence of non-compliance enforcement for
performance that is caused by the change rather than by the non-performance of the functional entity
.Also, the effective dates given in the Implementation differ from those in the draft standard. Different
requirement numbers are expressed in each.
Some of the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as
early as May 2011. We do not believe that the BAL-003-1 standard will be approved by the industry or the
NERC BoT at that time and that does not even take into account regulatory approval (or 12 months after BoT
adoption in those jurisdictions where no regulatory approval is required).
How can a standard begins to phase out while the successor standard is not anywhere near becoming
effective?If the SDT wants to propose a gradual replacement of the current R5, we would suggest that the
phase-out steps be tied to the date that the standard becomes effective.
Response: The SDT has removed the table showing the reduction schedule for the minimum bias setting.
82
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001726
Organization
Yes or No
Question 7 Comment
The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted. The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and
make necessary corrections. Please refer to Attachment B for reduction plan details.
ERCOT
No
What is the technical basis for the phase-out schedule? Making the standard requirements effective earlier
than the schedule shown could result in the unintended consequence of non-compliance enforcement for
performance that is caused by the change rather than by the non-performance of the functional entity.
Also, the effective dates given in the Implementation differ from those in the draft standard. Different
requirement numbers are expressed in each.
Some of the implementation steps (retiring R5 of BAL-003-0) presented in the implementation plan start as
early as May 2011. We do not believe that the BAL-003-1 standard will be approved by the industry or the
NERC BoT at that time and that does not even take into account regulatory approval (or 12 months after BoT
adoption in those jurisdictions where no regulatory approval is required). How can a standard begins to phase
out while the successor standard is not anywhere near becoming effective?
If the SDT wants to propose a gradual replacement of the current R5, we would suggest that the phase-out
steps be tied to the date that the standard becomes effective.
Response: The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Kansas City Power & Light
No
How can hard dates for the phasing out of the current R5 be in the implementation plan for a standard under
development? The concept of phasing out R5 and phasing in R2 could be done, however, this would take
considerable thought as to how to implement that. This current proposed implementation plan should be
carefully reconsidered.
83
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001727
Organization
Yes or No
Question 7 Comment
Response: Thank you for your comments. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the
Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
Progress Energy
No
We agree with the graduated implementation for the FRO portion of the standard, but feel NERC needs to
loosen the minimum frequency bias requirement immediately so that it matches the newly required frequency
response. There are also other areas within the EMS the besides BA's frequency bias that should be
addressed such as secondary frequency response systems that should also be included in this standard.
Additionally, if the industry was truly concerned with matching bias values to actual response, they would
switch to variable frequency bias. Variable bias requires additional up front work along with general
maintenance, but it truly is the best way to accurately bias the ACE equation.
Response: The SDT believes that gradually relaxing the present standard is the prudent way to proceed. The SDT believes that it is necessary to observe the
affect each decrement to the present standard has during all four seasons to assure reliability is not adversely impacted.
The SDT has revised the plan for reducing the minimum Frequency Bias Setting and is proposing another method for reducing the minimum Frequency Bias
Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
The SDT agrees that use of a variable, non-linear bias setting is the best solution.
We also agree with you that variable, non-linear bias setting would be a superior way to go.
NIPSCO
No
"Effective Date" section at the top of the Standard does not match the Implementation plan; I think there is an
R4 missing in the second part of 1.3 .In the implementation plan add RSG to "Compliance with the Standards"
5 year phase-in on removing the 1% is a good idea
Response: The SDT has corrected the errors noted. The SDT has revised the plan for reducing the minimum Frequency Bias Setting and is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Energy Mark, Inc.
No
Comment 18: The Proposed Effective Date in the implementation plan is inconsistent with the Effective Data
in the Draft Standard.
Comment 19: The completion of the implementation plan does not occur until 2015. This lengthy plan stems
from a standard that only measures reliability annually and provides only an annual window for changing
84
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001728
Organization
Yes or No
Question 7 Comment
parameters such as Minimum Frequency Response. Alternative methods that measure reliability more
frequently could me implemented with a shorter implementation plan.
Response: The SDT has corrected the mismatch between effective dates in the implementation plan and the standard.
The SDT believes that gradually relaxing the present standard is the prudent way to proceed. The SDT believes that it is necessary to observe the affect each
decrement to the present standard has during all four seasons to assure reliability is not adversely impacted. The SDT has revised the plan for reducing the
minimum Frequency Bias Setting and is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of
the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details.
Beacon Power Corporation
No
Why is it appropriate to delay implementation of this standard for over 12 months after applicable approval?
This seems an unnecessary delay considering the intent to operate under a field test. Similarly, delaying
implementation of R2 for over 2 years seems unnecessary. Based on the suggested schedule for measuring
FRM and implementing Frequency Bias Settings, there may be rationale to implement the standard on the
first calendar year following approval. However, delays beyond the beginning of the next calendar year should
require conclusive justification.
Response: The SDT believes that the affect reducing the minimum bias setting will have on frequency, including unintended consequences, will not be
observable for meaningful analysis over a short-time interval.
The SDT has added the R5 Requirement back into the proposed standard. The SDT has revised the plan for reducing the minimum Frequency Bias Setting. The
plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
EKPC
No
Specific dates should be tied to regulatory approval.
Response: The SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details.
85
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001729
Organization
ISO New Engand Inc.
Yes or No
No
Question 7 Comment
We do not agree that a meaningful Implementation Plan can be developed until such time as the data
gathering/field testing is completed. Therefore, we believe this Standard may be premature.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
American Electric Power
No
It is unprecedented that an implementation plan would require following some (but not all) requirement(s)
within multiple versions of the same standard. This would make following the standard very difficult. Having to
piece together multiple documents into a coherent requirement would be very difficult to achieve. There needs
to be a definitive start and stop date for each version, rather than a phase in and phase out across multiple
versions. We disagree with setting preselected dates beginning months away. Timing should be driven by
applicable regulatory approval, as opposed to dates which appear to be arbitrarily selected.
Going from 100% of the load-based, frequency bias calculation to 0% is unclear without correlating it to
something else being phased in over time.It is very hard to follow how BAL-003-0 R5 relates to BAL-003-1.
More work needs to be done by the SDT to explain how these relate to one another.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Attachment A has been revised for clarity. FRS Form 1 has been revised to correct calculation errors and allow for adjustments.
Duke Energy
No
Duke Energy does not agree with having prescribed dates for the gradual reduction of the minimum
Frequency Bias Setting, as the implementation may drive significant issues which could delay, or halt the
implementation at a certain level. It is not clear what process would be used to give the “go-ahead” to move to
86
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001730
Organization
Yes or No
Question 7 Comment
the next level (agree?).
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Patterson Consulting, Inc.
No
The implementation plan should address implementing these requirements at the same time for all Balancing
Authorities within an interconnection, regardless of regulatory approvals. The present implementation plan will
require some Balancing Authorities within an interconnection to operate to the new standard while other
Balancing Authorities operate to the old standard if multiple regulatory jurisdictions exist as they do within two
interconnections. This could lead to uncoordinated and unreliable operation within an interconnection.
Response: The SDT does not believe that staggered implementation will lead to uncoordinated and unreliable operation within an interconnection because these
changes affect secondary control. With regards to your comment concerning different “regulatory jurisdictions”, this issue is outside the scope of the project
approved SAR.
Independent Electricity System
Operator
No
We have a difficulty understanding the basis for some of the dates in the implementation plan.Some of the
implementation steps (retiring R5 of BAL-003-0) start as early as May 2011. We do not believe that the BAL003-1 standard will be approved by the industry or the NERC BoT at that time and that does not even take
into account regulatory approval (or 12 months after BoT adoption in those jurisdictions where no regulatory
approval is required). How can a standard begins to phase out while the successor standard is not anywhere
near becoming effective?If the SDT wants to propose a gradual replacement of the current R5, we would
suggest that the phase-out steps be tied to the date that the standard becomes effective.
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
87
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001731
Organization
Yes or No
Question 7 Comment
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Southern Company
Yes
We did not want to vote on Question 7, but clicked 'yes' in error.
Response: The SDT thanks you for your clarifying comment.
Westar Energy
Yes
Yes, if field testing validates the standard.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Associated Electric Cooperative,
Inc.
Yes
NorthWestern Energy
Yes
ENBALA Power Networks
Yes
SPP Standards Development
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
SERC OC Standards Review
Group
The implementation plan has specific dates for reducing the bias settings currently defined in Requirement 5
over several years. Perhaps these dates should not be specific but tied to months following regulatory
approval. Attachment A should be modified to match what is in the proposed standard. The values currently
shown as percent “of peak/0.1 Hz” should be changed to percent of estimated yearly peak demand per 0.1 Hz
change. For BAs that do not serve native load, percent “of upcoming years maximum generation/0.1 Hz
should be changed to percent of its estimated maximum generation level in the coming year/0.1 Hz change.
88
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001732
Organization
Yes or No
Question 7 Comment
Response: The SDT has added the R5 Requirement back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias
Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting.
The SDT believes that it is necessary to observe the affect each decrement to the present standard has during all four seasons to assure reliability is not adversely
impacted.
The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make
necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the revised plan is doable and prudent.
Attachment A has been revised for clarity.
Arizona Public Service Company
AZPS has a few questions:
1) has frequency performance been affected by the on-going RBC field trial,
2) what steps will be taken to isolate this field trial from the effects of the RBC field trial,
3) will the frequency bias reduction to 0.8% of peak load include a CPS2 grace-period for thos BAs not
involved in the RBC field trial?
Response: 1) The Frequency Response SDT cannot respond on RBS field trial matters.
2) This standard is meant to addresses primary control and the settings of the bias which would have an impact on the measures of the RBS field trial. SDT has
revised the plan for reducing the minimum Frequency Bias Setting. The plan is no longer tied to the Field Trial. The SDT has removed the table showing the
reduction schedule for the minimum bias setting. The SDT believes that it is necessary to observe the affect each decrement to the present standard has during
all four seasons to assure reliability is not adversely impacted. The SDT is proposing another method for reducing the minimum Frequency Bias Setting in which
the ERO will monitor the results of the reduction and make necessary corrections. Please refer to Attachment B for reduction plan details. The SDT believes the
revised plan is doable and prudent.
3) The Frequency Response SDT anticipates the RBC field trial will be concluded when this standard takes effect. The SDT is proposing that standards
requirements take effect for all entities within a regulatory jurisdiction at the same time.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
89
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001733
8. This standard proposes to eliminate the 1% minimum Frequency Bias over a period of 4 years as outlined in the Implementation Plan. Do
you agree that the elimination of the 1% minimum will bring Frequency Bias closer or equal to natural Frequency Response? If not, please
explain in the comment area.
Summary Consideration: Comments received indicate commenters are divided over whether elimination of the 1% minimum will bring
Frequency Bias closer or equal to the natural Frequency Response. Many commenters indicated that the Frequency Bias Setting will never
match the Frequency Response and that it is far better for reliability to over bias than under bias. Commenters also expressed concern
with how the Frequency Response Obligation (FRO) will be calculated; the rationale for the phase out schedule; and the impact this
proposal will have on secondary control.
The FR SDT refined language to indicate it is better to have a somewhat over bias condition, provided additional details on how the FRO is
calculated, explained the rationale for the phase out schedule proposed; including developing a reasonable, practical and accurate
measurement for natural Frequency Response.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 8 Comment
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.
We do not question the plan to change the minimum Frequency Bias Setting over a period of 4 years per se
in attempt to optimize AGC response by matching the Frequency Response of the system. However,
Frequency Response of the interconnection is constantly changing. As a result, the Frequency Bias Setting
will never match the Frequency Response exactly. It is better to overbias that underbias to prevent
withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency Bias Setting was chosen
to ensure that BAs are always over-biased. The standard needs to allow some margin in the Frequency Bias
Setting to ensure that the bias setting is overbiased.
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
Midwest ISO Standards
Collaborators
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
90
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001734
Organization
Yes or No
Question 8 Comment
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.We do not question the plan to change the minimum Frequency Bias Setting over a
period of 4 years per se in attempt to optimize AGC response by matching the Frequency Response of the
system. However, frequency Response of the interconnection is constantly changing. As a result, the
Frequency Bias Setting will never match the Frequency Response exactly. It is better to overbias that
underbias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency Bias
Setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some margin in
the Frequency Bias Setting to ensure that the bias setting is overbiased.
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
We Energies
No
We do note that the question asks if we disagree with eliminating Frequency Bias over a four year period.
The requirement actually applies to Frequency Bias Setting. This is important because there has been
confusion in some regulatory filings over the Frequency Response versus Frequency Bias Setting. Our
comments below assume that Frequency Bias Setting was intended to be used in the question since it is what
is in the BAL-003-0.1b R5.We do not question the plan to change the minimum Frequency Bias Setting over a
period of 4 years per se in an attempt to optimize AGC response by matching the Frequency Response of the
system. However, frequency Response of the interconnection is constantly changing. As a result, the
Frequency Bias Setting will never match the Frequency Response exactly. It is better to over-bias than
under-bias to prevent withdrawal of frequency response by AGC. Historically, the 1% floor for Frequency
Bias Setting was chosen to ensure that BAs are always over-biased. The standard needs to allow some
margin in the Frequency Bias Setting to ensure that the bias setting is over-biased
Response: The SDT agrees with your clarification that the 1% minimum applies to the Frequency Bias Setting. We also agree to evaluate the need to be
somewhat (as opposed to extremely) over-biased. For example, if a Balancing Authority’s observed Frequency Response was .4% of its annual forecasted peak
load then, at a minimum, a value such as .1% would be added to the Frequency Bias setting to make it less likely that the Frequency Response will be
counteracted by AGC actions.
Bonneville Power Administration
No
Until the calculations used for FRO are spelled out and how natural Frequency Response is to be measured,
BPA cannot agree that elimination of the 1% minimum will bring Frequecy Bias closer or equal to natural
Frequency Response.
Response: The SDT has provided clarification in Attachment A, Attachment B and the Background Documents.
IRC Standards Review
No
Please provide the technical basis for the 4-year phase-out schedule.
91
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001735
Organization
Yes or No
Committee
Question 8 Comment
The SRC suggests that incremental changes should be made and evaluated to determine whether they are
indeed beneficial before additional changes are made. Until a standard is defined, it is not appropriate to set
an implementation date on the transition.
Also, please clarify that the process is to gather data, analyze that data to determine what has been the actual
frequency response, and then to determine the Frequency Bias Settings to be closer to or equal to the natural
frequency response, and is not saying that the next actual frequency response must equal the Frequency
Bias Setting that the ERO has assigned. There is a subtle difference here that must be clarified in order to
avoid the unintended consequence of “punishing” an entity for not providing a response equal to the
Frequency Bias Setting.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
The intent of the Implementation Plan proposed was to evaluate the effectiveness of each setting change before additional refinement to the Frequency Bias
Setting is made and incorporated into the AGC algorithm. This has been removed from the Implementation Plan. The SDT has chosen an alternate method for
reducing the minimum Frequency Bias Setting.
Standard language is not intended to penalize entities for not providing a response equal to its Frequency Bias Setting. The intent of the standard is to establish a
Frequency Response Obligation (FRO) representing the minimum response required for reliable interconnected operations. The Frequency Bias Setting can differ
from the determined FRO value as appropriate for reliability for which compliance will only evaluate if the Frequency Bias Setting is refined correctly and
implemented in a timely manner.
ERCOT
No
Please provide the technical basis for the 4-year phase-out schedule. The SRC suggests that incremental
changes should be made and evaluated to determine whether they are indeed beneficial before additional
changes are made. Until a standard is defined, it is not appropriate to set an implementation date on the
transition.
Also, please clarify that the process is to gather data, analyze that data to determine what has been the actual
frequency response, and then to determine the Frequency Bias Settings to be closer to or equal to the natural
frequency response, and is not saying that the next actual frequency response must equal the Frequency
Bias Setting that the ERO has assigned. There is a subtle difference here that must be clarified in order to
avoid the unintended consequence of “punishing” an entity for not providing a response equal to the
Frequency Bias Setting.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
The intent of the Implementation Plan proposed was to evaluate the effectiveness of each setting change before additional refinement to the Frequency Bias
Setting is made and incorporated into the AGC algorithm. This has been removed from the Implementation Plan. The SDT has chosen an alternate method for
92
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001736
Organization
Yes or No
Question 8 Comment
reducing the minimum Frequency Bias Setting.
Standard language is not intended to penalize entities for not providing a response equal to its Frequency Bias Setting. The intent of the standard is to establish a
Frequency Response Obligation (FRO) representing the minimum response required for reliable interconnected operations. The Frequency Bias Setting can differ
from the determined FRO value as appropriate for reliability for which compliance will only evaluate if the Frequency Bias Setting is refined correctly and
implemented in a timely manner.
Kansas City Power & Light
No
Simply eliminating the minimum frequency response and establishing an FRO obligation for each BA will not
result in a knowledge that a BA has moved closer to its natural frequency response. First, there is an
underlying assumption that the FRO dictated for the BA will be “matched” by a BA’s resources to achieve a
natural response close the FRO and until improved methods of calculating a BA’s actual frequency response
are developed, there will be no accurate way of determining if a natural response is close to the FRO
obligation.
Response: The intent of the first sentence in the comment above is not clear. There is no underlying assumption that natural response will match the
frequency response obligation. However, the compliance process will provide a stimulus to the BA to achieve at least that level of frequency response.
The FR SDT is expending considerable effort to develop a reasonably accurate measurement of natural response, and is in the process of choosing among several
promising metrics.
NorthWestern Energy
No
Page 2 implies that there is currently too much frequency response based on the 1% of peak demand method
of establishing frequency bias. Even though NWE does not use the 1% method, NWE feels that the 1%
minimum has been a tried and true method of providing frequency response in the Western Interconnection.
Without the 1% minimum (and BA’s using a natural response less than the 1%), the total interconnection
frequency response would decrease according to research. This would lead to decreased interconnection
bias, causing other operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The opening sentence of this comment appears to be a misstatement. The FR SDT believes a gap exists between the natural Frequency Response
and the Frequency Bias Settings calculated based on the 1% of peak demand criteria, resulting in excessive and unnecessary regulation occurring that is related
to high frequency conditions following DCS events and other circumstances. The FR SDT agrees that a reduction in the 1% of peak demand criteria for the
Frequency Bias Setting can adversely affect the overall Interconnection Frequency Bias Setting, L10 values, and possibly CPS 2 compliance also.
Westar Energy
No
The 1% requirement should be phased out with the implementation of this standard.
Response: The technical basis for the phase out schedule is to allow time to evaluate how each Frequency Bias Setting change impacts both reliability and
control criteria CPS1 and CPS2 performance.
FMPP
No
There still needs to a floor value; 1% may not be the correct value, but zero is not the correct floor.
93
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001737
Organization
Yes or No
Question 8 Comment
Response: The floor will not be zero. Each Balancing Authority will have a required FRO contribution reflective of the natural Frequency Response in its
Frequency Bias Setting.
American Electric Power
No
Please see response to question 7.
Response: Please see our response to Question 7.
Duke Energy
No
Duke Energy agrees that a gradual reduction (in magnitude) of the minimum as part of the field test is needed
to determine what is the “right” amount of response needed, but the changes cannot be done in a vacuum.
Duke Energy continues to be concerned with the impact that the changes to the Frequency Bias Setting
(“FBS”) will have on the bounds guiding secondary control (CPS1, CPS2 and the draft Balancing Authority
ACE Limit or “BAAL” currently under a Field Trial under NERC Project 2010-14). Eastern Interconnection
Frequency Response: For those not familiar with the work of the FRRSDT or the NERC Resources
Subcommittee around Frequency Response, the estimated response for the Eastern Interconnection on
average appears to be less than half of the Interconnection’s total FBS in magnitude today. If the decision
was made to hold Frequency Response at its current level, this standard could result in the FBS being
reduced for many, if not most, Balancing Authorities to about half of what it is today. The FRO allocation
would eventually drive what the minimum FBS needs to be, with the FBS needing to be greater than or equal
to the FRO, or perhaps FRM, in magnitude at a minimum.
Estimating the impact: To look further into the secondary control performance implications of BAs using a
reduced FBS, Duke Energy took four sample months of clock-minute data for twelve BAs, cut the
Interconnection total and each BA’s FBS in half, recalculated each BA’s clock-minute ACE taking out half of
the bias component, and then calculated CPS1, CPS2 and BAAL estimated performance based upon those
changes. Recognizing that the secondary control and resulting ACE of the BAs would be different and
dependent upon the standards to be met, the results were not intended to estimate what the performance of
the BAs would be, but were intended to help indicate where the problem areas existed based upon today’s
operation measured to a tighter control criteria. Impact on CPS1 and BAAL: The two bounds that are
frequency-dependent, CPS1 and the draft BAAL, are cut in half for any given frequency by cutting the FBS in
half. For CPS1 the impact of reducing the FBS looked reasonable with the results leaning toward overall
improvement in CPS1 for almost half or better of the BAs (5 of 12, 8 of 12, 6 of 12, and 12 of 12) for the given
months even with the tighter bounds, but more analysis may be needed. Though CPS1 looks manageable,
the sample set did not include small BAs, and some BAs already in the 100-120% range appeared more at
risk. For BAAL the longest duration of ACE exceeding the low or high BAAL stayed the same or got worse in
all cases. As with today where the BAAL bounds get wider as frequency gets closer to 60 Hz where the
majority of operation occurs, the additional flexibility of operation is offset by the BAAL bounds getting tighter
than the CPS2 limits as frequency deviates farther from 60 Hz. With BAAL cut in half for this scenario,
compliance will be more challenging and costly to manage to not exceed 30 minutes for any event. One of the
94
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001738
Organization
Yes or No
Question 8 Comment
unknowns is whether the Frequency Trigger Limit for the BAAL calculation will stay where it’s at or be
lowered, as the current value was based upon UFLS at 59.82 Hz, rather than today’s UFLS of 59.7 Hz. The
BARCSDT under NERC Project 2010-14 has more work ahead before any changes can be proposed.Impact
on CPS2: Though the industry is not seeing a reliability need to tighten secondary control in normal operation,
the industry can’t avoid such “tightening” with CPS2 limits directly dependent upon the FBS of the Balancing
Authority and total FBS of the Interconnection. For the four months reviewed where CPS2 limits were cut in
half, if one looked at the results individually the drop in CPS2 performance across the twelve BAs ranged from
2.6% to 33.8%, 4% to 33.5%, 3.8% to 37.8%, and 3.1% to 35.1%, with a median of 19.4%, 18.4%, 20.3% and
18.9% for the four months. Noting that CPS2 performance must be 90% or greater on a monthly basis,
improving CPS2 performance by even 10% translates to over 70 hours of operation in a month where
additional secondary generation control and other actions may be required. Duke Energy notes also that with
less error in the ACE, the results indicate that the distribution of ten-minute events exceeding L10 would move
closer toward the 50-50 chance that CPS2 will be forcing control action even though the ACE is in support of
the Interconnection frequency (results showing the average moving from 27-34% to 39-43% of the ten-minute
periods exceeded when in support of Interconnection frequency).Conclusion: Duke Energy does not believe
there is a reliability need pushing the industry to tighten secondary control to the degree discussed above
simply as a result of reducing the Frequency Bias Setting. If the calculated Frequency Response of the
Interconnection stayed at its current level, what would be the justification for tightening the secondary control
requirements of CPS1, CPS2 and the proposed BAAL? Duke Energy supports taking more of the error out of
the ACE equation by having the FBS closer to the estimated Frequency Response of the Balancing Authority,
however, Duke Energy does not believe the result should be a significant increase in secondary control costs
to meet the CPS1, CPS2, or draft BAAL requirements.
Response: The SDT appreciates receiving this analysis of the impact Frequency Bias setting can have on secondary control. Please continue to analyze and
share this technical data to the extent possible with the SDT. The SDT will perform comparable analyses during the field trial for determining the proper balance
between having less “over control” than is perceived with respect to possibly increasing the secondary control cost incurred by individual Balancing Authorities
because a smaller Frequency Bias Setting is utilized.
Alberta Electric System Operator
No
The standard seems to propose to replace the 1% minimum frequency bias with the new proposed FRO. The
AESO finds it difficult to comment on if it is not clear on how the FRO is determined.
Response: The Frequency Response Obligation is used for determining if there is sufficient primary Frequency Response for reliability. The minimum Frequency
Bias Setting to be used in AGC will have a floor value needed to assure reliable control, and can be different than the Frequency Response Obligation.
The SDT has modified Attachment A to provide additional clarity regarding the calculation methodologies.
Independent Electricity System
Operator
Yes
We do not have an opinion on the proposed elimination but do have a difficulty understanding the phase-out
plan. Please see our comments under Q7, above.
95
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001739
Organization
Yes or No
Question 8 Comment
Response: The FR SDT has created Attachment B to provide clarifying language for the phase-out plan.
Please refer to the SDT response to question #7.
SPP Standards Development
Yes
While we agree that we think such a change will move the industry in the right direction, we have nothing
upon which to base that opinion. On the other hand, the 1% minimum does provide a safety net for the
interconnection. Moving away from the minimum requirement over a 4-year period should give us the
necessary operating experience to become more confident in our numbers.
Response: The goal of the phase-out plan is to determine the best Frequency Bias Setting floor value to use for reliability that is based on a measured and
cautionary approach.
Southern Company
Yes
Comments: Agree only to the extent that the natural Frequency response can be accurately determined.
Response: The FR SDT is investing considerable effort on behalf of industry to develop a reasonable, practical and accurate measurement of natural frequency
response and also a process for choosing the best of several promising metrics.
Progress Energy
Yes
We have seen actual system operations harmed by the current, excessive biasing requirement on several
occasions.
Response: The SDT thanks you for your affirmative response and clarifying comment.
NIPSCO
Yes
Obviously it will bring it closer. The 4 year phase-in is a great idea.
Response: The SDT thanks you for your affirmative response and clarifying comment..
Manitoba Hydro
Yes
Yes, the removal of the 1% of projected peak load which has a large window of probability for error should
improve BIAS calculations.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Patterson Consulting, Inc.
Yes
Moving Frequency Bias Settings closer to natural Frequency Response is critical to improving observation,
reporting, and control.
Response: The SDT thanks you for your affirmative response and clarifying comment.
South Carolina Electric and Gas
Yes
96
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001740
Organization
Yes or No
EKPC
Yes
Energy Mark, Inc.
Yes
Beacon Power Corporation
Yes
ENBALA Power Networks
Yes
SERC OC Standards Review
Group
Yes
FirstEnergy
Yes
Santee Cooper
Yes
LG&E and KU Energy
Yes
Arizona Public Service Company
Yes
Seattle City Light
Yes
ISO New Engand Inc.
Question 8 Comment
With .4% peak load being a typical actual frequency response lately for Balancing Authorities, the 1% of peak
load to .8% of peak load transition seems prudent. Perhaps a further reduction to .6% may be useful as well,
but lesser floors may in effect result in AGC too often canceling out the primary frequency response being
provided.
Response: The SDT thanks you for your clarifying comment.
Associated Electric Cooperative,
Inc.
I agree with this emerging standard’s recognizing that the arbitrary 1% of peak-load should be refined by
being lowered to better reflect each BA’s expected frequency response.
Response: The SDT thanks you for your clarifying comment.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
97
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001741
Organization
Yes or No
Question 8 Comment
Response: Please refer to the SDT response to Question 17.
98
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001742
9. Do you agree with the drafting team that this standard should be field tested? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters agreed that this standard should be field tested. Most commenters indicated
that the implementation plan should include information regarding the field trial and also be coordinated with the field trial schedule.
Individual commenters suggested that the field trial is not required if detailed calculations and definitions were provided to entities for
implementations and the field trial should not serve as a pre-established standard.
In response to industry feedback received, the SDT is presently field testing the methodologies for calculating FRM and FRO. The reduction
of the Frequency Bias Setting is no longer part of the field trial. The SDT has defined a process for the ERO to follow to reduce the
minimum Frequency Bias Setting once this proposed standard has been approved..
Organization
FirstEnergy
Yes or No
Question 9 Comment
No
We believe that the implementation plan should include information regarding the field trial and how it fits in
with the phase-in implementation. It appears as though the field trial is being conducted based on 2010 data
and will be concluded upon completion of the development of the standard but we think this could be clarified.
Furthermore, as stated in the process manual, a field test “should include at a minimum the data collection
and analysis or field test plan, the implementation schedule, and an expectation for periodic updates of the
results.” The field test information posted is not clear on the implementation schedule of the field test as well
as when and how periodic updates will be available.
Response: Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing
another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections.
Please refer to Attachment B for reduction plan details.
Bonneville Power Administration
No
BPA believes that this standard as written should not be field tested. The calculations to be used to set
frequency bias must be spelled out in detail and the definition of natural Frequency Response under multiple
loading conditions must also be detailed. Once these conditions have been adequately met, there will not be
a need for a field trial.
Response: Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting.
The plan is no longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing
another method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections.
99
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001743
Organization
Yes or No
Question 9 Comment
Please refer to Attachment B for reduction plan details.
MRO's NERC Standards Review
Subcommittee
Yes
The field test is not identified in the implementation plan. It should be.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary correction. Please refer
to Attachment B for reduction plan details.
Midwest ISO Standards
Collaborators
Yes
The field test is not identified in the implementation plan. It should be.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
SPP Standards Development
Yes
Field testing will provide an opportunity to learn as we move forward with the standard. Modifications can be
made as experience is gained and knowledge is acquired.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary correction. Please refer
to Attachment B for reduction plan details.
IRC Standards Review
Committee
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
100
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001744
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
ERCOT
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
ISO New Engand Inc.
Yes
A Field Test, sometimes called a Field Trial, is appropriate to identify and establish methods, but it should be
a Field Trial, not a pre-established standard. The standard should be put into place later after the technical
determinations have been accomplished.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Arizona Public Service Company
Yes
What criteria will be used to evaluate the field trial? What constitutes acceptable/non-acceptable results?
[see also, comments to question 7]
Response: Please refer to our comments for Question 7.
Progress Energy
Yes
This plan should be field tested, although it feels as though this is less of a "field test" based on engineering
judgement and more of trial and error testing. This problem should be studied to determine what is necessary
101
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001745
Organization
Yes or No
Question 9 Comment
to manage system frequency within desired limits for the worst single contingency during the period of time
the system is most vulnerable (minimum load). The result should be spread proportionally to all BAs in the
interconnection, and those BAs should respond to and bias their ACE equation by the required value.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Attachment A has been revised to clarify the calculation methodology.
NIPSCO
Yes
Great idea
Response: The SDT thanks you for your affirmative response and clarifying comment.
Westar Energy
Yes
This is a major change and field testing is required to valid the standard and allow for revisions based on
testing results
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Manitoba Hydro
Yes
Yes, to ensure the eastern interconnection frequency health does improve with these new methods and if it
does each BA will have a more accurate and fair BIAS setting.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
American Electric Power
Yes
The changes proposed should be thoroughly tested before any implementation.
102
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001746
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Patterson Consulting, Inc.
Yes
A field test will provide valuable refinment and verification of parameters, and should identify unexpected
ramifications.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
South Carolina Electric and Gas
Yes
We do agree that a field test should take place but more details on the field test would be helpful.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Independent Electricity System
Operator
Yes
The time required for the field test should be taken into account when developing the implementation plan,
especially the phase-out plan for R5.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Requirement R5 has been inserted back into the proposed standard. SDT has revised the plan for reducing the minimum Frequency Bias Setting. The plan is no
longer tied to the Field Trial. The SDT has removed the table showing the reduction schedule for the minimum bias setting. The SDT is proposing another
method for reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reduction and make necessary corrections. Please refer
to Attachment B for reduction plan details.
Santee Cooper
Yes
103
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001747
Organization
Yes or No
LG&E and KU Energy
Yes
SERC OC Standards Review
Group
Yes
Kansas City Power & Light
Yes
Southern Company
Yes
ENBALA Power Networks
Yes
NorthWestern Energy
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
EKPC
Yes
We Energies
Yes
Alberta Electric System Operator
Yes
Duke Energy
Yes
Seattle City Light
Yes
Northeast Power Coordinating
Council
Question 9 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
104
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001748
10. Attachment A of the proposed standard describes the criteria for selecting events to be analyzed. Do you agree with the criteria as
described in Attached A? If not, please explain in the comment area.
Summary Consideration: Comments received indicate the majority of commenters agree with having criteria for selecting events to be
analyzed and requested clarification on the rationale for the criteria proposed. Research performed by the FRR SDT indicates analysis
using 25 events and mean frequency data values will result in stable, consistent results.
Many commenters also expressed concern that the selection criteria was too stringent; that criteria language would omit selection of
events worth reviewing; that Balancing Authorities should have flexibility in choosing which event data is selected and also have ability to
modify submitted data for ensuring accuracy; and that using event data from the prior year could create double jeopardy. The intent for
frequency values selected is to ensure most generators responsive to the interconnection will experience a governor response. The FRR
SDT also agrees that interconnection subject matter experts and Balancing Authorities require the flexibility to select noteworthy events of
interest, flexibility to identify which events to include or exclude for analysis, and allowance for modifying data for quality and other
relevant concerns. The FRR SDT also believes that in those years where 25 acceptable events do not exist, stability and consistency
concerns outweigh any adverse impacts from utilizing a few events from the previous year for analysis and that actual impact on current
year results will be negligible.
After reviewing comments, the FRR SDT has revised Attachment A language for clarity. The team separated the rationale into a separate
document and also revised Form-1.
Organization
Santee Cooper
Yes or No
No
Question 10 Comment
In Attachment A, item 2.b. states that “The time from the start of the rapid change in frequency until the point
at which Frequency has largely stabilized should be less than 18 seconds.” It appears that this statement
was to ensure that frequency is rapidly decaying; however, frequency could continue to decay beyond 18
seconds and should still be considered an event.
Item 3 states that point A is calculated as “an average” is this considered to be an average of all samples or
selected samples.
Also, we would like to know how the different thresholds for the interconnections were determined.
We are also concerned with how the threshold would affect compliance to the standard if it was ever required
to be measured on an event basis, particularly those events close to the threshold dead-band settings. Words
such as “assumed” should be avoided.
Please explain how the number of 25 events was determined for the list of frequency events and explain how
those events will be distributed throughout the year (i.e., on and off-peak, and seasonal).
105
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001749
Organization
Yes or No
Question 10 Comment
Events that meet the selection criteria should be posted by the ERO on a monthly basis. This will allow BAs
to evaluate their performance throughout the year.
Response: The intent for using the words “largely stabilized” in the sentence provides desired flexibility for selecting events for analysis. For example, if
frequency drops from 60 Hz to 59.94 Hz in 6 seconds and then continues to decay to 59.935 Hz over the next 20 seconds; then this event would be selected for
analysis.
With respect to point A, all available samples for the time window specified are averaged. The number of samples obtained for averaging will be determined by
the Balancing Authority’s EMS scan rate.
Each Interconnection threshold will be determined by subject matter experts who have knowledge of the historical events being analyzed, CERTS research and
field trial results. It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis
difficult to validate.
Analysis of metrics being considered by the SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event samples
obtained for the year being reviewed. The SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection criteria
specified.
The SDT proposes posting event data on a quarterly basis so Balancing Authorities can periodically analyze data during the year.
Attachment A has been divided into two separate documents; a revised Attachment A containing the calculation methodology and a Background Document
explaining the development rationale for the standard’s requirements and measures.
Bonneville Power Administration
No
BPA does not agree with the criteria described in the attachment. 36 mHz is not a large enough deviation to
adequately measure frequency response. There is no need to go to that small of a deviation in order to
insure that 25 events are found over the course of a year.
Response: The FR SDT will consult with WECC subject matter experts to refine the frequency deviation selection criteria for the western interconnection. Keep
in mind the selection threshold will be adjusted over time, as supported by evidence, to ensure reasonable selection criteria is utilized.
SPP Standards Development
No
While Criteria 5 allows for the ERO to exclude 'non-conforming' SEFRD points there isn't a mechanism
provided that instructs us on how to exclude those points in FRS Form 1.
Would we be required to reach out for an additional point to get us back to 25 if a point is excluded? Who
excludes the point in question? Is it the BA or is it the ERO? Will the ERO have sufficient knowledge to
exclude the point in question?
In Critieria 2.a. the first sentence should read "The frequency deviation (Point A minus Point C) must
exceed...". Also, 36 MHz should be 36 mHz.
Response: The SDT has developed a new version of FRS Form 1, and it clarifies the process of how a Balancing Authority excludes an event. The ERO will not
106
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001750
Organization
Yes or No
Question 10 Comment
exclude events.
The Balancing Authority would not be required to replace an excluded event with another event since analysis of metrics being considered by the SDT shows the
median or mean frequency data analyzed will converge to a stable state using only 20 event samples obtained for the year being reviewed. Analysis also shows
that the median value is more consistent than the mean value when the sample set includes data for an event that otherwise should have been excluded from the
analysis.
The SDT thanks you for catching the typographical error referencing 36 mHz. The SDT has revised Attachment A and this value is no longer referenced..
IRC Standards Review
Committee
No
The criteria for events selection are acceptable, but the criteria stated in Attachment A for performance
required by the FRO is too stringent. Criteria requiring avoidance of Point C encroachment on step 1 of the
UFLS program is more stringent than proven performance that now exists. To make this change will be very
costly and will not provide for a commensurate increase in reliability.
Response: FRO values have not yet been selected. The intent is to choose FRO values that are necessary for the reliability of each interconnection.
ERCOT
No
The criteria for events selection are acceptable, but the criteria stated in Attachment A for performance
required by the FRO is too stringent. Criteria requiring avoidance of Point C encroachment on step 1 of the
UFLS program is more stringent than proven performance that now exists. To make this change will be very
costly and will not provide for a commensurate increase in reliability.
Response: FRO values have not yet been selected. The intent is to choose FRO values that are necessary for the reliability of each interconnection.
Southern Company
No
Comments: Selecting events just outside the governor deadband (e.g. 36 mHz in the EI) is not a good idea in
that it assumes too much precision in the response by governors at the deadband boundary. This will result
in a less accurate natural Frequency Response calculation for those large events where knowing an accurate
Frequency Response value is most critical. In other words the event selection “deadband” should be
somewhat larger than the Governor deadband even those this will result in somewhat fewer events in the final
set.
Response: The intent is to choose among the largest frequency deviation events to obtain a meaningful sample set for analysis accuracy. The FR SDT is open
to suggestions to refine the selection criteria for each interconnection. A balance needs to be established between having an inadequate sample resulting in less
computational accuracy versus having a sample that is not representative of actual response occurring for the larger frequency deviation events of concern.
Progress Energy
No
It should be explicitly stated that point C must be outside the standard frequency deviation deadband
referenced from 60.0 Hz, not a deviation of more than the frequency deviation deadband from the predisturbance frequency. Most of the new electronic govenors operate with a 60 Hz center instead of changes
in frequency relative to the current value.
107
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001751
Organization
Yes or No
Question 10 Comment
Additionally, the first limit under number 2 should be 36 mHz, not 36 MHz as they are a factor of 10^9
different.
Lastly, the event selection criteria listed in Attachment A uses the frequency as measured at Point C to qualify
an event, in an effort to ensure that the deviation exceeds the governor deadband. However, Point C is an
instantaneous point which will differ in value within the interconnect based on how close the loss of generation
is to the measuring point due to the elasticity of frequency across the interconnect during the inertial
response. Therefore, local readings by the BA should be allowed to exempt a specific event if the local
frequency did not exceed 36 mHz.
Response: It is expected that the selection criteria will yield events with Point C that clearly exceed the generator governor deadband and result in a response
action. While the distance between the measuring point and the loss of generation location will cause different Point C (and other) frequency values being
measured at different system locations, the variation in Point C frequency values among the different locations will not be significant for most events or most
Balancing Authorities. Keep in mind each Balancing Authority will use its EMS local frequency data for determining sample points A and B. The FR SDT
anticipates selecting events that will not require the Balancing Authority to exclude events because of local frequency values measured. The FR SDT will consider
high local frequency as a possible selection criteria exclusion factor in the next revision of Form 1.
NorthWestern Energy
No
Should state “ The Point C value is the minimum of frequency samples and should be within 8 seconds after
the start of the rapid change”. NWE feels some instances could be more than 8 seconds and “should” would
allow for this if it occurred.
Response: The original intent was to exclude such events however the SDT understands some of these events may provide interesting and valuable
information. Language proposed would give subject matter experts selecting the events necessary leeway to include such events. The SDT will consider
changing “shall” language to give subject matter experts more flexibility with selecting events.
Hydro-Quebec TransEnergie
No
The criteria to determine what should be considered as a frequency event should be defined by
Interconnection. For example, HQT has no dead band on governors; therefore the 36 mHz is not applicable.
If more than 25 events occurred within a year, will they all be selected or only a set of 25 will be? Who will
perform this selection and base on what criteria.
Response: Event selection criteria will be specified on an interconnection basis after consulting with subject matter experts for that interconnection. Selected
events will be chosen by subject matter experts for that interconnection.
Westar Energy
No
The lagging measure is a concern. The ERO should be required to provide an updated proposed/possible list
of frequency events monthly so BA's can determine their FRM through out the year so corrective action can
be taken if needed.
Prior year events should be excluded (just to get to 25 events). This could result in begin non-compliant twice
for the same events. If a BA is over performing in the first of the year and adjusts in the second half of the
108
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001752
Organization
Yes or No
Question 10 Comment
year then those second half of the year events are used in the next year, it could cause an inappropriate
violation.
BA's need the ability to exclude some events based on measure issues with specific events including scan
rates, unusual intermittent resource changes, non-conforming load, unusual ramping of load or interchange
during the event.
Response: Based on comments received from industry, the SDT proposes posting event data on a quarterly basis so Balancing Authorities can periodically
analyze data during the year.
Generally, each Balancing Authority will have 25 acceptable events occur each calendar year. Using a few events from the preceding year is not expected to
adversely affect accuracy of analysis results. The SDT is re-evaluating exclusionary criteria and is also developing a process to permit reasonable adjustments to
an event for atypical circumstances.
FMPP
No
Attachment A states that if a year occurs in which there are not 25 events that meet the remaining criteria
below, then the most recent 25 events (as defined below) will be used for determination of an entity’s
compliance with the FRM requirement and storage of SEFRD.
Problem - by using events from last year to determine an entity’s compliance with a Requirement for this year
puts the entity in double jeopardy for last year’s events, which were already used for compliance for last year.
Attachment A states that events occurring during periods in which either significant interchange schedule
ramping or load ramping is likely, should be excluded if other events are available for measurement purposes.
Questions - What is significant?How can the ERO determine significant interchange schedule ramping is
likely?Likely for how many BAs?It would be better to define significant and let the BA exclude any events that
meet this definition, since each BA will be ramping differently. Since SEFRD is defined as the individual
sample of event data from a Balancing Authority which represents the change in Net Actual Interchange
(NIA), divided by the change in frequency, expressed in MW/0.1Hz, whenever a BA includes an event with a
“significant” change in NIA due to a large interchange schedule ramp, the FRM is totally skewed, and should
not be included. If other events are available means that if other events are not available then an entity’s
compliance is going to be based on an event or events that has been skewed for the BA by significant
interchange schedule ramp.
Response: Generally, each Balancing Authority will have 25 acceptable events occur each calendar year. Using a few events from the preceding year is not
expected to adversely affect accuracy of analysis results. The SDT is re-evaluating exclusionary criteria and is also developing a process to permit reasonable
adjustments to an event for atypical circumstances. The SDT does not expect subject matter experts will select events with rapid load change or large schedule
change activity. Large schedule changes typically occur between 7 AM and 8 AM, and 10 PM and 11 PM, with 10 minute ramps across the top of the hour.
Having Balancing Authorities exclude these kinds of events could be problematic because balancing areas are different in size from one Balancing Authority to the
next. The SDT has developed a manual correction capability for the sampling process which, when used in conjunction with median value rationale, should
minimize the impact data skewing tendencies may have on analysis results.
109
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001753
Organization
American Electric Power
Yes or No
No
Question 10 Comment
Attachment A only appears to be attempting to address the frequency bias setting for AGC portion of overall
frequency response without addressing the governor response portion issue. Attachment A still tries to
address the issue solely at the Balancing Authority level without addressing criteria at the Generator &
Generator Operator levels.
WECC has stated through previously submitted comments from its three extensive validation result tests on
frequency response with respect to 5% droop for a 0.1 Hz frequency deviation that actual response would be
2.5 times greater if the proper governor response actually occurred. The studies also showed only 40% of the
governors effectively responded. Extensive test result studies such as WECC’s should not be ignored.
Attachment A criteria does not address the lack of frequency response from contributing factors associated
with actual governor response, impact of droop setting, amount of BA generation actually on-line at time of
event, maximum loading of generation and amount of BA imported interchange to meet load.
Response: The need for an accompanying generation SAR has been discussed and is outside of the current FR SDT scope. Verification of generator governor
response is important. The FR SDT encourages entities to continue studying generator governor response and related contributing factors cited.
Patterson Consulting, Inc.
No
I agree that criteria for event selection are needed, although these criteria appear to be unnecessarily
subjective. Items 1 and 2 are appropriate. However, item 3 seems to eliminate many events that should be
reviewed. For example, item 3 would eliminate any event with an initial frequency that is not 60 Hz, depending
on the subjective determination of "near" and "relatively steady."
Similarly, items 5 and 6 add more subjectivity to the selection of events, but may be necessary. It is not clear
that criteria listed in Attachment A are required to be used since much other content appears to be
explanatory, contextual, and instructional. These explanatory, contextual, and instructional aspects are
important, but should not be requirements.
Attachment A should be limited to event selection and calculations necessary to support the stated
requirements. Instructional, etc. information should be moved to another document. If other "requirements"
are included in Attachment A, they should be moved to the standard.
FRS Form 1 should be an attachment as this form contains and performs the required calculations. The
remaining information in Attachment A should become either a standalone (technical) document, or be
combined with information such as "FRS Form 1 Background and Instructions" and renamed.
As further clarification regarding the ambiguity identified in the previous paragraphs, Attachment A could be
interpreted as additional requirements on the Balancing Authority, ERO, or both. The language and scope are
not sufficiently clear to identify whether statements are informative or requirements. This lack of clarity makes
it impossible for entities to identify requirements, acquire appropriate tools and resources related to
requirements, and to provide suitable performance to meet requirements. For example, the statement "A final
listing of official events to be used in the calculation will be available from NERC by December 10 each year."
may be intended as a requirement rather than a statement suggesting a typical schedule. Further, if the
110
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001754
Organization
Yes or No
Question 10 Comment
previous statement is a typical schedule, then the statement "The ERO will use the following criteria for the
selection of events to be analyzed." could be interpreted as merely the typical process to be used, but not a
binding one. In short, the purpose and intention of Attachment A is not communicated unambiguously.
Response: Item 3 was intended as guidance to give subject matter experts flexibility in choosing the best possible events for analysis. The SDT recognizes that
in some years valid but less than ideal events from a selection criteria perspective may be chosen for analysis. The SDT will improve document clarity and also
consider if it is prudent to make selection criteria hard or soft requirements.
Attachment A has been divided into two separate documents; a revised Attachment A containing calculation methodology and a Background document explaining
the development rationale for the standard requirements and measures.
Xcel Energy
No
1) Using 25 events is likely excessive in the Western Interconnection. Several of the past few years have had
less than 10 events. Given the extent to which generation is built and resource profiles change, projecting 25
events will include events in the bias calculation that are less reflective of the current generation profile and
skew our bias results.
2) Calculating point A as “...an average over the period from -16 second to 0 seconds” for any event that
meets the criteria set in Attachment A means that Point A will likely be within 1-2 mHz of 60 Hz, regardless of
starting system conditions. This can cause data to be skewed, as the response will appear to be less if the
frequency immediately before the event is further from 60 Hz than the average. Further, it requires additional
data. If there is some corrupted data in the 16 seconds prior to the event, it may be required to throw out
event data. The 16 seconds prior to the event is not useful data.
3) Point 5 addresses excluding events “...in which significant interchange schedule ramping or load ramping is
likely...” Not only are the FRO and FRM definitions too vague, they require analysis of real time generation
and load ramping that may not be realistic. Attachment A should likely include specific criteria for removing
events, including lack of reasonable data and, as described here, significant schedule or load ramping, where
“significant” is defined.
Response: The SDT has reviewed your concern and determined that the WECC would have sufficient event data to analyze. Keep in mind an ERO specified
event can be excluded if data quality issues associated with FRS Form 1 exist. Also, manual adjustment to the actual net interchange value for schedule ramping
can be performed for completing FRS Form 1. Event selection criteria will allow sufficient flexibility for subject matter experts to avoid periods of rapid load
change (e.g., morning pickup and declining late evening load) and ten minute ramps across the top of the hour to the extent possible. The intention is to guide
the subject matter experts in choosing the best data set available so that relatively few adjustments, if any, will be needed.
LG&E and KU Energy
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
111
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001755
Organization
Yes or No
Question 10 Comment
distributed throughout the year (i.e., on and off-peak, and seasonal).The criteria in Attachment A should
include how and where the arresting frequency is measured
Response: The SDT thanks you for your affirmative response and clarifying comments.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event samples
obtained for the year being reviewed. The SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection criteria
specified.
Generally, subject matter experts will use high speed frequency recorder data to select events for analysis. Technology is now available that allows crosschecking data at multiple locations for the same event.
SERC OC Standards Review
Group
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
distributed throughout the year (i.e., on and off-peak, and seasonal).
Response: The SDT thanks you for your affirmative response and clarifying comment.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
South Carolina Electric and Gas
Yes
While we agree with the basic process, we would like to know how the different thresholds for the
interconnections were determined. The review team is also concerned with how the threshold would affect
compliance to the standard if it was ever required to be measured on an event basis, particularly those events
close to the threshold dead-band settings. Words such as “assumed” should be avoided. Please explain how
the number of 25 events was determined for the list of frequency events and explain how those events will be
distributed throughout the year (i.e., on and off-peak, and seasonal).
112
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001756
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
Arizona Public Service Company
Yes
AZPS would recommend using a lesser number of events and more severe events in the calculation.
Response: The SDT thanks you for your affirmative response and clarifying comment.
A balance needs to be established between having an inadequate sample resulting in less computational accuracy versus having a sample that is not
representative of actual response occurring for the larger frequency deviation events of concern.
NIPSCO
Yes
Pretty good
Response: The SDT thanks you for your affirmative response and clarifying comment.
EKPC
Yes
Please provide detailed information on the 25 events that will be chosen for the event.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been revised to include an improved detailed description of the criteria selection process.
The magnitude of the frequency change and the initial frequency values identified were selected to ensure that most generators responsive to the interconnection
will exceed the governor frequency dead band limits.
It is not the intent of this standard to seek compliance on a per event basis especially since data quality issues make this type of analysis difficult to validate.
Analysis of metrics being considered by the FR SDT shows the median or mean frequency data analyzed will converge to a stable state using only 20 event
samples obtained for the year being reviewed. The FR SDT expects the sample set to include seasonal, on-peak, and off-peak events that satisfy the selection
criteria specified.
Manitoba Hydro
Yes
Yes, 25 events should be sufficient to determine the FRM, while not overburdening the resources performing
the analysis.
113
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001757
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Duke Energy
Yes
Seattle City Light
Yes
We Energies
Yes
Energy Mark, Inc.
Yes
ENBALA Power Networks
Yes
Kansas City Power & Light
Yes
Midwest ISO Standards
Collaborators
Yes
FirstEnergy
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
AESO suggests that the criteria should also consider including some frequency events where the BA has
controlled separation from a region. In the case of Alberta, the frequency deviation is larger than most
regional frequency deviations and provides a better measure on Frequency Response. Would the proposed
standard permit for BA's to choose these events for inclusion in the determination of the frequency response?
Response: This is not a common occurrence. Very few Balancing Authorities operate in this manner. The expectation is events will be selected by the Balancing
Authorities. The Balancing Authority may exclude events from consideration for specific conditions such as data quality issues.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to the SDT response to Question 17.
114
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001758
11. The proposed standard has a document attached to it that describes the SDT’s reasoning for the Requirements (Attachment A - Frequency
Response Background Document). Do you agree with the SDT that this document is useful and provides a clear understanding of the
Requirements? If not, please explain in the comment area.
Summary Consideration: Several of the commenters did not agree that the Attachment A – Frequency Response Background document
in its current form was useful and provided a clear understanding of the Requirements. In general most commenters indicated that
Attachment A required correction, greater clarity and did not adequately explain the calculation methodology. The SDT has split
Attachment A into two separate documents, revised Attachment A to better explain the calculation methodology, and improved the
document’s clarity. The SDT also revised FRS Form 1 and the background document for clarity. Several commenters stated Requirement
R2 needed additional explanation so the SDT revised Requirement R2. Several commenters also expressed concern the standard was not
well defined as drafted so Requirement R5 was inserted back into the draft standard to resolve this concern. Another concern identified
that language appeared to give the ERO a blank check to make changes to the standard without an industry vote. Other commenters
requested a better explanation for how FRO is determined and why the median value is considered a reliable statistical measure for
calculating FRM.
R2. Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency Bias Setting (fixed or variable)
validated by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively coordinated
Tie Line Bias control.
R5. In order to ensure adequate control response, each Balancing Authority shall use a monthly average Frequency Bias Setting whose absolute
value is at least equal to one of the following:
•
The maximum percentage of the Balancing Authority Area’s estimated yearly Peak Demand within its metered boundary per 0.1 Hz change as
specified by the ERO in accordance with Attachment B.
•
The minimum percentage of the Balancing Authority Area’s estimated yearly peak generation for a generation-only Balancing Authority per
0.1 Hz change as specified by the ERO in accordance with Attachment B.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
No
Question 11 Comment
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
115
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001759
Organization
Yes or No
Question 11 Comment
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.
On page 3 in the last paragraph of the Frequency Response Obligation and Allocation section, we suggest
expanding the explanation of why Frequency Response Obligation is based on (peak generation + peak
load)/2. This will result in less responsibility of Frequency Response today for a generator only control area
than there currently is. Since load does respond to frequency, we are not suggesting this is wrong. We think
it simply needs to be expanded upon in the explanation.
Does load contribute the same amount as generation? If not, perhaps the ratio of gen and load response to
total response should be reflected in the calculation.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
The SDT believes that there is presently no obligation on the generator only BA and that the proposed FRO will place an obligation on the generator only BA. The
SDT has modified Attachment A to provide additional clarity concerning the calculation methodology.
The SDT believes that this is a methodology that is technologically neutral and provides an FRO allocation across all geographic areas.
Midwest ISO Standards
Collaborators
No
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.On page 3 in the last paragraph of the Frequency Response Obligation and
Allocation section, we suggest expanding the explanation of why Frequency Response Obligation is based on
(peak generation + peak load)/2. This will result in less responsibility of Frequency Response today for a
generator only control area than there currently is. Since load does respond to frequency, we are not
suggesting this is wrong. We think it simply needs to be expanded upon in the explanation. Does load
contribute the same amount as generation? If not, perhaps the ratio of gen and load response to total
response should be reflected in the calculation.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
The SDT believes that there is presently no obligation on the generator only BA and that the proposed FRO will place an obligation on the generator only BA. The
116
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001760
Organization
Yes or No
Question 11 Comment
SDT has modified Attachment A to provide additional clarity concerning the calculation methodology.
The SDT believes that this is a methodology that is technologically neutral and provides an FRO allocation across all geographic areas.
We Energies
No
Overall, we agree that the document is helpful. However, we do believe additional explanation is necessary
for Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed
from the Balancing Authority. There is an implied obligation that the ERO will determine the Frequency Bias
Setting but it is not stated explicitly. Thus, we are left wondering who has the responsibility for determining
the Frequency Bias Setting.
Response: The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide
further clarity as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control.”
FirstEnergy
No
We believe that more work is needed on this document and the requirements to provide for more clarity.
Response: The SDT has modified the Background Document to provide additional clarity concerning the reasoning behind the proposed requirements.
Bonneville Power Administration
No
Overall comment: Attachment A does not adequately spell out the methodology that is to be used to
determine the correct frequency bias for a Balancing Authority. In order for this standard to go forward, the
methodology must be explicitly spelled out and moved into the standard, not attached as a background
document that can be changed without vote.
o Frequency Bias Setting vs. Frequency Response
o RAS events should not be excluded.
These events are designed to not have response on the system, even though there may be some primary
response.
o Paragraph 1 - “each BA has one month” conflicts with the standard that says prior to January 10th or 45
days (1.4 Additional Compliance Information).
o 2.a - BPA is assuming the Drafting Team meant 36 mHz. 36 mHz is very small and can be achieve during
normal frequency deviations.
Point C “within 8 seconds” must be moved to 10 to 12 second range in order to work in WECC.
o 2.b - Why so far back on the -16 seconds?
o Third from the last paragraph - BPA cannot support a standard that isn’t well defined, doesn’t adequately
spell out the methodology behind the requirements and essentially gives the ERO a blank check to make
117
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001761
Organization
Yes or No
Question 11 Comment
changes to the standard without a vote.
o Second to last paragraph -If you have a poor responding BA control less than they are currently the better
responding BA will respond more due to the lower interconnection frequency. This will punish the BAs that
have good response and reward those that have poor response, depending on the methodology used to
calculate correct frequency bias terms.
o Frequency Bias Setting Floor - BPA cannot support a standard that isn’t well defined and essentially gives
the ERO a blank check to make changes to the standard without a vote.
o Frequency Response Obligation and Allocation - BPA cannot support a standard that isn’t well defined and
essentially gives the ERO a blank check for assigning an FRO to each BA. If this is the method for defining
FRO, then it should be included in the requirements section of the standard. However, this section does not
spell out how the FRO will be calculated other than that it will be based on the (peak generation + peak
load)/2. The full methodology for calculating the FRO must be detailed and put in the standard.
Response: The SDT has modified Attachment A and the Background Document to provide additional clarity concerning the calculation methodology and the
reasoning behind the proposed requirements. The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard
Requirement is enforceable as part of that Requirement.
The SDT has modified the FRS Form 1 to allow for adjustments. Any adjustment will have to be justified.
The SDT has corrected the mistake in Paragraph 1.
You are correct concerning the 36 mHZ and this has been corrected. The SDT is only using this to provide a minimum value for selection of events.
The SDT has analyzed several different time periods for the Point A, Point B and Point C values. The SDT has chosen the time periods based on this analysis as
detailed in Attachment A and FRS Form 1.
The SDT is proposing to use -16 seconds in order to account for varying AGC scan rates to obtain an average.
The SDT does not believe that there is any requirement presently in place that identifies good or poor responding BAs. The SDT further believes that a BA that is
providing proper Frequency Response recognizes the importance and will continue to provide the necessary Frequency Response. Those BAs that are not
providing adequate and sustained Frequency Response will be identified through the measure.
The SDT disagrees with your comment that this proposed standard gives the ERO a “blank check” to modify the standard. The proposed standard is attempting to
bring the Frequency Bias Setting and the natural Frequency Response closer together and not attempting to set a floor.
The SDT has modified Attachment A to provide additional clarity concerning the calculation methodologies. The SDT has been advised by NERC Legal that an
attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that Requirement.
SPP Standards Development
No
While we agree that Attachment A is useful, it hasn't quite got to the point where it clearly helps us understand
the requirements as well as the calculations and other determinations that must accompany the standard.
118
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001762
Organization
Yes or No
Question 11 Comment
Response: The SDT recognizes this and has responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
IRC Standards Review
Committee
No
Attachment A is useful, but it does not provide a clear understanding of all topics and issues. This is
evidenced by the questions and comments the SRC is submitting.
Response: The SDT recognizes this and have responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
ERCOT
No
Attachment A is useful, but it does not provide a clear understanding of all topics and issues. This is
evidenced by the questions and comments the SRC is submitting.
Response: The SDT recognizes this and have responded by revising FRS Form 1 and splitting Attachment A into two documents to better clarify the calculation
methodology and the reasoning for the requirements.
Southern Company
No
We did not want to vote on question 11 - clicked 'NO' in error Comments:
Attachment A
Comment 1: The initial draft of BAL-003 - Attachment A provides a range of valuable background details and
historical information about Frequency Response. However, all of this information is not pertinent to the BAs
ability to understand and comply with the Standard. The SDT should consider utilizing the Standards
Processes Manual (page 39) which provides a detailed description of various alternatives to an attached
supporting document. Document types include References, Guidance, Supplements, Training Material,
Procedures, and White Papers.
Comment 2: The Standards Processes Manual (page 39) makes clear that supporting “documents may
explain or facilitate implementation of the standards but do not themselves contain mandatory requirements
subject to compliance review.” Draft BAL-003 - Attachment A may be in contradiction to the Manual because
it suggests mandatory requirements for the BA. Refer to page one where a statement provides that the BA
must, within one month after receiving a listing of official events, assemble its data and calculate a Frequency
Response Measure. This obligation is not stated in BAL-003 or the proposed BAL-003-1. The Manual
explains that any mandatory requirements must be incorporated into the standard in the standards
development process. The SDT should first evaluate whether or not this is a requirement and second, if
alternative language may alleviate confusion.
Response: Attachment A has been split in to two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements.
The SDT has been advised by NERC Legal that an attachment explicitly referenced in a Reliability Standard Requirement is enforceable as part of that
119
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001763
Organization
Yes or No
Question 11 Comment
No
While the attachment provided insite into the distribution of the FRO for each BA, it lacks clarity on whether
the interconnection FRO is based on the largest category C event that occurred, or if this event is based on a
study.
Requirement.
Progress Energy
Additionally, if the event is from actual data, what happens if the interconnection is shown to need less
response than it currently has due to the response of frequency dependent loads.
What happens to BAs that "have only load with no native generation" if they do not meet their FRO? Are they
going to be required to meet their FRO through load managmenet schemes?
Response: Attachment A has been split in to two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised for clarity.
The SDT believes that a BA that is providing proper Frequency Response recognizes the importance and will continue to provide the necessary Frequency
Response. Those BAs that are not providing adequate and sustained Frequency Response will be identified through the measure. The FRO is and will be
determined based on the methodology detailed in Attachment A.
If A BA does not meet the Requirements then it will be found noncompliant. The proposed standard is setting a minimum Frequency Response but not
prescribing a method to meet the requirements. However, the SDT has identified methods of obtaining Frequency Response in the standard.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The SDT, in consultation with the NERC Frequency Response Initiative, has performed empirical studies that demonstrate the median is more resilient
to data quality problems and statistical outliers.
Energy Mark, Inc.
No
Comment 20: The document is useful, but it needs a number of modifications to provide a clear
understanding of the Requirements.Frequency Bias Setting vs. Frequency Response Section:
Comment 21: In bullet 1 the use of the word “storage” is unclear.
Comment 22: In bullet 3, The two boxes indicating that the Point A and Point B values are averages should
also indicate that the averaging periods for these calculations vary with the scan rate used to collect the data.
The correct averaging periods were presented in a table from the NERC Reference Document Understand
120
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001764
Organization
Yes or No
Question 11 Comment
and Calculating Frequency Response developed by Frequency Response Standard Drafting Team. These
scan values used for averaging should be included in the instructions.Frequency Response Obligation and
Allocation Section:
Comment 23: In the second paragraph of this section there is no supporting analysis that indicates the level
of reliability that the selection of “the largest category C event (N-2).” Without such analysis, there is no way
to determine the level of reliability that will be supported by this “target contingency protection criteria.” A
reliability criterion that supports an unknown level of reliability is no reliability criteria at all.
Comment 24: In paragraph four of this section, determination of the “administrative procedure to assign an
FRO to each BA for the upcoming year” is removed from the stakeholders and given to the ERO and the
NERC RS to determine. This is unacceptable in a stakeholder driven process without more information about
how this determination will be made.
Comment 25: In paragraph five of this section, an initial method is offered to determine the proportion of total
Frequency Response that each BA will use as their FRO. This method is not influenced by the need for
Frequency Response in any manner. It therefore, creates perverse incentives for BAs attempting to make
decisions concerning Frequency Response and fails to meet the requirement that “A reliability standard shall
neither mandate nor prohibit any specific market structure.” This is explained in greater detail later in my
comments in response to Questions 16 and 17.Methods of Obtaining Response Section:
Comment 26: In the first paragraph, it is suggested that the Frequency Response Obligation could be fulfilled
by participating in Reserve Sharing Group (RSG). RSGs were created because of the “non-coincident”
nature of the need for Contingency Reserve among BAs. In creating RSGs, all of the BAs in the RSG could
reduce the amount of Contingency Reserve that they individually held while still meeting the reliability
requirements associated with recovering from disturbances. The savings achieved by reducing individual
reserve and sharing reserves provided strong economic incentives to support the infrastructure to create,
manage and operate these RSGs. Unlike Contingency Reserves, Frequency Responsive Reserves are
always needed on a “coincident” basis because the frequency is the same throughout the interconnection.
The strong economic incentives associated with the supply of Contingency Reserves by RSGs do not exist
when considering the “coincident” need for Frequency Responsive Reserves. At best, there is only a small
reduction in need for reserves on an event by event basis and that small effect is significantly reduced when
the averaging period for event measurement is extended over time as the draft standard suggests, one year
average measurement period for Frequency Response.
Comment 27: In the second paragraph, it is suggested that the problem of obtaining Frequency Response be
passed to the RSGs rather than addressing it directly in this standard or in other standards under
development. In the distant past, the term “spinning reserve” was weakly related to the amount of Frequency
Responsive reserve available. However, in current NERC standards there is no defined relationship between
“spinning reserve” and Frequency Responsive Reserve. Therefore, there is no reason to pass this problem to
RSGs. However, if an RSG, after investigating the provision of Frequency Response chose to address the
problem, there should be no objection to an RSG taking responsibility of its members’ Frequency Response
121
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001765
Organization
Yes or No
Question 11 Comment
Obligations in a manner similar to a single BA.
Comment 28: In the third paragraph, it is suggested that “as long as all BAs within the RSG use the same
events for calculating FRM, BAs within the RSG may allocate a portion of their FRM to another RSG
participant.” When one considers that there are expected to be over 25 events in the annual calculation, the
probability that all BAs in a RSG will have the data available for the same 25 events should be expected to be
small, especially for large RSGs. Does selection of events for the RSG members in a manner to insure the
same 25 events offer an opportunity to bias the sample?
Response: Comment 20 – Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the
standard and a new document titled, “Frequency Response Standard Background Document”, that explains the reasoning behind the requirements. These
documents have also been revised to provide clarity.
Comment 21 – The SDT has removed the reference to “storage” from the documents.
Comment 22 – The SDT agrees and has included averaging periods based on AGC scan rates.
Comment 23 – The SDT agrees that further development is needed in this area, and will review this issue during the field trial and provide more definitive
analyses.
Comment 24 – The SDT has revised Attachment A to clarify the calculation methodology.
Comment 25 – The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region,
ISO, RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Comments 26 & 27 & 28 – The SDT appreciates these observations and has taken these comments under consideration including modifying the standard
regarding RSGs.
FMPP
No
It is useful, but Attachment A is not clear.
Response: Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised for clarity.
American Electric Power
No
As stated earlier, attempting to follow requirement(s) within multiple versions of the same standard would be
very difficult. In addition, more examples should be provided.
Response: Requirement R5 has been inserted back into this version of the draft standard and should eliminate the concern of trying to operate using multiple
versions of the same standard. This standard will replace all versions of BAL-003 currently in effect.
The SDT has also revised Attachment A and FRS Form 1 to provide clarity.
122
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001766
Organization
Yes or No
Duke Energy
No
Question 11 Comment
Attachment A is useful, however R2 of the standard references a “calculation methodology detailed in
Attachment A” and it isn’t clear to us what part of Attachment A is the methodology.
Also, in Attachment A the term “Interconnection Frequency Response Obligation” is used, but the definition of
FRO says it’s a BA value, so that’s inconsistent.
Overall, we agree that the document is helpful; however, we do believe additional explanation is necessary for
Requirement 2. It appears that the responsibility for identifying Frequency Bias Setting is being removed from
the Balancing Authority.
There is an implied obligation that the ERO will determine the Frequency Bias Setting but it is not stated
explicitly. Under the proposed standard, who has the responsibility for determining the Frequency Bias
Setting?
Response: The SDT has also revised Attachment A and FRS Form 1 to provide clarity.
The SDT is not suggesting that the ERO determine the Frequency Bias Settings. The SDT has modified the language in Requirement R2 to provide further clarity
as to the role of the ERO. The Requirement now reads “Each Balancing Authority not participating in Overlap Regulation Service shall implement the Frequency
Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effectively
coordinated Tie Line Bias control.”
Patterson Consulting, Inc.
No
The historical, contextual, and instruction information is valuable and needs to be associated with this
standard. This material should not be included in Attacment A, though, as described in previous responses. In
addition, there are inconsistent use of definitions and terms in the document that should be corrected.
Response: Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new
document titled, Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been
revised to provide clarity.
South Carolina Electric and Gas
Yes
It would be helpful to have a heading to transition from the criteria section to the reasoning section.
Also, the title of attachment A should include "Frequency Response" before "Background Document."
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
NIPSCO
Yes
Not sure if all the requirements need to be explained, we'll wait for future postings.
123
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001767
Organization
Yes or No
Question 11 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
Westar Energy
Yes
The attachment should be updated as the proposed standard is revised and the standard becomes effective
and field test results are available.
The typical frequency response curve with points A,B and C should be included and therefore part of the
standard.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity. The SDT will evaluate and determine if additional modifications are necessary prior to posting for industry approval.
The frequency curve points A, B and C are identified in FRS Form 1 and therefore are part of this standard.
Manitoba Hydro
Yes
While Attachment A is useful, it could be improved by adding a graph to better illustrate Point A and C and the
4 second data sampling rate.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
Seattle City Light
Yes
EKPC
Yes
ENBALA Power Networks
Yes
SERC OC Standards Review
Group
Yes
Kansas City Power & Light
Yes
124
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001768
Organization
Yes or No
Independent Electricity System
Operator
Yes
Santee Cooper
Yes
LG&E and KU Energy
Yes
Arizona Public Service Company
Question 11 Comment
AZPS agrees it is useful, however, more clarity of how the FRO is determined and how the FRO differs from
the FRM.
Response: The SDT thanks you for your comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
The FRO is the minimum amount of Frequency Response needed to comply with this standard. The FRM is the measure of the Frequency response provided
during an event.
Alberta Electric System Operator
AESO suggests that this document should provide a clear description and discussion of the concerns,
response measures at different aspects or time frames of frequency response (inertial response, governor
response, AGC response; arresting deviation and settled deviation),and should provide technical evidence or
reasons why the proposed standard can address the related concerns.
Response: The SDT thanks you for your clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
ISO New Engand Inc.
Attachment A is useful, but it does not provide a clear understanding of all topics and issues.
Response: The SDT thanks you for your clarifying comment.
Attachment A has been split into two documents. Attachment A now provides the calculation methodology to be used for the standard and a new document,
titled, “Frequency Response Standard Background Document”, that explains the reasoning for the requirements. These documents have also been revised to
provide clarity.
125
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001769
Organization
Northeast Power Coordinating
Council
Yes or No
Question 11 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
126
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001770
12. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s FRM. Do you agree with the SDT that this is
the proper method to calculate its FRM? If not, please explain in the comment area and if possible provide an alternate method to calculate
FRM.
Summary Consideration: Several of the commenters agreed that the calculation in FRS Form 1 is the proper method for calculating the
FRM. Many commenters expressed concern that the FRM calculation method was simplistic, did not capture all contributing factors, and
that use of the median value may result in a determination of noncompliance for otherwise compliant conditions. Regarding FRS Form 1,
many calculation errors were identified and several commenters indicated that the information provided was neither clear nor complete.
There was general consensus for conducting a field trial during which consideration of other statistical methods will be evaluated by the
SDT. A few commenters believe that the 1% of peak formula currently in use should be maintained. Another comment indicated that
certain events including contingent Balancing Authority events should not be used for the calculation. One commenter indicated more
study is needed to determine how to account for energy flowing across a Balancing Authority’s Area since this flow could affect frequency
response. Concern was also expressed indicating there is not a reliability basis or replacement for addressing the AGC Frequency
Response phase out approach for Requirement R5.
In response to industry comments the SDT has revised FRS Form 1 (including calculations) to allow for adjustments to the calculations.
The SDT affirms that the median is the preferred measure for eliminating statistical outliers which have a tendency to skew analysis
results. Other statistical methods will be considered by the SDT during the field trial. The SDT agrees there needs to be a floor Frequency
Response Setting threshold however the current 1% of peak of peak load/generation threshold is causing many Balancing Authorities to
over bias, causing unnecessary ACE and frequency undulations. The drafting team is proposing a phased approach for reducing the
Frequency Bias Setting value to less than 1% of peak load/generation for Balancing Authorities with actual Frequency Response is currently
less than this value. This approach is detailed in Attachment B.
Organization
Bonneville Power Administration
Yes or No
Question 12 Comment
No
RAS events and Contingent BA events shouldn’t be used in the calculation. The FRS Form 1 has a basic
flaw that needs correction. For Balancing Authorities that have frequency response wheeled across them by
other BAs (for example, with BPA, any contingency that occurs in the south will have frequency response
from BCHydro wheeled across it) and the associated losses will show as less frequency response by the BA
that is being wheeled across. BPA recommends that the generation and load be measured, primarily
generation, in order to find the frequency response of the BA. Since few, if any, BAs directly measure their
total load, the calculated load will have the same issue due to the responses wheeling across the BA (load is
generally calculated as total generation minus total interchange). Therefore, more study needs to be done to
determine how to account for the energy flowing across a BA.
Response: The drafting team has taken the suggestion to exclude RAS events for frequency response analysis and will study this further should there be a need
to incorporate more events to perform frequency response analysis.
127
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001771
Organization
Yes or No
Question 12 Comment
The method of analyzing a BA response is formed on a net metered basis to obtain the BA response. The response is not summed across intermediate BAs for
loss consideration and ultimate delivery of energy. In the case of Bias the deviation from present metering is an indication of response and load change within
the BA as noted in the response. Frequency response could be calculated by measuring each generator and load bus change but then there are distribution
losses reflected in the numbers. The generally accepted method presently assumes that change in loss for the frequency response MW delivery is not significant
when delivered by many sources.
SPP Standards Development
No
We do not necessarily agree that it does. Please see our response to Question 1.For the 2010 survey NERC
provided the Points A and Points B for the listed events in the provided spreadsheet. FRS Form 1 does not
contain that information, only the delta frequency. Please include the Point A and Point B frequencies for the
SEFRD events in FRS Form 1.
Response: Please refer to our response for Question 1. The drafting team has revised FRS Form 1 and Points A and B values are calculated in FRS Form 2 and
shown in FRS Form 1. These values will differ for each BA based on readings at the BAs location rather than a specific location in the interconnection.
IRC Standards Review
Committee
No
It is one method, but not necessarily the only proper method. Not all existing methods need to be replaced.
The SRC suggests scan data could be used so that different metrics can be evaluated.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
ERCOT
No
It is one method, but not necessarily the only proper method. Not all existing methods need to be replaced.
The SRC suggests scan data could be used so that different metrics can be evaluated.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
ISO New Engand Inc.
No
It is one method, but not necessarily the only proper method.
Response: The drafting team agrees with the IRC Standards Review committee conclusion that the field trial evaluation will support the proper selection of the
metric utilized. The SDT believes there is a need for a common methodology for evaluating Frequency Response.
Kansas City Power & Light
No
This method is too simplistic and does not take into account normal statistical variations in metering accuracy
and resolution for generation and tie-lines, does not take into account the natural variations of generation due
to mechanical variations, and does not take into account the impact of load control actions on generation.
Without taking these variations into account, the outcome is the wild calculation results that have been seen
in the current submissions by BA’s that should be an indication that the method needs considerable work to
be considered useful.
128
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001772
Organization
Yes or No
Question 12 Comment
Response: The drafting team disagrees that the method needs to address SCADA support concerns cited. There should be a documented reason for each error
which can be excluded. The field trial evaluation will identify errant calculations and any need for further revision.
Progress Energy
No
Progress Energy believes you can, and should calculate a frequency response for BAs with the contingency
also. We are also not certain that a strict median response should be used as it provides opportunity for BAs
to perform moderately most of the year and make up for it with a few days slightly above their desired median
target when they should take measures to hit their target every time within a standard deviation tolerance
(excluding outliers)
Response: We thank you for your support. The SDT, in consultation with the NERC Frequency Response Initiative, has performed empirical studies that
demonstrate the median is more resilient to data quality problems and statistical outliers. The SDT believes that this measurement methodology using the
median value is the most appropriate method at this time.
NorthWestern Energy
No
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly. Page 2 implies that there
is currently too much frequency response based on the 1% of peak demand method of establishing frequency
bias. Even though NWE does not use the 1% method, NWE feels that the 1% minimum has been a tried and
true method of providing frequency response in the Western Interconnection.Without the 1% minimum (and
BA’s using a natural response less than the 1%), the total interconnection frequency response would
decrease according to research. This would lead to decreased interconnection bias, causing other
operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The drafting team agrees that calculated frequency response varies from event to event. This is because there are multiple Balancing Authorities
interconnected and each BA has a small frequency response contribution compared to the variation in its load and generation experienced at any given moment.
This is why the drafting team is proposing to use the median value of events selected during the year as a measure of “average” response. The median is the
preferred measure to eliminate population statistical outliers which have tendency to skew results.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing testing using a bias setting value of less than 1% for BAs with frequency response that is less than the 1% value currently
calculated in order to better match the natural response. The drafting team agrees there needs to be a floor threshold however the current 1% threshold is
causing many BAs to over-bias, resulting in ACE and frequency undulations.
Please identify the research indicating control problems would occur using a minimum bias setting that is less than 1%.
129
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001773
Organization
Yes or No
Question 12 Comment
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
Energy Mark, Inc.
No
Comment 29: I agree that a method similar to the one suggested can be used to calculate the BA's FRM.
However, there are a number of errors in the suggested FRS Form 1.Data Entry Tab:
Comment 30: The calculation of SEFRD in column G is incorrect for events marked as Internal Contingency
in Column I. This calculation must also include the change in internal generation due to the Internal
Contingency. This adjustment must either be explained in the “Balancing Authority FRS Form 1 Background
and Instructions” or the calculation must be modified using a column added to the NERC FRS Form 1
(between column J and K) to include the size of the Internal Contingency in MW.
Comment 31: The calculation in cell L22 is incorrect because it includes the incorrect calculations from the
lines that indicate Internal Contingency. If the calculation in column G is corrected this cell will also be
corrected.
Comment 32: The calculation in cell L23 is incorrect because it includes the incorrect calculations from the
lines that indicate Internal Contingency. If the calculation in column G is corrected this cell will also be
corrected.
Comment 33: The calculation in cell L24 is incorrect. It provides the intercept of the linear regression for the
Frequency Response using the Intercept function. It should provide the slope of the regression of the change
in NAI from Column F to D regressed against the change in Frequency, Column B, using the LINEST function
with a forced fit through the origin, using the function y = mx. The correct value for the sample data in the
NERC FRS Form 1 is -24.7, not -16.2.
Comment 34: The calculation in cell L27 is incorrect. It provides the intercept of the linear regression for the
Frequency Response using the Intercept function. It should provide the slope of the regression of the change
in NAI from Column F to D regressed against the change in Frequency, Column B, using the LINEST function
with a forced fit through the origin, using the function y = mx. The correct value for the sample data in the
NERC FRS Form 1 is -22.5, not -33.9.
Comment 35: Cell M19 and M31 should read “...Frequency Response Obligation...”, not “...Frequency
Requirement Obligation...”
Comment 36: The regression methods described in Comments 33 & 34 above provide the best method to
calculate FRM. The linear regression method described is the only method of those suggested that properly
weights the data with respect to its influence on the value of FRM. Using the median fails to weight the data
at all. Using simple averaging weights the smaller events more than the larger events in the sample as
compared to their influence on the best estimate for FRM.
130
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001774
Organization
Yes or No
Question 12 Comment
Response: Comments 29,31, 32, 33, 34 and 35 – FRS Form 1 has been revised and corrected
Comments 30 – FRS Form 1 has been extensively revised and instructions for its use have be clarified.
Comment 36 – The SDT is evaluating several calculation methodologies. The SDT will propose the most suitable method in its final draft of this standard.
American Electric Power
No
The FRS Form 1 is actually calculating prior performance results from identified events to determine future
measure. The calculation method to determine a BA’s FRM still is not capturing all contributing factors that
occur in real time and have an impact at time of event occurrence to determine frequency response
performance to be measured. The calculation method and FRM needs to be more complete to include all of
these contributing factors such as magnitude of actual generation on line at time of occurrence that is capable
of governor & AGC response, actual generator loading, scheduled interchange imports to balance or meet
load demand, etc. The calculation method and FRM also needs to be more dynamic to allow inclusion of
these variable contributing factors to be able set proper measure and identify lack of performance to actually
address the issue, if there truly is one. There needs to be some form of measure at the actual generator level.
Measuring a BA’s aggregate response will not address contributing generators having negative governor or
AGC frequency response, and puts the entire burden on the BA when the performance issue to be resolved is
more at generator level.
There appears to be no reliability basis or replacement for addressing the AGC frequency response phase out
approach for R5 implementation plan. Without a reliability results based study to support this approach, it
appears on the surface that there is the potential to lose some of the AGC part of response.
Variable energy resources that are non-responsive must also be addressed in the overall calculation and
measure. Because the electric industry has evolved with unbundling of generation/transmission and
implementation of energy markets, there needs to be an ancillary service component for frequency response
to address the factor of independent players that impact the lack of or negative frequency response issue.
When impacting entities have financial factors that conflict with reliability intent, the reliability performance
process can be compromised and made more difficult to achieve.
Response: FRS Form 1 has been revised.
The dynamic measure as suggested implies the BA should have a dynamic response incorporated into its frequency bias setting as a variable component.
The SDT believes that the current 1% of peak of peak load/generation threshold is causing many Balancing Authorities to over bias, causing unnecessary ACE and
frequency undulations. The drafting team is proposing a phased approach for reducing the Frequency Bias Setting value to less than 1% of peak load/generation
for Balancing Authorities with actual Frequency Response that is currently less than this value. This approach is detailed in Attachment B.
The drafting team welcomes the initiative of companies to offer a NAESB solution for ancillary services which is beyond the scope of this SAR.
131
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001775
Organization
Yes or No
Duke Energy
No
Question 12 Comment
Other factors need to be considered and incorporated in the calculation. See comments to 1 and 2 above.
Response: Please see our response to Questions 1 and 2.
FRS Form 1 has been revised and the drafting team will list specific reasons for revisions and event exclusion.
Patterson Consulting, Inc.
Yes
Pending modifications based on results from the field test and subsequent operation under the new standard,
FRS Form 1 is a good start for calculating a Balancing Authority's Frequency Response Measurement and
Frequency Bias Setting.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
South Carolina Electric and Gas
Yes
The form must have clear instructions on its use and meanings of the terms.FRS Form 1 and Instructions
should be included as an attachment to the BAL-003-1 standard.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Santee Cooper
Yes
The form must have clear instructions on its use and meanings of the terms. The form should include the
ability to take into account changes in metered non-conforming loads.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised to allow for adjustments such as non-conforming load.
LG&E and KU Energy
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
FirstEnergy
Yes
Although the method seems acceptable in theory, the results of the field test will be needed to validate the
methodology.
Response: We thank you for your affirmative response and clarifying comment.
132
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001776
Organization
SERC OC Standards Review
Group
Yes or No
Yes
Question 12 Comment
The form must have clear instructions on its use and meanings of the terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
ENBALA Power Networks
Yes
ENBALA also believes that including an additional metric, such as the metric suggested in the recent
Lawrence Berkeley National Laboratory of a nadir-based frequency response, would be useful in assessing
the current inertial response capabilities and level of risk for under-frequency load shedding.
Response: We thank you for your affirmative response and clarifying comment.
The SDT will consider your suggestion during the field trial.
NIPSCO
Yes
Seems straightforward compared to other methods
Response: We thank you for your affirmative response and clarifying comment.
EKPC
Yes
The form should include clear instructions for use and clear definitions for terms.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Manitoba Hydro
Yes
Although it can be difficult for some events to determine the NIA and load values for the A & B points(due to
significant signal variations), this is still the best known method at this time.
Response: We thank you for your affirmative response and clarifying comment.
FRS Form 1 has been revised.
Seattle City Light
Yes
We Energies
Yes
Westar Energy
Yes
133
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001777
Organization
Yes or No
FMPP
Yes
Arizona Public Service Company
Yes
Midwest ISO Standards
Collaborators
Yes
Independent Electricity System
Operator
Yes
MRO's NERC Standards Review
Subcommittee
Yes
Alberta Electric System Operator
Question 12 Comment
The standard uses median of multiple SEFRD for the calculation of FRM, which is a reasonable method. The
AESO suggests NERC considers the alternative "zero-cross linear regression" method for the FRM
calculation. The key difference of "zero-cross linear regression" is that it puts more weight on events with
bigger frequency deviation. As the standard is to address the concerns related with large frequency error that
could cause UFLS, the more weight put on larger events seems more reasonable.
Response: We thank you for your input and suggested method will be considered during the field trial.
Refer to the response to Question 17.
Northeast Power Coordinating
Council
Response: Please see our response to Question 17.
134
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001778
13. The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authority’s Frequency Bias Setting. Do you agree with
the SDT that this is the proper method to calculate its Frequency Bias Setting? If not, please explain in the comment area and if possible
provide an alternate method to calculate Frequency Bias Setting.
Summary Consideration: Many of the commenters agreed with requiring the use of FRS Form 1 for calculating a Balancing Authority’s
Frequency Bias Setting. Most commenters agreed with the concept but expressed concern that FRS Form 1 had errors, incorrect
calculations, did not provide consideration for variable bias, and instructions were vague. Some commenters indicated that the
methodology was too simplistic and use of the median value is not an adequate approach. Comments were also received suggesting the
current 1% of peak methodology is a proven method that should be maintained and each Balancing Authority should be allowed to
determine its Frequency Bias Setting. One commenter suggested the FRO value should not be considered when determining the
Frequency Bias Setting. Another commenter suggested gradually lowering the Frequency Bias Setting floor threshold over several years to
assess the associated reliability impacts. The SDT agrees and implemented this approach. Initially the FRM will be computed to 0.8% of
the Balancing Authority’s forecasted peak load or generation. A recommendation was provided to estimate the Frequency Bias Setting
using a linear slope approach with a least square fit method. The SDT will assess this method as part of the field trial. Observations
provided include field testing must validate the methodology and that the methodology should include two measures (AGC and
interchange) for identifying lack of frequency response.
In response to industry comments the SDT has revised FRS Form 1 to allow adjustments for known variables that will impact the measure.
One commenter noted that Requirement R2 states that the ERO will provide the Frequency Bias Setting for each Balancing Authority
whereas FRS Form 1 specifies a calculation to obtain a value which the ERO is not required to review or use. The SDT has modified the
requirement to address this process reporting and implementation concern.
Organization
Bonneville Power Administration
Yes or No
Question 13 Comment
No
BPA thinks that the Form can be used as a tool, but the results shouldn’t be the required Frequency Bias
setting. Each individual BA should be allowed to set their own. Also, this shows no consideration for variable
bias. Variable bias changes greatly during a contingency and this should be considered.Please see
comments to number 12.
Response: The SDT agrees that measurement of individual generator’s performance would produce a more accurate measure of Primary Frequency Control and
that the SDT had not considered losses within a BA’s system due to frequency response of other BA’s frequency response flowing through their system. This
could indeed have some effect on the accuracy of the measure when using Interchange Actual for the measure. The SDT agrees that variable bias, based on real
time conditions (up and down headroom) of on line generators and other frequency responsive devices, will produce the most accurate value for the bias setting
if the BA implements a program that will accurately estimate Primary Frequency Control from each of its generators or other frequency responsive devices and
account for load dampening. Form 1 could still be used as a confirmation of general performance and to consistently measure every BA to the same events for
comparison to the Interconnection’s performance as a whole. If the BA were willing to measure performance of each generator and other frequency responsive
devices to the same list of events as an additional measure, this could be used in the field trial to determine the magnitude of the measurement error of Form 1.
135
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001779
Organization
Yes or No
Question 13 Comment
The SDT would like to move the industry to accept the use of variable bias as the superior method for setting the Bias in the ACE equation as long as the BA
meets its minimum FRO and that the variable bias result matches actual Primary Frequency Control performance within some tolerance. A BA should not be
allowed to use a variable bias just to inflate their L10 values for CPS2 compliance.
SPP Standards Development
No
We do not necessarily agree that it does. Please see our response to Question 1.Given the disclaimers on
page 7 of the FRS Form 1 instructions under Data Values, do the BAs have the discretion to change data in
Form 1 if it doesn't match the data they recorded on their system?
Response: FRS Form 1 has been revised to allow adjustments for known variables that will impact the measure. The field trial will validate the accuracy of the
measure and identify problems using Interchange Actual. The BA can adjust the t (0) event time to align with their frequency data but they should not change
their data. Adjustments should be made in the columns provided in the revised FRS Form 1.
IRC Standards Review
Committee
No
It appears to be one acceptable method, but not all the calculations done through the use of the form are
clearly described. Further, it says that the Frequency Bias Setting will be based upon the FRM, but it doesn’t
say how that will be done.
Response: FRS Form 1 has been revised to be clearer. Initially the FRM will be compared to 0.8 % of the BA’s forecasted peak load or generation. The Bias
setting will be based on the larger value. BA’s will continue to be able to use a variable bias.
ERCOT
No
It appears to be one acceptable method, but not all the calculations done through the use of the form are
clearly described. Further, it says that the Frequency Bias Setting will be based upon the FRM, but it doesn’t
say how that will be done.
Response: FRS Form 1 has been revised to be clearer. Initially the FRM will be compared to 0.8 % of the BA’s forecasted peak load or generation. The Bias
setting will be based on the larger value. BA’s will continue to be able to use a variable bias.
Kansas City Power & Light
No
This method is too simplistic and does not take into account normal statistical variations in metering accuracy
and resolution for generation and tie-lines, does not take into account the natural variations of generation due
to mechanical variations, and does not take into account the impact of load control actions on generation.
Without taking these variations into account, the outcome is the wild calculation results that have been seen
in the current submissions by BA’s that should be an indication that the method needs considerable work to
be considered useful.
Response: When the BA’s bias setting closely matches natural Primary Frequency Control, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE
impact on the Interconnection’s frequency. This may also cause greater difficulty maintaining CPS1 and CPS2 compliance. The sample size of identified events is
intended to address BA performance variability concerns.
FRS Form 1 has been revised to account for known variables that will impact the measure. The SDT believes that when actual BA Primary Frequency Control
136
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001780
Organization
Yes or No
Question 13 Comment
improves, the measure will be more consistent and useful.
Progress Energy
No
The FRO should not be part of the determination of the bias setting unless you are actually going to respond
by the FRO value. BAs should be trying to get their FRC <= FRO, but not biasing by the FRO. The bias has
no effect on the FRC. Progress Energy also think the % of projected peak requirement should be removed
now.
Response: The SDT agrees that the % of projected peak requirement has been contributing to Secondary Frequency Control problems and has determined that
a phased-in approach is the preferred method of eliminating this requirement. The FRO is not intended to be the BA’s bias setting unless the BA’s actual Primary
Frequency Control is equal to the BA’s FRO and meets the minimum of the 0.8% of the BA’s forecasted Peak Load or Generation.
NIPSCO
No
Not sure, It appears that the FR is about 1/2 of the freq bias in the East Int. I think that the bias could be
brought down gradually over several years while monitoring system frequency for reliability.
Response: The SDT agrees and the standard has been modified to reflect your concern.
NorthWestern Energy
No
Page 2 implies that there is currently too much frequency response based on the 1% of peak demand method
of establishing frequency bias. Even though NWE does not use the 1% method, NWE feels that the 1%
minimum has been a tried and true method of providing frequency response in the Western
Interconnection.Without the 1% minimum (and BA’s using a natural response less than the 1%), the total
interconnection frequency response would decrease according to research. This would lead to decreased
interconnection bias, causing other operational issues, such as lower L10 values and possible CPS2
compliance factors. A Balancing Authority’s frequency response is based upon a “median” value calculated
from analyzing multiple events. Frequency response during some of these events is better than others,
depending on the system conditions at the time and the amount system loading and unloaded generation
online at the time of the event. Given these circumstances a BA’s actual response could vary by event (better
or worse than median), thus compliance measurement per event to a frequency response obligation based on
the median response (over multiple events) could put BA’s in non-compliant situations unjustly.
Response: The drafting team agrees that calculated frequency response varies from event to event. This is because there are multiple Balancing Authorities
interconnected and each BA has a small frequency response contribution compared to the variation in its load and generation experienced at any given moment.
This is why the drafting team is proposing to use the median value of events selected during the year as a measure of “average” response. The median is the
preferred measure to eliminate population statistical outliers which have tendency to skew results.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing testing using a bias setting value of less than 1% for BAs with frequency response that is less than the 1% value currently
calculated in order to better match the natural response. The drafting team agrees there needs to be a floor threshold however the current 1% threshold is
137
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001781
Organization
Yes or No
Question 13 Comment
causing many BAs to over-bias, resulting in ACE and frequency undulations.
Please identify the research indicating control problems would occur using a minimum bias setting that is less than 1%.
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
The SDT agrees bias setting changes may impact CPS compliance calculation which is why the drafting team is proposing field testing using small, incremental
changes to the bias setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) indicates improved AGC and
frequency performance can be realized by better matching bias setting to frequency response; which should improve CPS compliance.
The SDT fails to see the implication that there is too much frequency response based on the 1% of peak demand method of establishing frequency bias. The bias
setting will not increase or decrease Primary Frequency Control. It will only impact the measure of ACE and the resulting Secondary Control of the BA. The 1%
minimum requirement was appropriate in the past when BA’s Primary Frequency Control was nearly equal to 1% of the forecasted peak load or peak generation.
Form 1 and this revision to BAL-003 would still require that the Bias setting in the ACE equation be equal to or greater than the natural Primary Frequency Control
of the BA with a minimum value of 0.8% of the BA’s forecasted peak load or peak generation. When the BA’s bias setting closely matches natural Primary
Frequency Control, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE impact on the Interconnection’s frequency. This may also cause greater
difficulty maintaining CPS1 and CPS2 compliance. The sample size of identified events is intended to address BA performance variability concerns. The field trial
results should prove if this is a correct assumption.
Energy Mark, Inc.
No
Comment 37: My initial comments associated with calculation of the Frequency Bias Setting are included in
my comments 3, 4, 5, 6, 30, 31, 32, 33, 34 and 36.
Comment 38: The determination of the Frequency Bias Setting using a median or mean value provides an
incorrect weighting of the individual SEFRD measurements to correctly determine the Frequency Bias Setting.
The Frequency Bias Setting as used in the ACE Equation represents a linear function of Frequency
Response to frequency error. The best estimate of the Frequency Bias Setting from this SEFRD data is the
slope of the line through the origin using a least-squares fit. Any other method of determining the Frequency
Bias Setting will improperly weight the individual data points contribution to the error thus providing a poorer
estimate of the true value of Frequency Response.
Response: Comment 37 - Please refer to our response to the comments noted.
Comment 38 - Once events have been identified and data collected the SDT can and will use multiple methods of determining the best selection of a bias setting
for BA’s using a fixed bias. The SDT will include your recommended method as one that is considered.
FMPP
No
It would be better to define significant and let the BA exclude any events that meet this definition, since each
BA will be ramping differently. Since SEFRD is defined as the individual sample of event data from a
Balancing Authority which represents the change in Net Actual Interchange (NIA), divided by the change in
frequency, expressed in MW/0.1Hz, whenever a BA includes an event with a “significant” change in NIA due
138
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001782
Organization
Yes or No
Question 13 Comment
to a large interchange schedule ramp, the FRM is totally skewed, and should not be included. If other events
are available means that if other events are not available then an entity’s compliance is going to be based on
an event or events that has been skewed for the BA by significant interchange schedule ramp.
Response: FRS Form 1 has been revised to account for known variables that will impact the measure. The SDT believes that when actual BA Primary Frequency
Control improves, the measure will be more consistent and useful. Using identified events and measuring every BA’s performance during these events will provide
comparison of all BA’s performance to the Interconnection’s performance as a whole.
American Electric Power
No
There should be two measures to identify lack of frequency response: A calculation and measure for the AGC
part of frequency response based on actual load and generation on line at time of occurrence that is variably
adjusted and measured, while also accounting for interchange imports to balance. Today’s frequency bias
setting does not really address the governor response issue. There also needs to be some form of generator
governor response calculation and measure that starts with a base foundation of droop setting/relative
governor response and is adjusted accordingly. As WECC appears to have shown in its studies, there would
be excessive governor response based on current droop setting if governors responded as they are expected.
This could be an indicator that governor response measure should only be a percentage of this droop, which
protects the generator. Different types of generators and their characteristics must also be factored in.Since
there does not appear to be a performance issue with the Standards involving CPS, we do not believe the
CPS Bounds L10 values should be reduced.
Response: FRS Form 1 has been revised to account for identified variables in measuring Primary Frequency Control. The SDT agrees that measuring generator
governor response and Primary Frequency Control would be beneficial for determining proper delivery of frequency response. The SDT also agrees that generator
governor and droop settings will impact Primary Frequency Control but this concern is outside the scope of this project and a separate SAR will be required to
address governor settings. The SDT is not aware of any WECC studies indicating excessive governor response based on current droop settings if governors
responded as they are expected. The industry nominal droop setting is 5% and this level of performance should limit transmission flows across specific elements
unless the planning process does not account for this flow during contingencies. If Primary Frequency Control is not evenly distributed across the Interconnection
or there is not participation in Primary Frequency Control by all generators with sufficient regulation margin, elements of the transmission system can become
overloaded during a contingency. The SDT believes that when the Bias setting in the BA’s ACE equation closely matches the Primary Frequency Control of the BA,
then the ACE will accurately measure the BA’s impact on Interconnection frequency through the CPS 1 and CPS 2 measures. If a BA has very low Primary
Frequency Control and resulting lower Bias setting, the L10 value will change also.
Duke Energy
No
Other factors need to be considered and incorporated in the calculation. See comments to 1 and 2 above.
Response: FRS Form 1 has been revised to account for known variables.
Patterson Consulting, Inc.
Yes
Requirement 2 states that the ERO will provide the Frequency Bias Setting for each Balancing Authority.
While FRS Form 1 makes a calculation, the requirement does not require the ERO to review or use the FRS
Form 1 value. Otherwise, pending modifications based on results from the field test and subsequent operation
139
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001783
Organization
Yes or No
Question 13 Comment
under the new standard, FRS Form 1 is a good start for calculating a Balancing Authority's Frequency
Response Measurement and Frequency Bias Setting.
Response: The SDT has modified the requirement to address the reporting and implementation process of the bias setting.
South Carolina Electric and Gas
Yes
The form must have clear instructions on its use and meanings of the terms. FRS Form 1 and Instructions
should be included as an attachment to the BAL-003-1 standard.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
Santee Cooper
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
MRO's NERC Standards Review
Subcommittee
Yes
We agree that using Points A and B is correct and the calculations in the spreadsheet are correct.
Response: Thank you for your comment.
LG&E and KU Energy
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
Midwest ISO Standards
Collaborators
Yes
We agree that using Points A and B is correct and the calculations in the spreadsheet are correct.
Response: Thank you for your comment.
FirstEnergy
Yes
Although the method seems acceptable in theory, the results of the field test will be needed to validate the
methodology.
Response: The SDT agrees. The field test will utilize the method to test the measure.
SERC OC Standards Review
Group
Yes
The form must have clear instructions on its use and meanings of the terms.
Response: The SDT agrees and has revised Form 1 with instructions to provide clarity in using the form.
140
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001784
Organization
EKPC
Yes or No
Yes
Question 13 Comment
The form should include clear instructions for use and clear definitions for terms.
Response: The SDT agrees and has revised Form 1 and included instructions to provide clarity in using the form.
We Energies
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
Independent Electricity System
Operator
Yes
Arizona Public Service Company
Yes
ENBALA Power Networks
Yes
Westar Energy
Yes
Alberta Electric System Operator
The AESO finds it difficult to comment as it is not clear how the FRO is determined.
Response: The revised instructions clarify the method for determining the FRO.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response for Question 17.
141
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001785
14. The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS Form 1 for calculating FRM and Frequency Bias
Setting. Do you agree with the SDT that this document provides a clear understanding of how to use the form? If not, please explain in the
comment area.
Summary Consideration: Several of the commenters did not agree that FRS Form 1 instructions provide a clear understanding of how to
use the form. The majority of commenters indicated that the instructions were incomplete, unclear, required better definitions, lacked
variable bias information, technically incomplete and mainly provided background information. In response to industry comments the SDT
has revised FRS Form 1 instructions and removed the background information.
Organization
MRO's NERC Standards Review
Subcommittee
Yes or No
Question 14 Comment
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Midwest ISO Standards
Collaborators
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
FirstEnergy
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
We Energies
No
On page 5 and 6, graphics appear to be missing. This document really provides no instructions but rather
explanations and background material for measuring frequency events. Instructions would be more along the
lines of step 1: Enter date in box, etc.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
LG&E and KU Energy
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable
142
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001786
Organization
Yes or No
Question 14 Comment
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
SERC OC Standards Review
Group
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. Fiqure 1 in Section B of the FRS Form 1 Instructions document should be
corrected so that it is viewable.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
South Carolina Electric and Gas
No
We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Bonneville Power Administration
No
There is no explanation for variable bias. If the suggesting from tab 2 is that a monthly average should be
used then this grossly misrepresents the amount of variable bias that is used during a contingency. For
example: BPAs monthly average ranges from-150 to -160, but during a contingency it can be in the -400 to 500 range.
Figure 1 does not show up so it cannot be determined if BPA agrees with Points A, B and C. Averaging the
pre and post data with 16 seconds and 34 seconds, respectively, will cause the calculations to be skewed
with some generator response, some tertiary response, etc. We do agree, if Figure 1 appears, that this does
spell out how to use the form, BPA just has issues with the data to be provided.
Response: Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions. The SDT is aware
of the extraneous influences in Net Actual Interchange values, and intends to select a sampling interval and an aggregation technique to minimize these
influences.
We apologize for the exclusion of Figure 1. The SDT has removed this figure from the revised instructions and has modified the FRS Form 1 and including
instructions within the form to provide clarity in using the spreadsheet.
SPP Standards Development
No
This document provides valuable background information regarding frequency deviations but lacks the
specific line-by-line Form 1 instructions as mentioned at the top of page 7. We need those details, what goes
in each column, how do we determine which values to use, etc. This would tend to minimize any confusion
that currently exists regarding completing the form.One specific item we'd like to see provided in the
instructions, as well as changed in Form 1, is carrying the Frequency Bias Setting value (Cell L32) out to two
decimals. The current limitation of one decimal has caused confusion in past surveys.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
143
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001787
Organization
IRC Standards Review
Committee
Yes or No
No
Question 14 Comment
The document explains much of the FRS Form 1, but not all, as commented previously.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
ERCOT
No
The document explains much of the FRS Form 1, but not all, as commented previously.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Progress Energy
No
The forms clarity can only truly be found by reverse engineering the formulas within each of the cells.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
ENBALA Power Networks
No
The FRS Form 1 Instructions that was downloaded from the supporting website seemed to be missing
information on page 5. We found that the accompanying FRS Form 1 (excel document) was more useful than
the actual instruction document in providing detail on the required calculation for the Bias Setting.
Response: The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Energy Mark, Inc.
No
Comment 39: The following comments apply to Balancing Authority FRS Form 1 Background and
Instructions.Section A:
Comment 40: The last sentence in the second paragraph should be modified to read, “Therefore, it is better
to analyze response only when significant frequency deviations occur until better measurement methods can
be developed to overcome these difficulties.”Section A, Subsection 1, Frequency Response:
Comment 41: The words “continuous and inverse relationship” should be changed to “bidirectional,
continuous and inverse relationship” in all three bullets. Frequency Response that is not provided bidirectionally will be rapidly depleted by oscillating frequency events.
Comment 42: If a BA has “non-bidirectional step-function Frequency Response” to frequency, it must also
have sufficient continuous frequency response to restore frequency, frequency response, and frequency
responsive reserves (margins) following the use of the “non-bidirectional step-function Frequency Response.”
Therefore, the Frequency Response of primary interest for this standard is a subset of the Frequency
Response defined in the NERC Glossary.
Comment 43: Simulations and actual experience on the interconnections have demonstrated that step
function Frequency Responses can result in frequency instability and oscillations when they are not effectively
coordinated with bidirectional, continuous and inverse Frequency Response. Therefore, it is imperative that
the standard differentiate this bidirectional, continuous and inverse Base Frequency Response from other
144
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001788
Organization
Yes or No
Question 14 Comment
Supplemental Frequency Responses that can be applied under restricted conditions to supplement it.Section
A, Subsection 2, Response to Internal and External Generation/Load Imbalances:
Comment 44: Most AGC Systems use the Frequency Bias Setting in conjunction with the frequency deviation
to determine whether an imbalance in load and generation is internal or external to the BA. This can only be
done effectively when the Frequency Bias Setting matches the internal Frequency Response of the BA.
Unless the minimum Frequency Bias Setting requirements are modified to allow this matching to be
implemented, the most AGC Systems will be unable to perform as indicated in this subsection.Section A,
Subsection 4, Effects of a Disturbance on all Balancing Authorities...:
Comment 45: The description should be modified as follows; “When a loss of generation occurs,
Interconnection frequency declines because machine speed must decrease to supply the energy shortfall
from rotating kinetic energy. Initially, rotating kinetic energy from all rotating machines with direct mechanicalto-electrical coupling addresses the entire shortfall by lowering machine speed, and hence frequency, of the
Interconnection*.* Initially, an amount of kinetic energy equal to the power (generation) lost will be withdrawn
from the stored energy in rotating machines with direct mechanical-to-electrical coupling throughout the
Interconnection. As the mechanical speeds are reduced, Interconnection frequency decreases proportionally.
Comment 46: The term Inadvertent Interchange is not correctly used at the end of the first paragraph. Tie
flow error indicates power. Inadvertent Interchange indicates energy (power integrated over an hour). A
better sentence would be, “The resulting tie flow error (NIA - NIS) will be integrated into Inadvertent
Interchange.”
Comment 47: The first sentence in the fifth paragraph states, “If the Frequency Bias Setting is greater (as an
absolute value) than the Balancing Authority’s actual Frequency Response, then its AGC will ... , which further
helps arrest the frequency decline, but increases Inadvertent Interchange. Frequency decline is arrested
within the first 10 seconds of an imbalance by the Frequency Response of the interconnection. AGC action is
not initiated until many seconds after the frequency decline is arrested. Therefore, a Frequency Bias Setting
greater than the actual Frequency Response will not result in the AGC System having any effect on the
arrested frequency or make any contribution to arrest the frequency decline. The only effect will be to provide
aid during the initial stages of the frequency recovery which is immediately withdrawn during the later stages
of the frequency recovery, while contributing to Inadvertent Interchange. In fact, the effect of a Frequency
Bias Setting greater than the actual Frequency Response is very similar to the effect the a BA receives from a
reserve sharing group with the exception that the reserve sharing group does not withdraw the aid until after
the frequency recovery has been completed. The last sentence in this paragraph is also incorrect for the
same reasons stated previously. If a BA’s Frequency Bias Setting is less than the actual Frequency
Response, the BA will still contribute to arresting the frequency, however, it may withdraw its Frequency
Response before the contingent BA or Reserve Sharing Group is able to initiate recovery contributing to
further frequency decline or a delayed frequency recovery.Section A, Subsection 5, Effects of a Disturbance
on the Contingent Balancing Authority:
Comment 48: In the first sentence, the phrase “as allowed by the Frequency Bias Settings” refers to the
145
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001789
Organization
Yes or No
Question 14 Comment
replacement power provided to the Contingent BA from the interconnection. The initial amount of
replacement power supplied to the Contingent BA is unaffected by the Frequency Bias Settings. The
Frequency Bias Settings will only affect how quickly the replacement power is withdrawn after the frequency
is arrested and stabilizes. The risk is that the replacement power will be withdrawn before the Contingent BA
or RSG can replace it.
Comment 49: The two boxes indicating that the Point A and Point B values are averages should also indicate
that the averaging periods for these calculations vary with the scan rate used to collect the data. The correct
averaging periods were presented in Definitions of Frequency Values for Frequency Response Calculation in
NERC Reference Document - Understand and Calculating Frequency Response.
Response: Comments 39 through 48: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning
language within this document are not incorporated in this version.
Comment 49: The SDT created FRS Form 2 to address your comments. In addition, the SDT has extensively modified the instructions for the use of these forms
to provide additional clarity.
EKPC
No
The form should include clear instructions for use and clear definitions for terms. All figures within the
document should be viewable. More examples for various situations (non-conforming loads) should be
included.
Response: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning figures within this
document are not incorporated in this version.
The SDT has modified the FRS Form 1 and included detailed instructions within the form to provide clarity in using the form.
American Electric Power
No
The FRO value and calculation formula assigned by the ERO is not totally clear. The survey form should
indicate the complete formula used by the ERO. It appears to be missing.
Response: The information you are referencing is now included in Attachment A. The SDT has also modified the FRS Form 1 and included detailed instructions
to provide clarity in using the form.
Duke Energy
No
The form does not recognize the impacts noted in the comment to 1 above. The form does show a column
that appears to allow for exclusion of contingent BA events, but it is not clear how that is accomplished, nor
how doing so matches the definitions currently proposed. Duke Energy agrees with the SERC OC comments
“We believe the FRS form 1 instructions should be improved by better defining the terms used and improving
the overall layout of the form. The document provided should be corrected so that all figures are viewable.”
The form does not provide much in the way of instructions.
146
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001790
Organization
Yes or No
Question 14 Comment
Response: The SDT has removed the FRS Form 1 Background Document from this standard and therefore your comments concerning figures within this
document are not incorporated in this version.
The SDT has also modified the FRS Form 1 and included detailed instructions within the form to provide clarity in using the form.
Santee Cooper
Yes
The instructions should include how to take into account changes in metered non-conforming loads.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT has modified FRS Form 1 to allow for adjustments such as nonconforming load.
The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
NIPSCO
Yes
We didn't read it but the form looks good.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT has modified the FRS Form 1 and included instructions to provide clarity in using the form.
Patterson Consulting, Inc.
Yes
There are inaccuracies that should be corrected, but the document is useful and valuable. The desired
"averaging" of scan-cycle data included in FRS Form 1 Background and Instructions should be made
mandatory to achieve the standard's purpose of providing consistent measurement methods.
Response: The SDT thanks you for your affirmative response and clarifying comment.
The SDT created FRS Form 2 to address the averaging issue identified in your comment. In addition, the SDT has extensively modified the instructions for the
use of these forms to provide additional clarity. The SDT has also modified the FRS Form 1, correcting errors in the calculations.
FMPP
Yes
Seattle City Light
Yes
Manitoba Hydro
Yes
NorthWestern Energy
Yes
Independent Electricity System
Operator
Yes
147
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001791
Organization
Yes or No
Kansas City Power & Light
Yes
Arizona Public Service Company
Yes
Northeast Power Coordinating
Council
Question 14 Comment
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
148
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001792
15. The SDT is soliciting comments on methods of obtaining Frequency Response to meet the FERC Order 693 directive. If possible please
provide any thoughts you may have on this subject.
Summary Consideration: Stakeholders provided the suggestions shown below as possible methods of obtaining Frequency Response to
meet the FERC Order 693 directive:
1.
Develop requirements applicable to the Generator Owner.
2.
Address droop, dead band settings and governor operation.
3.
Corroborate with manufacturers to address load demand response.
4.
Use generator output as a primary input for calculating Frequency Response
5.
Define ways Reserve Sharing Groups can assist Balancing Authorities in providing Frequency Response.
6.
Write standard requirements based on performance needs.
7.
Establish demand response as an ancillary service providing frequency response.
8.
Do not apply the standard to entities that do not have generation resources.
9.
Create a primary frequency market.
10.
Keep the 1% method currently in use.
11.
Ensure generators provide appropriate governor response and merchant generation contracts include a Frequency Response
obligation.
12.
Develop a specific continent wide Frequency Response definition.
13.
Provide a customer compensated pre-emptive load shedding program.
In response to industry comments the SDT delivered to NERC staff the recommendation for collaboration between the ERO and
manufacturers regarding load demand response. The SDT has specified in the latest draft standard other methods for a BA to obtain
Frequency Response. The SDT will examine, during the field trial, the possibility of transferring Frequency Response between BAs.
Organization
Santee Cooper
Yes or No
Question 15 Comment
The SDT should consider focusing and directing requirements at root causes. Specifically, the SDT should
develop requirements that apply to GOs and address droop requirements, deadband settings, governor
operation, etc., as well as specific response expectations which are measured and compared to reported
149
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001793
Organization
Yes or No
Question 15 Comment
settings. Such requirements would likely include exemption criteria to address older existing systems as well
as current operating conditions. Newer systems should be developed, however, to meet specific
requirements that will ultimately improve or maintain Frequency Response at acceptable levels. Subsequent
efforts by the ERO should also consider collaboration with manufacturers to address demand responses
associated with loads.
Response: This issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band settings and governor
operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these concerns. The
SDT will pass on your suggestion concerning further collaborations between the ERO and manufacturers.
Bonneville Power Administration
Primarily, frequency response comes from governor control at generators. In order to accurately measure
this, the output of generation should be used as one of the primary inputs to the calculation of frequency
response. Due to losses, as earlier explained, some BAs could be penalized due to losses associated with
other BA frequency response flowing over the BAs’ transmission system. This needs to be taken into account
when calculating the frequency response of the BAs.
Response: The SDT does not have adequate information to address this suggestion. An impact study would be the best option for conducting an analysis.
SPP Standards Development
The SDT has already offered a suggestion that Reserve Sharing Groups could assist Balancing Authorities in
the provision of Frequency Response. We're not familiar with such arrangements within Reserve Sharing
Groups and would need more information regarding the specifics of such sharing arrangements. That being
the case, as written the draft standard does not provide for the provision of Frequency Response by any entity
other than a Balancing Authority. Such arrangements would definitely have to be reflected in modifications to
Form 1.
Response: Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT has revised the standard to
include RSGs. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response. The SDT will examine,
during the field trial, the possibility of transferring Frequency Response between BAs.
IRC Standards Review
Committee
Demand Response performing as an ancillary service in which the resources are paid to reduce load upon
automatic or manual deployment can provide frequency response. Other devices are available, such as
flywheels or storage arrangements, such as battery banks, that can provide fast and sustainable response,
could also provide frequency response. The standard must be written around performance requirements and
results rather than prescriptive requirements that may have the unintended consequence of stifling innovation
and creativity in this area.
Within the ERCOT Interconnection and the ERCOT market construct, an ancillary service titled Load acting
as a Resource (LaaR) may provide up to 50% of the responsive reserve requirement and provides automatic
underfrequency relay activated response to frequency drops. Other market constructs provide for similar
150
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001794
Organization
Yes or No
Question 15 Comment
services.
As indicated in our comments under Q2, there is a missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an
industry discussion on this subject, and determine the entity(ies) responsible for governor actions/setting, the
mechanism to provide such a response, and the place for stipulating the necessary standard requirements to
enforce compliance for governor actions before further developing this BAL-003-1 standard.
Response: Manual deployment is not quick enough for frequency response. Automatic deployment of other devices could be useful to provide the desired
frequency response. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
ERCOT
Demand Response performing as an ancillary service in which the resources are paid to reduce load upon
automatic or manual deployment can provide frequency response. Other devices are available, such as
flywheels or storage arrangements, such as battery banks, that can provide fast and sustainable response,
could also provide frequency response. The standard must be written around performance requirements and
results rather than prescriptive requirements that may have the unintended consequence of stifling innovation
and creativity in this area.
Within the ERCOT Interconnection and the ERCOT market construct, an ancillary service titled Load acting
as a Resource (LaaR) may provide up to 50% of the responsive reserve requirement and provides automatic
underfrequency relay activated response to frequency drops. Other market constructs provide for similar
services.
As indicated in our comments under Q2, there is a missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an
industry discussion on this subject, and determine the entity(ies) responsible for governor actions/setting, the
mechanism to provide such a response, and the place for stipulating the necessary standard requirements to
enforce compliance for governor actions before further developing this BAL-003-1 standard.
Response: Manual deployment is not quick enough for frequency response. Automatic deployment of other devices could be useful to provide the desired
frequency response. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
151
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001795
Organization
Kansas City Power & Light
Yes or No
Question 15 Comment
The determination of sufficient frequency response in the interconnection is complex and varies according to
the ratio of generation online and the load in the interconnection. The calculation of actual frequency
response is also extremely challenging considering metering accuracy & resolution, SCADA sample rates,
statistical variations of load and generation. To accurately assess what is needed and the methods to
implement such a complex subject will take considerable thoughtfulness, time, testing and engineering
ingenuity.
Response: The SDT agrees with your comments and thanks you for your participation.
Progress Energy
We feel this problem exists on the generator level and this standard should only be applied to those entities
and their response. This will impact BAs of vertically integrated companies. Entities without generation
resources should not be held accountable for frequency response. If their energy supplier wants to make
them responsible for purchasing ancillary response service, that will be up to them on how they distribute it.
Based on the fact that schedules respond too slowly to meet the response window of the frequency measure,
schedules should never be used to measure response capabilities, thus making ancillary service
unnecessary.
Response: The SDT agrees that schedules are too slow to be used for Frequency Response. The SDT has also specified in the latest draft standard version
other methods for a BA to obtain Frequency Response.
The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…”
Regarding governor response - this issue has been discussed and the SDT understands your concern However, generator droop requirements, dead-band settings
and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns. Also, Requirements imposed on generators is outside the scope of the project approved SAR.
ENBALA Power Networks
ENBALA supports the creation of a Primary Frequency Market. This could be achieved in two methods:
Implementation of a new Market for Primary Frequency Response Or
Including in the definition of spinning reserves the requirement for resources to be capable of providing
Primary Frequency Response through autonomous and local control by governor action and inertial
response.
And
We particularly encourage the participation from all resources capable of providing this service in a
coordinated approach, including alternative technologies such as controllable loads, energy storage,
electrically-coupled wind farm controls, and demand response. Furthermore, we stress that this service needs
to be a coordinated, autonomous, and local control and should NOT be integrated in the AGC system.
152
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001796
Organization
Yes or No
Question 15 Comment
Response: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region, ISO,
RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
NIPSCO
We reviewed the related NERC Training Document from 2003 and your proposed method seems like the best
approach.
Response: The SDT thanks you for your support.
NorthWestern Energy
A Balancing Authority’s frequency response is based upon a “median” value calculated from analyzing
multiple events. Frequency response during some of these events is better than others, depending on the
system conditions at the time and the amount system loading and unloaded generation online at the time of
the event. Given these circumstances a BA’s actual response could vary by event (better or worse than
median), thus compliance measurement per event to a frequency response obligation based on the median
response (over multiple events) could put BA’s in non-compliant situations unjustly. Page 2 implies that there
is currently too much frequency response based on the 1% of peak demand method of establishing frequency
bias. Even though NWE does not use the 1% method, NWE feels that the 1% minimum has been a tried and
true method of providing frequency response in the Western Interconnection.
Without the 1% minimum (and BA’s using a natural response less than the 1%), the total interconnection
frequency response would decrease according to research. This would lead to decreased interconnection
bias, causing other operational issues, such as lower L10 values and possible CPS2 compliance factors.
Response: The drafting team agrees that there is great variability in calculated frequency response event to event. This is because in a multi-BA
Interconnection, a given BA’s frequency response contribution is small compared to the variations in load and generation within the BA at any given moment.
This is why the drafting team is proposing to use the median value of many events during the year as the measure of “average” response. The median is the
preferred measure of by statisticians when dealing with data populations containing outliers.
The SDT agrees the Interconnections possess sufficient frequency response.
The drafting team is proposing a test allowing all BAs with frequency response less than the 1% of peak to use a Frequency Bias Setting set less than 1% of peak
to better match the Frequency Bias setting to the natural response. The drafting team agrees a floor threshold needs to be maintained however the current 1%
of peak requirement is causing many BAs to over-bias, causing undulations in ACE and frequency.
The SDT would appreciate it if you could identify the research indicating control problems would be realized if the minimum bias setting was set less than 1%.
The SDT also agrees CPS compliance scoring may be affected which is why the drafting team proposes testing using incremental changes to the Frequency Bias
Setting. Research by Nathan Cohn (Control of Generation and Power Flow on Interconnected Systems) implies that better matching of the Frequency Bias Setting
to the system Frequency Response Characteristic will improve AGC and frequency performance, and also improve CPS compliance scoring.
The SDT does not agree that there is excessive frequency response because of the 1% of peak demand method for establishing the Frequency Bias Setting. The
153
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001797
Organization
Yes or No
Question 15 Comment
bias setting does not increase or decrease Primary Frequency Control. The bias setting value will only impact the measure of ACE and resulting Secondary
Control. The 1% of peak minimum threshold was appropriate in the past when BA Primary Frequency Control was nearly equal to 1% of the forecasted peak load
or peak generation. Keep in mind FRS Form 1 and the BAL-003 draft standard still require the ACE Frequency Bias Setting be set equal to or greater than the
Frequency Response Characteristic with an initial minimum value of 0.8% of the BA forecasted peak load or peak generation. When the BA Frequency Bias
Setting better matches the Frequency Response Characteristic, L10 and CPS1 and CPS2 will more accurately measure the BA’s ACE impact on Interconnection
frequency. This may result in lower CPS1 and CPS2 compliance scoring than currently realized.
The sample size of selected events used for analysis is intended to minimize the concern about variability of performance observed on an event-to-event basis so
that the BA can realize a consistent reference measure when performing analysis.
Energy Mark, Inc.
Comment 50: In those regions of North America where energy is supplied through markets, Frequency
Response should be defined as an additional Ancillary Service and acquired through these Ancillary Service
Markets. Attempts to acquire Frequency Response through methods external to the Ancillary Service
markets will contribute to market inefficiencies since these external methods must affect the capacity
available to the Ancillary Service markets. Use of out-of-market methods would oppose the very reasons that
electric energy markets were created in the first place.
Comment 51: BAs not participating in formal RTOs or ISOs could obtain Frequency Response by insuring
that their owned generation is providing appropriate Governor Response to the BA and that contracts will
merchant generation are modified to include the provision of Frequency Response in the merchant contracts.
It may be appropriate to request guidance from regulatory agencies encouraging the renogiation efforts
required to modify existing merchant generator contracts.
Comment 52: Whether Frequency Response is obtained through Ancillary Service Markets, merchant
generator contracts or owned generation, specific continent wide definitions for Frequency Response should
be developed to provide guidance and consistency in these diverse circumstances. NERC should be taking
the lead on developing the necessary continent wide definitions or policies for Frequency Response.
Response: Comments 50 & 51: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a
region, sub-region, ISO, RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Comment 52: The SDT will forward this comment to NERC staff.
Beacon Power Corporation
Beacon Power is a manufacturer and merchant developer of an innovative advanced energy storage
technology that uses flywheels. Beacon Power’s technology operates by using flywheels to rapidly recycle
energy from the grid in order to follow moment-by-moment changes in frequency nearly instantaneously. The
following characteristics of Beacon’s technology support the use of this technology for frequency response on
the electric grid.
− Responds to local frequency change in less than 1 second; full response in less than 4
seconds
− State of the art electronic control - accurate response. No dead-band required, but could be
incorporated if beneficial
- Inherently modular - Can be distributed around the grid. With distributed local
154
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001798
Organization
Yes or No
Question 15 Comment
response to frequency, less likely to be limited by congestion, and ensures islanded portions of the grid
maintain frequency response. The ability of Beacon Power’s flywheels to quickly and precisely respond to
frequency events on the grid makes this technology an ideal source of frequency response. The fast response
provided can aid in arresting rapid frequency decline on the system, which can assist in preventing the
frequency nadir from encroaching on the first step of Under Frequency Load Shedding. Because of its
modular design, flywheels can be built and positioned throughout the grid to provide a diversified frequency
response, ensuring adequate response during events that cause the grid to separate into islands. Any
standards developed by NERC must allow energy storage and should be inclusive of all technologies able to
provide frequency response. Storage resources that provide frequency response should be allowed to
recover their costs as a wholesale transmission facility subject to FERC’s jurisdiction. Storage facilities do not
generate electricity and operate only to enhance the reliability of transmission service. Given that there is no
open-market for frequency response, there are no concerns of cross-subsidization or competitive concerns.
This will address the FERC Order 693 directive to develop a method of obtaining frequency response, and will
improve the overall reliability of the interconnections. Beacon agrees with the approach of mandating
Balancing Authority response.
However, the SDT should go further to define performance requirements for different tiers of frequency
response, for example full response in 5 seconds maintained until 15 seconds, and full response in 15
seconds maintained until 90 seconds (numbers are for example only, the SDT would determine the
appropriate values), so that Balancing Authorities can be confident when acquiring new sources that
demonstrate those performance characteristics.
The use of Reserve Sharing Groups (as detailed in Attachment A) to provide a means of sharing Frequency
Response seems unnecessary. Since Frequency Response is contributed to the entire interconnection,
ignoring any propagation delays, any Balancing Authorities within an interconnection can share Frequency
Response if a consistent method of measuring and allocating it can be determined. However, since all online
sources of Frequency Response will contribute based on the change in frequency, this sharing of Frequency
Response will not improve interconnection performance. It will only allow Balancing Authorities with too few
sources to meet NERC requirements. Hence, sharing arrangements would only improve frequency
performance if it results in more frequency responsive sources being online during an event. Additionally, due
to the geographical differences of the Balancing Authorities within the Reserve Sharing Groups, their use is
not conducive to a diversified interconnection frequency response.
Response: Frequency Response required by the Standard fully satisfies the reliability needs of each Interconnection.
Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT is just offering this as a suggestion that
needs to be vetted. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Westar Energy
RSG and Spinning Reserve today is SECONDARY response. How does FERC see the RSG (or RTO
markets) providing PRIMARY frequency response? Allowing the RSG option does not "address the 693
155
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001799
Organization
Yes or No
Question 15 Comment
directive", only dumps it on the RSG with no direction. Using frequency responsive loads seems impractical
based on the small frequency deviation levels required. What customer would be ok with dropping load when
frequency drops to 59.964 or 59.92, etc.
Response: Since these are new Requirements, existing RSG agreements most likely do not address Frequency Response. The SDT is just offering this as a
suggestion that needs to be vetted. The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
Customers are not required to provide frequency responsive load for reliability however this is an options entities may wish to explore.
ISO New England Inc.
As indicated previously in our comments, there is missing piece to maintaining system frequency and
arresting frequency deviation, and that is the generators’ governor response. This standard appears to
incorrectly assume that the BAs have the resources/ability to provide (primary) Frequency Response, and this
is simply not the case. The BAs do not necessarily own facilities which can provide this service.
Response: The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…” The SDT has also specified in the latest draft
standard version other methods for a BA to obtain Frequency Response.
Regarding governor response - this issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band
settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address
these concerns.
Independent Electricity System
Operator
As indicated in our comments under Q2, there is missing piece to maintaining system frequency and arresting
frequency deviation, and that is the generators’ governor response. We suggest the SDT conduct an industry
discussion on this piece, and determine the entity responsible for governor actions/setting, the mechanism to
provide such a response, and the place for stipulating the necessary standard requirements to enforce
compliance for governor actions before further developing this BAL-003-1 standard.
Response: The NERC Reliability Standards do not dictate how Requirements are satisfied.
The SDT believes each Interconnection possesses sufficient frequency response.
Regarding governor response - this issue has been discussed and the SDT understands your concern. However, governor droop requirements, dead-band
settings and governor operation are outside the scope of the project approved SAR. The SDT believes that the Generator Verification standards will help address
these concerns.
Duke Energy
The efforts to develop the MOD-025/026 standards and the associated work to determine actual and
predicted generator response will do much to identify the response available and provide ways to plan for and
validate the response needed and supplied. ERCOT has demonstrated effective use of Load Acting as a
Resource (LAAR - essentially customer compensated pre-emptive load shedding). Exploration of similar
applications of this in other interconnections is warranted.
156
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001800
Organization
Yes or No
Question 15 Comment
Response: The NERC Reliability Standards do not necessarily dictate “how” Requirements are satisfied. A market can be created by a region, sub-region, ISO,
RTO or other entities as appropriate to facilitate compliance however the NERC Reliability Standards do not establish markets.
Patterson Consulting, Inc.
The SDT has taken the correct approach in mandating Balancing Authority response. Balancing Authorities
should be able to acquire that response from various sources to create a suitable portfolio to meet the
required performance. The industry may benefit if the SDT defined required performance characteristics for
Frequency Response from a technical perspective, such as initial response in less than 2-8 seconds,
maximum response in less than 2-40 seconds, continuous (or not) response, etc. (These values are
examples and should be determined by the SDT.) Once the market and industry understand expectations,
existing or new technologies with those characteristics become possible sources. Then, it is just a matter of
adjusting tariffs (compensation) to incent implementation. If Frequency Response is allowed to be shared
between Balancing Authorities, the SDT must create requirements to address such issues as deliverability,
measurement, and suitable electrical diversity throughout the interconnection.
Response: The SDT agrees with your comment. However, keep in mind that the SDT is responding to a FERC directive to “…define methods of obtaining
Frequency Response…” The SDT has also specified in the latest draft standard version other methods for a BA to obtain Frequency Response.
The SDT is evaluating several averaging time periods during the field trial. The SDT will select the averaging time period that provides the most accurate results.
Alberta Electric System Operator
Frequency Response has different aspects and time frames (inertia, governor and AGC response), the
method of obtaining Frequency Response should respect these different aspects and time frames.
Response: The SDT is responding to a FERC directive to “…define methods of obtaining Frequency Response…” The SDT has also specified in the latest draft
standard version other methods for a BA to obtain Frequency Response.
FirstEnergy
See our responses to Question 4.
Response: Please refer to our response to Question 4.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
157
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001801
16. If you are aware of any conflicts between the proposed standard and any regulatory function, rule order, tariff, rate schedule, legislative
requirement, or agreement please identify the conflict here.
Summary Consideration: Most of the commenters responding to this question provided a response but did not identify any conflicts. A
couple of the commenters felt that there may be a conflict with both the FERC Order 693 and the FERC March 18, 2010 order. Another
commenter felt that the requirements could impact CPS performance and that using events from the prior evaluation period could create
the possibility of double jeopardy.
The SDT explained that the comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue
needing to be addressed at this time was not correct. The SDT stated that in the December 16, 2010 FERC Order Accepting NERC’s
Compliance Filing the Commission states in par 12 “…NERC’s proposed action plan demonstrates a commitment to develop requirements
for minimum levels of frequency response needed for Reliable Operation consistent with the Commission’s directives in Order No. 693.”
The SDT believes that this clearly states that the directives from FERC Order 693 are to be addressed.
Concerning the comment that the requirements could impact CPS performance the SDT explained that it believes that the large gap
commonly found between natural frequency response and the frequency bias settings deployed based on 1% of peak load was resulting in
excessive and unnecessary regulation and was related to high frequency following DCS events and in other circumstances as well. The
SDT agreed that the reduction of the 1% of peak load floor for the frequency bias setting can affect the total interconnection frequency
bias setting, L10 values, and possibly CPS 2 compliance as well. The SDT further explained that it put Requirement R5 back in the
proposed standard with a process for reducing the minimum to provide for monitoring the system to ensure reliable operation.
With regards to the comment concerning the possibility for double jeopardy the SDT responded that the SDT expected each year to normally
have enough frequency events to avoid double jeopardy, but there was a need to have a backup plan in case a year does not yield sufficient frequency events.
Organization
FirstEnergy
Yes or No
Question 16 Comment
We are not aware of any conflicts at this time.
Response: The SDT thanks you for your participation.
IRC Standards Review
Committee
This proposed Field Trial and standard MAY conflict with Order 693 and the March 18, 2010 Order that
state:Specifically, the Commission stated: As the Commission noted in the NOPR and in our response to
FirstEnergy, Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall establish
and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing
Authority’s Frequency Response.” The Commission believes that the achievement of this Requirement is
fundamental to the tie line bias control schemes that have been in use to assist in balancing generation and
load in the Interconnections for many years.
158
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001802
Organization
Yes or No
Question 16 Comment
Further, in Order No. 693 the Commission concluded: We understand that the present Reliability Standard
sets the required frequency response of the balancing authorities to be approximately one percent or greater
by requiring that the frequency bias shall not be less than one percent and that the frequency bias be as close
as practical to, or greater than, the actual frequency response. March 18 Order concludesAccordingly, to
assure that NERC proceeds expeditiously, the Commission is setting a compliance deadline of six months
from the date of issuance of this order for the development of modifications to Reliability Standard BAL-003-0
that comply with the Commission’s directives as set forth in Order No. 693 to define the appropriate
periodicity of frequency response surveys necessary to ensure that Requirement R2 and other requirements
of the Reliability Standard are being met and the necessary amount of frequency response needed for reliable
operation. May 13, 2010 Order for a Technical Conference statedThus, we direct that NERC submit, within 30
days after the technical conference, a proposed schedule that includes firm deadlines for completing studies,
analyses needed to develop a frequency response requirement, and for submission of a modified Reliability
Standard that is responsive to the Commission directives in Order No. 693 pertaining to Reliability Standard
BAL-003-0.
In short the Orders only ask for the BAL-003 to be revised to provide a schedule for the Frequency Response
surveys. We may question whether the subjective 25 events per year is the same as a scheduled periodicity,
but the point here is that that is the only mandate that is needed immediately.
The only other requirement is that NERC file a schedule for completing its studies. Note that is not something
that is for a standard it is something for a NERC filing.
Response: The SDT disagrees with your comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue needing to be
addressed at this time. In the December 16, 2010 FERC Order Accepting NERC’s Compliance Filing the Commission states in par 12 “…NERC’s proposed action
plan demonstrates a commitment to develop requirements for minimum levels of frequency response needed for Reliable Operation consistent with the
Commission’s directives in Order No. 693.” This clearly states that the directives from FERC Order 693 are to be addressed.
ERCOT
This proposed Field Trial and standard MAY conflict with Order 693 and the March 18, 2010 Order that
state:Specifically, the Commission stated: As the Commission noted in the NOPR and in our response to
FirstEnergy, Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall establish
and maintain a Frequency Bias Setting that is as close as practical to, or greater than, the Balancing
Authority’s Frequency Response.” The Commission believes that the achievement of this Requirement is
fundamental to the tie line bias control schemes that have been in use to assist in balancing generation and
load in the Interconnections for many years. Further, in Order No. 693 the Commission concluded: We
understand that the present Reliability Standard sets the required frequency response of the balancing
authorities to be approximately one percent or greater by requiring that the frequency bias shall not be less
than one percent and that the frequency bias be as close as practical to, or greater than, the actual frequency
response. March 18 Order concludesAccordingly, to assure that NERC proceeds expeditiously, the
Commission is setting a compliance deadline of six months from the date of issuance of this order for the
development of modifications to Reliability Standard BAL-003-0 that comply with the Commission’s directives
159
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001803
Organization
Yes or No
Question 16 Comment
as set forth in Order No. 693 to define the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other requirements of the Reliability Standard are being met and the
necessary amount of frequency response needed for reliable operation. May 13, 2010 Order for a Technical
Conference statedThus, we direct that NERC submit, within 30 days after the technical conference, a
proposed schedule that includes firm deadlines for completing studies, analyses needed to develop a
frequency response requirement, and for submission of a modified Reliability Standard that is responsive to
the Commission directives in Order No. 693 pertaining to Reliability Standard BAL-003-0. In short the Orders
only ask for the BAL-003 to be revised to provide a schedule for the Frequency Response surveys. We may
question whether the subjective 25 events per year is the same as a scheduled periodicity, but the point here
is that that is the only mandate that is needed immediately. The only other requirement is that NERC file a
schedule for completing its studies. Note that is not something that is for a standard it is something for a
NERC filing.
Response: The SDT disagrees with your comment concerning the “…scheduled periodicity of Frequency Response surveys…” being the only issue needing to be
addressed at this time. In the December 16, 2010 FERC Order Accepting NERC’s Compliance Filing the Commission states in par 12 “…NERC’s proposed action
plan demonstrates a commitment to develop requirements for minimum levels of frequency response needed for Reliable Operation consistent with the
Commission’s directives in Order No. 693.” This clearly states that the directives from FERC Order 693 are to be addressed.
Arizona Public Service Company
AZPS would like clarity if Interpretations of BAL-003-0 will be part of BAL-003-1.
Response: This standard will replace all existing BA-003’s and incorporates any approved interpretation.
Energy Mark, Inc.
Comment 53: In Comment 25 I indicated that the suggested allocation method fails to meet the requirement
that “A reliability standard shall neither mandate nor prohibit any specific market structure.” My comments
here support that contention. The allocation method is not influenced by demand for frequency response. As
a consequence, only one side of a fair market is represented. Markets are effective because:
1. Markets are voluntary allowing the demand side of the market to choose to not create the need to acquire
a product or service.
2. Markets select the lowest cost product or service from competing offers to supply the product or service
demanded.When the allocation method is blind to the demand for the product or service it eliminates the most
efficient market designs from consideration, and therefore, mandates a market design that only looks at the
supply side of the market.
Comment 54: Selecting an allocation method for Frequency Response that considers both the supply and
demand sides of the market for Frequency Response would enable the implementation of a much more
efficient market design. Such an allocation method would allow demand side reductions in the need for
Frequency Response to compete with supply side increases in the need for Frequency Response allowing for
160
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001804
Organization
Yes or No
Question 16 Comment
the creation of the most efficient markets in this Ancillary Service.
Response: The SDT acknowledges your concerns but your market-related suggestions are outside the scope of the industry approved SAR.
FMPP
NERC Relablity Standards Conflict - by using events from last year to determine an entity’s compliance with a
Requirement for this year puts the entity in double jeopardy for last year’s events, which were already used
for compliance for last year.
Response: The SDT agrees that a standard should not place an entity in double jeopardy. The SDT expects that each year will normally have enough frequency
events to avoid double jeopardy, but it needs to have a backup plan in case a year does not yield sufficient frequency events.
American Electric Power
This Standard has the potential to affect Standards involving CPS performance with respect to the calculated
CPS Bounds L10 if relative.
Response: The SDT believes that the large gap commonly found between natural frequency response and the frequency bias settings deployed based on 1% of
peak load is resulting in excessive and unnecessary regulation and is related to high frequency following DCS events and in other circumstances as well. You are
correct in asserting that the reduction of the 1% of peak load floor for the frequency bias setting can affect the total interconnection frequency bias setting, L10
values, and possibly CPS 2 compliance as well.
The SDT has put Requirement R5 back in the proposed standard. The SDT has modified the plan for reduction of the minimum Frequency Bias Setting. The plan
is no longer tied to the Field Trial. The SDT has removed the table reflecting the reduction of the minimum bias setting. The SDT is proposing a method of
reducing the minimum Frequency Bias Setting in which the ERO will monitor the results of the reductions and adjusting them accordingly in an effort to bring the
Frequency Bias Setting closer to natural Frequency Response. Please refer to Attachment B for details of this reduction plan.
Northeast Power Coordinating
Council
Refer to the response to Question 17.
Response: Please refer to our response to Question 17.
Patterson Consulting, Inc.
None.
Kansas City Power & Light
No other comments.
161
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001805
17. Please provide any other comments (that you have not already provided in response to the questions above) that you
have on the draft standard BAL-003-1.
Summary Consideration: Several commenters indicated that the supplemental compliance information and attachment sections created
additional standard requirements. In response to this concern these documents have been revised. If a requirement states that the entity
must perform in accordnace with Attachment X, then Attachment X is an extension of that requirement and the performance identified in
the attachment is mandatory and enforceable.
Several commenters expressed concern that the Balancing Authority may not have the necessary means to effectively manage Frequency
Response and recommended that the SDT consider establishing a standard for generators to support the Balancing Authorities achieve the
necessary level of Frequency Response. The SDT explained that this standard will provide the metrics for Frequency Response while the
market will define itself.
Commenters also stated that insufficient detail has been provided for evaluating the appropriateness of the methodology used for
determining FRO. They indicated that the standard needed more details on how the FRO is calculated and allocated among the Balancing
Authorities. The SDT made significant modifications to Attachment A – Supporting Document which details the methodology used to
determine the calculations.
Commenters indicated that the plan to annually reduce the floor percentage for the Frequency Bias Settings may adversely impact
reliability. In response to this concern the Implementation Plan no longer outlines the Frequency Bias Setting reduction plan initially
proposed. Attachment B sets forth the procedure for reducing the Frequency Bias Setting floor threshold.
Another commenter stated that emphasis should be placed on the Frequency Excursion Curve Point C value and not other values because
the Point C value is critical for reliability. A request was also received to correlate the frequency response for the Point B value timeframe
window with the timeframe window for the Point C value. The SDT committed to reviewing this relationship during the field trial.
One commenter asked how to attain or schedule Frequency Response from another Balancing Authority if it is a market resource. The SDT
responded that the standard simply provides reliability metrics. Industry determines which markets and independent solutions could be
developed.
A comment was received requesting clarification of the NERC glossary term “native load” mentioned in the Implementation Plan. Instead
of providing clarification, this term has been removed from the Implementation Plan.
Twenty-five additional industry comments have been received regarding the draft BAL-003-1 standard as noted in the following table.
Organization
Northeast Power Coordinating
Council
Question 17 Comment
It is not clear from either Form 1 or its instructions whether the supplied frequency deviation for an event should be used
without modification, or if it should be overwritten with a value computed from the Balancing Authority’s data source (or if
162
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001806
Organization
Question 17 Comment
there is an option, to use the lesser value, for example). Clearly express which frequency deviation value to use.
The load sensitivity calculation is an important Balancing Authority Area value to compute accurately for modeling purposes.
As proposed, it would use the same computational technique as that used for frequency bias sampling calculations. To yield
a useful result, load values would need to have “convergence characteristics” similar to that found in the actual net
interchange values used for frequency bias sampling. While experience has shown that the average or median values of the
frequency bias samples computed for most Balancing Authorities will converge with about 20 samples, a similar outcome for
load sensitivity calculations might not occur. Frequency bias samples rely on the measured actual net interchange values
that are sampled at the AGC scan rate, and the actual net interchange tends to be a rather stable value because AGC and
operator actions usually keep the actual net interchange close to a scheduled value. The total net system load may have
greater volatility and may be trending in a particular direction much more often than actual net interchange. Also, the load
calculation typically relies on adding the sum of the generation within the Balancing Authority to the actual net interchange.
The generation values may have a slower scan rate, longer data latency periods, and smaller generators might not be
telemetered, with hourly scheduled values or manually entered values being used instead. These differences can contribute
to a very different convergence characteristic than that found for actual net interchange. Simply put, the load sensitivity
calculation needs validation.
The Form 1 instructions mention a generation only Balancing Authority form to be filled in. It is not shown on the
spreadsheet provided, and it is not clear what data should be entered, though it seems like it would still be actual net
interchange.Form 1 contains an entry form for a single Balancing Authority Interconnection, however, it is not referenced in
the Form 1 instructions.Section A of the Form 1 instructions contains excellent background material that explains why this
effort is important. However, section B needs a careful review so that the instructions are thorough and unambiguous.The
information on variable bias calculations seems sparse, and the requirements for variable bias should be reviewed
thoroughly with those Balancing Authorities that are familiar with the nuances and challenges of determining an appropriate
variable bias.If BIAS is set equal to response, about 50% of the time, AGC will cancel out the primary response; the BIAS,
therefore, should be slightly higher than the natural response but clearly 1% is too large. The game plan to continually
reduce the floor percentage for frequency bias settings needs to be reconsidered. With .4% peak load being a typical actual
frequency response lately for Balancing Authorities, the 1% of peak load to .8% of peak load transition seems prudent.
Perhaps a further reduction to .6% may be useful as well, but lesser floors may in effect result in AGC too often canceling out
the primary frequency response being provided.While the 16 to 52 second sampling window for point B computations seem
to be a reasonable initial guess for the metric, preliminary studies by the Frequency Responsive Reserve Standard Drafting
Team (FRRSDT) indicate that AGC contributions from fast acting hydro generators will be included in the samples. As those
same studies were not conclusive, perhaps the initial years of this standard could require the provision of scan rate data from
30 seconds before to 60 seconds after the start of the frequency decline for each event. While this significantly increases the
volume of data to be provided, it would allow the FRRSDT to determine the best sampling intervals to be used. Perhaps a
point B sampling interval of 15 to 30 seconds would filter out most of the fast acting AGC, but more data/analysis is needed
to determine the best sampling interval to be sure that the primary response data is not being corrupted by this fast acting
AGC response.To support Balancing Authorities in achieving the targeted level of frequency response, a standard for
generators is needed as well, as they are historically the largest source of discretionary frequency response. The standard
could give a Balancing Authority the right to waive these requirements should they pursue other sources of frequency
163
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001807
Organization
Question 17 Comment
response, such as ERCOT’s “load acting as a resource (LAAR)” efforts.
Point C values are the more important reliability metric. Since point C metrics are challenged with data quality issues on a
Balancing Authority and generator level, an effort should be made to correlate the required frequency response in the point B
time window with that needed in the point C time window (perhaps using rules of thumb, such as 100% of load’s frequency
response and 30% of generator’s frequency response occurs in time for point C).
While Attachment A mentions that N-2 category C events will be used to determine the frequency response obligation on an
interconnection level, there is insufficient detail provided at this time to evaluate the appropriateness of the obligations
selected. Efforts in this area for the frequency model developed by the Reliability-Based Control Standard Drafting Team
(and now the BARCSDT) for HQTE may shed some insight into this process.
Response: The SDT agrees that clearer instructions are needed in Form 1. This has been addressed in the revised form. The SDT also agrees that there may
be limited benefit from measuring the load response of a BA due to data fidelity and resolution. An attempt to measure a BA’s load response was included for the
field trial to determine its value and was not used in the BA’s frequency response measure. It is believed that some BA’s with generation data that is on a similar
scan rate as their Interchange data may find that it accurately measures their load dampening. The field trial will determine if it is useful or not. The SDT agrees
that the 16 to 52 second sampling window may include some fast acting AGC. The field trial will determine if this sampling period should be reduced. Form 1 has
been revised to include a minimum data set that starts 30 seconds before the event and ends not earlier than 60 seconds after the event to help identify the
overall best averaging periods. The SDT also agrees that the use of LaaRs in ERCOT is a great backup to Primary Frequency Control but would also like to point
out that this response only responds in one direction and does not provide bidirectional frequency stability for the moment to moment changes in frequency.
Once utilized, it takes hours to restore the service for the next contingency. During this time, the BA and Interconnection depends on Primary Frequency Control
from other sources that are continuous and bidirectional as long as headroom is available. The SDT agrees that Point C Primary Frequency Control is critical for
preventing UFLS and will use the field trial results to determine if the Point B measure of performance can be correlated to Point C performance. Thank you for
your comments.
Regarding governor response - this issue concerning generators has been discussed by the SDT. The SDT understands your concern. However, governor droop
requirements, dead-band settings, and governor operation is outside of the industry approved SAR. The SDT believes that the Generator Verification standards
will help address these concerns.
The N-2 criteria is being evaluated during the field trial.
ISO New Engand Inc.
It is not clear from either Form 1 or its instructions whether the supplied frequency deviation for an event should be used
without modification, or if it should be overwritten with a value computed from the Balancing Authority’s data source (or if
there is an option, to use the lesser value, for example). Clearly express which frequency deviation value to use.
2. The load sensitivity calculation is an important Balancing Authority Area value to compute accurately for modeling
purposes. As proposed, it would use the same computational technique as that used for frequency bias sampling
calculations. To yield a useful result, load values would need to have “convergence characteristics” similar to that found in
the actual net interchange values used for frequency bias sampling. While experience has shown that the average or
median values of the frequency bias samples computed for most Balancing Authorities will converge with about 20 samples,
a similar outcome for load sensitivity calculations might not occur. Frequency bias samples rely on the measured actual net
164
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001808
Organization
Question 17 Comment
interchange values that are sampled at the AGC scan rate, and the actual net interchange tends to be a rather stable value
because AGC and operator actions usually keep the actual net interchange close to a scheduled value. The total net system
load may have greater volatility and may be trending in a particular direction much more often than actual net interchange.
Also, the load calculation typically relies on adding the sum of the generation within the Balancing Authority to the actual net
interchange. The generation values may have a slower scan rate, longer data latency periods, and smaller generators might
not be telemetered, with hourly scheduled values or manually entered values being used instead. These differences can
contribute to a very different convergence characteristic than that found for actual net interchange. Simply put, the load
sensitivity calculation needs validation.The Form 1 instructions mention a generation only Balancing Authority form to be
filled in. It is not shown on the spreadsheet provided, and it is not clear what data should be entered, though it seems like it
would still be actual net interchange.Form 1 contains an entry form for a single Balancing Authority Interconnection, however,
it is not referenced in the Form 1 instructions.Section A of the Form 1 instructions contains excellent background material
that explains why this effort is important. However, section B needs a careful review so that the instructions are thorough
and unambiguous.The information on variable bias calculations seems sparse, and the requirements for variable bias should
be reviewed thoroughly with those Balancing Authorities that are familiar with the nuances and challenges of determining an
appropriate variable bias.If BIAS is set equal to response, about 50% of the time, AGC will cancel out the primary response;
the BIAS, therefore, should be slightly higher than the natural response but clearly 1% is too large. The game plan to
continually reduce the floor percentage for frequency bias settings needs to be reconsidered. With .4% peak load being a
typical actual frequency response lately for Balancing Authorities, the 1% of peak load to .8% of peak load transition seems
prudent. Perhaps a further reduction to .6% may be useful as well, but lesser floors may in effect result in AGC too often
canceling out the primary frequency response being provided.
While the 16 to 52 second sampling window for point B computations seem to be a reasonable initial guess for the metric,
preliminary studies by the Frequency Responsive Reserve Standard Drafting Team (FRRSDT) indicate that AGC
contributions from fast acting hydro generators will be included in the samples. As those same studies were not conclusive,
perhaps the initial years of this standard could require the provision of scan rate data from 30 seconds before to 60 seconds
after the start of the frequency decline for each event. While this significantly increases the volume of data to be provided, it
would allow the FRRSDT to determine the best sampling intervals to be used. Perhaps a point B sampling interval of 15 to
30 seconds would filter out most of the fast acting AGC, but more data/analysis is needed to determine the best sampling
interval to be sure that the primary response data is not being corrupted by this fast acting AGC response.
To support Balancing Authorities in achieving the targeted level of frequency response, a standard for generators is needed
as well, as they are historically the largest source of discretionary frequency response. The standard could give a Balancing
Authority the right to waive these requirements should they pursue other sources of frequency response, such as ERCOT’s
“load acting as a resource (LAAR)” efforts.
Point C values are the more important reliability metric. Since point C metrics are challenged with data quality issues on a
Balancing Authority and generator level, an effort should be made to correlate the required frequency response in the point B
time window with that needed in the point C time window (perhaps using rules of thumb, such as 100% of load’s frequency
response and 30% of generator’s frequency response occurs in time for point C).While Attachment A mentions that n-2
category C events will be used to determine the frequency response obligation on an interconnection level, there is
insufficient detail provided at this time to evaluate the appropriateness of the obligations selected. Efforts in this area for the
165
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001809
Organization
Question 17 Comment
frequency model developed by the Reliability-Based Control Standard Drafting Team (and now the BARCSDT) for HQTE
may shed some insight into this process.
Response: The SDT agrees that clearer instructions are needed in Form 1. This has been addressed in the revised form. The SDT also agrees that there may
be limited benefit from measuring the load response of a BA due to data fidelity and resolution. An attempt to measure a BA’s load response was included for the
field trial to determine its value and was not used in the BA’s frequency response measure. It is believed that some BA’s with generation data that is on a similar
scan rate as their Interchange data may find that it accurately measures their load dampening. The field trial will determine if it is useful or not. The SDT agrees
that the 16 to 52 second sampling window may include some fast acting AGC. The field trial will determine if this sampling period should be reduced. Form 1 has
been revised to include a minimum data set that starts 30 seconds before the event and ends not earlier than 60 seconds after the event to help identify the
overall best averaging periods. The SDT also agrees that the use of LaaRs in ERCOT is a great backup to Primary Frequency Control but would also like to point
out that this response only responds in one direction and does not provide bidirectional frequency stability for the moment to moment changes in frequency.
Once utilized, it takes hours to restore the service for the next contingency. During this time, the BA and Interconnection depends on Primary Frequency Control
from other sources that are continuous and bidirectional as long as headroom is available. The SDT agrees that Point C Primary Frequency Control is critical for
preventing UFLS and will use the field trial results to determine if the Point B measure of performance can be correlated to Point C performance. Thank you for
your comments.
This issue concerning generators has been discussed by the SDT. The SDT understands your concern. However, governor droop requirements, dead-band
settings, and governor operation is outside of the industry approved SAR. The SDT believes that the Generator Verification standards will help address these
concerns.
The N-2 criteria is being evaluated during the field trial.
Santee Cooper
Again, we believe that the SDT should consided or prior years’ data. We are concerned with how the total frequency
response obligation of an interconnection will be determined since this will ultimately determine each BA’s FRO. We believe
more detail should be presented on this issue.We appreciate the time and the work performed by the standard drafting team
on this standard that we feel is a necessary component for reliable operation of the Interconnections.
Response: The SDT does not understand the intent of the first sentence in your comment.. The next posting will be more explicit in the method for determining
the FRO.
MRO's NERC Standards Review
Subcommittee
We feel the Reserve Sharing Group should be removed from the applicability section as it’s not included in any requirement.
Response: The SDT has modified the proposed standard to better reflect the RSG responsibility in providing Frequency Response.
Xcel Energy
We feel Reserve Sharing Group should be removed from the applicability section since it is not included in any of the
requirements. Additionally, the documents are not clear as to how there is a field trial included in the proposal.
166
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001810
Organization
Question 17 Comment
Response: The SDT has modified the proposed standard to better reflect the RSG responsibility in providing Frequency Response.
LG&E and KU Energy
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data.We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.Please make
sure enhanced frequency response from load is examined as an economical source of frequency response per FERC
requirements in Order 693 paragraphs 336 and 375.
The SDT has not addressed how the requirements of the proposed standard can be implemented without a market
mechanism.All frequency response available in an RTO/ISO ancillary services market should be offered in a nondiscriminatory way (possibly on an OASIS).
The standard needs more detail (not an attachment) on how the Interconnect FRO is allocated to BAs. We further suggest
the SDT consider providing detail in Attachment A that the Reliability Coordinator will need to be involved in allocation of the
FRO to specific regions or plants within the Reliability Coordinator Area.
There is a good chance that the proper geographic location of frequency responsive reserves will increase Transfer Path
capability when the Transfer Path capability is limited by a loss of generation. This may be the case in the west where loss of
two Palo Verde units establishes the California-Oregon Intertie SOL because frequency responsive reserves are carried in
the Pacific Northwest, not near Palo Verde. The BAL-003-1 standard does not consider this issue.
Please review the (pk gen+pk load)/2 method described in Attachment A, page 3.We appreciate the time and the work
performed by the standard drafting team on this standard that we feel is a necessary component for reliable operation of the
Interconnections.
Response: The FRO is based on the forecasted values. The SDT had extensive discussions concerning the generation/load split for determining the BA FRO and
believes that the proposed methodology is both reasonably equitable and non-discriminatory.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
This standard provides metrics in which markets and independent solutions can be developed.
This standard provides a minimum requirement of a BA but does not prevent an RC from imposing further restrictions.
All of the methodologies proposed in this standard are being tested during the field trial.
SERC OC Standards Review
Group
The Standard Authorization Request Form references that BAL-003-0 originated as part of Project 2007-18, Reliability-based
Control. Actually, it originated in Project 2007-05, Balancing Authority Control.
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
167
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001811
Organization
Question 17 Comment
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data. We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.
We appreciate the time and the work performed by the standard drafting team on this standard which we feel is a necessary
component for reliable operation of the Interconnections.”The comments expressed herein represent a consensus of the
views of the above named members of the SERC OC Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”
Response: Revisions to BAL-003 were originally part of Project 2007-05, but Project 2007-05 was then merged on July 28, 2010 into Project 2007-18.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
The FRO is based on the forecasted values.
The methodologies proposed in this standard have been tested during the field trial.
South Carolina Electric and Gas
The Standard Authorization Request Form references that BAL-003-0 originated as part of Project 2007-18, Reliability-based
Control. Actually, it originated in Project 2007-05, Balancing Authority Control.
We are concerned that, in attachment A, the generation/load split in determining FRO may not be the most equitable method
for allocation. In general, we feel that Attachment A needs additional clarity, i.e., is the split based on forecasted or prior
years’ data. We are concerned with how the total frequency response obligation of an interconnection will be determined
since this will ultimately determine each BA’s FRO. We believe more detail should be presented on this issue.We appreciate
the time and the work performed by the standard drafting team on this standard that we feel is a necessary component for
reliable operation of the Interconnections.
Response: Revisions to BAL-003 were originally part of Project 2007-05, but Project 2007-05 was then merged on July 28, 2010 into Project 2007-18.
The SDT recognizes the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and provide
greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as supplemental standard information.
The FRO is based on the forecasted values.
The methodologies proposed in this standard have been tested during the field trial.
FirstEnergy
If not already planned, we suggest that the drafting team conduct a webinar on this project to clarify the deliverables and
answer questions that industry may have.
Response: The SDT conducted a Webinar on July 18, 2011 and is planning on holding another webinar in November 2011 to explain the changes made between
168
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001812
Organization
Question 17 Comment
versions.
Bonneville Power Administration
o D1.4 R1 Supplemental Information (first paragraph) - Adds an additional requirement outside of the requirements section.
o D1.4 R2 Supplemental Information (first paragraph) - Adds an additional requirement outside of the requirement section.
o D1.4 R Supplemental Information (Second paragraph) - Adds an additional requirement outside of the requirements
section. This number has nothing to do with frequency response during events. Also, has more to do with R1 than R2.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
SPP Standards Development
The reporting requirement in Attachment A under R1 '...each BA has one month to assemble its data and calculate the FRM.'
is not consistent with the reporting requirements in D. Compliance, 1.4 of the draft Standard.
R4 - We suggest replacing the word 'increase' with 'modify' or 'adjust'.
We also suggest deleting Balancing Authority Area and replacing it with combined areas at the end of the sentence.
Why is R4 in BAL-003-0 being retired?
Response: The SDT has corrected the error in the wording.
The SDT prefers to use the word “increase” to provide clarity that the Frequency Bias Setting should go up when providing this service. Use of the terms you are
suggesting could be interpreted to allow for adjustments up or down.
BAL-003-01.b Requirement R4 is not longer necessary. This Requirement addresses how to calculate Frequency Bias Settings. This is no longer needed since the
Frequency Bias Settings are calculated in FRS Form 1 using Frequency Response associated with the “official” list of events and a couple of “floor or ceiling” limits
(% of peak load/gen and FRO). The entire calculation is built into the FRS Form 1 workbook.
IRC Standards Review
Committee
The sections of “Additional Compliance Information” in the draft standard seem to create requirements as written. For
example, revision of 1.4 for R1 Supplemental Information is suggested to be as follows: Each Balancing Authority or the
Interconnection designated entity shall reports its previous year’s Frequency Response Measure (FRM) to the ERO on Form
1 by January 10 each year. If the ERO posts the official list of events after December 10, Balancing Authorities or the
Interconnection designated entity will be given 45 days from the date the ERO posts the official list of events to submit their
FRS Form 1.
If aA Balancing Authority may elects to fulfill its Frequency Response Obligation by participating as a member of a Reserve
Sharing Group (RSG). If a Balancing Authority elects to report as an RSG, the total of the participating Balancing Authorities’
FRO will be compared to the total of the participating Balancing Authorities’ FRM.
Further, revision of 1.4 for R2 Supplemental Information is suggested to be as follows:
Each Balancing Authority or the Interconnection designated entity shall reports its current year requested Frequency Bias
169
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001813
Organization
Question 17 Comment
Setting and Frequency Bias type (fixed or variable) to the ERO on FRS-Form 1 by January 10 each year. If the ERO posts
the official list of events after December 10, Balancing Authorities will be given 45 days from the date the ERONERC posts
the official list of events to submit their FRS Form 11. Once the FRM and Frequency Bias Settings have been validated by
the ERO, the ERO will disseminate the Frequency Bias Settings Report for all Balancing Authorities in each Interconnection
along with the implementation date.Balancing Authorities with variable Frequency Bias Settings shall calculate monthly
average Frequency Bias Settings. The previous year’s monthly averages will be reported annually on FRS Form 1.
Again, please clarify what qualifies as “variable” Frequency Bias Setting.
Also please clarify how the “monthly average Frequency Bias Settings” are to be calculated. Is it a daily or weekly or hourly
weighted average, or something else?
In Attachment A: What is the “frequency deviation event threshold specified for the Interconnection”? Where is it specified?
Please clarify.In Attachment A, 2.b.: Is this intended to be describing Point B? Please clarify.In Attachment A:
While the ERO is deciding which events to use, does this mean that, throughout the year, the BA must collect and save all
the relevant data for all events so as to have the data ready and available for when the ERO issues the list of events to be
reported?
In Attachment A, 4.: “Any indication or evidence of a secondary event occurrence after Point C should be reviewed for
inclusion based on having sufficient information to perform a full analysis of the event”. What meant by “should be
reviewed”? Who is to be doing the review? What are the criteria for the review?
In the Implementation Plan: “native load” is not defined in the ERCOT Interconnection. Please clarify.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
The Requirement and Measure have been modified to include references to RSGs.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions.
The SDT recognizes the need to convert Attachment A into two documents in order to provide further clarity. The first document will remain part of the standard
as Attachment A and provide greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as
supplemental standard information.
The current Reliability Standard BAL-005 cites the data required to be archived.
As envisioned, the ERO will post the events to be analyzed on a quarterly basis to allow a BA to review its performance throughout the year.
The Implementation Plan no longer references “Native Load”. However, this term is defined in the NERC Glossary of Terms.
ERCOT
The sections of “Additional Compliance Information” in the draft standard seem to create requirements as written. For
example, revision of 1.4 for R1 Supplemental Information is suggested to be as follows: Each Balancing Authority or the
Interconnection designated entity shall reports its previous year’s Frequency Response Measure (FRM) to the ERO on Form
170
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001814
Organization
Question 17 Comment
1 by January 10 each year. If the ERO posts the official list of events after December 10, Balancing Authorities or the
Interconnection designated entity will be given 45 days from the date the ERO posts the official list of events to submit their
FRS Form 1. If aA Balancing Authority may elects to fulfill its Frequency Response Obligation by participating as a member
of a Reserve Sharing Group (RSG). If a Balancing Authority elects to report as an RSG, the total of the participating
Balancing Authorities’ FRO will be compared to the total of the participating Balancing Authorities’ FRM.Further, revision of
1.4 for R2 Supplemental Information is suggested to be as follows:Each Balancing Authority or the Interconnection
designated entity shall reports its current year requested Frequency Bias Setting and Frequency Bias type (fixed or variable)
to the ERO on FRS-Form 1 by January 10 each year. If the ERO posts the official list of events after December 10,
Balancing Authorities will be given 45 days from the date the ERONERC posts the official list of events to submit their FRS
Form 11. Once the FRM and Frequency Bias Settings have been validated by the ERO, the ERO will disseminate the
Frequency Bias Settings Report for all Balancing Authorities in each Interconnection along with the implementation date.
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The
previous year’s monthly averages will be reported annually on FRS Form 1. Again, please clarify what qualifies as “variable”
Frequency Bias Setting. Also please clarify how the “monthly average Frequency Bias Settings” are to be calculated. Is it a
daily or weekly or hourly weighted average, or something else?In Attachment A: What is the “frequency deviation event
threshold specified for the Interconnection”? Where is it specified? Please clarify.In Attachment A, 2.b.: Is this intended to
be describing Point B? Please clarify.In Attachment A: While the ERO is deciding which events to use, does this mean that,
throughout the year, the BA must collect and save all the relevant data for all events so as to have the data ready and
available for when the ERO issues the list of events to be reported?In Attachment A, 4.: “Any indication or evidence of a
secondary event occurrence after Point C should be reviewed for inclusion based on having sufficient information to perform
a full analysis of the event”. What meant by “should be reviewed”? Who is to be doing the review? What are the criteria for
the review?In the Implementation Plan: “native load” is not defined in the ERCOT Interconnection. Please clarify.
Response: The Additional Compliance Section has been completely revised and the issues you identified have been removed.
The Requirement and Measure have been modified to include references to RSGs.
Variable frequency bias settings are determined by Balancing Authorities using a calculation based on present operating conditions.
The SDT recognizes the need to convert Attachment A into two documents in order to provide further clarity. The first document will remain part of the standard
as Attachment A and provide greater detail for the calculation methodologies. The second document will explain the rationale for the requirements as
supplemental standard information.
The current Reliability Standard BAL-005 cites the data required to be archived.
As envisioned, the ERO will post the events to be analyzed on a quarterly basis to allow a BA to review its performance throughout the year.
The Implementation Plan no longer references “Native Load”. However, this term is defined in the NERC Glossary of Terms.
Progress Energy
We believe this standard insufficiently addresses the true nature of the problem; however it does accuratly address the fact
171
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001815
Organization
Question 17 Comment
that the current BA minimum frequency bias setting is too large.
This standard should also exclude LSE's without generation capacity since this problem both exists and can be solved at the
generator level.
Response: The SDT agrees that the generator level can solve the issues. This standard is addressing directives from FERC Order 693. Any reference to a
generator requirement would be outside of the industry approved SAR.
The LSE is not cited as an applicable entity.
NIPSCO
We reviewed the number of BAs in the Eastern Interconnection and there are many. We're hoping that compliance to R1
would be covered by the RSGs similar to DCS.
Response: The SDT added the RSG as a applicable entity to allow a BA an alternative method for complying with this standard.
Energy Mark, Inc.
Comment 55: In Comment 25 I indicated that the suggested allocation method creates perverse incentives for BAs
attempting to make decisions concerning Frequency Response. My comments here support that contention. Since the
suggested allocation method is blind to changes in the demand for Frequency Response and it allocates the requirement to
supply Frequency Response on a fixed Peak Load / Peak Generation Ratio share, it supports economic decisions at the BA
level that are far from economic at the interconnection level. This perverse influence on economics and reliability are
illustrated with two examples.
Example 1: A BA with a Peak Load / Peak Generation Ratio share of 5% of the interconnection must decide whether
or not to implement a program to expend $1 M to reduce the demand for Frequency Response worth approximately a
comparable $5 M. From an interconnection level this is an obvious decision. The BA should implement the program.
However, when the allocation method is considered, if the BA implements the program, it will expend $1 M, but will
only see a reduction in its Frequency Response requirement of $.25 M. The remainder of the reduction in demand for
Frequency Response will be shared by the other BAs on the interconnection. Therefore, it is in the BAs interest to not
implement the program even though it provides excellent overall economics and results in improved reliability.
Example 2: A BA with a Peak Load / Peak Generation Ratio share of 5% of the interconnection must decide whether
or not to implement a program to save $1 M in annual maintenance expenses at its generation plants that will increase
the need for Frequency Response on the interconnection at an annual cost of $5 M. From an interconnection level
this is an obvious decision. The BA should not implement the program. However, when the allocation method is
considered, if the BA implements the program, it will save $1 M anually, but will only see a increase in its annual
expense for Frequency Response requirement of $.25 M. The remainder of the increase in demand for Frequency
Response will be shared by the other BAs on the interconnection. Therefore, it is in the BAs interest to implement the
program even though it fails to provide good economics and results in a decline in reliability.
These examples demonstrate why a fixed allocation method as suggested in Attachment A would result in perverse results
172
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001816
Organization
Question 17 Comment
with respect to reliability and economics.
Comment 56: A series of four technical papers were written and offered to the Frequency Response Standard Drafting
Team that describe a measurement method for Frequency Response that does not have the detrimental limitations that exist
with the Peak Load / Peak Generation Ratio share method suggested in Attachment A. These four paper are:1. Illian, H. F.,
Frequency Response Risk Measure, Prepared for the Frequency Response Standard Drafting Team, Energy Mark, July 1,
2010 revised September 7, 2010.2. Illian, H. F., Understanding ACE and CPS1, Prepared for the Frequency Response
Standard Drafting Team, Energy Mark, September 8, 2010.3. Illian, H. F., Frequency Response Reliability Measure for the
Balancing Authority, Prepared for the Frequency Response Standard Drafting Team, Energy Mark, October 11, 2010.4.
Illian, H. F., Description of Regressions for Frequency Response Analysis, Prepared for the Frequency Response Standard
Drafting Team, Energy Mark, September 21, 2010.PDFs of these papers have been forwarded to supplement these
comments and should be addended as part of my comments.
Response: Comment 54 – The SDT understands your concerns and has taken them under consideration during the development of this standard. The SDT will
provide technical justification for the methods it proposes within the standard.
Comment 55 – The SDT thanks you for your work in creating the aforementioned papers. The SDT has reviewed these papers and considered them during the
development of this standard. Furthermore, the SDT will forward them on to the appropriate NERC personnel.
Hydro-Quebec TransEnergie
The proposed NERC standard (BAL-003) does not take into account the “point C” issue. The proposed requirements are only
related to “point B”.The proposed NERC standard (BAL-003) validates that the Balancing Authority carries enough
Synchronized Reserve and that this reserve is really Frequency Responsive, on average in the most common situations
(based on the median). It is an “after-the-fact” evaluation of the performance of the Balancing Authority. However, there is
no guaranty that the Balancing Authority will maintain the required Synchronized Reserve either when the load is very low or
during peak load periods Real-time Monitoring of the frequency responsive reserve would be a good way to avoid this issue.
Response: The SDT is proposing a more conservative Point B result in order to protect for Point C UFLS.
We encourage real-time monitoring of Frequency Response as a good practice but mandating it is beyond industry approved SAR. Also, the SDT believes that
this is being addressed in the development of the Balancing Authority Reliability-based Control standards in Project 2010-14.
Westar Energy
Based on a Category C (N-2) event, what is the approximate Interconnection Frequency Response Obligation for each
Interconnection? What is the First Step UFLS for each Interconnection?
Since there is no NERC Standard requirement for what first step UFLS is, what if it changes during the year?
Response: The SDT recognized the need to convert Attachment A into two documents. The first document will remain part of the standard as Attachment A and
provide greater detail for the calculation methodologies, including FRO. The second document will explain the rationale for the requirements as supplemental
standard information. Table 2 in revised Attachment A shows the FRO for each interconnection and the methodology used to determine this value. The UFLS set
point used in the calculation is shown in Table 2 for each Interconnection. These values are intended to protect against frequency reaching the highest UFLS
173
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001817
Organization
Question 17 Comment
setting for credible contingencies.
The utilities have the ability to change the UFLS settings during the year. The entities FRO and Frequency Bias Setting would remain the same until it was
reviewed by the ERO. Your comment does emphasize the need for the ERO to coordinate these changes across standards but this is outside the scope of this
project..
EKPC
EKPC would like to express the importance of considering large non-conforming loads and their effects on smaller BAs.We
appreciate the drafting team’s effort and dedication to this standard.
Response: The SDT has modified FRS form 1 to allow for adjustments, including non-conforming load.
We Energies
The FRO and the standard in general focus on Frequency Response for an intact grid. Inadequate consideration is given to
unexpected events such as separation, islanding and partial or total BES failure. In these cases, the location of the FR
resources is important. For example, if a BA has a contract with an entity that controls load level to satisfy the required FRO,
that load may not be within the island created following a disruption to the BES. A complete BES failure may leave a black
start island with only load frequency response. Load frequency response is the ultimate dispersed source for this commodity,
but may be inadequate as the sole provider under abnormal grid conditions. For better grid security, other dispersed sources
of frequency response are desirable.
Comment on the NERC Resources Subcommittee Position Paper on Frequency Response (Discussion Draft):EOP-005-2
does not contain requirements for the Balancing Authority in a restoration event involving the use of black start resources.
Only Transmission Operators, Generator Operators, Transmission Owners identified in the Transmission Operators
restoration plan, and Distribution Providers identified in the Transmission Operators restoration plan have roles in that
standard. How will the BA “bring more Frequency Responsive resources to bear” during black start if they have no defined
role?
Response: This standard is not meant to be an emergency operations standard. However, this standard could assist an entity in identifying and solving the
problem you have mentioned.
The NERC RS Position Paper on Frequency Response is not a product of this standard. It is an information paper requested by the NERC OC. The RS posted the
document and received industry comments that were incorporated.
American Electric Power
If a balancing authority loses generation, what happen to the neighboring balancing authority’s AGC?
If an overall Reserve Sharing Group’s performance can possibly be used to meet performance measures, why is the RSG
not included in the Standard applicability for such functional entity?
Response: If the Frequency Bias Setting is close to natural Frequency Response, as this standard is proposing, the AGC impacts would be minimal or none.
The RSG is listed in the Applicability Section of this standard. The SDT has further modified Requirement R1 to identify the RSG within the requirement.
174
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001818
Organization
Duke Energy
Question 17 Comment
Below are just some of the points that Duke Energy believes need to be discussed further.
Relationship to other standards under development: Given the significant implications of this standard to the other balancingrelated standards, Duke Energy feels strongly that the Standards Committee should keep the work under Project 2010-14,
Balancing Authority Reliability-based Control, high on the list of standards to be developed. CPS1 and the proposed BAAL
are measures that make sense in the long term, as they provide “support to maintain Interconnection Frequency within
predefined bounds” and aid in “supporting frequency until the frequency is restored to schedule” as desired in the purpose
statement of this standard.
Reserve Sharing Group: Duke Energy understands and supports the concept that Frequency Response could be aggregated
over a Reserve Sharing Group, however the details need to be addressed in the measures, and in the requirements, which in
the current draft only apply to the Balancing Authority.
Field test: Duke Energy found the implementation plan and field test confusing. The information didn’t indicate when the field
test would start and end. The implementation plan proposes starting the gradual adjustment of BAL-003-0 R5 in May 2011 what if the standard hasn’t been approved by FERC by then? Shouldn’t those dates be tied somehow to the effective date of
BAL-003-1 which is in turn tied to regulatory approval where required? Or is that gradual decrease actually part of the field
test?
Frequency responsive resources: What are the attributes needed for a resource, or combination of resources, to be
considered capable of providing “Frequency Response”? The answer is a critical element to the development of market
products in a uniform manner across the Interconnection. Among other attributes, Frequency Response aids in arresting
sudden frequency decline, however frequency responsive resources must respond to positive and negative deviations in
Interconnection frequency. Having loads that drop off the system at certain levels of frequency are valuable tools in arresting
frequency decline, however such resources do nothing within the range of frequency in which the Interconnection operates
perhaps 99% of the time. This would point to perhaps two types of services to address frequency below 60 Hz - provision of
frequency response in normal and emergency operation, and provision of a service specific for arresting a significant drop in
frequency at a specific bound to reduce the possibility of UFLS needing to be utilized. Duke Energy believes these are two
different products and should not be considered interchangeable.
Methods of obtaining Frequency Response:
If frequency response is a market resource, how can it be attained or scheduled from another Balancing Authority? Duke
Energy believes this question needs to be asked of the Interchange Subcommittee.
As the concept of a Reserve Sharing Group providing a “group frequency response” would not in our opinion constitute
“interchange”, Duke Energy believes the measure for calculated response should look at the RSG as if it was a single BA,
rather than attempt to measure the RSG participants individually. On the other hand, outside of an RSG, if resources in one
BA Area were contracted to supplement the response of resources in another BA Area, would such response be provision of
a service between a source and sink BA, or would it be interchange with the Interconnection in some manner?
FRM calculation:
175
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001819
Organization
Question 17 Comment
Under the proposed definition, the FRM calculation would only consider provision of response from resources external to the
BA Area if the “interchange” came in the form of a Pseudo-tie adjustment to Actual Interchange - Dynamic Schedules would
not be accounted for. As the use of Pseudo-ties changes load calculations and other data, even the use of them may not
make sense compared perhaps to just having a mechanism to move the obligation to the area providing the response, and
then determining if the provision of just Frequency Response must absolutely carry into increased secondary control
requirements.
Separating primary response from secondary control:
Is it possible for resources in one BA to provide a measure of Frequency Response for another BA, but not result in a change
to each BA’s Frequency Bias Setting used in the secondary control requirements?
Response: The development of the Balancing Authority Reliability-based Control standards in Project 2010-14 are outside the scope of this SDT, however the
need to coordinate development was raised with the Standards Committee and the standards in Project 2010-14 that address “reserves” have been advanced as
high priority.
The SDT has modified Requirement R1 and the associated measure to identify the RSG.
In reference to your field trial comment the SDT has modified the Implementation Plan to no longer reference the field test or the reduction of the minimum
Frequency Bias Setting. The SDT has developed a process by which the ERO will reduce the minimum Frequency Bias Setting. The procedure used to reduce
the Frequency Bias Setting is detailed in Attachment B and is now tied to regulatory approval of this standard.
This standard will provide the metrics for Frequency Response while the market will define itself. The SDT encourages you to work with NAESB to define a
market.
The SDT encourages you to open a discussion with the Interchange Subcommittee concerning Frequency Response as a market resource.
The SDT has included language that defines how the RSG is to perform and comply with this standard. The SDT agrees that a Reserve Sharing Group providing
a “group frequency response” would not be interchange between the entities within that group. The SDT also agrees that the RSG would be evaluated as if it
were a single BA.
The SDT has incorporated an improved FRS Form 1 with instructions for its use. The SDT thanks you for your comment concerning Pseudo-tie but, based on the
information provided, the SDT is unsure of your question and cannot provide a further response.
With regards to your last comment, the SDT believes that it is possible as long as they are using a dynamic schedule.
Patterson Consulting, Inc.
Requirement 4 is worded incorrectly, although it is taken from the existing standard. Requirement 4 states "Each Balancing
Authority that is performing Overlap Regulation Service shall [increase] its Frequency Bias Setting in its ACE calculation by
combining the Frequency Bias Settings for the entire Baalancing Authority Area being controlled." (Bracketing added for
emphasis.) Considering Frequency Bias Settings are negative numbers, this requirement should have Balancing Authorities
"decrease" rather than "increase" their Frequency Bias Settings. For example, the requirement could state "Each Balancing
Authority that is performing Overlap Regulation Service shall decrease..." or if "decrease" is undesirable then "Each
Balancing Authority that is performing Overlap Regulation Service shall modify..."
176
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001820
Organization
Question 17 Comment
Response: The SDT understands your concern with the use of the term “increase” and has replaced this word with “modify”. The SDT revised Requirement R4
for additional clarity and it now reads:
Each Balancing Authority that is performing Overlap Regulation Service shall modify its Frequency Bias Setting in its ACE calculation to be
equivalent to the sum of the Frequency Bias Settings of the participating Balancing Authorities as validated by the ERO or calculate the
Frequency Bias Setting based on the entire area being combined and thereby represent the Frequency Response for the combined area being
controlled.
Associated Electric Cooperative,
Inc.
BAL-003-1 draft standard:
Apparent Intent and expectations:
1) I agree with this emerging standard’s recognizing that the arbitrary 1% of peak-load should be refined by being lowered to
better reflect each BA’s expected frequency response.
2) This emerging standard apparently attempts to address the divesture of generation from loads by utilizing the “(Load +
Generation)/2” formula, which seems fair.
3) I’m still struggling with the concept of being able to share in the success of an RSG, but not its failures if your BA was
individually successful. Something seems wrong with that approach. However if necessary, AECI will definitely use it to its
advantage.
4) I really would have liked to see the Measures that are currently in draft.
Comment on Definitions:
1) SEFRD - I had to read this definition several times because “The individual sample of event data” is actually an internally
calculated value derived from a set of event sample data, and not really a “sample” value at all. So, I believe the SEFRD
definition needs further work.
2) FRM is defined by undefined terms “FRS” and “FRS Form 1”.
3) FRO – fine
4) FRS - “Frequency Response Survey”
Requirements and Requirements Supplement Information1) R1 and R1 Supplemental Information, pp 2, 4
a) I believe these two sections should be combined into one requirement, specifying the basic BA requirement “or, if
the BA was within an RSG and elects to report from within that RSG’s performance,” that RSG’s performance
requirement.
b) The time-frame for reporting should be another requirement, and with a companion Measurement. (Concerning the
timing, the original response timeframe is 31 days, but the if NERC slips past the “normal” December 10 deadline, the
177
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001821
Organization
Question 17 Comment
response time requirement is increased by 50%, to 45 days? Did somebody make a mistake, or was this intentional?)
c) The problem with this requirement is that it relies on each BA to “read” its own frequency-performance, and does
not provide a clear system of comparison between BAs for the same frequency event. In other words, the drafting
team is trying to impose a nice bright-line objective standard, that is really resting on what is currently a very subjective
calculation of SEFRD. . (See item 3, Rx- below)
2) R2 and R2 Supplemental Information pp 2..4
a) See comment 1.b above, concerning reporting time-frame being another requirement
b) I believe every BA should report its monthly average frequency-bias setting, whether fixed-bias or variable-bias. In
the case of reporting fixed-bias, the first two months will likely be different from the remaining ten months within the
same calendar year.
3) Rx - I believe there is a hidden requirement, that the ERO monitor each interconnection’s frequency for candidate events,
then annually select and provide the top events for FRS Form 1 reporting. That same requirement should dictate that the ERO
provide the corresponding A, B, and C times for each FRS Form 1 reportable event, when the survey goes out. I believe this
requirement should be spelled-out, in order to improve reporting consistency and make the FRS reporting process a bit more
objective.
Response: “Apparent Intent”
Comments 1) & 2) – The SDT thanks you for your comment.
Comment 3) The SDT added the RSG as a applicable entity to allow a BA an alternative method for complying with this standard. The SDT has included
language that defines how the RSG is to perform and comply with this standard.
Comment 4) The SDT purposely left the measures out of the first draft. This was to ensure the focus would be on the requirements themselves. The SDT also
recognized that the requirements would probably need revision after receiving industry feedback.
Definitions:
Comment 1) The SDT agrees with your concern regarding the definition of SEFRD. The SDT has removed the definition from the standard.
Comment 2) The term FRS Form 1 is only identifying a form to be used when providing information to the ERO.
Comment 3) The SDT thanks you for your agreement with the definition.
Comment 4) Again, the term FRS is simply pointing to a particular for to be used when providing the information to the ERO.
Requirements:
Comment 1 a) The SDT has revised Requirement R1 to reference an RSG. The Requirement now reads “Each Balancing Authority (BA) or Reserve Sharing Group
(RSG) shall achieve an annual Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative
than its Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each BA or RSG to maintain an adequate level of
178
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
001822
Organization
Question 17 Comment
Frequency Response in the Interconnection.”
Comment 1 b) The Additional Compliance Section has been completely revised and the issues you identified have been removed.
Comment 1 c) The revised standard changes the methodology from subjective to directed.
Comment 2 a) The Additional Compliance Section has been completely revised and the issues you identified have been removed. The SDT has corrected the
timing issue you have referenced.
Comment 2 b) The SDT disagrees and believes that “fixed” should be reported on a annual basis while “variable” should be reported monthly due to the nature of
the calculation.
Comment 3) The SDT believes that Point C is not needed for the methodology being recommended. The revised FRS Form 1 and the new Form 2 provide
clarification concerning Point A and Point B.
Alberta Electric System Operator
Is there any relation or coordination between the work of this standard and the effort on "NERC RS Position Paper on
Frequency Response" ? The AESO believes these two projects should be coordinated.The AESO has also signed on to
comments submitted by the SRC. We see the SRC comments as continent wide and these AESO comments as more
Alberta specific.
Response: The NERC RS Position Paper on Frequency Response is not a product of this standard. It is an information paper requested by the NERC OC. The
RS posted the document and received industry comments that were incorporated. In addition, some of the Frequency Response SDT membership are also
members of the NERC RS.
Please refer to our comments to SRC.
Kansas City Power & Light
No other comments.
179
Consideration of Comments: Project 2007-12 BAL-003-1 – 1st Draft
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001823
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed standard and its associated documents for a 45 day
formal comment period and a successive 10 day ballot, from October 24, 2011through December
7, 2011.
Future Development Plan:
Anticipated Actions
1. Respond to comments submitted within the comment period
and with the successive ballot.
Anticipated Date
December, 2011
2. Conduct a recirculation ballot for ten days.
January, 2012
3. BOT adoption.
March, 2012
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001824
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Definitions of Terms used in the Standard
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually on FRS Form
1.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s Frequency Response contribution to the Interconnection, and discourage
response withdrawal through secondary control systems.
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001825
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored. To provide
consistent methods for measuring Frequency Response and determining the Frequency
Bias Setting.
Applicability:
1.1. Balancing Authority
1.2. Reserve Sharing Group (where applicable)
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
R4 and R5 of this standard shall become effective the first calendar day of the
first calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, R3, R4
and R5 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an
annual Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each BA or RSG to maintain an adequate level of Frequency Response in the
Interconnection. [Risk Factor: Medium ][Time Horizon: Operations Assessment]
R2.
Each Balancing Authority not participating in Overlap Regulation Service shall
implement the Frequency Bias Setting (fixed or variable) validated by the ERO, into its
Area Control Error (ACE) calculation beginning on the date specified by the ERO to
ensure effectively coordinated Tie Line Bias control. [Risk Factor: Medium ][Time
Horizon: Operations Planning]
R3.
Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001826
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
coordinated control, unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area. [Risk Factor: Medium ][Time Horizon: Real-time
Operations]
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation to be equivalent to the sum of the
Frequency Bias Settings of the participating Balancing Authorities as validated by the
ERO or calculate the Frequency Bias Setting based on the entire area being combined
and thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium ][Time Horizon: Operations Planning]
R5.
In order to ensure adequate control response, each Balancing Authority shall use a
monthly average Frequency Bias Setting whose absolute value is at least equal to one
of the following: [Risk Factor: Medium ][Time Horizon: Operations Planning]
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
Peak Demand within its metered boundary per 0.1 Hz change as specified by
the ERO in accordance with Attachment B.
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation-only Balancing Authority, per 0.1 Hz change
as specified by the ERO in accordance with Attachment B.
C. Measures
M1. The Balancing Authority or Reserve Sharing Group shall have FRS Form 1 with data
to show that its FRM is equal to or more negative than FRO to demonstrate compliance
with Requirement R1.
M2. The Balancing Authority shall have evidence such as a dated document in hard copy or
electronic format showing the ERO validated Frequency Bias Setting was entered into
its ACE calculation on the date specified or other evidence to demonstrate compliance
with Requirement R2.
M3. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format or operator interviews supported by other
evidence showing the AGC operating mode including explanation when operating in
other than Tie Line Bias mode to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing when Overlap Regulation Service is
provided including Frequency Bias Setting calculation to demonstrate compliance with
Requirement R4.
M5. The Balancing Authority shall have evidence such as dated data plus documented
formula to support the calculation retained in either hardcopy or electronic format
showing the monthly average Frequency Bias Setting or other evidence to demonstrate
compliance with Requirement R5.
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001827
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
1.3. Data Retention
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3, R4 and R5, Measures M1, M2, M3, M4, and M5 for
the current year plus three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Reserve Sharing Group shall retain data or evidence to show compliance with
Requirement R1 and Measure M1 for the current year plus three calendar years
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If a Balancing Authority or Reserve Sharing Group is found non-compliant, it
shall keep information related to the non-compliance until found compliant or for
the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and Flat Frequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001828
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO and the
Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO and the
Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO
and the Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO
and the Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority not
receiving Overlap
Regulation Service
failed to implement
the validated
Frequency Bias
Setting value into its
ACE calculation on
the date specified
but did so within 5
calendar days
following the date
specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days following the
date specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days following the
date specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
did not implement
the validated
Frequency Bias
Setting value into its
ACE calculation in
more than 25
calendar days
following the date
specified by the
ERO.
R3
N/A
N/A
N/A
The Balancing
Authority not
receiving Overlap
Regulation service
failed to operate
AGC in Tie Line
Bias mode and such
operation would not
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001829
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R4
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
combined footprint
setting-error less
than 5% of the
correct value.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
combined footprint
setting-error more
than 5% but less
than or equal to 15%
of the correct value.
R5
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was less
than or equal to 5%
below the minimum
specified by the
ERO.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 5% but
less than or equal to
15% below the
minimum specified
by the ERO.
have had an Adverse
Reliability Impact
on the Balancing
Authority’s Area.
The Balancing
The Balancing
Authority
Authority
incorrectly changed incorrectly changed
the Frequency Bias
the Frequency Bias
Setting value used in Setting value used in
its ACE calculation
its ACE calculation
when providing
when providing
Overlap Regulation Overlap Regulation
Services with
Services with
combined footprint
combined footprint
setting-error more
setting-error more
than 15% but less
than 25% of the
than or equal to 25% correct value.
OR
of the correct value.
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
The absolute value
The absolute value
of the Balancing
of the Balancing
Authorities’
Authorities’
calculated monthly
calculated monthly
average Frequency
average Frequency
Bias Setting was
Bias Setting was
more than 15% but
more than 25%
less than or equal to below the minimum
25% below the
specified by the
minimum specified
ERO.
by the ERO.
E. Regional Variance
None
F. Associated Documents
Attachment A - Frequency Response Standard Supporting Document
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001830
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Attachment B – Process for Adjusting Bias Setting Floor
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
0
1
BAL-003-1 Dra ft 2
Oc to b e r 24, 2011
Date
April 1, 2005
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001831
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed standard and its associated documents for a 45 day
formal comment period and a successive 10 day ballot, from October 2124, 2011through
December 57, 2011.
Future Development Plan:
Anticipated Actions
1. Respond to comments submitted within the comment period
and with the successive ballot.
Anticipated Date
December, 2011
2. Conduct a recirculation ballot for ten days.
January, 2012
3. BOT adoption.
March, 2012
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 1 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001832
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Definitions of Terms used in the Standard
Single Event Frequency Response Data (SEFRD)
The individual sample of event data from a Balancing Authority which represents the
change in Net Actual Interchange (NIA), divided by the change in frequency, expressed in
MW/0.1Hz.
Frequency Response Measure (FRM)
The median of all the Frequency Response Single Event Frequency Response Data
observations reported annually on FRS Form 1.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response contribution to the
total aggregate Frequency Response needed for the reliable operation of an
Interconnection assigned by the ERO.
Frequency Bias Setting
A numbervalue, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1
Hz, included inset into a Balancing Authority’s Area Control Error equation to account
forthat allows the Balancing Authority’s Frequency Response contribution to contribute
its Frequency Response to the Interconnection, and discourage response withdrawal
through secondary control systems.
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 2 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001833
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored. To schedule and
provide consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.2. Reserve Sharing Group (where applicable)
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 and R5 of this standard shall become effective the first calendar day of the
first calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, and R3,
R4 and R5 of this standard shall become effective the first calendar day of the
first calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an
annual Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each BA or RSG to maintain an adequate level of Frequency Response in the
Interconnection. [Risk Factor: Medium ][Time Horizon: Operations Assessment]
Each Balancing Authority not participating in Overlap Regulation
Service shall implement the Frequency Bias Setting (fixed or variable)
validatedprovided by the ERO, into its Area Control Error (ACE) calculation
beginning on the date specified by the ERO to ensure effectively coordinated Tie Line
Biassecondary control, using the results from the calculation methodology detailed in
Attachment A. [Risk Factor: Medium ][Time Horizon: Operations Planning]
R1.R2.
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 3 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001834
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Each Balancing Authority not receiving Overlap Regulation Service
shall operate its Automatic Generation Control (AGC) inon Tie Line Bias mode to
ensure effectively coordinated control, unless such operation would have an Adverse
Reliability Impact on the Balancing Authority’s Area. [Risk Factor: Medium ][Time
Horizon: Real-time Operations]
R2.R3.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall
modifyincrease its Frequency Bias Setting in its ACE calculation to be equivalent to
the sum of by combining the Frequency Bias Settings of the participating Balancing
Authorities as validated by the ERO or calculate the Frequency Bias Setting based on
the entire area being combined and thereby represent the Frequency Response for the
combinedentire area being controlled. [Risk Factor: Medium ][Time Horizon:
Operations Planning]
R5.
In order to ensure adequate control response, each Balancing Authority shall use a
monthly average Frequency Bias Setting whose absolute value is at least equal to one
of the following: [Risk Factor: Medium ][Time Horizon: Operations Planning]
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
Peak Demand within its metered boundary per 0.1 Hz change as specified by
the ERO in accordance with Attachment B.
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation-only Balancing Authority, per 0.1 Hz change
as specified by the ERO in accordance with Attachment B.
C. Measures
Measures for each Requirement will be provided in the second posting of the proposed
standard.
M1. The Balancing Authority or Reserve Sharing Group shall have FRS Form 1 with data
to show that its FRM is equal to or more negative than FRO to demonstrate compliance
with Requirement R1.
M2. The Balancing Authority shall have evidence such as a dated document in hard copy or
electronic format showing the ERO validated Frequency Bias Setting was entered into
its ACE calculation on the date specified or other evidence to demonstrate compliance
with Requirement R2.
M3. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format or operator interviews supported by other
evidence showing the AGC operating mode including explanation when operating in
other than Tie Line Bias mode to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing when Overlap Regulation Service is
provided including Frequency Bias Setting calculation to demonstrate compliance with
Requirement R4.
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 4 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001835
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
The Balancing Authority shall have evidence such as dated data plus documented
formula to support the calculation retained in either hardcopy or electronic format
showing the monthly average Frequency Bias Setting or other evidence to demonstrate
compliance with Requirement R5.
M1.M5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.Regional Entity
shall serve as the Compliance Enforcement Authority.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
1.3. Data Retention
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3, R4 and R5, Measures M1, M2, M3, M4, and M5 for
the current year plus three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Reserve Sharing Group shall retain data or evidence to show compliance with
Requirement R1 and Measure M1 for the current year plus three calendar years
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If a Balancing Authority or Reserve Sharing Group is found non-compliant, it
shall keep information related to the non-compliance until found compliant or for
the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 5 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001836
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
1.4. Additional Compliance Information
R1 Supplemental Information
Each Balancing Authority shall report its previous year’s Frequency Response
Measure (FRM) to the ERO on Form 1 by January 10 each year. If the ERO posts
the official list of events after December 10, Balancing Authorities will be given
45 days from the date the ERO posts the official list of events to submit their FRS
Form 1.
A Balancing Authority may elect to fulfill its Frequency Response Obligation by
participating as a member of a Reserve Sharing Group (RSG). If a Balancing
Authority elects to report as an RSG, the total of the participating Balancing
Authorities’ FRO will be compared to the total of the participating Balancing
Authorities’ FRM.
R2 Supplemental Information.
Each Balancing Authority shall report its current year requested Frequency Bias
Setting and Frequency Bias type (fixed or variable) to the ERO on FRS-Form 1
by January 10 each year. If the ERO posts the official list of events after
December 10, Balancing Authorities will be given 45 days from the date NERC
posts the official list of events to submit their FRS Form 1. Once the FRM and
Frequency Bias Settings have been validated by the ERO, the ERO will
disseminate the Frequency Bias Settings Report for all Balancing Authorities in
each Interconnection along with the implementation date.
Balancing Authorities with variable Frequency Bias Settings shall calculate
monthly average Frequency Bias Settings. The previous year’s monthly averages
will be reported annually on FRS Form 1. For Interconnections that are also
Balancing Authorities, Tie Line Bias control and Flat Frequency control are
equivalent and either is acceptable.
2.0 Violation Severity Levels
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO and the
Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO and the
Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO
and the Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
1% but by at most
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO
and the Balancing
Authority’s, or
Reserve Sharing
Groups, FRM was
less negative than its
FRO by more than
30% or by more
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 6 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001837
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
less negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
less negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority not
receiving Overlap
Regulation Service
failed to implement
the validated
Frequency Bias
Setting value into its
ACE calculation on
the date specified
but did so within 5
calendar days
following the date
specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days following the
date specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days following the
date specified by the
ERO.
The Balancing
Authority not
receiving Overlap
Regulation Service
did not implement
the validated
Frequency Bias
Setting value into its
ACE calculation in
more than 25
calendar days
following the date
specified by the
ERO.
R3
N/A
N/A
N/A
R4
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
combined footprint
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
combined footprint
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
The Balancing
Authority not
receiving Overlap
Regulation service
failed to operate
AGC in Tie Line
Bias mode and such
operation would not
have had an Adverse
Reliability Impact
on the Balancing
Authority’s Area.
The Balancing
The Balancing
Authority
Authority
incorrectly changed incorrectly changed
the Frequency Bias
the Frequency Bias
Setting value used in Setting value used in
its ACE calculation
its ACE calculation
when providing
when providing
Overlap Regulation Overlap Regulation
Services with
Services with
combined footprint
combined footprint
Page 7 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001838
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R5
setting-error less
than 5% of the
correct value.
setting-error more
than 5% but less
than or equal to 15%
of the correct value.
setting-error more
than 15% but less
than or equal to 25%
of the correct value.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was less
than or equal to 5%
below the minimum
specified by the
ERO.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 5% but
less than or equal to
15% below the
minimum specified
by the ERO.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 15% but
less than or equal to
25% below the
minimum specified
by the ERO.
setting-error more
than 25% of the
correct value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 25%
below the minimum
specified by the
ERO.
E. Regional Variance
None
F. Associated Documents
Attachment A - Frequency Response Standard Supporting DocumentBackground Document
Attachment B – Process for Adjusting Bias Setting Floor
FRS Form 1
FRS Form 21 Instructions
Frequency Response Standard Background Document
G. Version History
Version
0
Date
April 1, 2005
1
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 8 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001839
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
BAL-003-1 Dra ft 2
J u ly 12Oc to b e r 24, 2011
Page 9 of 9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
001840
Attachment A
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Supporting Document
Background
This document outlines the ERO process for supporting the Frequency Response Standard (FRS).
Event Selection Criteria
The ERO will use the following criteria to select FRS frequency excursion events for analysis.
1. The evaluation period for performing the annual Frequency Bias Setting and the Frequency
Response Measure (FRM) calculation is December 1 of the prior year through November 30 of
the current year.
2. The ERO will identify at least 25 frequency excursion events in each Interconnection for
calculating the Frequency Bias Setting and the FRM. If the ERO cannot identify in a given
evaluation period 25 frequency excursion events satisfying the limits specified in criteria 3
below, then similar acceptable events from the previous evaluation period also satisfying listed
criteria will be included with the data set by the ERO for determining FRS compliance.
3. The ERO will use two limits to determine if an acceptable frequency excursion event for
determining FRM has occurred:
a. The change in frequency (delta F) and the arresting frequency (Point C) must exceed the
excursion threshold values specified for the Interconnection in Table 1 below. Point C is
the arrested value of frequency observed within 8 seconds following the start of the
excursion.
Point C
Interconnection
East
West
Texas
HQ
Delta F
0.04Hz
0.05Hz
0.15Hz
0.20Hz
Under Frequency
< 59.97
< 59.97
< 59.90
< 59.85
Over Frequency
> 60.03
> 60.03
> 60.10
> 60.15
Table 1: Interconnection Frequency Excursion Threshold Values
b. The time from the start of the rapid change in frequency until the point at which
Frequency has stabilized within a narrow range should be less than 18 seconds.
July 18, 2011
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
001841
4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz. The A Value is
computed as an average over the period from -16 seconds to 0 seconds before the frequency
transient begins to decline.
5. Events that coincide with a second event that does not stabilize before the first scan used in the
B-Value will not be considered.
6. Frequency excursion events occurring during periods when large interchange schedule ramping
or load change is happening, and frequency excursion events occurring within 5 minutes of the
top of the hour, should be excluded from consideration if other acceptable frequency excursion
events can be used for analysis.
7. Select the cleanest 2 or 3 frequency excursion events occurring monthly that satisfy selection
criteria. If there are not 2 frequency excursion events satisfying selection criteria occurring
during the month, then other frequency excursion events from the same season of the year
satisfying selection criteria should be considered for use if necessary.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation. The
ERO will post the final list of frequency excursion events used for standard compliance by December 15
each year. Balancing Authorities are encouraged to develop scanning tools that identify candidate
frequency excursion events so they are ready to access data files when needed.
NOTE:
The ERO may use for analysis of Interconnection frequency performance, but not for
Balancing Authority Frequency Response, additional frequency excursion events not
satisfying the criteria specified.
Frequency Response Obligation (FRO) for the Interconnection
Each Interconnection will establish target contingency protection criteria. The default target listed in
Table 2 is based on the largest category C (N-2) event identified. However, this contingency protection
criterion includes a safety margin to prevent Point C from encroaching on the interconnection’s highest
Under Frequency Load Shed (UFLS) step for credible contingencies.
Eastern
Western
Texas
HQ
Starting Frequency
60
60
60
60
*Highest UFLS
59.6
59.5
59.3
58.5
Contingency Protection Criteria
4500
2740
2750
1700
**Base Obligation
1125
548
229
113
With 25% Safety Margin
1406
685
286
141
Table 2: Interconnection Frequency Response Obligations
Hz
Hz
MW
MW/0.1Hz
MW/0.1Hz
*The Eastern Interconnection set point listed is a compromise value for the highest UFLS step
setting of 59.5Hz used in the east and the special protection scheme’s highest UFLS step setting
of 59.7Hz used in Florida. It is extremely unlikely that an event elsewhere in the Eastern
Interconnection would cause the Florida UFLS special protection scheme to “false trip”.
July 18, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
001842
**In the Base Obligation measure for Texas, 1150 MW (Load Resources triggered by Under Frequency
Relays at 59.70 Hz) was reduced from its Contingency Protection Criteria level of 2750 MW to get 229
MW/0.1 Hz. This was reduced to accurately account for designed response from Load Resources within 30
cycles.
An Interconnection may propose alternate FRO protection criteria to the ERO. The ERO will confirm the
proposed alternate FRO protection criteria.
Balancing Authority Frequency Response Obligation (FRO) and
Frequency Bias Setting
The ERO will manage the administrative procedure for annually assigning an FRO and Frequency Bias
Setting to each Balancing Authority.
For a multiple Balancing Authority interconnection, the Interconnection Frequency Response Obligation
is allocated based on either the Balancing Authority Peak Demand or peak generation. Initial FRO
allocation will be based on the following method:
Projected BA Peak Load + BA installed capacity
Projected Interconnection Peak Load + Interconnection installed capacity
x Interconnection FRO
Each Balancing Authority shall report its previous year’s Frequency Response Measure (FRM), Frequency
Bias Setting and Frequency Bias type (fixed or variable) to the ERO on FRS Form 1 by January 10 each
year. If the ERO posts the official list of events after December 10, Balancing Authorities will be given 30
days from the date the ERO posts the official list of events to submit their FRS Form 1.
Once the ERO validates the data for all Balancing Authorities, the ERO will use FRS Form 1 data to post
the following information for each Balancing Authority for the upcoming year:
•
•
Frequency Bias Setting
Frequency Response Obligation (FRO)
Frequency Bias Setting will be the greater of (in absolute terms) the FRM or the Interconnection
minimum (as defined in Attachment B). FRS Form 1 will automatically calculate the Balancing
Authority’s Bias Settings. Balancing Authorities that provide Overlap Regulation will submit a FRS Form
1 that represents both the provider’s and the recipient(s)’ footprint. Once the data listed above is fully
posted, the ERO will announce the implementation date for changing the Frequency Bias Setting.
July 18, 2011
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
001843
Frequency Response Measure (FRM)
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as: “the data
from an individual event from a Balancing Authority that is used to calculate its Frequency Response,
expressed in MW/0.1Hz” as calculated on FRS Form 2. The SEFRD for a typical Balancing Authority in an
Interconnection with more than one Balancing Authority is basically the change in its Net Actual
Interchange on its tie lines with its adjacent Balancing Authorities divided by the change in
Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to their Net
Actual Interchange values to account for factors such as nonconforming loads. FRS Form 1 shows the
types of adjustments that are allowed.) The ERO will use a standardized sampling interval of 20 to 52
seconds in the computation of SEFRD values.
Assuming data entry is correct FRS Form 1 will automatically calculate the Balancing Authority’s FRM for
the past 12 months as the median of the SEFRD values. A Balancing Authority electing to report as an
RSG or a provider of Overlap Regulation Service will provide an FRS Form 1 for the aggregate of its
participants.
July 18, 2011
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Attachment B
001844
Process for Adjusting Minimum Frequency Bias Setting
Interconnection frequency performance is improved the closer all Balancing Authorities’ (BAs’) natural
Frequency Response is to Frequency Bias Setting (Cohn, 1966).
The BA calculates its natural Frequency Response based on the events in FRS Form 1. The BA will set its
Frequency Bias Setting to the greater of (in absolute value):
•
•
Natural Frequency Response
Interconnection Minimum (initially 1% of peak in BAL-003-0.1b).
For purposes of calculating the minimum Frequency Bias Setting, a Reserve Sharing Group or a Balancing
Authority providing Overlap Regulation will report the projected peak demand and generation of its
combined BAs’ areas on FRS Form 1.
This attachment outlines the process the ERO is to use for modifying minimum Frequency Bias Settings
to better meet reliability needs. The ERO may adjust the Frequency Bias Setting minimum in accordance
with this Attachment B.
The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other
balancing standard limits.
The initial minimum Frequency Bias Settings are outlined in the following table.
Interconnection
Eastern
Western
Texas
HQ
Minimum Frequency Bias Setting (in MW/0.1Hz)
0.8% of peak load or generation
0.8% of peak load or generation
0.8% of peak load or generation
0.8% of peak load or generation
Table 1. Initial Frequency Bias Setting Minimums
The ERO will annually review Frequency Bias Setting data submitted by BAs. If an Interconnection’s total
minimum Frequency Bias Setting exceeds (in absolute value) the Interconnection’s total natural
Frequency Response by more (in absolute value) than 0.2 percentage points (of peak load expressed in
MW/0.1Hz), the ERO may reduce (in absolute value) the minimum Frequency Bias Setting for BAs within
that Interconnection, by 0.1 percentage point to better match that Frequency Bias Setting and natural
Frequency Response.
July 18, 2011
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001845
Implementation Plan for BAL-003-1 – Frequency
Response & Frequency Bias Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b should be retired at midnight of the day immediately prior to the Effective Date of BAL003-1 in the Jurisdiction in which the new standard is becoming effective.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4 and R5
become effective:
Frequency Response Measure (FRM): The median of all the Frequency Response observations
reported annually on FRS Form 1.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.
Frequency Bias Setting: A numbervalue, either fixed or variable, usually expressed in MW/0.1
Hz, included inset into a Balancing Authority’s Area Control Error equation to account for
algorithm that allows the Balancing Authority’s Frequency Response contributionto contribute
its frequency response to the Interconnection and discourage withdrawal through secondary
control systems.
The existing definition of Frequency Bias Setting should be retired at midnight of the day immediately
prior to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming
effective.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following NERC
approved standards:
•
•
•
•
BAL-001-0.1a Real Power Balancing Control Performance
BAL-004-0 Time Error Correction
BAL-004-1 Time Error Correction
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001846
Once this standard becomes effective, the responsible entities identified in the applicability section of
the standard must comply with the requirements. These include:
• Balancing Authorities
• Reserve Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R2, R3, R4 and
R5 of this standard shall become effective the first calendar day of the first calendar quarter
12 months after applicable regulatory approval. In those jurisdictions where no regulatory
approval is required, Requirements R2, R3, R4 and R5 of this standard shall become
effective the first calendar day of the first calendar quarter 12 months after Board of
Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter 24
months after applicable regulatory approval. In those jurisdictions where no regulatory
approval is required, Requirements R1 of this standard shall become effective the first
calendar day of the first calendar quarter 24 months after Board of Trustees adoption.
BAL-003-1 – Frequency Response and Frequency Bias | Implementation Plan | October 24, 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001847
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b Requirements R1, R2, R3, R4 and R6 should be retired midnight of the day immediately
prior to the Effective Date ofwhen BAL-003-1 in the Jurisdiction in which the new standard is becoming
becomes effective.
BAL-003-0 Re1quirement R5 should be retired as outlined in the following table.
For those Balancing Authorities that serve native load:
•
•
•
•
•
May 2011 through December 2011
January 2012 through December 2012
January 2013 through December 2013
January 2014 through December 2014
January 2015 through
-0.8% of peak/0.1 Hz
-0.6% of peak/0.1 Hz
-0.4% of peak/0.1 Hz
-0.2% of peak/0.1 Hz
-0.0% of peak/0.1 Hz
For those Balancing Authorities that do not serve native load:
•
•
•
•
•
May 2011 through December 2011
generation/0.1 Hz
January 2012 through December 2012
generation/0.1 Hz
January 2013 through December 2013
generation/0.1 Hz
January 2014 through December 2014
generation/0.1 Hz
January 2015 through
generation/0.1 Hz
-0.8% of upcoming years maximum
-0.6% of upcoming years maximum
-0.4% of upcoming years maximum
-0.2% of upcoming years maximum
-0.0% of upcoming years maximum
The FRR drafting team, NERC and the NERC Resources Subcommittee will observe the impact
on frequency and will implement a reversion plan should frequency performance decline.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4
and R5 become effective:
July 12, 2011
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001848
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually on FRS Form 1.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
Frequency Bias Setting: A number, either a fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s Frequency Response contribution to the Interconnection,
and discourage response withdrawal through secondary control systems.
The existing definition of Frequency Bias Setting should be retired midnight of the day immediately prior
to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming effective.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved standards:
•
BAL-001-0.1a Real Power Balancing Control Performance
•
BAL-004-0 Time Error Correction
•
BAL-004-1 Time Error Correction
•
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
•
Reserve Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R21, R3, R4 and R54 of
this standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R21, R3, R4 and R54 of this standard shall become effective the first calendar day of
the first calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R12 of this
standard shall become effective the first calendar day of the first calendar quarter 24 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, Requirements R12 of this standard shall become effective the first calendar day of
the first calendar quarter 24 months after Board of Trustees adoption.
July 12, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001849
Fr e q u e n cy Re s p o n s e
St a n d a r d Ba ck g ro u n d
Do cu m e n t
October 2011
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001850
Ta b le o f Co n t e n t s
Contents
Table of Contents ............................................................................................................................ 1
Introduction .................................................................................................................................... 3
Background and Rationale by Requirement ................................................................................... 3
Requirement 1 ........................................................................................................................ 3
Background and Rationale ...................................................................................................... 3
Requirement 2 ........................................................................................................................ 6
Background and Rationale ...................................................................................................... 7
Requirement 3 ........................................................................................................................ 7
Background and Rationale ...................................................................................................... 7
Requirement 4 ........................................................................................................................ 8
Background and Rationale ...................................................................................................... 8
Requirement 5 ........................................................................................................................ 8
Background and Rationale ...................................................................................................... 9
How this Standard Meets the FERC Order 693 Directives............................................................ 10
FERC Directive ........................................................................................................................... 10
Levels of Non-Compliance ........................................................................................................ 10
Determine the appropriate periodicity of frequency response surveys necessary to ensure
that Requirement R2 and other Requirements of the Reliability Standard are met ............... 10
Define the necessary amount of Frequency Response needed for Reliable Operation for each
Balancing Authority with methods of obtaining and measuring that the frequency response is
achieved .................................................................................................................................... 10
Necessary Amount of Frequency Response ......................................................................... 10
Methods of Obtaining Frequency Response ........................................................................ 11
1
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001851
Measuring that the Frequency Response is Achieved .......................................................... 11
Going Beyond the Directive ...................................................................................................... 12
Good Practices and Tools.............................................................................................................. 13
Good Practices .......................................................................................................................... 13
Tools .......................................................................................................................................... 14
Field Trial ....................................................................................................................................... 15
2
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001852
I n t ro d u ct io n
This document provides background on the development, testing and implementation of BAL003-1 - Frequency Response Standard (FRS). The intent is to explain the rationale and
considerations for the Requirements and their associated compliance information. The
document also provides good practices and tips for Balancing Authorities with regard to
Frequency Response.
In Order No. 693, the FERC directed additional changes to BAL-003-0.1b. This document
explains how those directives are met by BAL-003-1.
The original Standards Authorization Request (SAR), finalized on June 30, 2007, assumed,
assumed the Frequency Response currently available to be adequate in all the North American
Interconnections. The goal of the SAR was to update the Standard to make the measurement
process more objective and to provide this objective data to Planners and Operators for
improved modeling. The improved models will improve understanding of the trends in
Frequency Response to determine if reliability limits were being approached. The Standard
would also lay the process groundwork for a transition to a performance-based Standard if
reliability limits were approached.
This document will be periodically updated by the FRS Drafting Team until the Standard is
approved (expected to occur during Springspring of 2012). Once approved, this document will
then be maintained and updated by the ERO and the NERC Resources Subcommittee.
Ba ckg r o u n d a n d Ra t io n a le b y Re q u ire m e n t
Re q u ire m e n t 1
R1. Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an annual
Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on FRS Form 1)
that is equal to or more negative than its Frequency Response Obligation (FRO) to ensure that
sufficient Frequency Response is provided by each BA or RSG to maintain an adequate level of
Frequency Response in the Interconnection.
Ba ckg ro u n d a n d Ra t io n a le
R1 is intended to meet the following primary objectives:
•
Determine whether a Balancing Authority (BA) has sufficient Frequency
Response for reliable operations.
•
Provide the feeder information needed to calculate CPS limits and Frequency
Bias Settings.
With regard to the first objective, FRS Form 1 and the process in Attachment A provide the
method for determining the Interconnections’ necessary amount of Frequency Response and
allocating it to the Balancing Authorities. The field trial for BAL-003-1 is testing an allocation
methodology based on the amount of load and generation in the BA. This is to accommodate
the wide spectrum of BAs from generation-only all the way to load-only.
3
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001853
The basic Frequency Response Obligation is based on non-coincident peak load and generation
data reported in FERC Form 714 for the previous full calendar year. The basic allocation
formula used by NERC is:
Where:
•
Peak GenBA is the average of monthly “Output of Generating Plants”, FERC Form
714, column f of Part II - Schedule 3.
•
Peak LoadBA is the average of “Monthly Peak Demand (MW)”, FERC Form 714,
column j of Part II - Schedule 3.
•
Peak GenInt is the sum of all BAs’ in that interconnection reported average
monthly peak generation.
•
Peak LoadInt is the sum of all BAs in that interconnection reported average
monthly peak demand.
Balancing Authorities can approximate their FRO by multiplying their Interconnection’s FRO by
their share of Interconnection bias.
Balancing Authorities that merge or that transfer load or generation need to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation for
the Interconnection remains the same.
Note: The methodology for determining the Interconnection’s Frequency Response Obligation
and allocating it to BAs may change on the basis of field trial results. The drafting team is
evaluating a risk-based approach for basing the Interconnection Frequency Response Obligation
on an historic probability density of frequency error, and for allocating the obligation on the
basis of the Balancing Authority’s average annual ACE share of frequency error.
Attachment A proposes the following Interconnection event criteria as a basis to determine an
Interconnection’s Frequency Response Obligation:
•
•
•
Largest category C loss-of-resource (N-2) event
Largest total generating plant with common voltage switchyard
Largest loss of generation in the interconnection in the last 10 years
Given the fact that the Interconnections currently have sufficient Frequency Response, few BAs
should encounter problems meeting R1, particularly with the options the Standard provides
with regard to obtaining Frequency Response.
With regard to the second objective above (determining Frequency Bias Settings and CPS
limits), Balancing Authorities have been asked to perform annual reviews of their Frequency
Bias Settings by measuring their Frequency Response, dating back to Policy 1. This obligation
4
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001854
was carried forward into BAL-003-01.b. While the associated training document provided
useful information, it left many of the details to the judgment of the person doing the analysis.
The FRS Form 1 and FRS Form 2 provide a consistent, objective process for calculating
Frequency Response to develop an annual measure, the FRM.
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as:
“the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz”. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change its Net
Actual Interchange on its tie lines with its adjacent Balancing Authorities divided by the change
in Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to
their Net Actual Interchange values to account for factors such as nonconforming loads. FRS
Form 1 shows the types of adjustments that are allowed.)
A standardized sampling interval of 20 to 52 seconds will be used in the computation of SEFRD
values. Microsoft Excel® spreadsheet interfaces for EMS scan rates of 2 through 6 seconds will
be provided to support the computation. During the field trial, other sampling intervals will be
evaluated as well to determine if another sampling interval is more appropriate.
In an attempt to balance the workload of Balancing Authorities with the need for accuracy in
the FRM, the field trial will require at least 25 samples selected during the course of the year to
compute the FRM. Research conducted by the Frequency Responsive Reserve Standard
Drafting Team (FRSDT) indicated that a Balancing Authority’s FRM will converge to a reasonably
stable value with 20 to 25 samples. The FRSDT will re-evaluate the required number of samples
during the field trial.
The FRSDT also evaluated different approaches for “averaging” individual event observations to
compute a technically sound estimate of Frequency Response Measure (FRM). The MW
contribution for a single BA in a multi-BA Interconnection is small compared to the minute to
minute changes in load, interchange and generation. For example, a 3000 MW BA in the east
may only be called on to contribute 10MW for the loss of a 1000MW. The 10 MW of governor
and load response may easily be masked ay a coincident change in load. Because of this large
“noise to signal” ratio, the mean did not prove to be an appropriate measure of true typical
performance.
In general, statisticians use the median as the best measure of central tendency when a
population has outliers. Two independent reviews by the FRSDT has shown the Median to be
less influenced by noise in the measurement process and the team has chosen the median as
the initial metric for calculating the BAs’ Frequency Response Measure.
In addition, The FRSDT is evaluating the linear regression as a means to estimate the BA’s
typical frequency response. This calculation is embedded in FRS Form 1 and will be evaluated
during the field trial. Initial review implies that the linear regression tends to skew calculated
FRM due to the influence of outliers. The outliers are being evaluated by the FRSDT as they
may point to needed improvements in the measurement process or training issues for the BA in
question.
5
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001855
In order to support field trial evaluations of sample size, sampling intervals, and aggregation
techniques, the FRSDT will be retrieving scan rate data from the Balancing Authorities for each
SEFRD. Additional frequency events may also be requested for research purposes, though they
will not be included in the FRM computation.
FERC Order No. 693 directed the ERO to define the number of Frequency Response surveys that
were conducted each year and to define a necessary amount of Frequency Response. R1
addresses both of these directives:
•
•
There is a single annual survey of at least 25-30 events each year.
The FRM calculated on FRS Form 1 is compared by the ERO against the FRO
determined 12 months earlier (when the last FRS Form 1 was submitted) to
verify the Balancing Authority provided its share of Interconnection Frequency
Response.
FERC Order No. 693 also directed that the Standard should identify methods for Balancing
Authorities to obtain Frequency Response. Requirement R1 allows Balancing Authorities to
participate in Reserve Sharing Groups (RSGs) to provide or obtain Frequency Response. These
may be the same RSGs that cooperate for BAL-002-0 or may be RSGs that form for the purposes
of BAL-003-1.
If BAs participate as an RSG for BAL-003-1, compliance is based on the sum of the participants’
performance.
Two other ways that BAs could obtain Frequency Response are through Supplemental Service
or Overlap Regulation Service:
No special action is needed if a BA provides or receives supplemental regulation.
If the regulation occurs via Pseudo Tie, the transfer occurs automatically as part
of Net Actual Interchange (NIA) and in response to information transferred from
recipient to provider.
•
If a BA provides overlap regulation, its FRS Form 1 will include the Frequency Bias
setting as well as peak load and generation of the combined Balancing Authority Areas.
The FRM event data will be calculated on the sum of the provider’s and recipient’s
performance.
•
In the Violation Severity Levels for Requirement R1, the impact of a BA not having enough
frequency response depends on two factors:
•
Does the Interconnection have sufficient response?
•
How short is the BA in providing its FRO?
The VSL takes these factors into account.
Re q u ire m e n t 2
R2. Each Balancing Authority not participating in Overlap Regulation Service shall implement
the Frequency Bias Setting (fixed or variable) validated by the ERO, into its Area Control Error
6
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001856
(ACE) calculation beginning on the date specified by the ERO to ensure effectively coordinated
Tie Line Bias control.
Ba ckg ro u n d a n d Ra t io n a le
Attachment A of the Standard discusses the process the ERO will follow to validate the BA’s FRS
Form 1 data and publish the official Frequency Bias Settings. Historically, it has taken multiple
rounds of validation and outreach to confirm each BA’s data due to transcription errors,
misunderstanding of instructions, and other issues. While BAs historically submit Bias Setting
data by January 1, it often takes one or more months to complete the process.
The target is to have BAs submit their data by January 10. The BAs are given 30 days to
assemble their data since the BAs are dependent on the ERO to provide them withthem with
FRS Form 1, and there may be process delays in distributing the forms since they rely on
identification of frequency events through November 30 of the preceding year.
Frequency Bias Settings generally change little from year to year. Given the fact that BAs can
encounter staffing or EMS change issues coincident with the date the ERO sets for new
Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date.
To recap the annual process:
1. The ERO posts the official list of frequency events to be used for this Standard in early
December. The FRS Form 1for each Interconnection will be posted shortly thereafter.
2. The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3. The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, The ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which
to implement revised Frequency Bias Setting values. Implementation typically would be
on or about March 1st of each year.
Re q u ire m e n t 3
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated
control, unless such operation would have an Adverse Reliability Impact on the Balancing
Authority’s Area.
Ba ckg ro u n d a n d Ra t io n a le
This requirement serves several functions. The primary reason for operating in Tie Line Bias is
so ACE is calculated properly for performance purposes. Even if a BA temporarily operated in
manual mode, as long as CPS is properly calculated and the BA met CPS, it is operating reliably.
7
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001857
There are legitimate reasons for taking AGC out of Tie Line Bias or operating manually including:
•
•
•
•
•
•
Telemetry problems that lead the operator to believe ACE is significantly in error.
The frequency input to AGC is not reflective of the BA’s true frequency (such as if the
control center were operating a local generator and disconnected from the
Interconnection).
During restoration (where one BA might be controlling frequency while another to
which it is connected is managing interchange between them).
For training purposes.
Many AGC systems will automatically switch to an alternate mode if the EMS
determines Tie Line Bias control could lead to problems.
For single BA Interconnections, Flat Frequency and Tie Line Bias are equivalent.
Because it is rare that temporary operation out of Tie Line Bias can lead to reliability problems,
the VSLs for this requirement are structured accordingly.
Re q u ire m e n t 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation to be equivalent to the sum of the Frequency Bias
Settings of the participating Balancing Authorities as validated by the ERO or calculate the
Frequency Bias Setting based on the entire area being combined and thereby represent the
Frequency Response for the combined area being controlled.
Ba ckg ro u n d a n d Ra t io n a le
This requirement reflects the operating principles first established by NERC Policy 1 and is
similar to Requirement R6 of the approved BAL-003-0.1b standard. Overlap Regulation Service
is a method of providing regulation service in which the Balancing Authority providing the
regulation service incorporates another Balancing Authority’s actual interchange, frequency
response, and schedules into the providing Balancing Authority’s AGC/ACE equation.
As noted earlier, a BA that is providing Overlap Regulation will report the sum of the Bias
Settings in its FRS Form 1. Balancing Authorities receiving Overlap Regulation Service have an
ACE and Frequency Bias Setting equal to zero (0).
Re q u ire m e n t 5
R5. In order to ensure adequate control response each Balancing Authority shall use a monthly
average Frequency Bias Setting whose absolute value is at least equal to one of the following:
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
Peak Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
8
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001858
•
The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation- only BA, per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
Ba ckg ro u n d a n d Ra t io n a le
BAL-003-0.1b standard requires a minimum Frequency Bias Setting equal in absolute value to
one percent of the Balancing Authority’s estimated yearly peak demand (or maximum
generation level if native load is not served). For most Balancing Authorities this calculated
amount of Frequency Bias is significantly greater in absolute value than their actual Frequency
Response characteristic (which represents an over-bias condition) resulting in over-control
since a larger magnitude response is realized. This is especially true in the Eastern
Interconnection where this condition requires excessive secondary frequency control response
which degrades overall system performance and increases operating cost as compared to
requiring an appropriate balance of primary and secondary frequency control response.
Balancing Authorities were given a minimum Frequency Bias Setting obligation because there
had never been a mandatory Frequency Response Obligation. This historic “one percent of
peak per 0.1Hz” obligation, dating back to NERC’s predecessor, NAPSIC, was intended to ensure
all BAs provide some support to Interconnection frequency.
The ideal system control state exists when the Frequency Bias Setting of the Balancing
Authority exactly matches the actual Frequency Response characteristic of the Balancing
Authority. If this is not achievable, over-bias is significantly better from a control perspective
than under-bias with the caveat that Frequency Bias is set relatively close in magnitude to the
Balancing Authority actual Frequency Response characteristic. Setting the Frequency Bias to
better approximate the Balancing Authority natural Frequency Response characteristic will
improve the quality and accuracy of ACE control, CPS & DCS and general AGC System control
response. This is the technical basis for recommending an adjustment to the long standing “1%
of peak/0.1Hz” Frequency Bias Setting. Attachment B is intended to bring the Balancing
Authorities’ Frequency Bias Setting closer to their natural Frequency Response. Attachment B
balances the following objectives:
•
•
•
Bring the Frequency Bias Setting and Frequency Response closer together.
Ensure there is no negative impact on other Standards (CPS, BAAL and to a lesser
extent DCS) by adjustments in the minimum Frequency Bias Setting, by
accommodating only minor adjustments.
Do not allow the Frequency Bias Setting minimum to drop below natural Frequency
Response, because under-biasing could affect an Interconnection adversely.
Finally, for BAs using variable bias, FRS Form 1 has a data entry location for the previous year’s
average monthly bias. The Balancing Authority and the ERO can compare this value to the
previous year’s Frequency Bias Setting minimum to ensure R5 has been met.
9
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001859
Ho w t h is St a n d a r d Me e t s t h e FERC Ord e r 6 9 3
Dire ct ive s
FERC Dir e ct ive
The following is the relevant paragraph of Order No. 693.
Accordingly, the Commission approves Reliability Standard BAL-003-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a modification to
BAL-003-0 through the Reliability Standards development process that: (1) includes
Levels of Non-Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other requirements of
the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) defines the necessary amount of Frequency Response needed for
Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.
1 . Le ve ls o f No n -Co m p lia n ce
VRFs and VSLs are an equally effective way of assigning compliance elements to the standard.
2 . De t e rm in e t h e a p p r o p ria t e p e rio d icit y o f fr e q u e n cy re s p o n s e s u rve ys
n e ce s s a ry t o e n s u re t h a t Re q u ire m e n t R2 a n d o t h e r Re q u ire m e n t s o f
t h e Re lia b ilit y St a n d a rd a re m e t
BAL-003 V0 R2 (the basis of Order No. 693) deals with the calculation of Frequency Bias Setting
such that it reflects natural Frequency Response.
The drafting team has determined that a sample size on the order of at least 25-30 events is
necessary to have a high confidence in the estimate of a BA’s Frequency Response. Selection of
the frequency excursion events used for analysis will be done via a method outlined in
Attachment A to the Standard.
On average, these events will represent the largest 2-3 “clean” frequency excursions occurring
each month.
Since Frequency Bias Setting is an annual obligation, the survey of the at least 25-30 frequency
excursion events will occur once each year.
3 . De fin e t h e n e ce s s a r y a m o u n t o f Fre q u e n cy Re s p o n s e n e e d e d fo r
Re lia b le Op e ra t io n fo r e a ch Ba la n cin g Au t h o rit y w it h m e t h o d s o f
o b t a in in g a n d m e a s u rin g t h a t t h e fr e q u e n cy re s p o n s e is a ch ie ve d
Ne ce s s a ry Am o u n t o f Fre q u e n cy Re s p o n s e
The drafting team has proposed the following approach to defining the necessary amount of
frequency response. In general, the goal is to avoid triggering the first step of under-frequency
load shedding (UFLS) in the given Interconnection for reasonable contingencies expected. The
10
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001860
methodology for determining each Interconnection’s and Balancing Authority’s obligation is
outlined in Attachment A to the Standard.
It should be noted that the standard cannot guarantee that there will never be a triggering of
UFLS as the magnitude of “point C” differs throughout an interconnection during a disturbance
and there are local areas that see much wider swings in frequency.
The contingency protection criterion is the largest reasonably expected contingency in the
Interconnection. This can be based on the largest observed credible contingency in the
previous 10 years or the largest Category C event for the Interconnection.
The Safety Margin included addresses the difference between Points B and C and accounts for
variables.
For multiple BA interconnections, the Frequency Response Obligation is allocated to BAs based
on size. This allocation will be based on the following calculation:
Me t h o d s o f Ob t a in in g Fre q u e n cy Re s p o n s e
The drafting team believes the following are valid methods of obtaining Frequency Response:
•
•
•
•
•
•
Supplemental regulation.
Overlap regulation.
Contractual service (The drafting team has developed an approach to obtain a
contractual share of Frequency Response from Adjacent Balancing Authorities. See FRS
Form 1). While the final rules with regard to contractual services are being defined, the
current expectation is that the ERO and the associated Region(s) should be notified
beforehand and that the service be at least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the
development of a NAESB business practice for Frequency Response service for linear
(droop) and stepped (e.g. LaaR in Texas) response).
Me a s u rin g t h a t t h e Fre q u e n cy Re s p o n s e is Ach ie ve d
FRS Form 1 and the underlying data retained by the BA will be used for measuring whether
Frequency Response was provided. FRS Form 1 will provide the guidance on how to account for
and measure Frequency Response.
11
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001861
Go in g Be yo n d t h e Dire ct ive
Based on the combined operating experience of the SDT, the drafting team believes each
Interconnection has sufficient Frequency Response. If margins decline, there may be a need for
additional standards or tools. The drafting team and the Resources Subcommittee are working
with the ERO on its Frequency Response Initiative to develop processes and good practices so
the Interconnections are prepared. These good practices and tools are described in the
following section.
The drafting team is also evaluating a risk-based approach for basing the Interconnection
Frequency Response Obligation on an historic probability density of frequency error, and for
allocating the obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error. This allocation method uses the inverse of the rationale for allocating the CPS1
epsilon requirement by Bias share.
12
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001862
Go o d P r a ct ice s a n d To o ls
Go o d P ra ct ice s
Knowing the quantity and depth of frequency responsive reserves in real time is a possible next
step to being better prepared for the next event. The challenge in achieving this is having the
knowledge of the capabilities of all sources of frequency response. Presently the primary
source of frequency response remains with the generation resources in our fleets.
Understanding how each of these sources performs to changes in system frequency and
knowing their limitations would improve the BA’s ability to measure frequency responsive
reserves. Presently there are only guidelines, criteria and protocols in some regions of the
industry that identify specific settings and performance expectations of primary frequency
response of resources. One method of gaining better understanding of performance is to
measure performance during actual events that occur on the system. This approach would only
provide feedback for performance during that specific event and would not provide insight into
depth of response or other limitations. Repeated measurements will increase confidence in
expected performance. NERC modeling standards are in process to be revised that will improve
the BA’s insight into predicting available frequency responsive reserves. However, knowing
how resources are operated, what modes of operation provide sustained primary frequency
response and knowing the operating range of this response would give the BA the knowledge
to accurately predict frequency response and the amount of frequency responsive reserves
available in real time.
Some benefits on several interconnections have been realized by communicating to generation
resources (GO) the importance of operating in modes that allow primary frequency response to
be sustained by the control systems of the resource. Other improvements in implementation
of primary frequency response have been achieved through improved settings on turbine
governors through the elimination of “step” frequency response with the simultaneous
reduction in governor dead-band settings. Improvements in the full AGC control loop of the
13
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001863
generating resource, which accounts for the expected primary frequency response, have
improved the delivery of quality primary frequency response while minimizing secondary
control actions of generators. Some of these actions can provide quick improvement in delivery
of primary frequency response.
Once primary frequency response sources are known the BA could calculate available reserves
that are frequency responsive. Planning for these reserves during normal and emergency
operations could be developed and added to the normal planning process.
To o ls
Single generating resource primary frequency response performance evaluation tools for steam
turbine, combustion turbine (simple cycle or combined cycle) and for intermittent resources are
available at the following link.
http://texasre.org/standards_rules/standardsdev/rsc/sar003/Pages/Default.aspx.
These tools and the regional standard associated with them are in their final stages of
development in the Texas region.
These tools will be posted on the NERC website.
14
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001864
Fie ld Tr ia l
This section is a summary of the Field Trial activities that have been or will be conducted by the
ERO, the Resources Subcommittee and the FRS Drafting Team.
1. The NERC BA recommendation (alert) and observations.√
2. The NERC governor recommendation (alert) and observations.√
3. The 2011 bias calculation √
1. Evaluate measurement methodology√
2. Serve as initial training for BAs√
3. Evaluate median, mean, regression and possibly other measures √
4. Evaluate sample size (to address the directive of frequency of surveys) √
5. Evaluate impact of inclusion/exclusion of internal contingencies √
6. Improve FRS Form 1√
4. Create supporting process for FRS Form 1 √
1. For Interconnection benchmarking (proving adequacy of frequency response)
2. Evaluating trend
3. Test process for developing candidate list for FRS Form 1
5. 2012 bias calculation
1. Further refinement of items in 2011 bias calculation
2. Test the FRO allocation methodology
3. Test approach for handling variable bias
4. Evaluate 12 month vs. 24 month rolling average approach to performance
6. Evaluate reduction in bias setting floor below 1% (initially 0.8% in 2012) to evaluate
impact on frequency and calculated CPS and BAAL performance.
7. Evaluate effectiveness of administrative process to support the standard.
8. Evaluate a risk-based approach for basing the Interconnection Frequency Response
Obligation on an historic probability density of frequency error, and for allocating the
obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error.
Body content goes here. Body content goes here. Body content goes here. Body content goes
here.
15
Frequency Response Standard Background Document – October 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001865
Standard BAL-003-0.1b — Frequency Response and Bias
A.
Introduction
1.
Title:
Frequency Response and Bias
2.
Number:
BAL-003-0.1b
3.
Purpose: This standard provides a consistent method for calculating the Frequency Bias
component of ACE.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
Immediately after approval of applicable regulatory authorities.
Requirements
R1. Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year
and recalculate its setting to reflect any change in the Frequency Response of the Balancing
Authority Area.
R1.1. The Balancing Authority may change its Frequency Bias Setting, and the method used
to determine the setting, whenever any of the factors used to determine the current bias
value change.
R1.2. Each Balancing Authority shall report its Frequency Bias Setting, and method for
determining that setting, to the NERC Operating Committee.
R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as
close as practical to, or greater than, the Balancing Authority’s Frequency Response.
Frequency Bias may be calculated several ways:
R2.1. The Balancing Authority may use a fixed Frequency Bias value which is based on a
fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The
Balancing Authority shall determine the fixed value by observing and averaging the
Frequency Response for several Disturbances during on-peak hours.
R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is
based on a variable function of Tie Line deviation to Frequency Deviation. The
Balancing Authority shall determine the variable frequency bias value by analyzing
Frequency Response as it varies with factors such as load, generation, governor
characteristics, and frequency.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Frequency Bias, unless such operation is adverse to system or Interconnection reliability.
R4. Balancing Authorities that use Dynamic Scheduling or Pseudo-ties for jointly owned units
shall reflect their respective share of the unit governor droop response in their respective
Frequency Bias Setting.
R4.1. Fixed schedules for Jointly Owned Units mandate that Balancing Authority (A) that
contains the Jointly Owned Unit must incorporate the respective share of the unit
governor droop response for any Balancing Authorities that have fixed schedules (B
and C). See the diagram below.
R4.2. The Balancing Authorities that have a fixed schedule (B and C) but do not contain the
Jointly Owned Unit shall not include their share of the governor droop response in
their Frequency Bias Setting.
Adopted by NERC Board of Trustees: October 29, 2008
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001866
Standard BAL-003-0.1b — Frequency Response and Bias
Jointly Owned Unit
A
C
B
R5. Balancing Authorities that serve native load shall have a monthly average Frequency Bias
Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1
Hz change.
R5.1. Balancing Authorities that do not serve native load shall have a monthly average
Frequency Bias Setting that is at least 1% of its estimated maximum generation level in
the coming year per 0.1 Hz change.
R6. A Balancing Authority that is performing Overlap Regulation Service shall increase its
Frequency Bias Setting to match the frequency response of the entire area being controlled. A
Balancing Authority shall not change its Frequency Bias Setting when performing
Supplemental Regulation Service.
C.
Measures
M1. Each Balancing Authority shall perform Frequency Response surveys when called for by the
Operating Committee to determine the Balancing Authority’s response to Interconnection
Frequency Deviations.
D.
Compliance
Not Specified.
E.
Regional Differences
None identified.
F.
Associated Documents
1.
Appendix 1 Interpretation of Requirement R3 (October 23, 2007).
2.
Appendix 2 Interpretation of Requirements R2, R2.2, R5, and R5.1 (February 12, 2008).
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Errata
0
March 16, 2007
Removed "Proposed" from Effective Date
FERC Approval — Order 693
Adopted by NERC Board of Trustees: October 29, 2008
New
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001867
Standard BAL-003-0.1b — Frequency Response and Bias
0a
December 19, 2007
Added Appendix 1 Interpretation of R3
approved by BOT on October 23, 2007
Addition
0a
July 21, 2008
FERC Approval of Interpretation of R3
Addition
0b
February 12, 2008
Added Appendix 2 Interpretation of R2,
R2.2, R5, and R5.1 approved by BOT on
February 12, 2008
Addition
0.1b
January 16, 2008
Section F: added “1.”; changed hyphen to “en
dash.” Changed font style for “Appendix 1” to
Arial; updated version number to “0.1b”
Errata
0.1b
October 29, 2008
BOT approved errata changes
Errata
0.1a
May 13, 2009
FERC Approved errata changes – version
changed to 0.1a (Interpretation of R2, R2.2,
R5, and R5.1 not yet approved)
Errata
0.1b
May 21, 2009
FERC Approved Interpretation of R2, R2.2,
R5, and R5.1
Addition
Adopted by NERC Board of Trustees: October 29, 2008
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001868
Standard BAL-003-0.1b — Frequency Response and Bias
Appendix 1
Interpretation of Requirement 3
Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 3 of
BAL-003-0?
Interpretation:
Requirement 3 of BAL-003-0 — Frequency Response and Bias deals with Balancing Authorities using
Tie-Line Frequency Bias as the normal mode of automatic generation control.
BAL-003-0
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Frequency Bias, unless such operation is adverse to system or Interconnection reliability.
Tie-Line Frequency Bias is one of the three foundational control modes available in a Balancing
Authority’s energy management system. (The other two are flat-tie and flat-frequency.) Many Balancing
Authorities layer other control objectives on top of their basic control mode, such as automatic inadvertent
payback, CPS optimization, time control (in single BA Interconnections).
As long as Tie-Line Frequency Bias is the underlying control mode and CPS1 is measured and reported
on the associated ACE equation, there is no violation of BAL-003-0 Requirement 3:
ACE = (NIA− NIS) – 10B (FA − FS) − IME
Adopted by NERC Board of Trustees: October 29, 2008
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001869
Standard BAL-003-0.1b — Frequency Response and Bias
Appendix 2
Interpretation of Requirements R2, R2.2, R5, R5.1
Request: ERCOT specifically requests clarification that a Balancing Authority is entitled to use a
variable bias value as authorized by Requirement R2.2, even though Requirement 5 seems not to account
for the possibility of variable bias settings.
Interpretation:
The consensus of the Resources Subcommittee is that BAL-003-0 — Frequency Response and Bias —
Requirement R2 does not conflict with BAL-003-0 Requirement R5.
BAL-003-0 — Frequency Response and Bias Requirement 2 requires a Balancing Authority to analyze
its response to frequency excursions as a first step in determining its frequency bias setting. The
Balancing Authority may then choose a fixed bias (constant through the year) per Requirement 2.1, or a
variable bias (varies with load, specific generators, etc.) per Requirement 2.2.
BAL-003-0
R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close
as practical to, or greater than, the Balancing Authority’s Frequency Response. Frequency Bias
may be calculated several ways:
R2.1.
The Balancing Authority may use a fixed Frequency Bias value which is based on a
fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The
Balancing Authority shall determine the fixed value by observing and averaging the
Frequency Response for several Disturbances during on-peak hours.
R2.2.
The Balancing Authority may use a variable (linear or non-linear) bias value, which is
based on a variable function of Tie Line deviation to Frequency Deviation. The
Balancing Authority shall determine the variable frequency bias value by analyzing
Frequency Response as it varies with factors such as load, generation, governor
characteristics, and frequency.
BAL-003-0 — Frequency Response and Bias Requirement 5 sets a minimum contribution for all
Balancing Authorities toward stabilizing interconnection frequency. The 1% bias setting establishes a
minimum level of automatic generation control action to help stabilize frequency following a disturbance.
By setting a floor on bias, Requirement 5 also helps ensure a consistent measure of control performance
among all Balancing Authorities within a multi-Balancing Authority interconnection. However, ERCOT
is a single Balancing Authority interconnection. The bias settings ERCOT uses do produce, on average,
the best level of automatic generation control action to meet control performance metrics. The bias value
in a single Balancing Authority interconnection does not impact the measure of control performance.
BAL-003-0
R5.
Balancing Authorities that serve native load shall have a monthly average Frequency Bias
Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1 Hz
change.
R5.1.
Balancing Authorities that do not serve native load shall have a monthly average
Frequency Bias Setting that is at least 1% of its estimated maximum generation level in
the coming year per 0.1 Hz change.
Adopted by NERC Board of Trustees: October 29, 2008
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001870
Unofficial Comment Form
Frequency Response (Project 2007-12)
Please DO NOT use this form to submit comments. Please use the electronic comment form to
submit comments on the first formal posting for Project 2007-12—Frequency Response. The
electronic comment form must be completed by December 8, 2011.
2007-12 Project Page
If you have questions please contact Darrel Richardson at [email protected] or
609.613.1848.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of
the bulk power system, particularly during disturbances and restoration. There is evidence of
continuing decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency
Response in each of the Interconnections can be analyzed, and the reasons for the decline in
Frequency Response can be identified. The standard would set a minimum Frequency Response
obligation for each Balancing Authority, provide a uniform calculation of Frequency Response and
Frequency Bias Settings that transition to values closer to natural Frequency Response, and
encourage coordinated AGC operation.
The Drafting Team would like to receive industry comments on this standard.
You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. The SDT has made minor modifications to the proposed definitions to provide additional clarity.
Do you agree that these modifications provide sufficient clarity? If not, please explain in the
comment area.
Yes
No
Comments:
2. The SDT has made minor modifications to the Requirements R1 through R4 to provide
additional clarity. Do you agree that these modifications provide sufficient clarity to comply
with the standard? If not, please explain in the comment area.
Yes
No
Comments:
Unofficial Comment Form
Project 2007-12 Frequency Response
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001871
3. The SDT has developed VRFs for the proposed Requirements within this standard. Do you
agree that these VRFs are appropriately set? If not, please explain in the comment area.
Yes
No
Comments:
4. The SDT has developed Measures for the proposed Requirements within this standard. Do you
agree with the proposed Measures in this standard? If not, please explain in the comment
area.
Yes
No
Comments:
5. The SDT has developed VSLs for the proposed Requirements within this standard. Do you
agree with these VSLs? If not, please explain in the comment area.
Yes
No
Comments:
6. The SDT divided the previously posted “Attachment A – Background Document” into two
documents to provide additional clarity. The first document “Attachment A- Supporting
Document” which details the methods used to develop the events to be analyzed, the FRO, FRM
and Frequency Bias Setting. Do you agree that the revised Attachment A – Supporting
Document provides sufficient clarity on the methodologies to be used? If not, please explain in
the comment area.
Yes
No
Comments:
7. The second document “BAL-003-1 Background Document” provides information behind the
development of the standard. Do you agree that this new document provides sufficient clarity
as to the development of the standard? If not, please explain in the comment area.
Yes
No
Comments:
8. The SDT has developed a new document titled Attachment B – Process for Adjusting Bias
Setting Floor. This document is intended to provide the methodology the ERO will use to
reduce the minimum Frequency Bias Setting to become closer to natural Frequency Response.
Do you agree that this document provides clear and concise instructions for the ERO to follow?
If not, please explain in the comment area.
Unofficial Comment Form
Project 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001872
Yes
No
Comments:
9. The SDT has provided an additional spreadsheet, FRS Form 2, to assist the Balancing Authority
in providing the data needed to comply with the proposed standard. Do you agree that this
spreadsheet is useful and the instructions are meaningful? If not, please explain in the
comment area.
Yes
No
Comments:
10. Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1.
Comments:
Unofficial Comment Form
Project 2007-12 Frequency Response
3
001873
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
R1. Each Balancing Authority shall
This
Attachment A
review its Frequency Bias
Requirement
Each Balancing Authority shall report its previous year’s
Settings by January 1 of each
has been
Frequency Response Measure (FRM), Frequency Bias
year and recalculate its setting
moved into
Setting and Frequency Bias type (fixed or variable) to the
to reflect any change in the
BAL-003-1
ERO on FRS Form 1 by January 10 each year. If the ERO
Frequency Response of the
Attachment A
Balancing Authority Area.
& FRS Form 1
posts the official list of events after December 10,
R1.1. The Balancing Authority
Balancing Authorities will be given 30 days from the date
may change its Frequency
the ERO posts the official list of events to submit their FRS
Bias Setting, and the
Form 1.
method used to determine
the setting, whenever any
AND
of the factors used to
determine the current bias
FRS Form 1
value change.
Note : Balancing Authorities with variable Frequency Bias
R1.2. Each Balancing Authority
Settings shall calculate monthly average Frequency Bias
shall report its Frequency
Settings. The previous year’s monthly averages will be
Bias Setting, and method
reported annually on FRS Form 1.
for determining that
setting, to the NERC
Operating Committee.
R2. Each Balancing Authority shall
This
R2.
Each Balancing Authority not participating in Overlap
establish and maintain a Frequency
Requirement
Regulation Service shall implement the Frequency Bias Setting
October 24, 2011 | Mapping of Requirements in Approved BAL-003-0 to Draft 2 of BAL-003-1
001874
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
(fixed or variable) validated by the ERO, into its Area Control Error
Bias Setting that is as close as practical is included in
BAL-003-1 as
(ACE) calculation beginning on the date specified by the ERO to
to, or greater than, the Balancing
described in
ensure effectively coordinated Tie Line Bias control.
Authority’s Frequency Response.
the Proposed
Frequency Bias may be calculated
Language
AND
several ways:
R2.1. The Balancing Authority Section.
may use a fixed Frequency Bias
Attachment A
value which is based on a
Each Balancing Authority shall report its previous year’s
fixed, straight-line function of
Frequency Response Measure (FRM), Frequency Bias
Tie Line deviation versus
Frequency Deviation. The
Setting and Frequency Bias type (fixed or variable) to the
Balancing Authority shall
ERO on FRS Form 1 by January 10 each year. If the ERO
determine the fixed value by
posts the official list of events after December 10,
observing and averaging the
Balancing Authorities will be given 30 days from the date
Frequency Response for
the ERO posts the official list of events to submit their FRS
several Disturbances during
Form 1.
on-peak hours.
R2.2. The Balancing Authority
AND
may use a variable (linear or
non-linear) bias value, which is
FRS Form 1
based on a variable function of
Tie Line deviation to
Note : Balancing Authorities with variable Frequency Bias
Frequency Deviation. The
Settings shall calculate monthly average Frequency Bias
Balancing Authority shall
Settings. The previous year’s monthly averages will be
determine the variable
reported annually on FRS Form 1.
frequency bias value by
AND
October 24, 2011 | Mapping of Requirements in Approved BAL-003-0 to Draft 2 of BAL-003-1
001875
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
analyzing Frequency Response
as it varies with factors such as
A portion of this Requirement is being phased out in accordance
load, generation, governor
with the process detailed in Attachment B. This phase out is
characteristics, and frequency.
intended to bring the Frequency Bias Setting closer or equal to the
natural Frequency Response.
R3. Each Balancing Authority shall
This
R3. Each Balancing Authority not receiving Overlap Regulation
operate its Automatic Generation
Requirement
Service shall operate its Automatic Generation Control (AGC)
Control (AGC) on Tie Line Frequency
has been
in Tie Line Bias mode to ensure effectively coordinated
Bias, unless such operation is adverse moved into
control, unless such operation would have an Adverse
to system or Interconnection
BAL-003-1
Reliability Impact on the Balancing Authority’s Area. In this
reliability.
Requirement
instance, the Balancing Authority shall document the reasons
R3.
for such operation.
R4. Balancing Authorities that use
This
This Requirement addresses how to calculate Frequency Bias
Dynamic Scheduling or PseudoRequirement
Settings. This is no longer needed since the Frequency Bias Settings
ties for jointly owned units shall
has been
are calculated in FRS Form 1 using Frequency Response associated
reflect their respective share of
removed from
with the “official” list of events and a couple of “floor or ceiling”
the unit governor droop response the BAL-003-1
limits (% of peak load/gen and FRO). The entire calculation is built
in their respective Frequency Bias standard.
into the FRS Form 1 workbook.
Setting.
R4.1. Fixed schedules for Jointly
Owned Units mandate that
Balancing Authority (A) that
contains the Jointly Owned Unit
must incorporate the respective
share of the unit governor droop
response for any Balancing
October 24, 2011 | Mapping of Requirements in Approved BAL-003-0 to Draft 2 of BAL-003-1
001876
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Authorities that have fixed
schedules (B and C).
R4.2. The Balancing Authorities that
have a fixed schedule (B and C)
but do not contain the Jointly
Owned Unit shall not include
their share of the governor
droop response in their
Frequency Bias Setting.
R5. Balancing Authorities that serve
This
R5. Each Balancing Authority shall use a monthly average
native load shall have a monthly
Requirement
Frequency Bias Setting whose absolute value is at least equal
average Frequency Bias Setting that is has been
to one of the following:
at least 1% of the Balancing
moved into
Authority’s estimated yearly peak
BAL-003-1
•
The minimum percentage of the Balancing Authority
demand per 0.1 Hz change.
Requirement
Area’s estimated yearly Peak Demand within its
R5.1. Balancing Authorities
R5.
metered boundary per 0.1 Hz change as specified by
that do not serve native load
the ERO in accordance with Attachment B.
shall have a monthly average
Frequency Bias Setting that is
•
The minimum percentage of the Balancing Authority
at least 1% of its estimated
Area’s estimated yearly peak generation for a
maximum generation level in
generation-only Balancing Authority, per 0.1 Hz change
the coming year per 0.1 Hz
as specified by the ERO in accordance with Attachment
change.
B.
R6. A Balancing Authority that is
This
R4. Each Balancing Authority that is performing Overlap
performing Overlap Regulation
Requirement
Regulation Service shall modify its Frequency Bias Setting in
Service shall increase its Frequency
has been
its ACE calculation to be equivalent to the sum of the
October 24, 2011 | Mapping of Requirements in Approved BAL-003-0 to Draft 2 of BAL-003-1
001877
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Bias Setting to match the frequency
moved into
Frequency Bias Settings of the participating Balancing
response of the entire area being
BAL-003-1
Authorities as validated by the ERO or calculate the
controlled. A Balancing Authority shall Requirement
Frequency Bias Setting based on the entire area being
not change its Frequency Bias Setting R4.
combined and thereby represent the Frequency Response for
when performing Supplemental
the combined area being controlled.
Regulation Service.
October 24, 2011 | Mapping of Requirements in Approved BAL-003-0 to Draft 2 of BAL-003-1
001878
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet.
Step 2
For identified events in column B of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
Balancing Authority abbreviation)
Step 5
"Summary" worksheet contains each event's results for your Balancing Authority.
Note
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The previous
year’s monthly averages will be reported annually on FRS Form 1.
001879
Event
Number
NERC FRS FORM 1 20 to 52 second Value B
Balancing Authority
MyBA
Date/Time
(Central Prevailing)
DelFreq
BA
Time
BA
DelFreq
Value "A" Information
NAI
Adjustment
Value "B" Information
NAI
Adjustment
Enter Addition Data in column R ==>
SEFRD
(MW/0.1Hz)
Exclude for
data error *
Information
Event
Value "A"
Value "B"
MW Loss
Load
Load
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
1
12/3/2010 17:28
-0.044
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
2
12/19/2010 23:50
-0.037
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
3
1/21/2011 7:36
-0.043
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
4
2/16/2011 10:54
-0.042
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
2012
5
4/20/2011 6:27
-0.065
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Eastern
6
4/20/2011 16:34
-0.046
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
MyBA
7
4/22/2011 10:53
-0.050
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
8
4/26/2011 20:20
-0.059
0:00:00
0.000
0.0
0.0
0.0
0.0
9
4/27/2011 16:36
-0.082
0:00:00
0.000
0.0
0.0
0.0
10
5/12/2011 14:37
-0.051
0:00:00
0.000
0.0
0.0
11
0:00:00
0.000
0.0
12
0:00:00
0.000
13
0:00:00
0.000
14
0:00:00
15
1186
Bias Calculation Form Year
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Interconnection
1306
0.0
0.0
Balancing Authority
1203
0.0
0.0
N
Contact Name
1400
0.0
0.0
#DIV/0!
N
Contact Phone #
0.0
0.0
0.0
#DIV/0!
N
Contact e-mail
2783
0.0
0.0
0.0
0.0
#DIV/0!
N
Current Year's Actual Peak
1179
0.0
0.0
0.0
0.0
0.0
Y
Internal Generating Capacity
0.0
0.0
0.0
0.0
0.0
0.0
Y
Next Year's Projected Peak
0.0
0.0
0.0
0.0
0.0
0.0
Y
0.0
0.0
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
2011
Current year
0.0
0.0
16
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
-70.0
2011 Frequency Response Obligation (FRO)
0.0
0.0
17
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
18
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
Summary Statistics
0.0
0.0
19
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
0.0
0.0
20
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
21
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
22
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
23
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
24
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
25
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
26
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
27
28
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-70.0
0.0
0.0
0.0
0.0
29
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
0.0
0.0
30
31
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.0
0.0
0.0
0.0
32
33
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.0
0.0
0.0
0.0
34
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
Do you RECEIVE Overlap regulation?
0.0
0.0
35
36
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
If Yes, list the BA name and the associated Bias of that BA
0.0
0.0
0.0
0.0
37
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
38
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
39
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
40
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
41
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
42
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
-33.8
#DIV/0!
N
Bias -MW/0.1 Hz
N
Bias -MW/0.1 Hz
Average Frequency Response (MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
2011 FRM - Median Frequency Response (MW/0.1Hz)
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Balancing Authority
Select Reason(s) for adjustment
Reason(s)
001880
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" into "BA Form 2 Data"
worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a
copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
BA name)
Note:
Only one set of average periods of evaluation is displayed. Other worksheets for the additional
average periods are hidden.
001881
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493
80.66089
-0.07090523 -26.89761
-0.05190677
9.955449
-0.0580477
3.367024
-0.07557242
36.33443
-0.0563805
0.488253
-0.0573329
2.758037
-0.0517609
13.64342
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
-0.05849838
0.750192
-0.04850006
2.230058
-0.04500008
9.477859
-0.03750229
0.355309
-0.04750061
2.170702
-0.05550003
29.38207
-0.047
4.601381
-0.06
1.593515
-0.06
52.37091
-0.051
33.94787
-0.1
100
N
Y
N
Y
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
001882
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time
(Central Prevailing)
12/3/2010 17:28
12/19/2010 23:50
1/21/2011 7:36
2/16/2011 10:54
4/20/2011 6:27
4/20/2011 16:34
4/22/2011 10:53
4/26/2011 20:20
4/27/2011 16:36
5/12/2011 14:37
MyBA
DelFreq
-0.044
-0.037
-0.043
-0.042
-0.065
-0.046
-0.050
-0.059
-0.082
-0.051
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Ramping
Units
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 12 to 24 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Notes:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange (contingency size for single BA interconnections) solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the six types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be entered as negative numbers.
4) Pumped Hydro:
- Values for pumping must be entered as negative values.
- Values for generating must be entered as positive values.
5) Rampling Units:
- Values are entered as positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Value for Value A is the pre-contingency generation from the contingent unit(s).
- Value for Value B is usually 0 MW, but may be the load that remains on the system that was "netted" out by the now offline generation.
Generation MW as +
(If load occurs due to gen
loss, enter MW as - at value
B)
001883
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Date/Time
(Central Prevailing)
12/3/2010 17:28
12/19/2010 23:50
1/21/2011 7:36
2/16/2011 10:54
4/20/2011 6:27
4/20/2011 16:34
4/22/2011 10:53
4/26/2011 20:20
4/27/2011 16:36
5/12/2011 14:37
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
Average Frequency Response (MW/0.1Hz)
2012 FRM - Median Frequency Response
(MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
2012 Frequency Response Obligation (FRO)
NERC FRS FORM 1
MyBA
DelFreq
-0.044
-0.037
-0.043
-0.042
-0.065
-0.046
-0.050
-0.059
-0.082
-0.051
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Time
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
BA
12 to 24 18 to 30 20 to 40 18 to 52 20 to 52
DelFreq
SEFRD
SEFRD
SEFRD
SEFRD
SEFRD
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
-33.77
-70
#DIV/0!
-33.77
-70
#DIV/0!
-33.77
-70
#DIV/0!
-33.77
-70
#DIV/0!
-33.77
-70
12 to 24 P.U. Performance
Exclude for
data error *
N
N
N
N
N
N
N
N
N
N
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 30 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 40 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Sustained
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 52 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 52 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
001884
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
average
FBS* for
month
-10.0
-7.0
-12.0
-8.0
-27.0
-8.7
-8.0
-8.0
-8.2
-8.0
-8.0
-12.0
-10.4
Average Annual Bias
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001
001885
Interconnection Performance
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing)
1
12/3/2010 17:28
2
12/19/2010 23:50
3
1/21/2011 7:36
4
2/16/2011 10:54
5
4/20/2011 6:27
6
4/20/2011 16:34
7
4/22/2011 10:53
8
4/26/2011 20:20
9
4/27/2011 16:36
10
5/12/2011 14:37
11
1/0/1900 0:00
12
1/0/1900 0:00
13
1/0/1900 0:00
14
1/0/1900 0:00
15
1/0/1900 0:00
16
1/0/1900 0:00
17
1/0/1900 0:00
18
1/0/1900 0:00
19
1/0/1900 0:00
20
1/0/1900 0:00
21
1/0/1900 0:00
22
1/0/1900 0:00
23
1/0/1900 0:00
24
1/0/1900 0:00
25
1/0/1900 0:00
26
1/0/1900 0:00
27
1/0/1900 0:00
28
1/0/1900 0:00
29
1/0/1900 0:00
30
1/0/1900 0:00
31
1/0/1900 0:00
32
1/0/1900 0:00
33
1/0/1900 0:00
34
1/0/1900 0:00
35
1/0/1900 0:00
36
1/0/1900 0:00
37
1/0/1900 0:00
38
1/0/1900 0:00
39
1/0/1900 0:00
40
1/0/1900 0:00
41
1/0/1900 0:00
42
1/0/1900 0:00
DelFreq
-0.044
-0.037
-0.043
-0.042
-0.065
-0.046
-0.05
-0.059
-0.082
-0.051
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Value B
12 to 24 sec
Average
Frequency
FR B
12 to 24 sec
Average
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
001886
Value A Data
BA Performance
JOU
NonTransferred
Contingent
FR B
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
20 to 52 sec
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Average Frequency Interchange Imp(-) Exp (+)
Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW
MW
Initial
Performance
Adjusted
P.U.
001887
Value B
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming Pumped Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Frequency Interchange Imp(-) Exp (+) Load (-)Load (-) Gen (+)Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
Value B
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
20 to 40 second Average Per
Net
Actual
Interchange
MW
001888
20 to 40 second Average Period Evaluation
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
Value B
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW/0.1 Hz
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
18 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
001889
Value B
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
Hz
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
001890
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet.
Step 2
For identified events in column B of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
Balancing Authority abbreviation)
Step 5
"Summary" worksheet contains each event's results for your Balancing Authority.
Note
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The previous
year’s monthly averages will be reported annually on FRS Form 1.
001891
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
ERCO
Enter Addition Data in column R ==>
Information
Event
Number
Date/Time
(Central Prevailing)
BA
DelFreq
Value "A" Information
MW Lost
Adjustment
Value "B" Information
MW Lost
Adjustment
SEFRD
(MW/0.1Hz)
Exclude for
data error *
Event
Value "A"
MW Loss
Load
DelFreq
BA
Time
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
1
12/6/2010 11:25
-0.101
11:25:50
-0.095
755.1
0.0
0.0
0.0
-798.1
N
755.3
35688.6
35469.9
2
12/9/2010 17:34
-0.074
17:34:12
-0.107
753.1
0.0
0.0
0.0
-703.0
N
718.8
34418.4
34111.3
3
12/11/2010 23:38
-0.166
23:38:26
-0.198
821.1
0.0
0.0
0.0
-414.1
N
819.5
29590.8
29403.0
4
12/16/2010 15:16
-0.074
15:15:58
-0.078
617.1
0.0
0.0
0.0
-788.7
N
2012
Bias Calculation Form Year
615.8
31769.4
31741.1
5
12/19/2010 2:39
-0.111
2:39:20
-0.133
720.3
0.0
0.0
0.0
-541.6
N
Texas
Interconnection
719.8
30239.7
30135.2
6
12/26/2010 8:23
-0.066
8:32:02
-0.039
494.4
0.0
0.0
0.0
-1252.2
N
ERCO
Balancing Authority
538
39597.9
39185.6
7
1/9/2011 18:52
-0.108
18:51:58
-0.108
575.2
0.0
0.0
0.0
-534.9
N
Ken McIntyre
Contact Name
516.3
40357.4
40269.5
8
1/11/2011 6:50
-0.091
6:50:14
-0.091
456.9
0.0
0.0
0.0
-499.9
N
512-248-3969
Contact Phone #
523
48145.5
48054.2
9
1/20/2011 0:01
-0.198
0:01:52
-0.198
786.1
0.0
0.0
0.0
-397.4
N
784.9
28998.6
28794.7
10
1/21/2011 3:46
-0.171
3:46:26
-0.171
650.0
0.0
0.0
0.0
-379.6
N
63453
Current Year's Actual Peak
624
40462.5
40291.5
11
1/23/2011 14:53
-0.149
14:53:18
-0.149
403.7
0.0
0.0
0.0
-271.6
N
75314
Internal Generating Capacity
400.1
31488.8
31483.8
12
1-28-11 5:21:00
-0.058
5:21:44
-0.056
311.5
0.0
0.0
0.0
-556.6
N
63783
Next Year's Projected Peak
324.9
32641.7
32711.8
13
1/29/2011 22:29
-0.122
22:29:28
-0.082
646.2
0.0
351.3
0.0
Y
532
27749.0
27729.3
14
2-1-11 22:28:00
-0.078
22:27:46
-0.078
459.3
0.0
0.0
0.0
-589.5
N
459.3
51871.7
51714.3
15
2-2-11 2:18:00
-0.158
2:18:42
-0.158
716.9
0.0
0.0
0.0
-452.5
N
2011
Current year
717
49441.4
49290.7
16
2-2-11 5:39:00
-0.125
5:39:12
-0.124
578.5
0.0
0.0
0.0
-466.9
N
-286.0
2011 Frequency Response Obligation (FRO)
520
52943.4
52864.7
17
2-2-11 8:24:00
-0.188
8:24:28
-0.187
775.3
0.0
0.0
0.0
-413.6
N
776
52047.5
51917.7
18
2-2-11 10:55:00
-0.190
10:55:38
-0.190
840.9
0.0
0.0
0.0
-443.7
N
840.91
52733.0
52604.6
19
2-9-11 13:01:00
-0.114
13:01:36
-0.114
598.7
0.0
11.2
0.0
-516.3
N
581.8
50685.2
50619.1
20
2-15-11 16:40:00
-0.216
16:40:02
-0.216
770.0
0.0
0.0
0.0
-356.7
N
770
31612.4
31388.7
21
2-16-11 9:25:00
-0.197
9:25:36
-0.175
569.9
0.0
0.0
0.0
-324.9
N
601.6
31135.6
31020.1
22
3-3-11 11:17:00
-0.094
11:17:34
-0.094
440.5
0.0
0.0
0.0
-467.5
N
440.9
31497.4
31443.5
23
3-14-11 6:09:00
-0.208
6:09:32
-0.208
970.7
0.0
0.0
0.0
-467.5
N
924
26752.6
26597.6
24
3-14-11 7:08:00
-0.127
7:08:12
-0.127
487.0
0.0
0.0
0.0
-382.5
N
487.4
29065.2
29088.1
25
3-16-11 20:45:00
-0.074
20:45:06
-0.074
397.6
0.0
0.0
0.0
-538.3
N
397.8
33412.6
33257.8
26
3-23-11 14:46:00
-0.063
14:46:46
-0.063
621.2
0.0
0.0
0.0
-993.6
N
1013.6
38733.6
38255.9
27
28
3-24-11 13:59:00
3-25-11 16:13:00
-0.182
-0.172
13:59:06
16:13:26
-0.177
-0.168
498.3
553.4
0.0
0.0
0.0
67.1
0.0
0.0
-281.5
-288.8
N
N
-286.0
568.8
591.4
35353.8
40151.5
35240.8
39989.1
29
3-29-11 6:43:00
-0.099
6:43:06
-0.099
742.8
0.0
0.0
0.0
-747.0
N
-556.4
735.3
31093.9
31034.9
30
31
3-31-11 12:21:00
4-5-11 22:02:00
-0.112
-0.090
12:21:24
22:02:04
-0.112
-0.090
421.0
518.5
0.0
0.0
0.0
0.0
0.0
0.0
-376.6
-578.3
N
N
420.3
519.4
31970.4
30986.5
31774.6
30848.3
32
33
4-20-11 13:40:00
4-27-11 23:27:00
-0.145
-0.133
13:40:54
23:27:04
-0.145
-0.133
785.5
691.8
0.0
0.0
0.0
0.0
0.0
0.0
-543.4
-520.5
N
N
787.9
697.2
41620.0
29943.1
41463.4
29703.5
34
5-11-11 14:04:00
-0.121
14:04:46
-0.121
726.0
0.0
0.0
0.0
-598.8
N
723
42265.9
42113.4
35
36
5-16-11 8:06:00
5-19-11 14:08:00
-0.101
-0.197
8:06:36
14:07:56
-0.101
-0.197
471.1
995.1
0.0
0.0
0.0
0.0
0.0
0.0
-464.3
-504.6
N
N
471
1162.3
30202.7
42909.6
30136.8
42610.2
37
5-23-11 17:34:00
-0.092
17:34:38
-0.092
533.3
0.0
0.0
0.0
-579.2
N
552
50589.7
50488.3
38
5-29-11 22:03:00
-0.118
22:03:06
-0.118
762.3
0.0
0.0
0.0
-646.4
N
761.9
44769.7
44478.0
39
6-22-11 13:18:00
0.080
13:18:38
0.031
-258.6
0.0
0.0
0.0
-825.6
N
-258.56
44769.2
44457.0
40
6-27-11 12:54:00
-0.149
12:54:00
-0.131
661.2
0.0
0.0
0.0
-504.4
N
659.5
56971.1
56832.7
41
7-18-11 9:13:00
-0.097
9:13:14
-0.094
386.3
0.0
0.0
0.0
-409.7
N
464
45315.0
45296.7
42
7-18-11 20:50:00
-0.119
20:50:38
-0.128
596.1
0.0
0.0
0.0
-466.9
N
593.3
57050.3
56884.0
[email protected] Contact e-mail
Summary Statistics
-533.8
-33.8
-504.4
N
Average Frequency Response (MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
2011 FRM - Median Frequency Response (MW/0.1Hz)
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Bias -MW/0.1 Hz
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Value "B"
Load
001892
Bias -MW/0.1 Hz
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" into "BA Form 2 Data"
worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a
copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
BA name)
Note:
Only one set of average periods of evaluation is displayed. Other worksheets for the additional
average periods are hidden.
Balancing Authority
001893
Select Reason(s) for adjustment
Reason(s)
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493
80.66089
-0.07090523 -26.89761
-0.05190677
9.955449
-0.0580477
3.367024
-0.07557242
36.33443
-0.0563805
0.488253
-0.0573329
2.758037
-0.0517609
13.64342
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
-0.05849838
0.750192
-0.04850006
2.230058
-0.04500008
9.477859
-0.03750229
0.355309
-0.04750061
2.170702
-0.05550003
29.38207
-0.047
4.601381
-0.06
1.593515
-0.06
52.37091
-0.051
33.94787
-0.1
100
N
Y
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
001894
N
Y
001895
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
ERCO
Date/Time
(Central Prevailing)
DelFreq
12/6/2010 11:25 -0.101
12/9/2010 17:34 -0.074
12/11/2010 23:38 -0.166
12/16/2010 15:16 -0.074
12/19/2010 2:39 -0.111
12/26/2010 8:23 -0.066
1/9/2011 18:52 -0.108
1/11/2011 6:50 -0.091
1/20/2011 0:01 -0.198
1/21/2011 3:46 -0.171
1/23/2011 14:53 -0.149
1-28-11 5:21:00 -0.058
1/29/2011 22:29 -0.122
2-1-11 22:28:00 -0.078
2-2-11 2:18:00 -0.158
2-2-11 5:39:00 -0.125
2-2-11 8:24:00 -0.188
2-2-11 10:55:00 -0.190
2-9-11 13:01:00 -0.114
2-15-11 16:40:00 -0.216
2-16-11 9:25:00 -0.197
3-3-11 11:17:00 -0.094
3-14-11 6:09:00 -0.208
3-14-11 7:08:00 -0.127
3-16-11 20:45:00 -0.074
3-23-11 14:46:00 -0.063
3-24-11 13:59:00 -0.182
3-25-11 16:13:00 -0.172
3-29-11 6:43:00 -0.099
3-31-11 12:21:00 -0.112
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Ramping
Units
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
4-5-11 22:02:00
-0.090
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
4-20-11 13:40:00
4-27-11 23:27:00
5-11-11 14:04:00
-0.145
-0.133
-0.121
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
5-16-11 8:06:00
-0.101
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
5-19-11 14:08:00
5-23-11 17:34:00
5-29-11 22:03:00
-0.197
-0.092
-0.118
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
6-22-11 13:18:00
0.080
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
6-27-11 12:54:00
-0.149
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
4-27-11 23:27:00
-0.133
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
001896
42
5-11-11 14:04:00
-0.121
Sign Convention for scan
data collected in Form 2
0.0
0.0
Imports: MWs are Exports: MWs are +
0.0
0.0
Loads in MW as -
0.0
0.0
Load MW as Generation MW as +
0.0
0.0
Enter Gen MW as +
0.0
0.0
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
0.0
Generation MW as +
(If load occurs due to gen loss,
enter MW as - at value B)
Notes:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange (contingency size for single BA interconnections) solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the six types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be entered as negative numbers.
4) Pumped Hydro:
- Values for pumping must be entered as negative values.
- Values for generating must be entered as positive values.
5) Rampling Units:
- Values are entered as positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Value for Value A is the pre-contingency generation from the contingent unit(s).
- Value for Value B is usually 0 MW, but may be the load that remains on the system that was "netted" out by the now offline generation.
0.0
001897
Net Total
Adjustments
Value B 12 to 24 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
001898
0.0
001899
Event
Number
NERC FRS FORM 1 12 to 24 second Value B
Balancing Authority
ERCO
Date/Time
(Central Prevailing)
DelFreq
BA
Time
BA
DelFreq
Value "A" Information
MW Lost
Adjustment
Value "B" Information
MW Lost
Adjustment
SEFRD
(MW/0.1Hz)
Exclude for
data error *
1
12/6/2010 11:25
-0.101
11:25:50
-0.103
755.1
0.0
0.0
0.0
-735.7
N
2
12/9/2010 17:34
-0.074
17:34:12
-0.111
753.1
0.0
0.0
0.0
-675.8
N
3
12/11/2010 23:38
-0.166
23:38:26
-0.185
821.1
0.0
0.0
0.0
-443.5
N
4
12/16/2010 15:16
-0.074
15:15:58
-0.082
617.1
0.0
0.0
0.0
-755.3
N
2012
5
12/19/2010 2:39
-0.111
2:39:20
-0.112
720.3
0.0
0.0
0.0
-643.2
N
Texas
6
12/26/2010 8:23
-0.066
8:32:02
-0.060
494.4
0.0
0.0
0.0
-828.5
N
ERCO
7
1/9/2011 18:52
-0.108
18:51:58
-0.122
575.2
0.0
0.0
0.0
-472.6
N
Ken McIntyre
8
1/11/2011 6:50
-0.091
6:50:14
-0.097
456.9
0.0
0.0
0.0
-473.4
N
512-248-3969
9
1/20/2011 0:01
-0.198
0:01:52
-0.189
786.1
0.0
0.0
0.0
-415.7
N
[email protected]
10
1/21/2011 3:46
-0.171
3:46:26
-0.157
650.0
0.0
0.0
0.0
-412.8
N
63453
11
1/23/2011 14:53
-0.149
14:53:18
-0.136
403.7
0.0
0.0
0.0
-297.1
N
75314
12
1-28-11 5:21:00
-0.058
5:21:44
-0.068
311.5
0.0
0.0
0.0
-459.4
N
63783
13
1/29/2011 22:29
-0.122
22:29:28
-0.123
646.2
0.0
113.9
0.0
14
2-1-11 22:28:00
-0.078
22:27:46
-0.082
459.3
0.0
0.0
0.0
-563.6
N
15
2-2-11 2:18:00
-0.158
2:18:42
-0.155
716.9
0.0
0.0
0.0
-463.2
N
2011
16
2-2-11 5:39:00
-0.125
5:39:12
-0.114
578.5
0.0
0.0
0.0
-508.2
N
-286
17
2-2-11 8:24:00
-0.188
8:24:28
-0.167
775.3
0.0
0.0
0.0
-463.2
N
18
2-2-11 10:55:00
-0.190
10:55:38
-0.187
840.9
0.0
0.0
0.0
-448.6
N
19
2-9-11 13:01:00
-0.114
13:01:36
-0.105
598.7
0.0
17.3
0.0
-553.2
N
20
2-15-11 16:40:00
-0.216
16:40:02
-0.204
770.0
0.0
0.0
0.0
-377.7
N
21
2-16-11 9:25:00
-0.197
9:25:36
-0.177
569.9
0.0
0.0
0.0
-321.1
N
22
3-3-11 11:17:00
-0.094
11:17:34
-0.098
440.5
0.0
0.0
0.0
-449.9
N
23
3-14-11 6:09:00
-0.208
6:09:32
-0.205
970.7
0.0
0.0
0.0
-473.0
N
24
3-14-11 7:08:00
-0.127
7:08:12
-0.127
487.0
0.0
0.0
0.0
-383.2
N
25
3-16-11 20:45:00
-0.074
20:45:06
-0.089
397.6
0.0
0.0
0.0
-447.9
N
26
3-23-11 14:46:00
-0.063
14:46:46
-0.082
621.2
0.0
0.0
0.0
-753.3
N
27
28
3-24-11 13:59:00
3-25-11 16:13:00
-0.182
-0.172
13:59:06
16:13:26
-0.186
-0.187
498.3
553.4
0.0
0.0
0.0
66.7
0.0
0.0
-268.1
-260.9
N
N
-286
29
3-29-11 6:43:00
-0.099
6:43:06
-0.123
742.8
0.0
0.0
0.0
-604.3
N
-556.4
30
31
3-31-11 12:21:00
4-5-11 22:02:00
-0.112
-0.090
12:21:24
22:02:04
-0.112
-0.083
421.0
518.5
0.0
0.0
0.0
0.0
0.0
0.0
-375.7
-622.8
N
N
-463.2
32
4-20-11 13:40:00
-0.145
13:40:54
-0.162
785.5
0.0
0.0
0.0
-483.9
N
33
4-27-11 23:27:00
-0.133
23:27:04
-0.132
691.8
0.0
0.0
0.0
-523.2
N
34
5-11-11 14:04:00
-0.121
14:04:46
-0.126
726.0
0.0
0.0
0.0
-574.0
N
Y
Summary Statistics
-499.6
-33.8
001900
35
5-16-11 8:06:00
-0.101
8:06:36
-0.110
471.1
0.0
0.0
0.0
-427.2
N
36
5-19-11 14:08:00
-0.197
14:07:56
-0.223
995.1
0.0
0.0
0.0
-446.8
N
37
5-23-11 17:34:00
-0.092
17:34:38
-0.112
533.3
0.0
0.0
0.0
-475.9
N
38
5-29-11 22:03:00
-0.118
22:03:06
-0.133
762.3
0.0
0.0
0.0
-573.8
N
39
6-22-11 13:18:00
0.080
13:18:38
0.036
-258.6
0.0
0.0
0.0
-716.4
N
40
6-27-11 12:54:00
-0.149
12:54:00
-0.144
661.2
0.0
0.0
0.0
-459.1
N
41
7-18-11 9:13:00
-0.097
9:13:14
-0.096
386.3
0.0
0.0
0.0
-403.3
N
42
7-18-11 20:50:00
-0.119
20:50:38
-0.133
596.1
0.0
0.0
0.0
-447.5
N
001901
Information
Value "A"
Value "B"
Load
Load
35688.6
35448.9
34418.4
34067.3
29590.8
29332.9
Bias Calculation Form Year
31769.4
31711.5
Interconnection
30239.7
30095.9
Balancing Authority
39597.9
39157.5
Contact Name
40357.4
40313.0
Contact Phone #
48145.5
48119.3
Contact e-mail
28998.6
28706.9
Current Year's Actual Peak
40462.5
40291.4
Internal Generating Capacity
31488.8
31381.1
Next Year's Projected Peak
32641.7
32677.9
27749.0
27564.7
51871.7
51739.1
Current year
49441.4
49253.7
2011 Frequency Response Obligation (FRO)
52943.4
52893.3
52047.5
51826.7
52733.0
52504.3
50685.2
50470.3
31612.4
31207.5
31135.6
30972.9
31497.4
31383.3
26752.6
26452.9
29065.2
29072.8
33412.6
33249.3
38733.6
38264.0
Average Frequency Response (MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
35353.8
40151.5
35176.6
39958.5
31093.9
30933.8
2011 FRM - Median Frequency Response (MW/0.1Hz)
31970.4
30986.5
31779.5
30797.5
41620.0
41377.9
29943.1
29643.5
42265.9
42054.1
001902
30202.7
30090.9
42909.6
42474.0
50589.7
50457.9
44769.7
44439.2
44769.2
44674.8
56971.1
56795.9
45315.0
45257.8
57050.3
56857.6
001903
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493 80.660891
-0.07090523 -26.89761
-0.05190677 9.9554492
-0.0580477
3.367024
-0.07557242 36.334427
-0.0563805
0.488253
-0.0573329 2.7580369
-0.0517609 13.643417
-0.04999924 11.100746
-0.052 -19.90685
-0.05599976 12.325464
-0.05849838 0.7501918
-0.04850006 2.2300578
-0.04500008 9.4778593
-0.03750229
0.355309
-0.04750061 2.1707019
-0.05550003 29.382074
-0.047 4.6013813
-0.06 1.5935149
-0.06 52.370908
-0.051 33.947874
-0.1
100
N
Y
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
001904
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
N
Y
001905
Balancing Authority
NERC FRS FORM 1 20 to 40 second Value B
ERCO
Information
Event
Number
Date/Time
(Central Prevailing)
DelFreq
BA
Time
BA
DelFreq
Value "A" Information
MW Lost
Adjustment
Value "B" Information
MW Lost
Adjustment
SEFRD
(MW/0.1Hz)
Exclude for
data error *
Value "A"
Load
Value "B"
Load
1
12/6/2010 11:25
-0.101
11:25:50
-0.098
755.1
0.0
0.0
0.0
-774.5
N
35688.6
35410.9
2
12/9/2010 17:34
-0.074
17:34:12
-0.105
753.1
0.0
0.0
0.0
-716.0
N
34418.4
34096.6
3
12/11/2010 23:38
-0.166
23:38:26
-0.200
821.1
0.0
0.0
0.0
-410.9
N
29590.8
29391.6
4
12/16/2010 15:16
-0.074
15:15:58
-0.083
617.1
0.0
0.0
0.0
-747.3
N
2012
Bias Calculation Form Year
31769.4
31745.3
5
12/19/2010 2:39
-0.111
2:39:20
-0.133
720.3
0.0
0.0
0.0
-542.7
N
Texas
Interconnection
30239.7
30120.0
6
12/26/2010 8:23
-0.066
8:32:02
-0.047
494.4
0.0
0.0
0.0
-1048.4
N
ERCO
Balancing Authority
39597.9
39182.0
7
1/9/2011 18:52
-0.108
18:51:58
-0.107
575.2
0.0
0.0
0.0
-535.8
N
Ken McIntyre
Contact Name
40357.4
40236.2
8
1/11/2011 6:50
-0.091
6:50:14
-0.094
456.9
0.0
0.0
0.0
-485.3
N
512-248-3969
Contact Phone #
48145.5
48020.9
9
1/20/2011 0:01
-0.198
0:01:52
-0.196
786.1
0.0
0.0
0.0
-401.5
N
10
1/21/2011 3:46
-0.171
3:46:26
-0.168
650.0
0.0
0.0
0.0
-386.0
N
63453
11
1/23/2011 14:53
-0.149
14:53:18
-0.147
403.7
0.0
0.0
0.0
-275.2
N
12
1-28-11 5:21:00
-0.058
5:21:44
-0.062
311.5
0.0
0.0
0.0
-504.5
N
13
1/29/2011 22:29
-0.122
22:29:28
-0.121
646.2
0.0
203.7
0.0
14
2-1-11 22:28:00
-0.078
22:27:46
-0.080
459.3
0.0
0.0
0.0
15
2-2-11 2:18:00
-0.158
2:18:42
-0.156
716.9
0.0
0.0
16
2-2-11 5:39:00
-0.125
5:39:12
-0.120
578.5
0.0
17
2-2-11 8:24:00
-0.188
8:24:28
-0.185
775.3
18
2-2-11 10:55:00
-0.190
10:55:38
-0.188
19
2-9-11 13:01:00
-0.114
13:01:36
20
2-15-11 16:40:00
-0.216
21
2-16-11 9:25:00
-0.197
22
3-3-11 11:17:00
23
[email protected] Contact e-mail
28998.6
28787.2
Current Year's Actual Peak
40462.5
40282.2
75314
Internal Generating Capacity
31488.8
31481.5
63783
Next Year's Projected Peak
32641.7
32700.6
Y
27749.0
27623.1
-575.8
N
51871.7
51712.3
0.0
-458.1
N
2011
Current year
49441.4
49287.6
0.0
0.0
-482.9
N
-286
2011 Frequency Response Obligation (FRO)
52943.4
52850.2
0.0
0.0
0.0
-418.6
N
52047.5
51926.0
840.9
0.0
0.0
0.0
-448.3
N
-0.114
598.7
0.0
17.3
0.0
-508.4
N
16:40:02
-0.209
770.0
0.0
0.0
0.0
-368.4
N
9:25:36
-0.175
569.9
0.0
0.0
0.0
-325.9
N
-0.094
11:17:34
-0.095
440.5
0.0
0.0
0.0
-462.4
3-14-11 6:09:00
-0.208
6:09:32
-0.207
970.7
0.0
0.0
0.0
24
3-14-11 7:08:00
-0.127
7:08:12
-0.128
487.0
0.0
0.0
25
3-16-11 20:45:00
-0.074
20:45:06
-0.079
397.6
0.0
26
3-23-11 14:46:00
-0.063
14:46:46
-0.064
621.2
27
28
3-24-11 13:59:00
3-25-11 16:13:00
-0.182
-0.172
13:59:06
16:13:26
-0.174
-0.174
498.3
553.4
52733.0
52612.4
50685.2
50612.1
31612.4
31367.8
31135.6
31008.9
N
31497.4
31438.9
-469.6
N
26752.6
26582.4
0.0
-379.6
N
29065.2
29079.8
0.0
0.0
-506.2
N
33412.6
33251.9
0.0
0.0
0.0
-963.4
N
38733.6
38253.7
0.0
0.0
0.0
67.0
0.0
0.0
-285.6
-280.3
N
N
-286
-556.4
Summary Statistics
-523.2
Average Frequency Response (MW/0.1Hz)
-33.8
Regression Estimate of Frequency Response (MW/0.1Hz)
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
35353.8
40151.5
35226.5
39984.1
31093.9
31034.6
2011 FRM - Median Frequency Response (MW/0.1Hz)
31970.4
30986.5
31784.3
30850.3
29
3-29-11 6:43:00
-0.099
6:43:06
-0.101
742.8
0.0
0.0
0.0
-735.8
N
30
31
3-31-11 12:21:00
4-5-11 22:02:00
-0.112
-0.090
12:21:24
22:02:04
-0.113
-0.087
421.0
518.5
0.0
0.0
0.0
0.0
0.0
0.0
-372.2
-599.2
N
N
32
4-20-11 13:40:00
-0.145
13:40:54
-0.147
785.5
0.0
0.0
0.0
-533.8
N
41620.0
41449.8
33
4-27-11 23:27:00
-0.133
23:27:04
-0.132
691.8
0.0
0.0
0.0
-522.1
N
29943.1
29706.5
34
5-11-11 14:04:00
-0.121
14:04:46
-0.121
726.0
0.0
0.0
0.0
-598.5
N
42265.9
42114.1
35
5-16-11 8:06:00
-0.101
8:06:36
-0.103
471.1
0.0
0.0
0.0
-456.5
N
30202.7
30124.6
36
5-19-11 14:08:00
-0.197
14:07:56
-0.200
995.1
0.0
0.0
0.0
-498.0
N
42909.6
42598.7
37
5-23-11 17:34:00
-0.092
17:34:38
-0.097
533.3
0.0
0.0
0.0
-552.5
N
50589.7
50481.7
38
5-29-11 22:03:00
-0.118
22:03:06
-0.117
762.3
0.0
0.0
0.0
-649.0
N
44769.7
44483.3
39
6-22-11 13:18:00
0.080
13:18:38
0.033
-258.6
0.0
0.0
0.0
-792.0
N
44769.2
44477.2
40
6-27-11 12:54:00
-0.149
12:54:00
-0.133
661.2
0.0
0.0
0.0
-497.8
N
56971.1
56824.3
41
7-18-11 9:13:00
-0.097
9:13:14
-0.093
386.3
0.0
0.0
0.0
-416.6
N
45315.0
45285.6
42
7-18-11 20:50:00
-0.119
20:50:38
-0.128
596.1
0.0
0.0
0.0
-465.0
N
57050.3
56878.7
-497.8
001906
001907
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493
80.66089
-0.07090523 -26.89761
-0.05190677
9.955449
-0.0580477
3.367024
-0.07557242
36.33443
-0.0563805
0.488253
-0.0573329
2.758037
-0.0517609
13.64342
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
-0.05849838
0.750192
-0.04850006
2.230058
-0.04500008
9.477859
-0.03750229
0.355309
-0.04750061
2.170702
-0.05550003
29.38207
-0.047
4.601381
-0.06
1.593515
-0.06
52.37091
-0.051
33.94787
-0.1
100
N
Y
N
Y
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
001908
001909
Balancing Authority
Event
Number
Date/Time
(Central Prevailing)
NERC FRS FORM 1 18 to 52 second Value B
ERCO
BA
DelFreq
Value "A" Information
MW Lost
Adjustment
Value "B" Information
MW Lost
Adjustment
SEFRD
(MW/0.1Hz)
Exclude for
data error *
Information
Value "A"
Value "B"
Load
Load
DelFreq
BA
Time
1
12/6/2010 11:25
-0.101
11:25:50
-0.095
755.1
0.0
0.0
0.0
-793.0
N
35688.6
35459.3
2
12/9/2010 17:34
-0.074
17:34:12
-0.107
753.1
0.0
0.0
0.0
-702.7
N
34418.4
34109.5
3
12/11/2010 23:38
-0.166
23:38:26
-0.198
821.1
0.0
0.0
0.0
-414.7
N
29590.8
29398.7
4
12/16/2010 15:16
-0.074
15:15:58
-0.078
617.1
0.0
0.0
0.0
-787.6
N
2012
Bias Calculation Form Year
31769.4
31741.9
5
12/19/2010 2:39
-0.111
2:39:20
-0.132
720.3
0.0
0.0
0.0
-547.3
N
Texas
Interconnection
30239.7
30135.7
6
12/26/2010 8:23
-0.066
8:32:02
-0.041
494.4
0.0
0.0
0.0
-1216.6
N
ERCO
Balancing Authority
39597.9
39184.3
7
1/9/2011 18:52
-0.108
18:51:58
-0.108
575.2
0.0
0.0
0.0
-532.1
N
Ken McIntyre
Contact Name
40357.4
40275.8
8
1/11/2011 6:50
-0.091
6:50:14
-0.092
456.9
0.0
0.0
0.0
-498.4
N
512-248-3969
Contact Phone #
48145.5
9
1/20/2011 0:01
-0.198
0:01:52
-0.197
786.1
0.0
0.0
0.0
-399.0
N
10
1/21/2011 3:46
-0.171
3:46:26
-0.170
650.0
0.0
0.0
0.0
-381.3
N
63453
11
1/23/2011 14:53
-0.149
14:53:18
-0.148
403.7
0.0
0.0
0.0
-272.5
N
12
1-28-11 5:21:00
-0.058
5:21:44
-0.057
311.5
0.0
0.0
0.0
-549.8
N
13
1/29/2011 22:29
-0.122
22:29:28
-0.085
646.2
0.0
338.1
0.0
14
2-1-11 22:28:00
-0.078
22:27:46
-0.078
459.3
0.0
0.0
0.0
15
2-2-11 2:18:00
-0.158
2:18:42
-0.158
716.9
0.0
0.0
16
2-2-11 5:39:00
-0.125
5:39:12
-0.123
578.5
0.0
17
2-2-11 8:24:00
-0.188
8:24:28
-0.186
775.3
0.0
18
2-2-11 10:55:00
-0.190
10:55:38
-0.189
840.9
19
2-9-11 13:01:00
-0.114
13:01:36
-0.113
20
2-15-11 16:40:00
-0.216
16:40:02
21
2-16-11 9:25:00
-0.197
9:25:36
22
3-3-11 11:17:00
-0.094
23
3-14-11 6:09:00
24
3-14-11 7:08:00
25
[email protected] Contact e-mail
48065.0
28998.6
28794.4
Current Year's Actual Peak
40462.5
40291.0
75314
Internal Generating Capacity
31488.8
31481.8
63783
Next Year's Projected Peak
32641.7
32710.6
Y
27749.0
27719.2
-588.0
N
51871.7
51714.6
0.0
-452.8
N
2011
Current year
49441.4
49289.6
0.0
0.0
-469.4
N
-286
2011 Frequency Response Obligation (FRO)
52943.4
52861.2
0.0
0.0
-417.6
N
52047.5
51915.6
0.0
0.0
0.0
-444.6
N
598.7
0.0
11.5
0.0
-517.9
N
-0.215
770.0
0.0
0.0
0.0
-358.0
N
-0.175
569.9
0.0
0.0
0.0
-324.7
N
11:17:34
-0.094
440.5
0.0
0.0
0.0
-466.8
-0.208
6:09:32
-0.208
970.7
0.0
0.0
0.0
-0.127
7:08:12
-0.127
487.0
0.0
0.0
0.0
3-16-11 20:45:00
-0.074
20:45:06
-0.074
397.6
0.0
0.0
26
3-23-11 14:46:00
-0.063
14:46:46
-0.063
621.2
0.0
27
28
3-24-11 13:59:00
3-25-11 16:13:00
-0.182
-0.172
13:59:06
16:13:26
-0.178
-0.169
498.3
553.4
29
3-29-11 6:43:00
-0.099
6:43:06
-0.100
30
31
3-31-11 12:21:00
4-5-11 22:02:00
-0.112
-0.090
12:21:24
22:02:04
-0.112
-0.089
32
4-20-11 13:40:00
-0.145
13:40:54
33
4-27-11 23:27:00
-0.133
23:27:04
34
5-11-11 14:04:00
-0.121
14:04:46
35
5-16-11 8:06:00
-0.101
36
5-19-11 14:08:00
37
52733.0
52601.5
50685.2
50613.5
31612.4
31388.5
31135.6
31018.5
N
31497.4
31440.9
-467.0
N
26752.6
26588.3
-382.6
N
29065.2
29087.1
0.0
-536.8
N
33412.6
33257.7
0.0
0.0
-987.3
N
38733.6
38257.8
0.0
0.0
0.0
67.0
0.0
0.0
-280.5
-287.3
N
N
-286
35353.8
40151.5
35238.1
39989.9
742.8
0.0
0.0
0.0
-740.8
N
-556.4
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
31093.9
31031.3
421.0
518.5
0.0
0.0
0.0
0.0
0.0
0.0
-376.7
-584.2
N
N
-501.6
2011 FRM - Median Frequency Response (MW/0.1Hz)
31970.4
30986.5
31774.8
30845.4
-0.146
785.5
0.0
0.0
0.0
-538.8
N
41620.0
41460.3
-0.133
691.8
0.0
0.0
0.0
-521.9
N
29943.1
29700.8
-0.121
726.0
0.0
0.0
0.0
-598.9
N
42265.9
42111.6
8:06:36
-0.102
471.1
0.0
0.0
0.0
-462.3
N
30202.7
30134.4
-0.197
14:07:56
-0.198
995.1
0.0
0.0
0.0
-501.6
N
42909.6
42602.5
5-23-11 17:34:00
-0.092
17:34:38
-0.093
533.3
0.0
0.0
0.0
-572.4
N
50589.7
50486.4
38
5-29-11 22:03:00
-0.118
22:03:06
-0.119
762.3
0.0
0.0
0.0
-642.1
N
44769.7
44476.4
39
6-22-11 13:18:00
0.080
13:18:38
0.032
-258.6
0.0
0.0
0.0
-819.7
N
44769.2
44473.3
40
6-27-11 12:54:00
-0.149
12:54:00
-0.132
661.2
0.0
0.0
0.0
-501.7
N
56971.1
56831.1
41
7-18-11 9:13:00
-0.097
9:13:14
-0.094
386.3
0.0
0.0
0.0
-409.1
N
45315.0
45294.9
42
7-18-11 20:50:00
-0.119
20:50:38
-0.128
596.1
0.0
0.0
0.0
-466.0
N
57050.3
56882.9
Summary Statistics
-532.0
Average Frequency Response (MW/0.1Hz)
-33.8
Regression Estimate of Frequency Response (MW/0.1Hz)
001910
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493
80.66089
-0.07090523 -26.89761
-0.05190677
9.955449
-0.0580477
3.367024
-0.07557242
36.33443
-0.0563805
0.488253
-0.0573329
2.758037
-0.0517609
13.64342
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
-0.05849838
0.750192
-0.04850006
2.230058
-0.04500008
9.477859
-0.03750229
0.355309
-0.04750061
2.170702
-0.05550003
29.38207
-0.047
4.601381
-0.06
1.593515
-0.06
52.37091
-0.051
33.94787
-0.1
100
N
Y
N
Y
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
001911
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Date/Time
(Central Prevailing)
DelFreq
12/6/2010 11:25 -0.101
12/9/2010 17:34 -0.074
12/11/2010 23:38 -0.166
12/16/2010 15:16 -0.074
12/19/2010 2:39 -0.111
12/26/2010 8:23 -0.066
1/9/2011 18:52 -0.108
1/11/2011 6:50 -0.091
1/20/2011 0:01 -0.198
1/21/2011 3:46 -0.171
1/23/2011 14:53 -0.149
1-28-11 5:21:00 -0.058
1/29/2011 22:29 -0.122
2-1-11 22:28:00 -0.078
2-2-11 2:18:00 -0.158
2-2-11 5:39:00 -0.125
2-2-11 8:24:00 -0.188
2-2-11 10:55:00 -0.190
2-9-11 13:01:00 -0.114
2-15-11 16:40:00 -0.216
2-16-11 9:25:00 -0.197
3-3-11 11:17:00 -0.094
3-14-11 6:09:00 -0.208
3-14-11 7:08:00 -0.127
3-16-11 20:45:00 -0.074
3-23-11 14:46:00 -0.063
3-24-11 13:59:00 -0.182
3-25-11 16:13:00 -0.172
3-29-11 6:43:00 -0.099
3-31-11 12:21:00 -0.112
4-5-11 22:02:00 -0.090
4-20-11 13:40:00 -0.145
4-27-11 23:27:00 -0.133
5-11-11 14:04:00 -0.121
5-16-11 8:06:00 -0.101
5-19-11 14:08:00 -0.197
5-23-11 17:34:00 -0.092
5-29-11 22:03:00 -0.118
6-22-11 13:18:00
0.080
6-27-11 12:54:00 -0.149
7-18-11 9:13:00 -0.097
7-18-11 20:50:00 -0.119
Average Frequency Response (MW/0.1Hz)
2012 FRM - Median Frequency Response
(MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
2012 Frequency Response Obligation (FRO)
NERC FRS FORM 1
ERCO
BA
Time
11:25:50
17:34:12
23:38:26
15:15:58
2:39:20
8:32:02
18:51:58
6:50:14
0:01:52
3:46:26
14:53:18
5:21:44
22:29:28
22:27:46
2:18:42
5:39:12
8:24:28
10:55:38
13:01:36
16:40:02
9:25:36
11:17:34
6:09:32
7:08:12
20:45:06
14:46:46
13:59:06
16:13:26
6:43:06
12:21:24
22:02:04
13:40:54
23:27:04
14:04:46
8:06:36
14:07:56
17:34:38
22:03:06
13:18:38
12:54:00
9:13:14
20:50:38
BA
12 to 24 18 to 30 20 to 40 18 to 52 20 to 52
DelFreq SEFRD
SEFRD
SEFRD
SEFRD
SEFRD
-0.101
-736.4
-750.9
-775.5
-795.7
-800.4
-0.105
-682.1
-720.0
-716.6
-703.6
-703.9
-0.200
-445.3
-411.1
-411.6
-415.2
-414.6
-0.085
-757.2
-723.3
-750.8
-794.9
-796.4
-0.126
-653.2
-578.6
-545.3
-550.3
-543.4
-0.054
-833.0
-921.5
-1074.5
-1364.9
-1396.9
-0.111
-476.0
-518.9
-536.4
-532.8
-535.5
-0.095
-473.9
-482.1
-485.8
-499.6
-501.2
-0.198
-417.2
-398.3
-401.9
-399.4
-397.8
-0.164
-413.4
-396.2
-386.3
-381.8
-380.0
-0.145
-298.2
-279.1
-275.3
-272.7
-271.8
-0.065
-459.8
-479.0
-506.4
-564.4
-570.8
-0.124
-0.079
-564.6
-583.2
-576.1
-589.0
-590.5
-0.154
-463.3
-466.3
-458.4
-453.1
-452.8
-0.115
-508.5
-504.9
-484.2
-471.3
-468.7
-0.179
-464.7
-435.8
-419.7
-419.1
-414.4
-0.185
-448.9
-454.5
-448.4
-444.8
-443.9
-0.111
-560.3
-531.2
-514.4
-518.8
-516.8
-0.200
-379.1
-386.1
-369.7
-359.6
-358.2
-0.175
-321.2
-325.1
-326.0
-324.8
-325.0
-0.096
-450.3
-458.4
-462.9
-467.4
-468.1
-0.206
-473.2
-472.1
-469.7
-467.1
-467.6
-0.128
-383.2
-380.7
-379.7
-382.9
-382.7
-0.079
-455.9
-503.0
-507.2
-542.1
-543.8
-0.065
-807.2
-956.6
-964.2
-990.4
-996.3
-0.176
-268.8
-284.0
-285.7
-280.8
-281.7
-0.180
-261.0
-270.6
-280.8
-288.2
-289.6
-0.101
-630.9
-741.8
-737.6
-743.0
-748.6
-0.111
-375.8
-379.6
-372.4
-378.9
-379.0
-0.084
-628.6
-616.9
-599.8
-587.1
-580.0
-0.149
-486.6
-529.8
-534.3
-540.2
-544.2
-0.131
-524.9
-526.7
-522.4
-522.2
-520.8
-0.119
-577.2
-612.6
-599.1
-599.3
-599.2
-0.107
-427.7
-441.7
-457.1
-463.1
-465.0
-0.207
-449.0
-480.6
-498.7
-502.5
-505.2
-0.103
-476.7
-522.1
-555.2
-578.0
-583.9
-0.123
-574.8
-624.6
-651.2
-643.9
-647.9
0.034
-721.6
-762.0
-795.0
-825.6
-831.2
-0.137
-459.8
-484.4
-498.1
-502.3
-504.8
-0.095
-403.4
-405.8
-417.1
-409.7
-410.3
-0.129
-448.2
-464.0
-465.1
-466.1
-467.0
-499.56
-517.56
-523.18
-532.02
-533.84
-463.19
-33.77
-286
-481.99
-33.77
-286
-497.76
-33.77
-286
-501.63
-33.77
-286
-504.36
-33.77
-286
12 to 24 P.U. Performance
Exclude for
data error *
N
N
N
N
N
N
N
N
N
N
N
N
Y
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
18 to 30 P.U. Performance
Initial
Initial
Sustained
Initial
Initial
Sustained
Adjusted
Unadjusted
Adjusted
Unadjusted
2.57
2.57 No Evaluation
2.62
2.62 No Evaluation
2.36
2.36 No Evaluation
2.51
2.51 No Evaluation
1.55
1.55 No Evaluation
1.43
1.43 No Evaluation
2.64
2.64 No Evaluation
2.53
2.53 No Evaluation
2.25
2.25 No Evaluation
2.01
2.01 No Evaluation
2.90
2.90 No Evaluation
3.20
3.20 No Evaluation
1.65
1.65 No Evaluation
1.81
1.81 No Evaluation
1.66
1.66 No Evaluation
1.69
1.69 No Evaluation
1.45
1.45 No Evaluation
1.39
1.39 No Evaluation
1.44
1.44 No Evaluation
1.38
1.38 No Evaluation
1.04
1.04 No Evaluation
0.98
0.98 No Evaluation
1.61
1.61 No Evaluation
1.67
1.67 No Evaluation
1.51
1.51 No Evaluation
1.50
1.50 No Evaluation
1.97
1.97 No Evaluation
2.04
2.04 No Evaluation
1.62
1.62 No Evaluation
1.63
1.63 No Evaluation
1.78
1.78 No Evaluation
1.76
1.76 No Evaluation
1.62
1.62 No Evaluation
1.51
1.51 No Evaluation
1.57
1.57 No Evaluation
1.59
1.59 No Evaluation
1.93
1.93 No Evaluation
1.84
1.84 No Evaluation
1.32
1.32 No Evaluation
1.35
1.35 No Evaluation
1.12
1.12 No Evaluation
1.14
1.14 No Evaluation
1.57
1.57 No Evaluation
1.60
1.60 No Evaluation
1.65
1.65 No Evaluation
1.65
1.65 No Evaluation
1.34
1.34 No Evaluation
1.33
1.33 No Evaluation
1.57
1.57 No Evaluation
1.76
1.76 No Evaluation
2.63
2.63 No Evaluation
3.34
3.34 No Evaluation
0.94
0.94 No Evaluation
0.99
0.99 No Evaluation
0.91
0.91 No Evaluation
0.95
0.95 No Evaluation
2.11
2.11 No Evaluation
2.58
2.58 No Evaluation
1.31
1.31 No Evaluation
1.33
1.33 No Evaluation
2.18
2.18 No Evaluation
2.15
2.15 No Evaluation
1.69
1.69 No Evaluation
1.85
1.85 No Evaluation
1.83
1.83 No Evaluation
1.84
1.84 No Evaluation
2.01
2.01 No Evaluation
2.14
2.14 No Evaluation
1.49
1.49 No Evaluation
1.54
1.54 No Evaluation
1.56
1.56 No Evaluation
1.68
1.68 No Evaluation
1.66
1.66 No Evaluation
1.82
1.82 No Evaluation
2.01
2.01 No Evaluation
2.17
2.17 No Evaluation
2.50
2.50 No Evaluation
2.66
2.66 No Evaluation
1.61
1.61 No Evaluation
1.69
1.69 No Evaluation
1.41
1.41 No Evaluation
1.42
1.42 No Evaluation
1.56
1.56 No Evaluation
1.62
1.62 No Evaluation
1.74
1.74
1.80
1.80
20 to 40 P
001912
20 to 40 P.U. Performance
18 to 52 P.U. Performance
Initial
Initial
Sustained
Initial
Initial
Sustained
Adjusted
Unadjusted
Adjusted
Unadjusted
2.71
2.71 No Evaluation
2.77
2.77 No Evaluation
2.50
2.50 No Evaluation
2.46
2.46 No Evaluation
1.44
1.44 No Evaluation
1.45
1.45 No Evaluation
2.61
2.61 No Evaluation
2.75
2.75 No Evaluation
1.90
1.90 No Evaluation
1.91
1.91 No Evaluation
3.67
3.67 No Evaluation
4.25
4.25 No Evaluation
1.87
1.87 No Evaluation
1.86
1.86 No Evaluation
1.70
1.70 No Evaluation
1.74
1.74 No Evaluation
1.40
1.40 No Evaluation
1.39
1.39 No Evaluation
1.35
1.35 No Evaluation
1.33
1.33 No Evaluation
0.96
0.96 No Evaluation
0.95
0.95 No Evaluation
1.76
1.76 No Evaluation
1.92
1.92 No Evaluation
1.28
1.28 No Evaluation
1.27
1.27 No Evaluation
2.01
2.01 No Evaluation
2.06
2.06 No Evaluation
1.60
1.60 No Evaluation
1.58
1.58 No Evaluation
1.69
1.69 No Evaluation
1.64
1.64 No Evaluation
1.46
1.46 No Evaluation
1.46
1.46 No Evaluation
1.57
1.57 No Evaluation
1.55
1.55 No Evaluation
1.78
1.78 No Evaluation
1.81
1.81 No Evaluation
1.29
1.29 No Evaluation
1.25
1.25 No Evaluation
1.14
1.14 No Evaluation
1.14
1.14 No Evaluation
1.62
1.62 No Evaluation
1.63
1.63 No Evaluation
1.64
1.64 No Evaluation
1.63
1.63 No Evaluation
1.33
1.33 No Evaluation
1.34
1.34 No Evaluation
1.77
1.77 No Evaluation
1.88
1.88 No Evaluation
3.37
3.37 No Evaluation
3.45
3.45 No Evaluation
1.00
1.00 No Evaluation
0.98
0.98 No Evaluation
0.98
0.98 No Evaluation
1.00
1.00 No Evaluation
2.57
2.57 No Evaluation
2.59
2.59 No Evaluation
1.30
1.30 No Evaluation
1.32
1.32 No Evaluation
2.10
2.10 No Evaluation
2.04
2.04 No Evaluation
1.87
1.87 No Evaluation
1.88
1.88 No Evaluation
1.83
1.83 No Evaluation
1.82
1.82 No Evaluation
2.09
2.09 No Evaluation
2.09
2.09 No Evaluation
1.60
1.60 No Evaluation
1.62
1.62 No Evaluation
1.74
1.74 No Evaluation
1.75
1.75 No Evaluation
1.93
1.93 No Evaluation
2.00
2.00 No Evaluation
2.27
2.27 No Evaluation
2.25
2.25 No Evaluation
2.77
2.77 No Evaluation
2.87
2.87 No Evaluation
1.74
1.74 No Evaluation
1.75
1.75 No Evaluation
1.46
1.46 No Evaluation
1.43
1.43 No Evaluation
1.63
1.63 No Evaluation
1.63
1.63 No Evaluation
1.82
1.82
1.85
1.85
20 to 52 P.U. Performance
Initial
Initial
Sustained
Adjusted
Unadjusted
2.79
2.79 No Evaluation
2.46
2.46 No Evaluation
1.45
1.45 No Evaluation
2.76
2.76 No Evaluation
1.89
1.89 No Evaluation
4.38
4.38 No Evaluation
1.87
1.87 No Evaluation
1.75
1.75 No Evaluation
1.39
1.39 No Evaluation
1.33
1.33 No Evaluation
0.95
0.95 No Evaluation
1.95
1.95 No Evaluation
1.25
1.25 No Evaluation
2.06
2.06 No Evaluation
1.58
1.58 No Evaluation
1.63
1.63 No Evaluation
1.45
1.45 No Evaluation
1.55
1.55 No Evaluation
1.81
1.81 No Evaluation
1.25
1.25 No Evaluation
1.14
1.14 No Evaluation
1.63
1.63 No Evaluation
1.63
1.63 No Evaluation
1.34
1.34 No Evaluation
1.88
1.88 No Evaluation
3.47
3.47 No Evaluation
0.98
0.98 No Evaluation
1.01
1.01 No Evaluation
2.61
2.61 No Evaluation
1.32
1.32 No Evaluation
2.02
2.02 No Evaluation
1.90
1.90 No Evaluation
1.82
1.82 No Evaluation
2.09
2.09 No Evaluation
1.62
1.62 No Evaluation
1.76
1.76 No Evaluation
2.03
2.03 No Evaluation
2.26
2.26 No Evaluation
2.89
2.89 No Evaluation
1.76
1.76 No Evaluation
1.43
1.43 No Evaluation
1.63
1.63 No Evaluation
1.85
1.85
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
001913
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
average
FBS* for
month
-10.0
-7.0
-12.0
-8.0
-27.0
-8.7
-8.0
-8.0
-8.2
-8.0
-8.0
-12.0
-10.4
Average Annual Bias
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001
001914
Interconnection Performance
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing)
1
12/6/2010 11:25
2
12/9/2010 17:34
3
12/11/2010 23:38
4
12/16/2010 15:16
5
12/19/2010 2:39
6
12/26/2010 8:23
7
1/9/2011 18:52
8
1/11/2011 6:50
9
1/20/2011 0:01
10
1/21/2011 3:46
11
1/23/2011 14:53
12
1/28/2011 5:21
13
1/29/2011 22:29
14
2/1/2011 22:28
15
2/2/2011 2:18
16
2/2/2011 5:39
17
2/2/2011 8:24
18
2/2/2011 10:55
19
2/9/2011 13:01
20
2/15/2011 16:40
21
2/16/2011 9:25
22
3/3/2011 11:17
23
3/14/2011 6:09
24
3/14/2011 7:08
25
3/16/2011 20:45
26
3/23/2011 14:46
27
3/24/2011 13:59
28
3/25/2011 16:13
29
3/29/2011 6:43
30
3/31/2011 12:21
31
4/5/2011 22:02
32
4/20/2011 13:40
33
4/27/2011 23:27
34
5/11/2011 14:04
35
5/16/2011 8:06
36
5/19/2011 14:08
37
5/23/2011 17:34
38
5/29/2011 22:03
39
6/22/2011 13:18
40
6/27/2011 12:54
41
7/18/2011 9:13
42
7/18/2011 20:50
DelFreq
-0.101
-0.074
-0.166
-0.074
-0.111
-0.066
-0.108
-0.091
-0.198
-0.171
-0.149
-0.058
-0.122
-0.078
-0.158
-0.125
-0.188
-0.19
-0.114
-0.216
-0.197
-0.094
-0.208
-0.127
-0.074
-0.063
-0.182
-0.172
-0.099
-0.112
-0.09
-0.145
-0.133
-0.121
-0.101
-0.197
-0.092
-0.118
0.08
-0.149
-0.097
-0.119
Monday, December 06, 2010
Thursday, December 09, 2010
Saturday, December 11, 2010
Thursday, December 16, 2010
Sunday, December 19, 2010
Sunday, December 26, 2010
Sunday, January 09, 2011
Tuesday, January 11, 2011
Thursday, January 20, 2011
Friday, January 21, 2011
Sunday, January 23, 2011
Friday, January 28, 2011
Saturday, January 29, 2011
Tuesday, February 01, 2011
Wednesday, February 02, 2011
Wednesday, February 02, 2011
Wednesday, February 02, 2011
Wednesday, February 02, 2011
Wednesday, February 09, 2011
Tuesday, February 15, 2011
Wednesday, February 16, 2011
Thursday, March 03, 2011
Monday, March 14, 2011
Monday, March 14, 2011
Wednesday, March 16, 2011
Wednesday, March 23, 2011
Thursday, March 24, 2011
Friday, March 25, 2011
Tuesday, March 29, 2011
Thursday, March 31, 2011
Tuesday, April 05, 2011
Wednesday, April 20, 2011
Wednesday, April 27, 2011
Wednesday, May 11, 2011
Monday, May 16, 2011
Thursday, May 19, 2011
Monday, May 23, 2011
Sunday, May 29, 2011
Wednesday, June 22, 2011
Monday, June 27, 2011
Monday, July 18, 2011
Monday, July 18, 2011
A Point
Time
FPointA
Hz
11:25:50
17:34:12
23:38:26
15:15:58
2:39:20
8:32:02
18:51:58
6:50:14
0:01:52
3:46:26
14:53:18
5:21:44
22:29:28
22:27:46
2:18:42
5:39:12
8:24:28
10:55:38
13:01:36
16:40:02
9:25:36
11:17:34
6:09:32
7:08:12
20:45:06
14:46:46
13:59:06
16:13:26
6:43:06
12:21:24
22:02:04
13:40:54
23:27:04
14:04:46
8:06:36
14:07:56
17:34:38
22:03:06
13:18:38
12:54:00
9:13:14
20:50:38
59.9970
59.9930
60.0090
59.9710
59.9930
59.9340
59.9880
59.9780
60.0170
60.0440
59.9780
59.9660
60.0010
59.9690
60.0150
59.9210
60.0360
60.0090
60.0250
60.0300
59.9800
59.9710
60.0280
60.0120
59.9850
59.9950
59.9770
59.9960
59.9620
59.9870
59.9120
60.0220
60.0030
60.0175
60.0020
59.9758
59.9351
59.9060
60.0130
59.9770
59.9570
60.0070
A Value
Hz
59.9965
59.9980
60.0061
59.9731
59.9870
59.9443
59.9880
59.9805
60.0062
60.0447
59.9999
59.9734
59.9997
59.9695
60.0135
59.9233
60.0354
60.0077
60.0224
60.0341
59.9919
59.9666
60.0315
60.0054
59.9876
59.9897
59.9981
60.0142
59.9635
59.9865
59.9182
60.0246
60.0075
60.0087
59.9986
59.9756
59.9352
59.9060
60.0336
59.9738
59.9576
60.0084
t(0) Time
11:25:52
17:34:14
23:38:28
15:16:00
2:39:22
8:32:04
18:52:00
6:50:16
0:01:54
3:46:28
14:53:20
5:21:46
22:29:30
22:27:48
2:18:44
5:39:14
8:24:30
10:55:40
13:01:38
16:40:04
9:25:38
11:17:36
6:09:34
7:08:14
20:45:08
14:46:48
13:59:08
16:13:28
6:43:08
12:21:26
22:02:06
13:40:56
23:27:06
14:04:48
8:06:38
14:07:58
17:34:40
22:03:08
13:18:40
12:54:02
9:13:16
20:50:40
C Value
Hz
59.8100
59.8040
59.7470
59.8110
59.8060
59.8260
59.8410
59.8700
59.7610
59.8870
59.8600
59.8760
59.8390
59.8750
59.8410
59.8060
59.8530
59.8020
59.9100
59.7570
59.8000
59.8390
59.7900
59.8410
59.8660
59.7060
59.7990
59.8130
59.7460
59.8600
59.7170
59.8240
59.7910
59.8533
59.8701
59.7176
59.8174
59.7480
60.0810
59.8200
59.8590
59.8660
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec
12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
59.8939
-736.38
59.8959
-750.94
59.9019
-775.46
59.9013
-795.67
59.9019
59.8866
-682.10
59.8933
-720.02
59.8909
-716.56
59.8908
-703.56
59.8909
59.8210
-445.26
59.8059
-411.13
59.8078
-411.60
59.8081
-415.20
59.8078
59.8914
-757.17
59.8877
-723.27
59.8949
-750.84
59.8948
-794.94
59.8949
59.8750
-653.15
59.8614
-578.56
59.8540
-545.29
59.8554
-550.26
59.8540
59.8846
-832.97
59.8903
-921.48
59.9048
-1074.55
59.9036
-1364.88
59.9048
59.8663
-475.95
59.8770
-518.87
59.8805
-536.43
59.8799
-532.79
59.8805
59.8840
-473.93
59.8857
-482.14
59.8891
-485.78
59.8888
-499.63
59.8891
59.8171
-417.20
59.8086
-398.27
59.8085
-401.89
59.8092
-399.42
59.8085
59.8873
-413.44
59.8806
-396.16
59.8735
-386.30
59.8743
-381.81
59.8735
59.8640
-298.19
59.8551
-279.13
59.8512
-275.33
59.8517
-272.72
59.8512
59.9056
-459.82
59.9083
-478.96
59.9174
-506.40
59.9167
-564.36
59.9174
59.8767
-239.96
59.8753
-237.09
59.9174
-244.00
59.9152
1547.87
59.9174
59.8880
-564.61
59.8907
-583.21
59.8916
-576.14
59.8914
-588.96
59.8916
59.8587
-463.28
59.8597
-466.26
59.8551
-458.39
59.8552
-453.12
59.8551
59.8094
-508.54
59.8086
-504.87
59.7994
-484.21
59.8000
-471.29
59.7994
59.8680
-464.75
59.8563
-435.76
59.8479
-419.66
59.8497
-419.13
59.8479
59.8203
-448.89
59.8227
-454.49
59.8182
-448.43
59.8186
-444.78
59.8182
59.9173
-560.29
59.9117
-531.22
59.9086
-514.37
59.9090
-518.79
59.9086
59.8303
-379.14
59.8344
-386.14
59.8182
-369.70
59.8191
-359.56
59.8182
59.8144
-321.17
59.8166
-325.14
59.8165
-325.96
59.8164
-324.83
59.8165
59.8687
-450.25
59.8704
-458.40
59.8724
-462.92
59.8723
-467.40
59.8724
59.8263
-473.15
59.8259
-472.10
59.8239
-469.73
59.8237
-467.13
59.8239
59.8783
-383.22
59.8774
-380.67
59.8781
-379.65
59.8781
-382.86
59.8781
59.8989
-455.89
59.9086
-503.02
59.9138
-507.23
59.9136
-542.06
59.9138
59.9073
-807.19
59.9247
-956.57
59.9272
-964.25
59.9268
-990.42
59.9272
59.8123
-268.77
59.8224
-283.96
59.8211
-285.69
59.8205
-280.78
59.8211
59.8277
-261.02
59.8344
-270.59
59.8458
-280.76
59.8449
-288.20
59.8458
59.8406
-630.95
59.8629
-741.81
59.8641
-737.61
59.8632
-743.02
59.8641
59.8744
-375.78
59.8756
-379.60
59.8747
-372.38
59.8747
-378.88
59.8747
59.8350
-628.65
59.8339
-616.94
59.8286
-599.76
59.8295
-587.13
59.8286
59.8623
-486.59
59.8759
-529.84
59.8801
-534.28
59.8788
-540.17
59.8801
59.8753
-524.88
59.8760
-526.70
59.8746
-522.43
59.8749
-522.21
59.8746
59.8822
-577.22
59.8901
-612.63
59.8874
-599.12
59.8875
-599.33
59.8874
59.8883
-427.67
59.8920
-441.67
59.8972
-457.14
59.8967
-463.10
59.8972
59.7529
-449.01
59.7684
-480.64
59.7784
-498.65
59.7772
-502.47
59.7784
59.8231
-476.74
59.8325
-522.12
59.8431
-555.20
59.8420
-577.96
59.8431
59.7731
-574.81
59.7834
-624.61
59.7881
-651.17
59.7873
-643.95
59.7881
60.0697
-721.62
60.0676
-761.98
60.0649
-794.96
60.0652
-825.60
60.0649
59.8297
-459.82
59.8371
-484.44
59.8426
-498.14
59.8419
-502.30
59.8426
59.8619
-403.41
59.8624
-405.78
59.8634
-417.13
59.8632
-409.72
59.8634
59.8751
-448.21
59.8799
-463.99
59.8807
-465.09
59.8804
-466.09
59.8807
001915
Value A Data
FR B
Net
20 to 52 sec
Actual
Average Frequency Interchange
MW
Hz
MW
-800.37
59.9965
755.11
-703.93
59.9980
753.07
-414.61
60.0061
821.10
-796.39
59.9731
617.09
-543.40
59.9870
720.33
-1396.89
59.9443
494.44
-535.46
59.9880
575.22
-501.17
59.9805
456.86
-397.82
60.0062
786.05
-380.03
60.0447
650.00
-271.79
59.9999
403.71
-570.77
59.9734
311.47
1653.06
59.9997
646.21
-590.45
59.9695
459.33
-452.82
60.0135
716.93
-468.69
59.9233
578.49
-414.43
60.0354
775.26
-443.88
60.0077
840.89
-516.81
60.0224
598.69
-358.19
60.0341
769.98
-324.98
59.9919
569.86
-468.08
59.9666
440.45
-467.61
60.0315
970.67
-382.72
60.0054
486.97
-543.82
59.9876
397.56
-996.30
59.9897
621.17
-281.72
59.9981
498.31
-289.62
60.0142
553.38
-748.57
59.9635
742.82
-378.95
59.9865
421.05
-580.03
59.9182
518.48
-544.21
60.0246
785.54
-520.76
60.0075
691.80
-599.24
60.0087
726.02
-464.95
59.9986
471.09
-505.24
59.9756
995.08
-583.92
59.9352
533.33
-647.86
59.9060
762.32
-831.17
60.0336
-258.56
-504.79
59.9738
661.23
-410.31
59.9576
386.25
-467.01
60.0084
596.15
BA Performance
JOU
NonTransferred
Contingent
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Imp(-) Exp (+)
Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
Value B
BA
Load
MW
35689
34418
29591
31769
30240
39598
40357
48146
28999
40462
31489
32642
27749
51872
49441
52943
52048
52733
50685
31612
31136
31497
26753
29065
33413
38734
35354
40152
31094
31970
30986
41620
29943
42266
30203
42910
50590
44770
44769
56971
45315
57050
Bias
Setting
EPFR
MW
22.86
13.06
-40.00
175.50
84.89
364.04
78.37
127.33
-40.81
-292.21
0.81
173.86
1.63
199.16
-88.15
501.18
-231.00
-50.60
-146.11
-222.84
53.06
217.94
-205.69
-35.10
80.81
66.93
12.24
-93.05
238.34
88.15
533.83
-160.81
-48.97
-56.72
8.97
159.27
423.29
613.83
-219.57
171.41
276.71
-54.69
Frequency
Hz
59.8939
59.8866
59.8210
59.8914
59.8750
59.8846
59.8663
59.8840
59.8171
59.8873
59.8640
59.9056
59.8767
59.8880
59.8587
59.8094
59.8680
59.8203
59.9173
59.8303
59.8144
59.8687
59.8263
59.8783
59.8989
59.9073
59.8123
59.8277
59.8406
59.8744
59.8350
59.8623
59.8753
59.8822
59.8883
59.7529
59.8231
59.7731
60.0697
59.8297
59.8619
59.8751
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
113.91
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
17.31
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
66.73
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Performance
Adjusted
P.U.
2.57
2.36
1.55
2.64
2.25
2.90
1.65
1.66
1.45
1.44
1.04
1.61
1.51
1.97
1.62
1.78
1.62
1.57
1.93
1.32
1.12
1.57
1.65
1.34
1.57
2.63
0.94
0.91
2.11
1.31
2.18
1.69
1.83
2.01
1.49
1.56
1.66
2.01
2.50
1.61
1.41
1.56
001916
Value B
Initial
Performance
Unadjusted
P.U.
2.57
2.36
1.55
2.64
2.25
2.90
1.65
1.66
1.45
1.44
1.04
1.61
1.51
1.97
1.62
1.78
1.62
1.57
1.93
1.32
1.12
1.57
1.65
1.34
1.57
2.63
0.94
0.91
2.11
1.31
2.18
1.69
1.83
2.01
1.49
1.56
1.66
2.01
2.50
1.61
1.41
1.56
Sustained
Performance
P.U.
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
35449
34067
29333
31711
30096
39157
40313
48119
28707
40291
31381
32678
27565
51739
49254
52893
51827
52504
50470
31208
30973
31383
26453
29073
33249
38264
35177
39959
30934
31779
30798
41378
29644
42054
30091
42474
50458
44439
44675
56796
45258
56858
18 to 30 second Average Period Evaluation
Bias
Net
Setting
Actual
EPFR
Frequency Interchange
MW
Hz
MW
693.12
59.8959
0.00
740.69
59.8933
0.00
1168.87
59.8059
0.00
708.97
59.8877
0.00
816.25
59.8614
0.00
753.75
59.8903
0.00
873.16
59.8770
0.00
757.48
59.8857
0.00
1194.06
59.8086
0.00
736.03
59.8806
0.00
888.08
59.8551
0.00
616.62
59.9083
0.00
805.05
59.8753
113.82
731.36
59.8907
0.00
922.59
59.8597
0.00
1244.43
59.8086
0.00
861.96
59.8563
0.00
1173.53
59.8227
0.00
540.13
59.9117
17.27
1108.23
59.8344
0.00
1211.78
59.8166
0.00
857.29
59.8704
0.00
1134.35
59.8259
0.00
794.79
59.8774
0.00
660.46
59.9086
0.00
605.43
59.9247
0.00
1225.77
59.8224
0.00
1125.02
59.8344
66.87
1041.07
59.8629
0.00
819.98
59.8756
0.00
1077.44
59.8339
0.00
899.27
59.8759
0.00
814.39
59.8760
0.00
769.19
59.8901
0.00
729.10
59.8920
0.00
1613.70
59.7684
0.00
1155.02
59.8325
0.00
1481.38
59.7834
0.00
-455.24
60.0676
0.00
1111.96
59.8371
0.00
902.08
59.8624
0.00
815.32
59.8799
0.00
JOU
NonTransferred
Contingent
Dynamic
Conforming Pumped Ramping
Frequency
BA
Schedules
Load
Hydro
Units
Response
Lost Generation
Imp(-) Exp (+) Load (-)Load (-) Gen (+)Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Value B
Initial
Performance
Adjusted
P.U.
2.62
2.51
1.43
2.53
2.01
3.20
1.81
1.69
1.39
1.38
0.98
1.67
1.50
2.04
1.63
1.76
1.51
1.59
1.84
1.35
1.14
1.60
1.65
1.33
1.76
3.34
0.99
0.95
2.58
1.33
2.15
1.85
1.84
2.14
1.54
1.68
1.82
2.17
2.66
1.69
1.42
1.62
Initial
Performance
Unadjusted
P.U.
2.62
2.51
1.43
2.53
2.01
3.20
1.81
1.69
1.39
1.38
0.98
1.67
1.50
2.04
1.63
1.76
1.51
1.59
1.84
1.35
1.14
1.60
1.65
1.33
1.76
3.34
0.99
0.95
2.58
1.33
2.15
1.85
1.84
2.14
1.54
1.68
1.82
2.17
2.66
1.69
1.42
1.62
Sustained
Performance
P.U.
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
BA
Bias
Setting
MW
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
35340
34085
29363
31747
30116
39176
40208
48008
28784
40274
31467
32693
27600
51717
49280
52827
51915
52603
50564
31374
30997
31421
26534
29072
33243
38266
35215
39985
31019
31785
30837
41434
29685
42103
30113
42561
50478
44480
44560
56806
45274
56872
20 to 40 second Average Per
Bias
Net
Setting
Actual
EPFR
Frequency Interchange
MW
Hz
MW
680.06
59.8990
0.00
696.85
59.8928
0.00
1267.75
59.8063
0.00
733.23
59.8905
0.00
904.87
59.8543
0.00
716.44
59.8971
0.00
803.19
59.8806
0.00
746.29
59.8864
0.00
1250.03
59.8105
0.00
779.87
59.8764
0.00
945.92
59.8532
0.00
598.90
59.9116
0.00
814.38
59.8786
203.71
713.64
59.8897
0.00
916.06
59.8570
0.00
1250.03
59.8035
0.00
938.45
59.8502
0.00
1157.67
59.8202
0.00
576.51
59.9080
17.25
1081.18
59.8251
0.00
1197.79
59.8170
0.00
846.10
59.8714
0.00
1137.15
59.8248
0.00
800.39
59.8771
0.00
597.02
59.9091
0.00
491.62
59.9253
0.00
1159.54
59.8236
0.00
1081.18
59.8407
67.01
895.55
59.8625
0.00
812.52
59.8734
0.00
1084.91
59.8317
0.00
810.65
59.8775
0.00
809.72
59.8750
0.00
717.38
59.8874
0.00
705.56
59.8954
0.00
1512.44
59.7758
0.00
1093.50
59.8387
0.00
1414.22
59.7885
0.00
-441.25
60.0663
0.00
1063.46
59.8409
0.00
898.35
59.8649
0.00
784.53
59.8802
0.00
001917
20 to 40 second Average Period Evaluation
JOU
NonDynamic
Conforming
Pumped
Schedules
Load
Hydro
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
MW
MW
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Value B
Ramping
Units
Gen (+)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Performance
Adjusted
P.U.
2.71
2.50
1.44
2.61
1.90
3.67
1.87
1.70
1.40
1.35
0.96
1.76
1.28
2.01
1.60
1.69
1.46
1.57
1.78
1.29
1.14
1.62
1.64
1.33
1.77
3.37
1.00
0.98
2.57
1.30
2.10
1.87
1.83
2.09
1.60
1.74
1.93
2.27
2.77
1.74
1.46
1.63
Initial
Performance
Unadjusted
P.U.
2.71
2.50
1.44
2.61
1.90
3.67
1.87
1.70
1.40
1.35
0.96
1.76
1.28
2.01
1.60
1.69
1.46
1.57
1.78
1.29
1.14
1.62
1.64
1.33
1.77
3.37
1.00
0.98
2.57
1.30
2.10
1.87
1.83
2.09
1.60
1.74
1.93
2.27
2.77
1.74
1.46
1.63
Sustained
Performance
P.U.
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
BA
Bias
Setting
MW
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
35411
34097
29392
31745
30120
39182
40236
48021
28787
40282
31481
32701
27623
51712
49288
52850
51926
52612
50612
31368
31009
31439
26582
29080
33252
38254
35226
39984
31035
31784
30850
41450
29706
42114
30125
42599
50482
44483
44477
56824
45286
56879
18 to 52 second Average Period Evaluation
JOU
NonBias
Net
Dynamic
Conforming
Pumped
Setting
Actual
Schedules
Load
Hydro
EPFR
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
MW
Hz
MW
MW
MW
MW
659.53
59.9013
0.00
0.00
0.00
0.00
699.90
59.8908
0.00
0.00
0.00
0.00
1265.04
59.8081
0.00
0.00
0.00
0.00
714.74
59.8948
0.00
0.00
0.00
0.00
951.59
59.8554
0.00
0.00
0.00
0.00
672.00
59.9036
0.00
0.00
0.00
0.00
779.44
59.8799
0.00
0.00
0.00
0.00
742.04
59.8888
0.00
0.00
0.00
0.00
1237.73
59.8092
0.00
0.00
0.00
0.00
807.35
59.8743
0.00
0.00
0.00
0.00
958.72
59.8517
0.00
0.00
0.00
0.00
577.01
59.9167
0.00
0.00
0.00
0.00
792.50
59.9152
338.14
0.00
0.00
0.00
720.08
59.8914
0.00
0.00
0.00
0.00
933.79
59.8552
0.00
0.00
0.00
0.00
1283.44
59.8000
0.00
0.00
0.00
0.00
978.31
59.8497
0.00
0.00
0.00
0.00
1174.21
59.8186
0.00
0.00
0.00
0.00
600.76
59.9090
11.51
0.00
0.00
0.00
1142.16
59.8191
0.00
0.00
0.00
0.00
1194.99
59.8164
0.00
0.00
0.00
0.00
840.00
59.8723
0.00
0.00
0.00
0.00
1143.94
59.8237
0.00
0.00
0.00
0.00
802.60
59.8781
0.00
0.00
0.00
0.00
593.63
59.9136
0.00
0.00
0.00
0.00
487.97
59.9268
0.00
0.00
0.00
0.00
1151.65
59.8205
0.00
0.00
0.00
0.00
1040.05
59.8449
67.03
0.00
0.00
0.00
897.58
59.8632
0.00
0.00
0.00
0.00
826.94
59.8747
0.00
0.00
0.00
0.00
1098.82
59.8295
0.00
0.00
0.00
0.00
800.22
59.8788
0.00
0.00
0.00
0.00
816.25
59.8749
0.00
0.00
0.00
0.00
735.39
59.8875
0.00
0.00
0.00
0.00
682.81
59.8967
0.00
0.00
0.00
0.00
1464.07
59.7772
0.00
0.00
0.00
0.00
1053.60
59.8420
0.00
0.00
0.00
0.00
1380.80
59.7873
0.00
0.00
0.00
0.00
-432.76
60.0652
0.00
0.00
0.00
0.00
1038.87
59.8419
0.00
0.00
0.00
0.00
882.15
59.8632
0.00
0.00
0.00
0.00
782.41
59.8804
0.00
0.00
0.00
0.00
Transferred
Contingent
Ramping
Frequency
BA
Units
Response
Lost Generation
Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
001918
Value B
Initial
Performance
Adjusted
P.U.
2.77
2.46
1.45
2.75
1.91
4.25
1.86
1.74
1.39
1.33
0.95
1.92
1.27
2.06
1.58
1.64
1.46
1.55
1.81
1.25
1.14
1.63
1.63
1.34
1.88
3.45
0.98
1.00
2.59
1.32
2.04
1.88
1.82
2.09
1.62
1.75
2.00
2.25
2.87
1.75
1.43
1.63
Initial
Performance
Unadjusted
P.U.
2.77
2.46
1.45
2.75
1.91
4.25
1.86
1.74
1.39
1.33
0.95
1.92
1.27
2.06
1.58
1.64
1.46
1.55
1.81
1.25
1.14
1.63
1.63
1.34
1.88
3.45
0.98
1.00
2.59
1.32
2.04
1.88
1.82
2.09
1.62
1.75
2.00
2.25
2.87
1.75
1.43
1.63
Sustained
Performance
P.U.
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
35459
34110
29399
31742
30136
39184
40276
48065
28794
40291
31482
32711
27719
51715
49290
52861
51916
52601
50614
31388
31019
31441
26588
29087
33258
38258
35238
39990
31031
31775
30845
41460
29701
42112
30134
42603
50486
44476
44473
56831
45295
56883
20 to 52 second Average Period Evaluation
JOU
NonBias
Net
Dynamic
Conforming
Pumped
Setting
Actual
Schedules
Load
Hydro
EPFR
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
MW
Hz
MW
MW
MW
MW
644.66
59.9019
0.00
0.00
0.00
0.00
712.86
59.8909
0.00
0.00
0.00
0.00
1253.04
59.8078
0.00
0.00
0.00
0.00
687.10
59.8949
0.00
0.00
0.00
0.00
944.31
59.8540
0.00
0.00
0.00
0.00
629.42
59.9048
0.00
0.00
0.00
0.00
784.33
59.8805
0.00
0.00
0.00
0.00
725.92
59.8891
0.00
0.00
0.00
0.00
1245.78
59.8085
0.00
0.00
0.00
0.00
820.96
59.8735
0.00
0.00
0.00
0.00
968.25
59.8512
0.00
0.00
0.00
0.00
543.80
59.9174
0.00
0.00
0.00
0.00
553.96
59.9174
351.29
0.00
0.00
0.00
709.23
59.8916
0.00
0.00
0.00
0.00
945.76
59.8551
0.00
0.00
0.00
0.00
1306.00
59.7994
0.00
0.00
0.00
0.00
981.31
59.8479
0.00
0.00
0.00
0.00
1184.47
59.8182
0.00
0.00
0.00
0.00
594.23
59.9086
11.16
0.00
0.00
0.00
1181.57
59.8182
0.00
0.00
0.00
0.00
1198.98
59.8165
0.00
0.00
0.00
0.00
834.03
59.8724
0.00
0.00
0.00
0.00
1151.46
59.8239
0.00
0.00
0.00
0.00
795.93
59.8781
0.00
0.00
0.00
0.00
564.48
59.9138
0.00
0.00
0.00
0.00
477.78
59.9272
0.00
0.00
0.00
0.00
1172.13
59.8211
0.00
0.00
0.00
0.00
1012.51
59.8458
67.05
0.00
0.00
0.00
893.16
59.8641
0.00
0.00
0.00
0.00
818.06
59.8747
0.00
0.00
0.00
0.00
1113.36
59.8286
0.00
0.00
0.00
0.00
791.22
59.8801
0.00
0.00
0.00
0.00
816.61
59.8746
0.00
0.00
0.00
0.00
734.82
59.8874
0.00
0.00
0.00
0.00
674.32
59.8972
0.00
0.00
0.00
0.00
1454.64
59.7784
0.00
0.00
0.00
0.00
1031.72
59.8431
0.00
0.00
0.00
0.00
1389.08
59.7881
0.00
0.00
0.00
0.00
-425.54
60.0649
0.00
0.00
0.00
0.00
1032.10
59.8426
0.00
0.00
0.00
0.00
893.16
59.8634
0.00
0.00
0.00
0.00
780.70
59.8807
0.00
0.00
0.00
0.00
Transferred
Contingent
Ramping
Frequency
BA
Units
Response
Lost Generation
Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Performance
Adjusted
P.U.
2.79
2.46
1.45
2.76
1.89
4.38
1.87
1.75
1.39
1.33
0.95
1.95
1.25
2.06
1.58
1.63
1.45
1.55
1.81
1.25
1.14
1.63
1.63
1.34
1.88
3.47
0.98
1.01
2.61
1.32
2.02
1.90
1.82
2.09
1.62
1.76
2.03
2.26
2.89
1.76
1.43
1.63
Initial
Performance
Unadjusted
P.U.
2.79
2.46
1.45
2.76
1.89
4.38
1.87
1.75
1.39
1.33
0.95
1.95
1.25
2.06
1.58
1.63
1.45
1.55
1.81
1.25
1.14
1.63
1.63
1.34
1.88
3.47
0.98
1.01
2.61
1.32
2.02
1.90
1.82
2.09
1.62
1.76
2.03
2.26
2.89
1.76
1.43
1.63
Sustained
Performance
P.U.
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
35470
34111
29403
31741
30135
39186
40270
48054
28795
40292
31484
32712
27729
51714
49291
52865
51918
52605
50619
31389
31020
31443
26598
29088
33258
38256
35241
39989
31035
31775
30848
41463
29704
42113
30137
42610
50488
44478
44457
56833
45297
56884
Bias
Setting
EPFR
MW
640.71
712.54
1254.91
686.42
953.38
621.89
780.53
724.06
1250.69
825.85
971.43
539.30
539.30
707.93
946.46
1310.23
992.94
1186.92
596.92
1186.92
1198.45
833.15
1150.05
796.28
563.11
475.15
1168.10
1006.77
887.69
818.17
1119.32
783.22
818.94
734.98
671.54
1446.88
1024.52
1383.98
-424.07
1027.51
892.31
778.99
001919
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet.
Step 2
For identified events in column B of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
Balancing Authority abbreviation)
Step 5
"Summary" worksheet contains each event's results for your Balancing Authority.
Note
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The previous
year’s monthly averages will be reported annually on FRS Form 1.
001920
NERC FRS FORM 1 20 to 52 second Value B
Balancing Authority
HQ
Date/Time
(Central Prevailing)
DelFreq
BA
Time
BA
DelFreq
-0.101
0:00:00
0.000
0.0
0.0
0.0
2
0:00:00
0.000
0.0
0.0
3
0:00:00
0.000
0.0
0.0
4
0:00:00
0.000
0.0
5
0:00:00
0.000
6
0:00:00
0.000
7
0:00:00
0.000
8
0:00:00
9
0:00:00
10
Enter Addition Data in column R ==>
Select Reason(s) for adjustment
Information
Event
Number
SEFRD
(MW/0.1Hz)
Exclude for
data error *
0.0
#DIV/0!
N
0.0
0.0
#DIV/0!
0.0
0.0
#DIV/0!
0.0
0.0
0.0
#DIV/0!
N
1901
0.0
0.0
0.0
0.0
#DIV/0!
N
Hydro Quebec
0.0
0.0
0.0
0.0
#DIV/0!
N
HQ
0.0
0.0
0.0
0.0
#DIV/0!
N
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0:00:00
0.000
0.0
0.0
0.0
0.0
11
0:00:00
0.000
0.0
0.0
0.0
12
0:00:00
0.000
0.0
0.0
0.0
1
12/6/2010 11:25
13
0:00:00
0.000
Value "A" Information
MW Lost
Adjustment
0.0
0.0
Value "B" Information
MW Lost
Adjustment
0.0
N
0.0
0.0
N
0.0
0.0
-0.040
10.7
Bias Calculation Form Year
0.0
0.0
-0.05252493
80.66089
Interconnection
0.0
0.0
-0.07090523 -26.89761
Balancing Authority
0.0
0.0
-0.05190677
9.955449
Contact Name
0.0
0.0
-0.0580477
3.367024
N
Contact Phone #
0.0
0.0
-0.07557242
36.33443
N
Contact e-mail
0.0
0.0
-0.0563805
#DIV/0!
N
Current Year's Actual Peak
0.0
0.0
-0.0573329
0.0
#DIV/0!
N
Internal Generating Capacity
0.0
0.0
-0.0517609
13.64342
0.0
#DIV/0!
N
Next Year's Projected Peak
0.0
0.0
-0.04999924
11.10075
0.0
0.0
-0.05599976
12.32546
Current year
0.0
0.0
-0.05849838
0.750192
1900 Frequency Response Obligation (FRO)
0.0
0.0
-0.04850006
2.230058
-0.04500008
9.477859
0.0
0.0
-0.03750229
0.355309
Average Frequency Response (MW/0.1Hz)
0.0
0.0
-0.04750061
2.170702
0.0
0.0
-0.05550003
29.38207
Y
0.0
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
1900
16
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
-141.0
0.000
0.0
0.0
0.0
Reason(s)
0.0
14
0:00:00
Value "B"
Load
0.0
0.0
755.3
15
17
Event
Value "A"
MW Loss
Load
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
0.0
#DIV/0!
N
0.0
0.0
0.0
-0.058
23.2
-0.066
27.7
0.488253
2.758037
-0.052 -19.90685
18
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
19
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
20
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
21
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
-0.047
4.601381
22
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
-0.06
1.593515
23
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
-0.06
52.37091
24
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
-0.051
33.94787
25
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
-0.1
100
26
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
27
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Next Year's
0.0
0.0
28
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
-141.0
0.0
0.0
29
0:00:00
0.000
0.0
#DIV/0!
1901 Frequency Response Obligation (FRO)
1901 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
0.0
0.0
0.0
0.0
N
#DIV/0!
1900 FRM - Median Frequency Response (MW/0.1Hz)
0.0
0.0
Y
0.0
0.0
0.0
0.0
Do you RECEIVE Overlap regulation?
0.0
0.0
If Yes, list the BA name and the associated Bias of that BA
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
0.0
0.0
#DIV/0!
N
31
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
32
33
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
N
N
34
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
35
36
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
N
N
30
0:00:00
0.000
Summary Statistics
#DIV/0!
-33.8
N
Bias -MW/0.1 Hz
Regression Estimate of Frequency Response (MW/0.1Hz)
37
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
38
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
39
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
40
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
41
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
42
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
0.0
0.0
N
Bias -MW/0.1 Hz
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Balancing Authority
N
Y
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" into "BA Form 2 Data"
worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a
copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
BA name)
Note:
Only one set of average periods of evaluation is displayed. Other worksheets for the additional
average periods are hidden.
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
001921
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time
(Central Prevailing)
12/6/2010 11:25
HQ
DelFreq
-0.101
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Ramping
Units
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 12 to 24 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Notes:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange (contingency size for single BA interconnections) solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the six types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be entered as negative numbers.
4) Pumped Hydro:
- Values for pumping must be entered as negative values.
- Values for generating must be entered as positive values.
5) Rampling Units:
- Values are entered as positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Value for Value A is the pre-contingency generation from the contingent unit(s).
- Value for Value B is usually 0 MW, but may be the load that remains on the system that was "netted" out by the now offline generation.
Generation MW as +
(If load occurs due to gen
loss, enter MW as - at value
B)
001922
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Average Frequency Response (MW/0.1Hz)
1901 FRM - Median Frequency Response
(MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
1901 Frequency Response Obligation (FRO)
NERC FRS FORM 1
HQ
Date/Time
(Central Prevailing)
DelFreq
12/6/2010 11:25 -0.101
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1/0/1900 0:00
0.000
1-0-00 0:00:00
0.000
1/0/1900 0:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
0.000
1-0-00 0:00:00
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
1-0-00 0:00:00
0.000
BA
Time
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
BA
12 to 24 18 to 30 20 to 40 18 to 52 20 to 52
DelFreq SEFRD
SEFRD
SEFRD
SEFRD
SEFRD
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.000
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
-33.77
-141
#DIV/0!
-33.77
-141
#DIV/0!
-33.77
-141
#DIV/0!
-33.77
-141
#DIV/0!
-33.77
-141
12 to 24 P.U. Performance
Exclude for
data error *
N
N
N
N
N
N
N
N
N
N
N
N
Y
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
Initial
Initial
Sustained
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 30 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 40 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Sustained
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 52 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 52 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Sustained
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
001923
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
average
FBS* for
month
-10.0
-7.0
-12.0
-8.0
-27.0
-8.7
-8.0
-8.0
-8.2
-8.0
-8.0
-12.0
-10.4
Average Annual Bias
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001
001924
Interconnection Performance
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
12/6/2010 11:25
-0.101
2
1/0/1900 0:00
0
3
1/0/1900 0:00
0
4
1/0/1900 0:00
0
5
1/0/1900 0:00
0
6
1/0/1900 0:00
0
7
1/0/1900 0:00
0
8
1/0/1900 0:00
0
9
1/0/1900 0:00
0
10
1/0/1900 0:00
0
11
1/0/1900 0:00
0
12
1/0/1900 0:00
0
13
1/0/1900 0:00
0
14
1/0/1900 0:00
0
15
1/0/1900 0:00
0
16
1/0/1900 0:00
0
17
1/0/1900 0:00
0
18
1/0/1900 0:00
0
19
1/0/1900 0:00
0
20
1/0/1900 0:00
0
21
1/0/1900 0:00
0
22
1/0/1900 0:00
0
23
1/0/1900 0:00
0
24
1/0/1900 0:00
0
25
1/0/1900 0:00
0
26
1/0/1900 0:00
0
27
1/0/1900 0:00
0
28
1/0/1900 0:00
0
29
1/0/1900 0:00
0
30
1/0/1900 0:00
0
31
1/0/1900 0:00
0
32
1/0/1900 0:00
0
33
1/0/1900 0:00
0
34
1/0/1900 0:00
0
35
1/0/1900 0:00
0
36
1/0/1900 0:00
0
37
1/0/1900 0:00
0
38
1/0/1900 0:00
0
39
1/0/1900 0:00
0
40
1/0/1900 0:00
0
41
1/0/1900 0:00
0
42
1/0/1900 0:00
0
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Value B
12 to 24 sec
Average
Frequency
FR B
12 to 24 sec
Average
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
001925
Value A Data
BA Performance
JOU
NonTransferred
Contingent
FR B
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
20 to 52 sec
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Average Frequency Interchange Imp(-) Exp (+)
Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW
MW
Initial
Performance
Adjusted
P.U.
001926
Value B
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming Pumped Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Frequency Interchange Imp(-) Exp (+) Load (-)Load (-) Gen (+)Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
Value B
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
20 to 40 second Average Per
Net
Actual
Interchange
MW
001927
20 to 40 second Average Period Evaluation
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
Value B
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW/0.1 Hz
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
18 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
001928
Value B
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
Hz
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
001929
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet.
Step 2
For identified events in column B of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
Balancing Authority abbreviation)
Step 5
"Summary" worksheet contains each event's results for your Balancing Authority.
Note
Balancing Authorities with variable Frequency Bias Settings shall calculate monthly average Frequency Bias Settings. The previous
year’s monthly averages will be reported annually on FRS Form 1.
001930
NERC FRS FORM 1 20 to 52 second Value B
Balancing Authority
MyBA
Date/Time
(Central Prevailing)
DelFreq
BA
Time
BA
DelFreq
-0.111
0:00:00
0.000
Enter Addition Data in column R ==>
Select Reason(s) for adjustment
Information
Event
Number
1
3/7/2011 11:48
Value "A" Information
NAI
Adjustment
0.0
0.0
Value "B" Information
NAI
Adjustment
0.0
SEFRD
(MW/0.1Hz)
Exclude for
data error *
#DIV/0!
N
0.0
2
3/14/2011 9:01
-0.055
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
3
3/16/2011 16:54
-0.070
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
-0.079
10.7
N
2012
N
Western
0.0
-0.07090523 -26.89761
-0.113
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
MyBA
Balancing Authority
0.0
0.0
-0.05190677
9.955449
4/1/2011 17:57
-0.088
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Contact Name
0.0
0.0
-0.0580477
3.367024
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Contact Phone #
810
0.0
0.0
-0.07557242
36.33443
0.0
0.0
-0.0563805
810
0.0
0.0
-0.0573329
2.758037
0.0
0.0
-0.0517609
13.64342
#DIV/0!
Bias Calculation Form Year
27.7
-0.040
3/22/2011 10:47
0.0
#DIV/0!
-0.066
3/26/2011 15:49
0.0
0.0
23.2
0.0
0.0
3/22/2011 10:50
0.0
0.0
-0.058
0.0
0.0
4
0.0
0.0
Reason(s)
0.0
6
0.000
0.0
710
Value "B"
Load
5
0:00:00
0.000
0.0
7
-0.120
0:00:00
Event
Value "A"
MW Loss
Load
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
0.0
8
4/28/2011 17:09
-0.116
0:00:00
9
5/11/2011 14:04
-0.070
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Contact e-mail
10
5/24/2011 23:34
-0.074
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Current Year's Actual Peak
11
5-31-11 1:58:00
-0.076
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
Internal Generating Capacity
12
6-1-11 12:04:00
13
6-24-11 22:10:00
14
6-25-11 19:52:00
-0.085
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
15
7-3-11 18:51:00
-0.061
0:00:00
0.000
0.0
0.0
0.0
0.0
#DIV/0!
N
7-10-11 22:17:00
-0.091
#DIV/0!
N
16
-0.096
-0.090
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
N
0:00:00
0.000
0.0
0.0
0.0
0.0
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
18
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
19
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
20
0:00:00
11.10075
-0.052 -19.90685
0.0
0.0
-0.05599976
12.32546
2011
Current year
0.0
0.0
-0.05849838
0.750192
-50.0
2011 Frequency Response Obligation (FRO)
0.0
0.0
-0.04850006
2.230058
Summary Statistics
#DIV/0!
Average Frequency Response (MW/0.1Hz)
0.0
-0.04500008
0.0
-0.03750229
0.355309
0.0
0.0
-0.04750061
2.170702
0.0
-0.05550003
0.0
-0.047
4.601381
0.0
0.0
0.0
0.0
Y
0.0
0.0
-0.06
1.593515
0.0
0.0
0.0
0.0
Y
0.0
0.0
-0.06
52.37091
0.0
Y
0.0
9.477859
0.000
0.0
Y
0.0
0.0
0.000
0.0
0.0
-0.04999924
0.488253
0:00:00
0.0
0.0
0.0
0.0
80.66089
0:00:00
0.000
0.0
0.0
0.0
-0.05252493
22
0:00:00
0.0
750
0.0
23
21
0.000
Next Year's Projected Peak
N
17
0.0
Interconnection
-33.8
Regression Estimate of Frequency Response (MW/0.1Hz)
0.0
29.38207
24
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
-0.051
33.94787
25
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
-0.1
100
26
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
27
28
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-50.0
0.0
0.0
0.0
0.0
29
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
Next Year's
2012 Frequency Response Obligation (FRO)
2012 Frequency Bias Setting - (minimum of FRM, next year's FRO,
or 0.8% of Projected Peak [Load + Gen]/2)
30
31
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
#DIV/0!
2011 FRM - Median Frequency Response (MW/0.1Hz)
32
33
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
34
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
35
36
0:00:00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
37
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
38
0:00:00
0.000
0.0
0.0
0.0
0.0
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Bias -MW/0.1 Hz
Balancing Authority
Y
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
40
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
41
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
42
0:00:00
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
N
Bias -MW/0.1 Hz
N
Y
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Balancing Authority
N
Y
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" into "BA Form 2 Data" worksheet
of this workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form1.xlsx and send a
copy of this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your
BA name)
Note:
Only one set of average periods of evaluation is displayed. Other worksheets for the additional
average periods are hidden.
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Ramping units (RU)
Xfred Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & RU
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & RU
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & RU
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & RU & TFR
DS & NL & PH & RU & CBA
DS & NL & PH & RU & TFR & CBA
NL & PH
NL & RU
NL & TFR
NL & CBA
NL & PH & RU
NL & PH & TFR
NL & PH & BAA
NL & PH & RU & TFR
NL & PH & RU & CBA
NL & PH & RU & TFR & CBA
PH & RU
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR
PH & RU & CBA
PH & TFR
PH & CBA
PH & RU & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
namic schedules for joint-owned units (DS)
nconforming load (NL)
mped hydro (PH)
mping units (RU)
ed Frequency Response (TFR)
ntingent BA adjustment for loss of units (CBA)
& NL
& PH
& RU
& TFR
& CBA
& NL & PH
& NL & RU
U DS & NL & TFR
& NL & CBA
& NL & PH & RU
& NL & PH & TFR
& NL & PH & CBA
& NL & PH & RU & TFR
& NL & PH & RU & CBA
& NL & PH & RU & TFR & CBA
& PH
& RU
& TFR
& CBA
& PH & RU
& PH & TFR
& PH & BAA
& PH & RU & TFR
& PH & RU & CBA
& PH & RU & TFR & CBA
& RU
& TFR
& CBA
& RU & TFR
& RU & CBA
& TFR
& CBA
& RU & TFR
& RU & CBA
& TFR
& CBA
& RU & TFR & CBA
& TFR
& CBA
& TFR & CBA
R & CBA
001931
001932
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time
(Central Prevailing)
3/7/2011 11:48
3/14/2011 9:01
3/16/2011 16:54
3/22/2011 10:47
3/22/2011 10:50
3/26/2011 15:49
4/1/2011 17:57
4/28/2011 17:09
5/11/2011 14:04
5/24/2011 23:34
5/31/2011 1:58
6-1-11 12:04:00
6/24/2011 22:10
6-25-11 19:52:00
7-3-11 18:51:00
7-10-11 22:17:00
MyBA
DelFreq
-0.111
-0.055
-0.070
-0.079
-0.120
-0.113
-0.088
-0.116
-0.070
-0.074
-0.076
-0.096
-0.090
-0.085
-0.061
-0.091
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Ramping
Units
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 12 to 24 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Notes:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange (contingency size for single BA interconnections) solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the six types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be entered as negative numbers.
4) Pumped Hydro:
- Values for pumping must be entered as negative values.
- Values for generating must be entered as positive values.
5) Rampling Units:
- Values are entered as positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Value for Value A is the pre-contingency generation from the contingent unit(s).
- Value for Value B is usually 0 MW, but may be the load that remains on the system that was "netted" out by the now offline generation.
Generation MW as +
(If load occurs due to gen
loss, enter MW as - at value
B)
001933
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Date/Time
(Central Prevailing)
3/7/2011 11:48
3/14/2011 9:01
3/16/2011 16:54
3/22/2011 10:47
3/22/2011 10:50
3/26/2011 15:49
4/1/2011 17:57
4/28/2011 17:09
5/11/2011 14:04
5/24/2011 23:34
5-31-11 1:58:00
6-1-11 12:04:00
6-24-11 22:10:00
6-25-11 19:52:00
7-3-11 18:51:00
7-10-11 22:17:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
1-0-00 0:00:00
Average Frequency Response (MW/0.1Hz)
2012 FRM - Median Frequency Response
(MW/0.1Hz)
Regression Estimate of Frequency Response (MW/0.1Hz)
2012 Frequency Response Obligation (FRO)
NERC FRS FORM 1
MyBA
DelFreq
-0.111
-0.055
-0.070
-0.079
-0.120
-0.113
-0.088
-0.116
-0.070
-0.074
-0.076
-0.096
-0.090
-0.085
-0.061
-0.091
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Time
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
BA
12 to 24 18 to 30 20 to 40 18 to 52 20 to 52
DelFreq
SEFRD
SEFRD
SEFRD
SEFRD
SEFRD
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
-33.77
-50
#DIV/0!
-33.77
-50
#DIV/0!
-33.77
-50
#DIV/0!
-33.77
-50
#DIV/0!
-33.77
-50
12 to 24 P.U. Performance
Exclude for
data error *
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
N
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 30 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 40 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Sustained
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
18 to 52 P.U. Performance
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 52 P.U. Performance
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Initial
Initial
Adjusted
Unadjusted
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Sustained
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
001934
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
average
FBS* for
month
-10.0
-7.0
-12.0
-8.0
-27.0
-8.7
-8.0
-8.0
-8.2
-8.0
-8.0
-12.0
-10.4
Average Annual Bias
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001
001935
Interconnection Performance
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing)
1
3/7/2011 11:48
2
3/14/2011 9:01
3
3/16/2011 16:54
4
3/22/2011 10:47
5
3/22/2011 10:50
6
3/26/2011 15:49
7
4/1/2011 17:57
8
4/28/2011 17:09
9
5/11/2011 14:04
10
5/24/2011 23:34
11
5/31/2011 1:58
12
6/1/2011 12:04
13
6/24/2011 22:10
14
6/25/2011 19:52
15
7/3/2011 18:51
16
7/10/2011 22:17
17
1/0/1900 0:00
18
1/0/1900 0:00
19
1/0/1900 0:00
20
1/0/1900 0:00
21
1/0/1900 0:00
22
1/0/1900 0:00
23
1/0/1900 0:00
24
1/0/1900 0:00
25
1/0/1900 0:00
26
1/0/1900 0:00
27
1/0/1900 0:00
28
1/0/1900 0:00
29
1/0/1900 0:00
30
1/0/1900 0:00
31
1/0/1900 0:00
32
1/0/1900 0:00
33
1/0/1900 0:00
34
1/0/1900 0:00
35
1/0/1900 0:00
36
1/0/1900 0:00
37
1/0/1900 0:00
38
1/0/1900 0:00
39
1/0/1900 0:00
40
1/0/1900 0:00
41
1/0/1900 0:00
42
1/0/1900 0:00
DelFreq
-0.111
-0.055
-0.07
-0.079
-0.12
-0.113
-0.088
-0.116
-0.07
-0.074
-0.076
-0.096
-0.09
-0.085
-0.061
-0.091
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Value B
12 to 24 sec
Average
Frequency
FR B
12 to 24 sec
Average
MW
Value A Data
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Net
18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Actual
Average
Average
Average
Average
Average
Average
Average
Average Frequency Interchange
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Hz
MW
001936
BA Performance
JOU
NonTransferred
Contingent
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Imp(-) Exp (+)
Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
001937
Value B
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming Pumped Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Frequency Interchange Imp(-) Exp (+) Load (-)Load (-) Gen (+)Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
Value B
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
20 to 40 second Average Period Evaluation
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW/0.1 Hz
MW
Initial
Performance
Adjusted
P.U.
001938
Value B
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
18 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
Value B
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Frequency Interchange Imp(-) Exp (+) Load (-)
Hz
MW
MW
MW
001939
d Average Period Evaluation
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
001940
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
C
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Ramping units
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 2 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with up to 60 minutes of data. Be sure "Data" worksheet is clear of any old data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 313 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A313"
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency of the event on the center vertical grid line of the graph (Red Trend).
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 427.
Edit cell "C11" of the "Evaluation" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A427"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if you're interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar.
When set appropriately, the "Target" trend on the "Sustained" graph will model what Interchange Actual should have done during the event recovery period based on your minimum FRO.
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
001941
Time (T)
10/12/09 02:12:00
10/12/09 02:12:02
10/12/09 02:12:04
10/12/09 02:12:06
10/12/09 02:12:08
10/12/09 02:12:10
10/12/09 02:12:12
10/12/09 02:12:14
10/12/09 02:12:16
10/12/09 02:12:18
10/12/09 02:12:20
10/12/09 02:12:22
10/12/09 02:12:24
10/12/09 02:12:26
10/12/09 02:12:28
10/12/09 02:12:30
10/12/09 02:12:32
10/12/09 02:12:34
10/12/09 02:12:36
10/12/09 02:12:38
10/12/09 02:12:40
10/12/09 02:12:42
10/12/09 02:12:44
10/12/09 02:12:46
10/12/09 02:12:48
10/12/09 02:12:50
10/12/09 02:12:52
10/12/09 02:12:54
10/12/09 02:12:56
10/12/09 02:12:58
10/12/09 02:13:00
10/12/09 02:13:02
10/12/09 02:13:04
10/12/09 02:13:06
10/12/09 02:13:08
10/12/09 02:13:10
10/12/09 02:13:12
10/12/09 02:13:14
10/12/09 02:13:16
10/12/09 02:13:18
10/12/09 02:13:20
10/12/09 02:13:22
10/12/09 02:13:24
10/12/09 02:13:26
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
Hz
MW
MW
59.98 3669.878
350
59.981 3672.385
350
59.98 3669.878
350
59.981 3672.385
350
59.98
3671.7
350
59.98 3670.949
350
59.982 3671.698
350
59.981 3671.548
350
59.979
3672.31
350
59.981 3672.775
350
59.982 3672.174
350
59.979 3672.276
350
59.979 3674.263
350
59.98 3674.508
350
59.98 3673.844
350
59.983 3675.092
350
59.986 3672.106
350
59.986
3669.33
350
59.98 3669.168
350
59.976
3671.5
350
59.975
3673.56
350
59.979 3673.897
350
59.981 3673.834
350
59.982 3671.887
350
59.987 3671.635
350
59.99
3671.22
350
59.993
3671.56
350
59.994 3671.283
350
59.995 3670.772
350
59.995 3668.362
350
59.995 3668.129
350
59.995 3668.245
350
59.995 3669.291
350
59.994 3670.494
350
59.994 3671.254
350
59.995 3670.683
350
59.997 3670.156
350
60.001 3670.212
350
60.002 3670.712
350
60.001 3670.329
350
60.003 3671.184
350
60.003 3671.227
350
60.005 3670.267
350
60.003
3670.19
350
NonTransferred
Contingent
Conforming
Pumped
Ramping
Frequency
BA
BA
Load
Hydro
Units
Response
Lost Generation
Bias
Load (-)
Load (-) Gen (+)
Gen (+)
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW
MW/0.1 Hz
MW
MW/0.1 Hz
-351.361511
0
0
10
15
-103
-351.361511
0
0.5
10
15
-103
-351.361511
0
1
10
15
-103
-357.94751
0
1.5
10
15
-103
-357.94751
0
2
10
15
-103
-357.94751
0
2.5
10
15
-103
-357.94751
0
3
10
15
-103
-357.94751
0
3.5
10
15
-103
-360.234741
0
4
10
15
-103
-360.234741
0
4.5
10
15
-103
-360.234741
0
5
10
15
-103
-360.234741
0
5.5
10
15
-103
-360.234741
0
6
10
15
-103
-346.525879
0
6.5
10
15
-103
-346.525879
0
7
10
15
-103
-346.525879
0
7.5
10
15
-103
-346.525879
0
8
10
15
-103
-346.525879
0
8.5
10
15
-103
-296.443359
0
9
10
15
-103
-296.443359
0
9.5
10
15
-103
-296.443359
0
10
10
15
-103
-296.443359
0
10.5
10
15
-103
-296.443359
0
11
10
15
-103
-341.061157
0
11.5
10
15
-103
-341.061157
0
12
10
15
-103
-341.061157
0
12.5
10
15
-103
-341.061157
0
13
10
15
-103
-341.061157
0
13.5
10
15
-103
-322.826294
0
14
10
15
-103
-322.826294
0
14.5
10
15
-103
-322.826294
0
15
10
15
-103
-322.826294
0
15.5
10
15
-103
-322.826294
0
16
10
15
-103
-321.544403
0
16.5
10
15
-103
-321.544403
0
17
10
15
-103
-321.544403
0
17.5
10
15
-103
-321.544403
0
18
10
15
-103
-321.544403
0
18.5
10
15
-103
-362.136261
0
19
10
15
-103
-362.136261
0
19.5
10
15
-103
-362.136261
0
20
10
15
-103
-362.136261
0
20.5
10
15
-103
-362.136261
0
21
10
15
-103
-336.311798
0
21.5
10
15
-103
BA
Load
MW
7500
7500.33
7500.66
7500.99
7501.32
7501.65
7501.98
7502.31
7502.64
7502.97
7503.3
7503.63
7503.96
7504.29
7504.62
7504.95
7505.28
7505.61
7505.94
7506.27
7506.6
7506.93
7507.26
7507.59
7507.92
7508.25
7508.58
7508.91
7509.24
7509.57
7509.9
7510.23
7510.56
7510.89
7511.22
7511.55
7511.88
7512.21
7512.54
7512.87
7513.2
7513.53
7513.86
7514.19
001942
10/12/09 02:13:28
10/12/09 02:13:30
10/12/09 02:13:32
10/12/09 02:13:34
10/12/09 02:13:36
10/12/09 02:13:38
10/12/09 02:13:40
10/12/09 02:13:42
10/12/09 02:13:44
10/12/09 02:13:46
10/12/09 02:13:48
10/12/09 02:13:50
10/12/09 02:13:52
10/12/09 02:13:54
10/12/09 02:13:56
10/12/09 02:13:58
10/12/09 02:14:00
10/12/09 02:14:02
10/12/09 02:14:04
10/12/09 02:14:06
10/12/09 02:14:08
10/12/09 02:14:10
10/12/09 02:14:12
10/12/09 02:14:14
10/12/09 02:14:16
10/12/09 02:14:18
10/12/09 02:14:20
10/12/09 02:14:22
10/12/09 02:14:24
10/12/09 02:14:26
10/12/09 02:14:28
10/12/09 02:14:30
10/12/09 02:14:32
10/12/09 02:14:34
10/12/09 02:14:36
10/12/09 02:14:38
10/12/09 02:14:40
10/12/09 02:14:42
10/12/09 02:14:44
10/12/09 02:14:46
10/12/09 02:14:48
10/12/09 02:14:50
10/12/09 02:14:52
10/12/09 02:14:54
10/12/09 02:14:56
10/12/09 02:14:58
10/12/09 02:15:00
10/12/09 02:15:02
10/12/09 02:15:04
60
60.001
60.003
60.004
60.005
60.001
59.999
60.001
60.004
60.004
60.004
60.004
60.005
60.003
60.002
60.003
60.001
59.999
59.999
59.997
59.998
59.996
59.995
59.993
59.993
59.996
59.999
60.001
60.005
60.007
60.007
60.005
60.002
59.999
59.997
59.999
60.002
60.007
60.01
60.011
60.009
60.003
59.997
59.995
59.994
59.994
60
60.001
59.998
3671.092
3670.249
3670.67
3669.899
3669.534
3670.199
3671.628
3671.123
3671.968
3671.444
3671.872
3671.875
3671.066
3672.873
3673.235
3673.498
3673.531
3672.75
3673.186
3674.322
3673.576
3673.365
3671.821
3672.093
3671.998
3671.568
3671.073
3670.957
3671.441
3670.893
3670.162
3670.513
3670.62
3672.713
3672.086
3671.07
3670.826
3670.823
3671.809
3673.363
3672.736
3673.255
3674.415
3675.426
3674.755
3674.29
3675.311
3675.157
3675.166
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-336.311798
-336.311798
-336.311798
-336.311798
-316.443054
-316.443054
-316.443054
-316.443054
-316.443054
-325.464294
-325.464294
-325.464294
-325.464294
-325.464294
-336.614166
-336.614166
-336.614166
-336.614166
-336.614166
-316.726166
-316.726166
-316.726166
-316.726166
-316.726166
-320.195526
-320.195526
-320.195526
-320.195526
-320.195526
-341.86615
-341.86615
-341.86615
-341.86615
-341.86615
-348.597839
-348.597839
-348.597839
-348.597839
-348.597839
-329.085022
-329.085022
-329.085022
-329.085022
-329.085022
-342.418243
-342.418243
-342.418243
-342.418243
-342.418243
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
22
22.5
23
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
28.5
29
29.5
30
30.5
31
31.5
32
32.5
33
33.5
34
34.5
35
35.5
36
36.5
37
37.5
38
38.5
39
39.5
40
40.5
41
41.5
42
42.5
43
43.5
44
44.5
45
45.5
46
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7514.52
7514.85
7515.18
7515.51
7515.84
7516.17
7516.5
7516.83
7517.16
7517.49
7517.82
7518.15
7518.48
7518.81
7519.14
7519.47
7519.8
7520.13
7520.46
7520.79
7521.12
7521.45
7521.78
7522.11
7522.44
7522.77
7523.1
7523.43
7523.76
7524.09
7524.42
7524.75
7525.08
7525.41
7525.74
7526.07
7526.4
7526.73
7527.06
7527.39
7527.72
7528.05
7528.38
7528.71
7529.04
7529.37
7529.7
7530.03
7530.36
001943
10/12/09 02:15:06
10/12/09 02:15:08
10/12/09 02:15:10
10/12/09 02:15:12
10/12/09 02:15:14
10/12/09 02:15:16
10/12/09 02:15:18
10/12/09 02:15:20
10/12/09 02:15:22
10/12/09 02:15:24
10/12/09 02:15:26
10/12/09 02:15:28
10/12/09 02:15:30
10/12/09 02:15:32
10/12/09 02:15:34
10/12/09 02:15:36
10/12/09 02:15:38
10/12/09 02:15:40
10/12/09 02:15:42
10/12/09 02:15:44
10/12/09 02:15:46
10/12/09 02:15:48
10/12/09 02:15:50
10/12/09 02:15:52
10/12/09 02:15:54
10/12/09 02:15:56
10/12/09 02:15:58
10/12/09 02:16:00
10/12/09 02:16:02
10/12/09 02:16:04
10/12/09 02:16:06
10/12/09 02:16:08
10/12/09 02:16:10
10/12/09 02:16:12
10/12/09 02:16:14
10/12/09 02:16:16
10/12/09 02:16:18
10/12/09 02:16:20
10/12/09 02:16:22
10/12/09 02:16:24
10/12/09 02:16:26
10/12/09 02:16:28
10/12/09 02:16:30
10/12/09 02:16:32
10/12/09 02:16:34
10/12/09 02:16:36
10/12/09 02:16:38
10/12/09 02:16:40
10/12/09 02:16:42
59.998
59.995
59.992
59.986
59.986
59.986
59.988
59.989
59.988
59.987
59.985
59.984
59.983
59.982
59.984
59.984
59.985
59.986
59.987
59.99
59.99
59.987
59.983
59.98
59.979
59.983
59.987
59.986
59.988
59.987
59.983
59.978
59.979
59.979
59.989
59.991
59.988
59.983
59.989
59.991
59.989
59.992
59.993
59.995
59.996
59.998
59.998
60
59.999
3674.442
3674.319
3674.906
3676.329
3676.714
3677.791
3675.972
3675.543
3676.593
3676.931
3677.223
3677.067
3677.361
3678.455
3679.228
3679.731
3679.059
3677.627
3677.482
3676.409
3677.528
3677.371
3676.915
3678.086
3679.233
3680.163
3679.213
3678.344
3677.653
3677.678
3678.951
3679.279
3678.729
3679.606
3680.287
3679.026
3678.813
3678.489
3678.72
3678.74
3678.971
3679.39
3677.063
3678.33
3678.49
3677.944
3676.763
3678.951
3678.456
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-338.794647
-338.794647
-338.794647
-338.794647
-338.794647
-335.931
-335.931
-335.931
-335.931
-335.931
-339.712402
-339.712402
-339.712402
-339.712402
-339.712402
-332.024658
-332.024658
-332.024658
-332.024658
-332.024658
-330.759033
-330.759033
-330.759033
-330.759033
-330.759033
-323.419952
-323.419952
-323.419952
-323.419952
-323.419952
-342.350922
-342.350922
-342.350922
-342.350922
-342.350922
-345.081818
-345.081818
-345.081818
-345.081818
-345.081818
-346.537384
-346.537384
-346.537384
-346.537384
-346.537384
-342.905762
-342.905762
-342.905762
-342.905762
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
46.5
47
47.5
48
48.5
49
49.5
50
50.5
51
51.5
52
52.5
53
53.5
54
54.5
55
55.5
56
56.5
57
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
63
63.5
64
64.5
65
65.5
66
66.5
67
67.5
68
68.5
69
69.5
70
70.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7530.69
7531.02
7531.35
7531.68
7532.01
7532.34
7532.67
7533
7533.33
7533.66
7533.99
7534.32
7534.65
7534.98
7535.31
7535.64
7535.97
7536.3
7536.63
7536.96
7537.29
7537.62
7537.95
7538.28
7538.61
7538.94
7539.27
7539.6
7539.93
7540.26
7540.59
7540.92
7541.25
7541.58
7541.91
7542.24
7542.57
7542.9
7543.23
7543.56
7543.89
7544.22
7544.55
7544.88
7545.21
7545.54
7545.87
7546.2
7546.53
001944
10/12/09 02:16:44
10/12/09 02:16:46
10/12/09 02:16:48
10/12/09 02:16:50
10/12/09 02:16:52
10/12/09 02:16:54
10/12/09 02:16:56
10/12/09 02:16:58
10/12/09 02:17:00
10/12/09 02:17:02
10/12/09 02:17:04
10/12/09 02:17:06
10/12/09 02:17:08
10/12/09 02:17:10
10/12/09 02:17:12
10/12/09 02:17:14
10/12/09 02:17:16
10/12/09 02:17:18
10/12/09 02:17:20
10/12/09 02:17:22
10/12/09 02:17:24
10/12/09 02:17:26
10/12/09 02:17:28
10/12/09 02:17:30
10/12/09 02:17:32
10/12/09 02:17:34
10/12/09 02:17:36
10/12/09 02:17:38
10/12/09 02:17:40
10/12/09 02:17:42
10/12/09 02:17:44
10/12/09 02:17:46
10/12/09 02:17:48
10/12/09 02:17:50
10/12/09 02:17:52
10/12/09 02:17:54
10/12/09 02:17:56
10/12/09 02:17:58
10/12/09 02:18:00
10/12/09 02:18:02
10/12/09 02:18:04
10/12/09 02:18:06
10/12/09 02:18:08
10/12/09 02:18:10
10/12/09 02:18:12
10/12/09 02:18:14
10/12/09 02:18:16
10/12/09 02:18:18
10/12/09 02:18:20
59.995
59.991
59.992
59.995
59.998
60.001
60.003
60.006
60.009
60.009
60.011
60.012
60.011
60.01
60.008
60.007
60.011
60.012
60.013
60.01
60.01
60.007
60.009
60.009
60.006
60.006
60.009
60.009
60.008
60.009
60.009
60.005
60.004
60.001
59.999
59.993
59.991
59.994
59.992
59.994
59.992
59.994
59.995
59.993
59.99
59.99
59.987
59.983
59.977
3679.148
3679.903
3680.041
3678.997
3677.86
3678.493
3678.267
3677.686
3677.899
3678.364
3679.209
3678.659
3678.653
3679.057
3679.703
3680.604
3679.806
3680.625
3680.263
3679.851
3679.561
3679.946
3679.44
3679.912
3679.517
3679.888
3679.608
3679.06
3679.261
3679.164
3679.025
3679.152
3678.572
3678.295
3678.249
3678.236
3677.83
3677.955
3677.772
3676.666
3677.093
3677.141
3676.401
3678.516
3679.872
3680.197
3678.743
3678.428
3677.921
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-342.905762
-340.094391
-340.094391
-340.094391
-340.094391
-340.094391
-342.771179
-342.771179
-342.771179
-342.771179
-342.771179
-342.909912
-342.909912
-342.909912
-342.909912
-342.909912
-343.286011
-343.286011
-343.286011
-343.286011
-343.286011
-331.852966
-331.852966
-331.852966
-331.852966
-331.852966
-329.98822
-329.98822
-329.98822
-329.98822
-329.98822
-255.444168
-255.444168
-255.444168
-255.444168
-255.444168
-254.838303
-254.838303
-254.838303
-254.838303
-254.838303
-257.146973
-257.146973
-257.146973
-257.146973
-257.146973
-262.289368
-262.289368
-262.289368
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
71
71.5
72
72.5
73
73.5
74
74.5
75
75.5
76
76.5
77
77.5
78
78.5
79
79.5
80
80.5
81
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7546.86
7547.19
7547.52
7547.85
7548.18
7548.51
7548.84
7549.17
7549.5
7549.83
7550.16
7550.49
7550.82
7551.15
7551.48
7551.81
7552.14
7552.47
7552.8
7553.13
7553.46
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
001945
10/12/09 02:18:22
10/12/09 02:18:24
10/12/09 02:18:26
10/12/09 02:18:28
10/12/09 02:18:30
10/12/09 02:18:32
10/12/09 02:18:34
10/12/09 02:18:36
10/12/09 02:18:38
10/12/09 02:18:40
10/12/09 02:18:42
10/12/09 02:18:44
10/12/09 02:18:46
10/12/09 02:18:48
10/12/09 02:18:50
10/12/09 02:18:52
10/12/09 02:18:54
10/12/09 02:18:56
10/12/09 02:18:58
10/12/09 02:19:00
10/12/09 02:19:02
10/12/09 02:19:04
10/12/09 02:19:06
10/12/09 02:19:08
10/12/09 02:19:10
10/12/09 02:19:12
10/12/09 02:19:14
10/12/09 02:19:16
10/12/09 02:19:18
10/12/09 02:19:20
10/12/09 02:19:22
10/12/09 02:19:24
10/12/09 02:19:26
10/12/09 02:19:28
10/12/09 02:19:30
10/12/09 02:19:32
10/12/09 02:19:34
10/12/09 02:19:36
10/12/09 02:19:38
10/12/09 02:19:40
10/12/09 02:19:42
10/12/09 02:19:44
10/12/09 02:19:46
10/12/09 02:19:48
10/12/09 02:19:50
10/12/09 02:19:52
10/12/09 02:19:54
10/12/09 02:19:56
10/12/09 02:19:58
59.977
59.989
59.995
59.999
59.994
59.989
59.987
59.986
59.984
59.983
59.985
59.986
59.985
59.986
59.98
59.981
59.981
59.989
59.998
60.007
60.007
59.997
59.986
59.981
59.977
59.974
59.976
59.974
59.974
59.977
59.979
59.979
59.982
59.984
59.987
59.988
59.988
59.987
59.987
59.987
59.985
59.984
59.982
59.983
59.989
59.989
59.988
59.984
59.982
3680.254
3682.07
3681.329
3678.656
3678.077
3677.78
3678.427
3678.473
3678.278
3677.822
3676.615
3677.397
3677.917
3677.95
3678.617
3678.963
3681.252
3680.737
3680.045
3678.161
3674.076
3676.222
3676.669
3677.497
3677.49
3675.186
3675.437
3680.451
3682.032
3683.829
3682.843
3681.108
3680.566
3678.229
3676.752
3675.759
3671.942
3671.166
3670.476
3670.129
3671.542
3672.048
3671.576
3672.104
3672.414
3671.882
3671.837
3671.336
3670.726
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-262.289368
-262.289368
-256.647949
-256.647949
-256.647949
-256.647949
-256.647949
-256.307251
-256.307251
-256.307251
-256.307251
-256.307251
-249.086395
-249.086395
-249.086395
-249.086395
-249.086395
-253.742477
-253.742477
-253.742477
-253.742477
-253.742477
-257.421204
-257.421204
-257.421204
-257.421204
-257.421204
-261.73822
-261.73822
-261.73822
-261.73822
-261.73822
-271.875977
-271.875977
-271.875977
-271.875977
-271.875977
-262.073486
-262.073486
-262.073486
-262.073486
-262.073486
-260.36441
-260.36441
-260.36441
-260.36441
-260.36441
-352.644379
-352.644379
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
001946
10/12/09 02:20:00
10/12/09 02:20:02
10/12/09 02:20:04
10/12/09 02:20:06
10/12/09 02:20:08
10/12/09 02:20:10
10/12/09 02:20:12
10/12/09 02:20:14
10/12/09 02:20:16
10/12/09 02:20:18
10/12/09 02:20:20
10/12/09 02:20:22
10/12/09 02:20:24
10/12/09 02:20:26
10/12/09 02:20:28
10/12/09 02:20:30
10/12/09 02:20:32
10/12/09 02:20:34
10/12/09 02:20:36
10/12/09 02:20:38
10/12/09 02:20:40
10/12/09 02:20:42
10/12/09 02:20:44
10/12/09 02:20:46
10/12/09 02:20:48
10/12/09 02:20:50
10/12/09 02:20:52
10/12/09 02:20:54
10/12/09 02:20:56
10/12/09 02:20:58
10/12/09 02:21:00
10/12/09 02:21:02
10/12/09 02:21:04
10/12/09 02:21:06
10/12/09 02:21:08
10/12/09 02:21:10
10/12/09 02:21:12
10/12/09 02:21:14
10/12/09 02:21:16
10/12/09 02:21:18
10/12/09 02:21:20
10/12/09 02:21:22
10/12/09 02:21:24
10/12/09 02:21:26
10/12/09 02:21:28
10/12/09 02:21:30
10/12/09 02:21:32
10/12/09 02:21:34
10/12/09 02:21:36
59.983
59.981
59.982
59.983
59.986
59.989
59.987
59.985
59.98
59.98
59.983
59.98
59.979
59.979
59.981
59.981
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.981
59.979
59.976
59.977
59.972
59.971
59.973
59.973
59.973
59.974
59.971
59.975
59.977
59.977
59.975
59.976
59.98
59.979
59.981
59.982
59.982
59.982
59.982
59.981
59.982
59.984
3670.372
3671.364
3671.401
3672.156
3672.181
3670.296
3668.071
3668.59
3669.908
3670.399
3670.263
3669.382
3670.102
3670.438
3671.403
3672.442
3672.372
3671.947
3670.938
3670.705
3670.137
3669.279
3672.391
3672.558
3674.052
3672.626
3671.8
3673.183
3673.874
3676.263
3676.623
3676.87
3676.543
3675.464
3675.752
3675.256
3674.87
3671.277
3671.593
3670.587
3669.963
3669.54
3669.497
3668.706
3667.677
3666.482
3666.599
3666.911
3666.442
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-352.644379
-352.644379
-352.644379
-354.89566
-354.89566
-354.89566
-354.89566
-354.89566
-340.46936
-340.46936
-340.46936
-340.46936
-340.46936
-337.642914
-337.642914
-337.642914
-337.642914
-337.642914
-284.36084
-284.36084
-284.36084
-284.36084
-284.36084
-260.467987
-260.467987
-260.467987
-260.467987
-260.467987
-253.141541
-253.141541
-253.141541
-253.141541
-253.141541
-251.929871
-251.929871
-251.929871
-251.929871
-251.929871
-250.674194
-250.674194
-250.674194
-250.674194
-250.674194
-253.631866
-253.631866
-253.631866
-253.631866
-253.631866
-246.957306
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
001947
10/12/09 02:21:38
10/12/09 02:21:40
10/12/09 02:21:42
10/12/09 02:21:44
10/12/09 02:21:46
10/12/09 02:21:48
10/12/09 02:21:50
10/12/09 02:21:52
10/12/09 02:21:54
10/12/09 02:21:56
10/12/09 02:21:58
10/12/09 02:22:00
10/12/09 02:22:02
10/12/09 02:22:04
10/12/09 02:22:06
10/12/09 02:22:08
10/12/09 02:22:10
10/12/09 02:22:12
10/12/09 02:22:14
10/12/09 02:22:16
10/12/09 02:22:18
10/12/09 02:22:20
10/12/09 02:22:22
10/12/09 02:22:24
10/12/09 02:22:26
10/12/09 02:22:28
10/12/09 02:22:30
10/12/09 02:22:32
10/12/09 02:22:34
10/12/09 02:22:36
10/12/09 02:22:38
10/12/09 02:22:40
10/12/09 02:22:42
10/12/09 02:22:44
10/12/09 02:22:46
10/12/09 02:22:48
10/12/09 02:22:50
10/12/09 02:22:52
10/12/09 02:22:54
10/12/09 02:22:56
10/12/09 02:22:58
10/12/09 02:23:00
10/12/09 02:23:02
10/12/09 02:23:04
10/12/09 02:23:06
10/12/09 02:23:08
10/12/09 02:23:10
10/12/09 02:23:12
10/12/09 02:23:14
59.985
59.987
59.989
59.993
59.996
59.998
59.998
60.004
60.007
60.01
60.013
60.014
60.013
60.008
60.008
60.01
60.019
60.019
60.023
60.021
60.02
60.021
60.021
60.02
60.019
60.019
60.022
60.025
60.025
60.026
60.02
60.02
60.018
60.018
60.02
60.019
60.019
60.023
60.022
60.022
60.025
60.02
60.02
60.02
60.02
60.02
60.021
60.021
60.018
3666.405
3667.456
3666.38
3665.262
3664.031
3663.825
3663.229
3662.055
3661.695
3662.076
3662.224
3662.959
3663.794
3664.139
3665.278
3664.159
3663.265
3663.184
3661.929
3661.512
3659.172
3658.661
3656.785
3657.571
3658.126
3657.71
3658.015
3660.228
3659.224
3658.698
3658.669
3658.155
3659.13
3659.778
3660.82
3662.531
3662.387
3662.079
3662.39
3662.678
3663.577
3663.539
3662.959
3662.552
3662.543
3663.601
3663.91
3663.69
3662.791
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-246.957306
-246.957306
-246.957306
-246.957306
-254.541779
-254.541779
-254.541779
-254.541779
-254.541779
-256.571594
-256.571594
-256.571594
-256.571594
-256.571594
-258.37262
-258.37262
-258.37262
-258.37262
-258.37262
-263.047363
-263.047363
-263.047363
-263.047363
-263.047363
-260.984375
-260.984375
-260.984375
-260.984375
-260.984375
-261.318329
-261.318329
-261.318329
-261.318329
-261.318329
-262.1026
-262.1026
-262.1026
-262.1026
-262.1026
-262.71701
-262.71701
-262.71701
-262.71701
-262.71701
-260.016479
-260.016479
-260.016479
-260.016479
-260.016479
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
001948
10/12/09 02:23:16
10/12/09 02:23:18
10/12/09 02:23:20
10/12/09 02:23:22
10/12/09 02:23:24
10/12/09 02:23:26
10/12/09 02:23:28
10/12/09 02:23:30
10/12/09 02:23:32
10/12/09 02:23:34
10/12/09 02:23:36
10/12/09 02:23:38
10/12/09 02:23:40
10/12/09 02:23:42
10/12/09 02:23:44
10/12/09 02:23:46
10/12/09 02:23:48
10/12/09 02:23:50
10/12/09 02:23:52
10/12/09 02:23:54
10/12/09 02:23:56
10/12/09 02:23:58
10/12/09 02:24:00
10/12/09 02:24:02
10/12/09 02:24:04
10/12/09 02:24:06
10/12/09 02:24:08
10/12/09 02:24:10
10/12/09 02:24:12
10/12/09 02:24:14
10/12/09 02:24:16
10/12/09 02:24:18
10/12/09 02:24:20
10/12/09 02:24:22
10/12/09 02:24:24
10/12/09 02:24:26
10/12/09 02:24:28
10/12/09 02:24:30
10/12/09 02:24:32
10/12/09 02:24:34
10/12/09 02:24:36
10/12/09 02:24:38
10/12/09 02:24:40
10/12/09 02:24:42
10/12/09 02:24:44
10/12/09 02:24:46
10/12/09 02:24:48
10/12/09 02:24:50
10/12/09 02:24:52
60.014
60.014
60.014
60.013
60.013
60.01
60.008
60.011
60.011
60.012
60.012
60.009
60.009
60.009
60.009
60.005
60.002
59.999
59.996
59.995
59.997
59.998
59.998
59.998
59.998
59.995
59.995
59.992
59.993
59.988
59.988
59.982
59.982
59.982
59.982
59.984
59.982
59.978
59.978
59.976
59.975
59.974
59.974
59.979
59.98
59.981
59.98
59.984
59.987
3663.396
3663.698
3664.315
3665.313
3665.798
3666.141
3666.726
3667.677
3667.545
3666.688
3666.449
3666.71
3667.696
3667.398
3667.043
3666.624
3666.223
3665.88
3665.403
3665.802
3665.68
3665.352
3664.948
3665.065
3666.133
3666.64
3666.735
3667.084
3667.557
3667.337
3667.853
3668.116
3668.691
3669.399
3669.606
3671.228
3670.25
3670.265
3671.549
3673.243
3674.263
3675.824
3676.418
3676.306
3674.637
3675.329
3675.226
3674.768
3674.399
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-263.87323
-263.87323
-263.87323
-263.87323
-263.87323
-264.5979
-264.5979
-264.5979
-264.5979
-264.5979
-262.415924
-262.415924
-262.415924
-262.415924
-262.415924
-259.685242
-259.685242
-259.685242
-259.685242
-259.685242
-255.911011
-255.911011
-255.911011
-255.911011
-255.911011
-258.148193
-258.148193
-258.148193
-258.148193
-258.148193
-258.873596
-258.873596
-258.873596
-258.873596
-258.873596
-249.33757
-249.33757
-249.33757
-249.33757
-249.33757
-258.278168
-258.278168
-258.278168
-258.278168
-258.278168
-258.406372
-258.406372
-258.406372
-258.406372
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
001949
10/12/09 02:24:54
10/12/09 02:24:56
10/12/09 02:24:58
10/12/09 02:25:00
10/12/09 02:25:02
10/12/09 02:25:04
10/12/09 02:25:06
10/12/09 02:25:08
10/12/09 02:25:10
10/12/09 02:25:12
10/12/09 02:25:14
10/12/09 02:25:16
10/12/09 02:25:18
10/12/09 02:25:20
10/12/09 02:25:22
10/12/09 02:25:24
10/12/09 02:25:26
10/12/09 02:25:28
10/12/09 02:25:30
10/12/09 02:25:32
10/12/09 02:25:34
10/12/09 02:25:36
10/12/09 02:25:38
10/12/09 02:25:40
10/12/09 02:25:42
10/12/09 02:25:44
10/12/09 02:25:46
10/12/09 02:25:48
10/12/09 02:25:50
10/12/09 02:25:52
10/12/09 02:25:54
10/12/09 02:25:56
10/12/09 02:25:58
10/12/09 02:26:00
10/12/09 02:26:02
10/12/09 02:26:04
10/12/09 02:26:06
10/12/09 02:26:08
10/12/09 02:26:10
10/12/09 02:26:12
10/12/09 02:26:14
10/12/09 02:26:16
10/12/09 02:26:18
10/12/09 02:26:20
10/12/09 02:26:22
10/12/09 02:26:24
10/12/09 02:26:26
10/12/09 02:26:28
10/12/09 02:26:30
59.988
59.988
59.99
59.992
59.991
59.991
59.991
59.993
59.993
59.996
60.002
60.002
60.003
60.004
60.005
60.004
60.002
60.004
60.008
60.01
60.01
60.01
60.011
60.013
60.014
60.013
60.012
60.011
60.011
60.017
60.022
60.017
60.014
60.013
60.014
60.017
60.017
60.019
60.019
60.019
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
3673.514
3673.04
3672.442
3673.056
3671.68
3671.493
3669.53
3670.066
3670.028
3671.744
3671.578
3672.625
3672.674
3673.819
3673.25
3673.182
3673.496
3672.418
3672.363
3672.217
3672.261
3673.182
3673.603
3673.553
3674.312
3674.537
3673.813
3673.204
3672.563
3673.068
3672.388
3672.52
3671.25
3671.288
3672.989
3672.982
3672.915
3671.952
3671.193
3671.627
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-258.406372
-260.538879
-260.538879
-260.538879
-260.538879
-260.538879
-257.88208
-257.88208
-257.88208
-257.88208
-257.88208
-258.588654
-258.588654
-258.588654
-258.588654
-258.588654
-261.906158
-261.906158
-261.906158
-261.906158
-261.906158
-256.747803
-256.747803
-256.747803
-256.747803
-256.747803
-167.431976
-167.431976
-167.431976
-167.431976
-167.431976
-164.973404
-164.973404
-164.973404
-164.973404
-164.973404
-157.628082
-157.628082
-157.628082
-157.628082
-157.628082
-155.531708
-155.531708
-155.531708
-155.531708
-155.531708
-160.447235
-160.447235
-160.447235
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
001950
10/12/09 02:26:32
10/12/09 02:26:34
10/12/09 02:26:36
10/12/09 02:26:38
10/12/09 02:26:40
10/12/09 02:26:42
10/12/09 02:26:44
10/12/09 02:26:46
10/12/09 02:26:48
10/12/09 02:26:50
10/12/09 02:26:52
10/12/09 02:26:54
10/12/09 02:26:56
10/12/09 02:26:58
10/12/09 02:27:00
10/12/09 02:27:02
10/12/09 02:27:04
10/12/09 02:27:06
10/12/09 02:27:08
10/12/09 02:27:10
10/12/09 02:27:12
10/12/09 02:27:14
10/12/09 02:27:16
10/12/09 02:27:18
10/12/09 02:27:20
10/12/09 02:27:22
10/12/09 02:27:24
10/12/09 02:27:26
10/12/09 02:27:28
10/12/09 02:27:30
10/12/09 02:27:32
10/12/09 02:27:34
10/12/09 02:27:36
10/12/09 02:27:38
10/12/09 02:27:40
10/12/09 02:27:42
10/12/09 02:27:44
10/12/09 02:27:46
10/12/09 02:27:48
10/12/09 02:27:50
10/12/09 02:27:52
10/12/09 02:27:54
10/12/09 02:27:56
10/12/09 02:27:58
10/12/09 02:28:00
10/12/09 02:28:02
10/12/09 02:28:04
10/12/09 02:28:06
10/12/09 02:28:08
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.19
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3737.157
3761.25
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.5
3784.962
3784.73
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-160.447235
-160.447235
-163.958603
-163.958603
-163.958603
-163.958603
-163.958603
-166.072449
-166.072449
-166.072449
-166.072449
-166.072449
-163.766586
-163.766586
-163.766586
-163.766586
-163.766586
-165.101685
-165.101685
-165.101685
-165.101685
-165.101685
-165.476395
-165.476395
-165.476395
-165.476395
-165.476395
-206.459106
-206.459106
-206.459106
-206.459106
-206.459106
-211.256042
-211.256042
-211.256042
-211.256042
-211.256042
-214.346695
-214.346695
-214.346695
-214.346695
-214.346695
-212.172699
-212.172699
-212.172699
-212.172699
-212.172699
-215.598175
-215.598175
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
10
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
001951
10/12/09 02:28:10
10/12/09 02:28:12
10/12/09 02:28:14
10/12/09 02:28:16
10/12/09 02:28:18
10/12/09 02:28:20
10/12/09 02:28:22
10/12/09 02:28:24
10/12/09 02:28:26
10/12/09 02:28:28
10/12/09 02:28:30
10/12/09 02:28:32
10/12/09 02:28:34
10/12/09 02:28:36
10/12/09 02:28:38
10/12/09 02:28:40
10/12/09 02:28:42
10/12/09 02:28:44
10/12/09 02:28:46
10/12/09 02:28:48
10/12/09 02:28:50
10/12/09 02:28:52
10/12/09 02:28:54
10/12/09 02:28:56
10/12/09 02:28:58
10/12/09 02:29:00
10/12/09 02:29:02
10/12/09 02:29:04
10/12/09 02:29:06
10/12/09 02:29:08
10/12/09 02:29:10
10/12/09 02:29:12
10/12/09 02:29:14
10/12/09 02:29:16
10/12/09 02:29:18
10/12/09 02:29:20
10/12/09 02:29:22
10/12/09 02:29:24
10/12/09 02:29:26
10/12/09 02:29:28
10/12/09 02:29:30
10/12/09 02:29:32
10/12/09 02:29:34
10/12/09 02:29:36
10/12/09 02:29:38
10/12/09 02:29:40
10/12/09 02:29:42
10/12/09 02:29:44
10/12/09 02:29:46
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.01
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-215.598175
-215.598175
-215.598175
-218.327255
-218.327255
-218.327255
-218.327255
-218.327255
-217.379425
-217.379425
-217.379425
-217.379425
-217.379425
-214.830353
-214.830353
-214.830353
-214.830353
-214.830353
-227.655914
-227.655914
-227.655914
-227.655914
-227.655914
-225.018082
-225.018082
-225.018082
-225.018082
-225.018082
-228.365158
-228.365158
-228.365158
-228.365158
-228.365158
-234.075333
-234.075333
-234.075333
-234.075333
-234.075333
-228.798157
-228.798157
-228.798157
-228.798157
-228.798157
-229.466965
-229.466965
-229.466965
-229.466965
-229.466965
-228.980164
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
001952
10/12/09 02:29:48
10/12/09 02:29:50
10/12/09 02:29:52
10/12/09 02:29:54
10/12/09 02:29:56
10/12/09 02:29:58
10/12/09 02:30:00
10/12/09 02:30:02
10/12/09 02:30:04
10/12/09 02:30:06
10/12/09 02:30:08
10/12/09 02:30:10
10/12/09 02:30:12
10/12/09 02:30:14
10/12/09 02:30:16
10/12/09 02:30:18
10/12/09 02:30:20
10/12/09 02:30:22
10/12/09 02:30:24
10/12/09 02:30:26
10/12/09 02:30:28
10/12/09 02:30:30
10/12/09 02:30:32
10/12/09 02:30:34
10/12/09 02:30:36
10/12/09 02:30:38
10/12/09 02:30:40
10/12/09 02:30:42
10/12/09 02:30:44
10/12/09 02:30:46
10/12/09 02:30:48
10/12/09 02:30:50
10/12/09 02:30:52
10/12/09 02:30:54
10/12/09 02:30:56
10/12/09 02:30:58
10/12/09 02:31:00
10/12/09 02:31:02
10/12/09 02:31:04
10/12/09 02:31:06
10/12/09 02:31:08
10/12/09 02:31:10
10/12/09 02:31:12
10/12/09 02:31:14
10/12/09 02:31:16
10/12/09 02:31:18
10/12/09 02:31:20
10/12/09 02:31:22
10/12/09 02:31:24
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
3771.67
3769.63
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.81
3712.092
3714.623
3715.13
3716.168
3716.461
3716.98
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-228.980164
-228.980164
-228.980164
-228.980164
-219.975555
-219.975555
-219.975555
-219.975555
-219.975555
-229.089249
-229.089249
-229.089249
-229.089249
-229.089249
-229.663269
-229.663269
-229.663269
-229.663269
-229.663269
-229.233856
-229.233856
-229.233856
-229.233856
-229.233856
-231.409882
-231.409882
-231.409882
-231.409882
-231.409882
-218.622284
-218.622284
-218.622284
-218.622284
-218.622284
-213.535858
-213.535858
-213.535858
-213.535858
-213.535858
-225.651855
-225.651855
-225.651855
-225.651855
-225.651855
-212.573639
-212.573639
-212.573639
-212.573639
-212.573639
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
001953
10/12/09 02:31:26
10/12/09 02:31:28
10/12/09 02:31:30
10/12/09 02:31:32
10/12/09 02:31:34
10/12/09 02:31:36
10/12/09 02:31:38
10/12/09 02:31:40
10/12/09 02:31:42
10/12/09 02:31:44
10/12/09 02:31:46
10/12/09 02:31:48
10/12/09 02:31:50
10/12/09 02:31:52
10/12/09 02:31:54
10/12/09 02:31:56
10/12/09 02:31:58
10/12/09 02:32:00
10/12/09 02:32:02
10/12/09 02:32:04
10/12/09 02:32:06
10/12/09 02:32:08
10/12/09 02:32:10
10/12/09 02:32:12
10/12/09 02:32:14
10/12/09 02:32:16
10/12/09 02:32:18
10/12/09 02:32:20
10/12/09 02:32:22
10/12/09 02:32:24
10/12/09 02:32:26
10/12/09 02:32:28
10/12/09 02:32:30
10/12/09 02:32:32
10/12/09 02:32:34
10/12/09 02:32:36
10/12/09 02:32:38
10/12/09 02:32:40
10/12/09 02:32:42
10/12/09 02:32:44
10/12/09 02:32:46
10/12/09 02:32:48
10/12/09 02:32:50
10/12/09 02:32:52
10/12/09 02:32:54
10/12/09 02:32:56
10/12/09 02:32:58
10/12/09 02:33:00
10/12/09 02:33:02
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.13
3732.53
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.3
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.42
3778.554
3779.692
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-219.897293
-219.897293
-219.897293
-219.897293
-219.897293
-231.1754
-231.1754
-231.1754
-231.1754
-231.1754
-226.634125
-226.634125
-226.634125
-226.634125
-226.634125
-227.255066
-227.255066
-227.255066
-227.255066
-227.255066
-229.290222
-229.290222
-229.290222
-229.290222
-229.290222
-221.461365
-221.461365
-221.461365
-221.461365
-221.461365
-241.274368
-241.274368
-241.274368
-241.274368
-241.274368
-243.071854
-243.071854
-243.071854
-243.071854
-243.071854
-241.670212
-241.670212
-241.670212
-241.670212
-241.670212
-228.149307
-228.149307
-228.149307
-228.149307
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
001954
10/12/09 02:33:04
10/12/09 02:33:06
10/12/09 02:33:08
10/12/09 02:33:10
10/12/09 02:33:12
10/12/09 02:33:14
10/12/09 02:33:16
10/12/09 02:33:18
10/12/09 02:33:20
10/12/09 02:33:22
10/12/09 02:33:24
10/12/09 02:33:26
10/12/09 02:33:28
10/12/09 02:33:30
10/12/09 02:33:32
10/12/09 02:33:34
10/12/09 02:33:36
10/12/09 02:33:38
10/12/09 02:33:40
10/12/09 02:33:42
10/12/09 02:33:44
10/12/09 02:33:46
10/12/09 02:33:48
10/12/09 02:33:50
10/12/09 02:33:52
10/12/09 02:33:54
10/12/09 02:33:56
10/12/09 02:33:58
10/12/09 02:34:00
10/12/09 02:34:02
10/12/09 02:34:04
10/12/09 02:34:06
10/12/09 02:34:08
10/12/09 02:34:10
10/12/09 02:34:12
10/12/09 02:34:14
10/12/09 02:34:16
10/12/09 02:34:18
10/12/09 02:34:20
10/12/09 02:34:22
10/12/09 02:34:24
10/12/09 02:34:26
10/12/09 02:34:28
10/12/09 02:34:30
10/12/09 02:34:32
10/12/09 02:34:34
10/12/09 02:34:36
10/12/09 02:34:38
10/12/09 02:34:40
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.85
3786.304
3787.259
3787.516
3787.955
3788.03
3788.607
3789.216
3787.537
3785.842
3786.077
3787.93
3788.76
3786.875
3786.55
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-228.149307
-235.128983
-235.128983
-235.128983
-235.128983
-235.128983
-246.433136
-246.433136
-246.433136
-246.433136
-246.433136
-236.553543
-236.553543
-236.553543
-236.553543
-236.553543
-230.297562
-230.297562
-230.297562
-230.297562
-230.297562
-231.175537
-231.175537
-231.175537
-231.175537
-231.175537
-225.61763
-225.61763
-225.61763
-225.61763
-225.61763
-230.734421
-230.734421
-230.734421
-230.734421
-230.734421
-234.847107
-234.847107
-234.847107
-234.847107
-234.847107
-228.960922
-228.960922
-228.960922
-228.960922
-228.960922
-231.177917
-231.177917
-231.177917
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
316
316.5
317
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
001955
10/12/09 02:34:42
10/12/09 02:34:44
10/12/09 02:34:46
10/12/09 02:34:48
10/12/09 02:34:50
10/12/09 02:34:52
10/12/09 02:34:54
10/12/09 02:34:56
10/12/09 02:34:58
10/12/09 02:35:00
10/12/09 02:35:02
10/12/09 02:35:04
10/12/09 02:35:06
10/12/09 02:35:08
10/12/09 02:35:10
10/12/09 02:35:12
10/12/09 02:35:14
10/12/09 02:35:16
10/12/09 02:35:18
10/12/09 02:35:20
10/12/09 02:35:22
10/12/09 02:35:24
10/12/09 02:35:26
10/12/09 02:35:28
10/12/09 02:35:30
10/12/09 02:35:32
10/12/09 02:35:34
10/12/09 02:35:36
10/12/09 02:35:38
10/12/09 02:35:40
10/12/09 02:35:42
10/12/09 02:35:44
10/12/09 02:35:46
10/12/09 02:35:48
10/12/09 02:35:50
10/12/09 02:35:52
10/12/09 02:35:54
10/12/09 02:35:56
10/12/09 02:35:58
10/12/09 02:36:00
10/12/09 02:36:02
10/12/09 02:36:04
10/12/09 02:36:06
10/12/09 02:36:08
10/12/09 02:36:10
10/12/09 02:36:12
10/12/09 02:36:14
10/12/09 02:36:16
10/12/09 02:36:18
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
3789.769
3791.54
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.54
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.41
3790.467
3790.665
3790.42
3789.674
3789.267
3789.148
3790.43
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.08
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-231.177917
-231.177917
-236.489288
-236.489288
-236.489288
-236.489288
-236.489288
-245.038925
-245.038925
-245.038925
-245.038925
-245.038925
-223.605682
-223.605682
-223.605682
-223.605682
-223.605682
-231.119354
-231.119354
-231.119354
-231.119354
-231.119354
-237.20665
-237.20665
-237.20665
-237.20665
-237.20665
-240.516373
-240.516373
-240.516373
-240.516373
-240.516373
-237.566055
-237.566055
-237.566055
-237.566055
-237.566055
-231.581421
-231.581421
-231.581421
-231.581421
-231.581421
-235.850845
-235.850845
-235.850845
-235.850845
-235.850845
-233.559982
-233.559982
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
001956
10/12/09 02:36:20
10/12/09 02:36:22
10/12/09 02:36:24
10/12/09 02:36:26
10/12/09 02:36:28
10/12/09 02:36:30
10/12/09 02:36:32
10/12/09 02:36:34
10/12/09 02:36:36
10/12/09 02:36:38
10/12/09 02:36:40
10/12/09 02:36:42
10/12/09 02:36:44
10/12/09 02:36:46
10/12/09 02:36:48
10/12/09 02:36:50
10/12/09 02:36:52
10/12/09 02:36:54
10/12/09 02:36:56
10/12/09 02:36:58
10/12/09 02:37:00
10/12/09 02:37:02
10/12/09 02:37:04
10/12/09 02:37:06
10/12/09 02:37:08
10/12/09 02:37:10
10/12/09 02:37:12
10/12/09 02:37:14
10/12/09 02:37:16
10/12/09 02:37:18
10/12/09 02:37:20
10/12/09 02:37:22
10/12/09 02:37:24
10/12/09 02:37:26
10/12/09 02:37:28
10/12/09 02:37:30
10/12/09 02:37:32
10/12/09 02:37:34
10/12/09 02:37:36
10/12/09 02:37:38
10/12/09 02:37:40
10/12/09 02:37:42
10/12/09 02:37:44
10/12/09 02:37:46
10/12/09 02:37:48
10/12/09 02:37:50
10/12/09 02:37:52
10/12/09 02:37:54
10/12/09 02:37:56
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.69
3784.831
3785.01
3784.32
3782.809
3782.11
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.17
3771.73
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.25
3758.041
3760.965
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-233.559982
-233.559982
-233.559982
-219.009995
-219.009995
-219.009995
-219.009995
-219.009995
-205.338913
-205.338913
-205.338913
-205.338913
-205.338913
-236.285355
-236.285355
-236.285355
-236.285355
-236.285355
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
371.5
372
372.5
373
373.5
374
374.5
375
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
001957
10/12/09 02:37:58
10/12/09 02:38:00
10/12/09 02:38:02
10/12/09 02:38:04
10/12/09 02:38:06
10/12/09 02:38:08
10/12/09 02:38:10
10/12/09 02:38:12
10/12/09 02:38:14
10/12/09 02:38:16
10/12/09 02:38:18
10/12/09 02:38:20
10/12/09 02:38:22
10/12/09 02:38:24
10/12/09 02:38:26
10/12/09 02:38:28
10/12/09 02:38:30
10/12/09 02:38:32
10/12/09 02:38:34
10/12/09 02:38:36
10/12/09 02:38:38
10/12/09 02:38:40
10/12/09 02:38:42
10/12/09 02:38:44
10/12/09 02:38:46
10/12/09 02:38:48
10/12/09 02:38:50
10/12/09 02:38:52
10/12/09 02:38:54
10/12/09 02:38:56
10/12/09 02:38:58
10/12/09 02:39:00
10/12/09 02:39:02
10/12/09 02:39:04
10/12/09 02:39:06
10/12/09 02:39:08
10/12/09 02:39:10
10/12/09 02:39:12
10/12/09 02:39:14
10/12/09 02:39:16
10/12/09 02:39:18
10/12/09 02:39:20
10/12/09 02:39:22
10/12/09 02:39:24
10/12/09 02:39:26
10/12/09 02:39:28
10/12/09 02:39:30
10/12/09 02:39:32
10/12/09 02:39:34
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
3762.022
3763.822
3763.1
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.57
3761.92
3759.627
3758.522
3752.429
3750.102
3753.83
3753.51
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.37
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.65
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
396
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
413
413.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
001958
10/12/09 02:39:36
10/12/09 02:39:38
10/12/09 02:39:40
10/12/09 02:39:42
10/12/09 02:39:44
10/12/09 02:39:46
10/12/09 02:39:48
10/12/09 02:39:50
10/12/09 02:39:52
10/12/09 02:39:54
10/12/09 02:39:56
10/12/09 02:39:58
10/12/09 02:40:00
10/12/09 02:40:02
10/12/09 02:40:04
10/12/09 02:40:06
10/12/09 02:40:08
10/12/09 02:40:10
10/12/09 02:40:12
10/12/09 02:40:14
10/12/09 02:40:16
10/12/09 02:40:18
10/12/09 02:40:20
10/12/09 02:40:22
10/12/09 02:40:24
10/12/09 02:40:26
10/12/09 02:40:28
10/12/09 02:40:30
10/12/09 02:40:32
10/12/09 02:40:34
10/12/09 02:40:36
10/12/09 02:40:38
10/12/09 02:40:40
10/12/09 02:40:42
10/12/09 02:40:44
10/12/09 02:40:46
10/12/09 02:40:48
10/12/09 02:40:50
10/12/09 02:40:52
10/12/09 02:40:54
10/12/09 02:40:56
10/12/09 02:40:58
10/12/09 02:41:00
10/12/09 02:41:02
10/12/09 02:41:04
10/12/09 02:41:06
10/12/09 02:41:08
10/12/09 02:41:10
10/12/09 02:41:12
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.86
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.34
3750.7
3749.75
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.83
3737.583
3736.229
3734.897
3733.434
3733.115
3730.51
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
414
414.5
415
415.5
416
416.5
417
417.5
418
418.5
419
419.5
420
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
437.5
438
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
001959
10/12/09 02:41:14
10/12/09 02:41:16
10/12/09 02:41:18
10/12/09 02:41:20
10/12/09 02:41:22
10/12/09 02:41:24
10/12/09 02:41:26
10/12/09 02:41:28
10/12/09 02:41:30
10/12/09 02:41:32
10/12/09 02:41:34
10/12/09 02:41:36
10/12/09 02:41:38
10/12/09 02:41:40
10/12/09 02:41:42
10/12/09 02:41:44
10/12/09 02:41:46
10/12/09 02:41:48
10/12/09 02:41:50
10/12/09 02:41:52
10/12/09 02:41:54
10/12/09 02:41:56
10/12/09 02:41:58
10/12/09 02:42:00
10/12/09 02:42:02
10/12/09 02:42:04
10/12/09 02:42:06
10/12/09 02:42:08
10/12/09 02:42:10
10/12/09 02:42:12
10/12/09 02:42:14
10/12/09 02:42:16
10/12/09 02:42:18
10/12/09 02:42:20
10/12/09 02:42:22
10/12/09 02:42:24
10/12/09 02:42:26
10/12/09 02:42:28
10/12/09 02:42:30
10/12/09 02:42:32
10/12/09 02:42:34
10/12/09 02:42:36
10/12/09 02:42:38
10/12/09 02:42:40
10/12/09 02:42:42
10/12/09 02:42:44
10/12/09 02:42:46
10/12/09 02:42:48
10/12/09 02:42:50
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
60.043
60.045
60.04
60.041
60.039
60.039
60.036
60.038
60.033
60.034
60.037
60.037
60.035
3729.18
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.56
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.1
3690.477
3696.865
3696.877
3696.182
3696.541
3696.968
3698.686
3699.631
3698.787
3699.712
3700.106
3699.968
3701.122
3701.865
3701.614
3701.998
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
450.5
451
451.5
452
452.5
453
453.5
454
454.5
455
455.5
456
456.5
457
457.5
458
458.5
459
459.5
460
460.5
461
461.5
462
462.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.3
7800.63
7800.96
7801.29
7801.62
7801.95
7802.28
7802.61
7802.94
7803.27
7803.6
7803.93
7804.26
7804.59
7804.92
7805.25
001960
10/12/09 02:42:52
10/12/09 02:42:54
10/12/09 02:42:56
10/12/09 02:42:58
10/12/09 02:43:00
10/12/09 02:43:02
10/12/09 02:43:04
10/12/09 02:43:06
10/12/09 02:43:08
10/12/09 02:43:10
10/12/09 02:43:12
10/12/09 02:43:14
10/12/09 02:43:16
10/12/09 02:43:18
10/12/09 02:43:20
10/12/09 02:43:22
10/12/09 02:43:24
10/12/09 02:43:26
10/12/09 02:43:28
10/12/09 02:43:30
10/12/09 02:43:32
10/12/09 02:43:34
10/12/09 02:43:36
10/12/09 02:43:38
10/12/09 02:43:40
10/12/09 02:43:42
10/12/09 02:43:44
10/12/09 02:43:46
10/12/09 02:43:48
10/12/09 02:43:50
10/12/09 02:43:52
10/12/09 02:43:54
10/12/09 02:43:56
10/12/09 02:43:58
10/12/09 02:44:00
10/12/09 02:44:02
10/12/09 02:44:04
10/12/09 02:44:06
10/12/09 02:44:08
10/12/09 02:44:10
10/12/09 02:44:12
10/12/09 02:44:14
10/12/09 02:44:16
10/12/09 02:44:18
10/12/09 02:44:20
10/12/09 02:44:22
10/12/09 02:44:24
10/12/09 02:44:26
10/12/09 02:44:28
60.03
60.033
60.036
60.033
60.034
60.032
60.032
60.034
60.033
60.037
60.035
60.035
60.036
60.039
60.037
60.039
60.036
60.034
60.038
60.037
60.037
60.037
60.038
60.04
60.043
60.045
60.045
60.042
60.043
60.04
60.044
60.046
60.042
60.034
60.039
60.039
60.036
60.037
60.034
60.033
60.032
60.031
60.033
60.027
60.031
60.032
60.031
60.031
60.033
3702.913
3703.909
3705.522
3704.967
3704.087
3702.771
3703.706
3704.905
3705.435
3704.36
3702.588
3702.204
3701.942
3702.25
3703.318
3702.457
3702.525
3703.269
3703.844
3702.865
3702.518
3702.28
3692.427
3692.178
3700.276
3698.755
3697.729
3696.916
3697.368
3697.346
3698.429
3694.763
3693.584
3693.241
3696.798
3699.364
3701.791
3700.708
3700.753
3702.148
3705.213
3707.521
3707.287
3706.988
3707.34
3707.917
3707.384
3706.857
3707.615
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
463
463.5
464
464.5
465
465.5
466
466.5
467
467.5
468
468.5
469
469.5
470
470.5
471
471.5
472
472.5
473
473.5
474
474.5
475
475.5
476
476.5
477
477.5
478
478.5
479
479.5
480
480.5
481
481.5
482
482.5
483
483.5
484
484.5
485
485.5
486
486.5
487
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7805.58
7805.91
7806.24
7806.57
7806.9
7807.23
7807.56
7807.89
7808.22
7808.55
7808.88
7809.21
7809.54
7809.87
7810.2
7810.53
7810.86
7811.19
7811.52
7811.85
7812.18
7812.51
7812.84
7813.17
7813.5
7813.83
7814.16
7814.49
7814.82
7815.15
7815.48
7815.81
7816.14
7816.47
7816.8
7817.13
7817.46
7817.79
7818.12
7818.45
7818.78
7819.11
7819.44
7819.77
7820.1
7820.43
7820.76
7821.09
7821.42
001961
10/12/09 02:44:30
10/12/09 02:44:32
10/12/09 02:44:34
10/12/09 02:44:36
10/12/09 02:44:38
10/12/09 02:44:40
10/12/09 02:44:42
10/12/09 02:44:44
10/12/09 02:44:46
10/12/09 02:44:48
10/12/09 02:44:50
10/12/09 02:44:52
10/12/09 02:44:54
10/12/09 02:44:56
10/12/09 02:44:58
10/12/09 02:45:00
10/12/09 02:45:02
10/12/09 02:45:04
10/12/09 02:45:06
10/12/09 02:45:08
10/12/09 02:45:10
10/12/09 02:45:12
10/12/09 02:45:14
10/12/09 02:45:16
10/12/09 02:45:18
10/12/09 02:45:20
10/12/09 02:45:22
10/12/09 02:45:24
10/12/09 02:45:26
10/12/09 02:45:28
10/12/09 02:45:30
10/12/09 02:45:32
10/12/09 02:45:34
10/12/09 02:45:36
10/12/09 02:45:38
10/12/09 02:45:40
10/12/09 02:45:42
10/12/09 02:45:44
10/12/09 02:45:46
10/12/09 02:45:48
10/12/09 02:45:50
10/12/09 02:45:52
10/12/09 02:45:54
10/12/09 02:45:56
10/12/09 02:45:58
10/12/09 02:46:00
10/12/09 02:46:02
10/12/09 02:46:04
10/12/09 02:46:06
60.039
60.039
60.038
60.037
60.035
60.037
60.04
60.042
60.035
60.036
60.04
60.045
60.045
60.048
60.042
60.044
60.044
60.044
60.041
60.04
60.04
60.045
60.044
60.042
60.039
60.042
60.042
60.041
60.038
60.036
60.037
60.039
60.038
60.04
60.039
60.037
60.038
60.039
60.04
60.037
60.037
60.037
60.039
60.038
60.036
60.035
60.033
60.031
60.03
3706.823
3703.746
3701.582
3700.847
3701.208
3702.212
3701.686
3700.397
3699.69
3700.366
3700.827
3700.662
3696.935
3695.688
3695.819
3693.824
3694.799
3696.897
3696.023
3697.502
3698.424
3699.427
3700.177
3699.806
3697.577
3697.681
3698.507
3698.359
3698.466
3699.077
3700.262
3701.592
3700.902
3700.143
3700.27
3701.139
3701.586
3700.264
3699.458
3699.721
3700.458
3699.505
3698.794
3699.216
3699.4
3700.661
3702.173
3702.968
3705.195
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
487.5
488
488.5
489
489.5
490
490.5
491
491.5
492
492.5
493
493.5
494
494.5
495
495.5
496
496.5
497
497.5
498
498.5
499
499.5
500
500.5
501
501.5
502
502.5
503
503.5
504
504.5
505
505.5
506
506.5
507
507.5
508
508.5
509
509.5
510
510.5
511
511.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7821.75
7822.08
7822.41
7822.74
7823.07
7823.4
7823.73
7824.06
7824.39
7824.72
7825.05
7825.38
7825.71
7826.04
7826.37
7826.7
7827.03
7827.36
7827.69
7828.02
7828.35
7828.68
7829.01
7829.34
7829.67
7830
7830.33
7830.66
7830.99
7831.32
7831.65
7831.98
7832.31
7832.64
7832.97
7833.3
7833.63
7833.96
7834.29
7834.62
7834.95
7835.28
7835.61
7835.94
7836.27
7836.6
7836.93
7837.26
7837.59
001962
10/12/09 02:46:08
10/12/09 02:46:10
10/12/09 02:46:12
10/12/09 02:46:14
10/12/09 02:46:16
10/12/09 02:46:18
10/12/09 02:46:20
10/12/09 02:46:22
10/12/09 02:46:24
10/12/09 02:46:26
10/12/09 02:46:28
10/12/09 02:46:30
10/12/09 02:46:32
10/12/09 02:46:34
10/12/09 02:46:36
10/12/09 02:46:38
10/12/09 02:46:40
10/12/09 02:46:42
10/12/09 02:46:44
10/12/09 02:46:46
10/12/09 02:46:48
10/12/09 02:46:50
10/12/09 02:46:52
10/12/09 02:46:54
10/12/09 02:46:56
10/12/09 02:46:58
10/12/09 02:47:00
10/12/09 02:47:02
10/12/09 02:47:04
10/12/09 02:47:06
10/12/09 02:47:08
10/12/09 02:47:10
10/12/09 02:47:12
10/12/09 02:47:14
10/12/09 02:47:16
10/12/09 02:47:18
10/12/09 02:47:20
10/12/09 02:47:22
10/12/09 02:47:24
10/12/09 02:47:26
10/12/09 02:47:28
10/12/09 02:47:30
10/12/09 02:47:32
10/12/09 02:47:34
10/12/09 02:47:36
10/12/09 02:47:38
10/12/09 02:47:40
10/12/09 02:47:42
10/12/09 02:47:44
60.032
60.032
60.037
60.042
60.041
60.036
60.031
60.032
60.031
60.034
60.034
60.032
60.038
60.043
60.044
60.042
60.045
60.04
60.04
60.043
60.043
60.041
60.04
60.038
60.043
60.044
60.042
60.036
60.043
60.041
60.042
60.043
60.043
60.036
60.039
60.039
60.037
60.034
60.035
60.035
60.035
60.036
60.03
60.03
60.03
60.031
60.031
60.032
60.031
3704.952
3705.775
3705.621
3703.744
3701.981
3700.756
3700.747
3702.213
3705.059
3705.514
3704.449
3703.831
3703.62
3702.795
3701.432
3697.38
3696.25
3696.302
3693.518
3693.577
3695.197
3695.186
3693.786
3694.753
3694.926
3694.938
3694.159
3691.33
3692.686
3693.238
3693.39
3692.357
3690.951
3690.836
3692.042
3693.114
3694.117
3695.258
3695.581
3695.949
3695.491
3696.305
3696.486
3697.336
3699.171
3699.357
3699.251
3699.117
3699.105
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
512
512.5
513
513.5
514
514.5
515
515.5
516
516.5
517
517.5
518
518.5
519
519.5
520
520.5
521
521.5
522
522.5
523
523.5
524
524.5
525
525.5
526
526.5
527
527.5
528
528.5
529
529.5
530
530.5
531
531.5
532
532.5
533
533.5
534
534.5
535
535.5
536
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7837.92
7838.25
7838.58
7838.91
7839.24
7839.57
7839.9
7840.23
7840.56
7840.89
7841.22
7841.55
7841.88
7842.21
7842.54
7842.87
7843.2
7843.53
7843.86
7844.19
7844.52
7844.85
7845.18
7845.51
7845.84
7846.17
7846.5
7846.83
7847.16
7847.49
7847.82
7848.15
7848.48
7848.81
7849.14
7849.47
7849.8
7850.13
7850.46
7850.79
7851.12
7851.45
7851.78
7852.11
7852.44
7852.77
7853.1
7853.43
7853.76
001963
10/12/09 02:47:46
10/12/09 02:47:48
10/12/09 02:47:50
10/12/09 02:47:52
10/12/09 02:47:54
10/12/09 02:47:56
10/12/09 02:47:58
10/12/09 02:48:00
10/12/09 02:48:02
10/12/09 02:48:04
10/12/09 02:48:06
10/12/09 02:48:08
10/12/09 02:48:10
10/12/09 02:48:12
10/12/09 02:48:14
10/12/09 02:48:16
10/12/09 02:48:18
10/12/09 02:48:20
10/12/09 02:48:22
10/12/09 02:48:24
10/12/09 02:48:26
10/12/09 02:48:28
10/12/09 02:48:30
10/12/09 02:48:32
10/12/09 02:48:34
10/12/09 02:48:36
10/12/09 02:48:38
10/12/09 02:48:40
10/12/09 02:48:42
10/12/09 02:48:44
10/12/09 02:48:46
10/12/09 02:48:48
10/12/09 02:48:50
10/12/09 02:48:52
10/12/09 02:48:54
10/12/09 02:48:56
10/12/09 02:48:58
10/12/09 02:49:00
10/12/09 02:49:02
10/12/09 02:49:04
10/12/09 02:49:06
10/12/09 02:49:08
10/12/09 02:49:10
10/12/09 02:49:12
10/12/09 02:49:14
10/12/09 02:49:16
10/12/09 02:49:18
10/12/09 02:49:20
10/12/09 02:49:22
60.032
60.032
60.032
60.033
60.037
60.04
60.039
60.042
60.036
60.039
60.041
60.04
60.035
60.036
60.038
60.037
60.041
60.04
60.036
60.033
60.034
60.038
60.04
60.041
60.037
60.037
60.036
60.037
60.038
60.039
60.038
60.034
60.033
60.031
60.034
60.029
60.029
60.031
60.03
60.03
60.026
60.022
60.021
60.024
60.023
60.02
60.021
60.023
60.025
3699.126
3698.954
3698.136
3698.277
3697.412
3695.94
3693.736
3693.224
3691.759
3691.919
3692.798
3691.582
3692.374
3693.302
3694.71
3694.331
3693.815
3693.617
3694.324
3694.27
3694.66
3693.748
3692.532
3691.445
3691.012
3691.799
3693.077
3693.727
3693.117
3692.641
3688.159
3689.02
3688.208
3690.092
3693.172
3693.321
3694.593
3695.225
3694.609
3693.412
3693.509
3696.026
3698.012
3699.062
3699.414
3698.935
3700.084
3700.544
3700.486
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
536.5
537
537.5
538
538.5
539
539.5
540
540.5
541
541.5
542
542.5
543
543.5
544
544.5
545
545.5
546
546.5
547
547.5
548
548.5
549
549.5
550
550.5
551
551.5
552
552.5
553
553.5
554
554.5
555
555.5
556
556.5
557
557.5
558
558.5
559
559.5
560
560.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7854.09
7854.42
7854.75
7855.08
7855.41
7855.74
7856.07
7856.4
7856.73
7857.06
7857.39
7857.72
7858.05
7858.38
7858.71
7859.04
7859.37
7859.7
7860.03
7860.36
7860.69
7861.02
7861.35
7861.68
7862.01
7862.34
7862.67
7863
7863.33
7863.66
7863.99
7864.32
7864.65
7864.98
7865.31
7865.64
7865.97
7866.3
7866.63
7866.96
7867.29
7867.62
7867.95
7868.28
7868.61
7868.94
7869.27
7869.6
7869.93
001964
10/12/09 02:49:24
10/12/09 02:49:26
10/12/09 02:49:28
10/12/09 02:49:30
10/12/09 02:49:32
10/12/09 02:49:34
10/12/09 02:49:36
10/12/09 02:49:38
10/12/09 02:49:40
10/12/09 02:49:42
10/12/09 02:49:44
10/12/09 02:49:46
10/12/09 02:49:48
10/12/09 02:49:50
10/12/09 02:49:52
10/12/09 02:49:54
10/12/09 02:49:56
10/12/09 02:49:58
10/12/09 02:50:00
10/12/09 02:50:02
10/12/09 02:50:04
10/12/09 02:50:06
10/12/09 02:50:08
10/12/09 02:50:10
10/12/09 02:50:12
10/12/09 02:50:14
10/12/09 02:50:16
10/12/09 02:50:18
10/12/09 02:50:20
10/12/09 02:50:22
10/12/09 02:50:24
10/12/09 02:50:26
10/12/09 02:50:28
10/12/09 02:50:30
10/12/09 02:50:32
10/12/09 02:50:34
10/12/09 02:50:36
10/12/09 02:50:38
10/12/09 02:50:40
10/12/09 02:50:42
10/12/09 02:50:44
10/12/09 02:50:46
10/12/09 02:50:48
10/12/09 02:50:50
10/12/09 02:50:52
10/12/09 02:50:54
10/12/09 02:50:56
10/12/09 02:50:58
10/12/09 02:51:00
60.026
60.026
60.025
60.024
60.024
60.025
60.023
60.023
60.022
60.026
60.029
60.026
60.024
60.021
60.025
60.025
60.025
60.023
60.026
60.024
60.022
60.023
60.026
60.025
60.02
60.02
60.019
60.015
60.016
60.017
60.015
60.015
60.017
60.017
60.012
60.01
60.008
60.002
59.999
59.999
60.002
60.003
60.004
60.001
59.996
59.993
59.992
59.989
59.987
3698.596
3697.961
3699.914
3700.802
3701.301
3701.45
3701.349
3701.094
3701.702
3702.07
3701.965
3700.269
3700.241
3701.09
3701.268
3701.205
3700.587
3700.532
3700.177
3700.295
3700.277
3700.841
3700.863
3700.26
3700.052
3699.926
3700.965
3702.581
3703.516
3703.824
3703.672
3703.689
3703.003
3702.921
3703
3703.167
3703.918
3703.616
3703.775
3703.751
3701.534
3700.617
3700.88
3700.625
3701.389
3701.737
3700.671
3700.826
3700.977
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
561
561.5
562
562.5
563
563.5
564
564.5
565
565.5
566
566.5
567
567.5
568
568.5
569
569.5
570
570.5
571
571.5
572
572.5
573
573.5
574
574.5
575
575.5
576
576.5
577
577.5
578
578.5
579
579.5
580
580.5
581
581.5
582
582.5
583
583.5
584
584.5
585
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7870.26
7870.59
7870.92
7871.25
7871.58
7871.91
7872.24
7872.57
7872.9
7873.23
7873.56
7873.89
7874.22
7874.55
7874.88
7875.21
7875.54
7875.87
7876.2
7876.53
7876.86
7877.19
7877.52
7877.85
7878.18
7878.51
7878.84
7879.17
7879.5
7879.83
7880.16
7880.49
7880.82
7881.15
7881.48
7881.81
7882.14
7882.47
7882.8
7883.13
7883.46
7883.79
7884.12
7884.45
7884.78
7885.11
7885.44
7885.77
7886.1
001965
10/12/09 02:51:02
10/12/09 02:51:04
10/12/09 02:51:06
10/12/09 02:51:08
10/12/09 02:51:10
10/12/09 02:51:12
10/12/09 02:51:14
10/12/09 02:51:16
10/12/09 02:51:18
10/12/09 02:51:20
10/12/09 02:51:22
10/12/09 02:51:24
10/12/09 02:51:26
10/12/09 02:51:28
10/12/09 02:51:30
10/12/09 02:51:32
10/12/09 02:51:34
10/12/09 02:51:36
10/12/09 02:51:38
10/12/09 02:51:40
10/12/09 02:51:42
10/12/09 02:51:44
10/12/09 02:51:46
10/12/09 02:51:48
10/12/09 02:51:50
10/12/09 02:51:52
10/12/09 02:51:54
10/12/09 02:51:56
10/12/09 02:51:58
10/12/09 02:52:00
10/12/09 02:52:02
10/12/09 02:52:04
10/12/09 02:52:06
10/12/09 02:52:08
10/12/09 02:52:10
10/12/09 02:52:12
10/12/09 02:52:14
10/12/09 02:52:16
10/12/09 02:52:18
10/12/09 02:52:20
10/12/09 02:52:22
10/12/09 02:52:24
10/12/09 02:52:26
10/12/09 02:52:28
10/12/09 02:52:30
10/12/09 02:52:32
10/12/09 02:52:34
10/12/09 02:52:36
10/12/09 02:52:38
59.985
59.985
59.986
59.984
59.981
59.98
59.977
59.975
59.976
59.972
59.974
59.977
59.975
59.973
59.971
59.971
59.976
59.979
59.98
59.979
59.982
59.982
59.983
59.981
59.979
59.978
59.976
59.978
59.977
59.976
59.978
59.975
59.971
59.97
59.97
59.971
59.99
59.998
59.999
59.999
59.998
59.999
60.003
60.005
60.005
60.01
60.013
60.02
60.022
3700.7
3699.854
3700.237
3700.342
3700.77
3700.789
3701.625
3703.166
3704.187
3704.785
3705.811
3706.958
3706.688
3706.543
3706.257
3707.027
3710.118
3710.531
3708.701
3708.018
3706.942
3706.343
3706.125
3706.311
3706.119
3706.19
3707.721
3709.409
3708.971
3708.531
3708.071
3707.24
3709.213
3709.961
3711.75
3711.98
3710.695
3707.867
3704.912
3705.639
3703.787
3703.191
3702.071
3699.51
3698.658
3698.137
3697.882
3698.668
3698.604
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
585.5
586
586.5
587
587.5
588
588.5
589
589.5
590
590.5
591
591.5
592
592.5
593
593.5
594
594.5
595
595.5
596
596.5
597
597.5
598
598.5
599
599.5
600
600.5
601
601.5
602
602.5
603
603.5
604
604.5
605
605.5
606
606.5
607
607.5
608
608.5
609
609.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7886.43
7886.76
7887.09
7887.42
7887.75
7888.08
7888.41
7888.74
7889.07
7889.4
7889.73
7890.06
7890.39
7890.72
7891.05
7891.38
7891.71
7892.04
7892.37
7892.7
7893.03
7893.36
7893.69
7894.02
7894.35
7894.68
7895.01
7895.34
7895.67
7896
7896.33
7896.66
7896.99
7897.32
7897.65
7897.98
7898.31
7898.64
7898.97
7899.3
7899.63
7899.96
7900.29
7900.62
7900.95
7901.28
7901.61
7901.94
7902.27
001966
10/12/09 02:52:40
10/12/09 02:52:42
10/12/09 02:52:44
10/12/09 02:52:46
10/12/09 02:52:48
10/12/09 02:52:50
10/12/09 02:52:52
10/12/09 02:52:54
10/12/09 02:52:56
10/12/09 02:52:58
10/12/09 02:53:00
10/12/09 02:53:02
10/12/09 02:53:04
10/12/09 02:53:06
10/12/09 02:53:08
10/12/09 02:53:10
10/12/09 02:53:12
10/12/09 02:53:14
10/12/09 02:53:16
10/12/09 02:53:18
10/12/09 02:53:20
10/12/09 02:53:22
10/12/09 02:53:24
10/12/09 02:53:26
10/12/09 02:53:28
10/12/09 02:53:30
10/12/09 02:53:32
10/12/09 02:53:34
10/12/09 02:53:36
10/12/09 02:53:38
10/12/09 02:53:40
10/12/09 02:53:42
10/12/09 02:53:44
10/12/09 02:53:46
10/12/09 02:53:48
10/12/09 02:53:50
10/12/09 02:53:52
10/12/09 02:53:54
10/12/09 02:53:56
10/12/09 02:53:58
10/12/09 02:54:00
10/12/09 02:54:02
10/12/09 02:54:04
10/12/09 02:54:06
10/12/09 02:54:08
10/12/09 02:54:10
10/12/09 02:54:12
10/12/09 02:54:14
10/12/09 02:54:16
60.024
60.025
60.025
60.024
60.023
60.029
60.029
60.029
60.028
60.028
60.031
60.032
60.033
60.031
60.03
60.022
60.021
60.019
60.017
60.017
60.017
60.016
60.015
60.015
60.012
60.009
60.008
60.008
60.005
60.005
60.003
59.999
59.997
59.999
60
59.998
59.995
59.994
59.992
59.993
59.988
59.985
59.986
59.988
59.988
59.985
59.983
59.983
59.985
3697.868
3694.672
3693.912
3693.418
3688.301
3688.021
3689.143
3688.237
3687.878
3687.026
3686.683
3685.276
3685.576
3685.985
3686.418
3687.159
3687.873
3688.997
3690.426
3690.776
3692.715
3692.578
3692.462
3693.173
3693.249
3693.743
3695.124
3694.681
3694.741
3694.199
3693.75
3693.624
3692.806
3691.15
3691.407
3691.077
3690.588
3689.797
3688.483
3689.445
3689.553
3689.525
3689.736
3688.853
3688.24
3687.494
3687.475
3686.707
3685.66
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
610
610.5
611
611.5
612
612.5
613
613.5
614
614.5
615
615.5
616
616.5
617
617.5
618
618.5
619
619.5
620
620.5
621
621.5
622
622.5
623
623.5
624
624.5
625
625.5
626
626.5
627
627.5
628
628.5
629
629.5
630
630.5
631
631.5
632
632.5
633
633.5
634
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7902.6
7902.93
7903.26
7903.59
7903.92
7904.25
7904.58
7904.91
7905.24
7905.57
7905.9
7906.23
7906.56
7906.89
7907.22
7907.55
7907.88
7908.21
7908.54
7908.87
7909.2
7909.53
7909.86
7910.19
7910.52
7910.85
7911.18
7911.51
7911.84
7912.17
7912.5
7912.83
7913.16
7913.49
7913.82
7914.15
7914.48
7914.81
7915.14
7915.47
7915.8
7916.13
7916.46
7916.79
7917.12
7917.45
7917.78
7918.11
7918.44
001967
10/12/09 02:54:18
10/12/09 02:54:20
10/12/09 02:54:22
10/12/09 02:54:24
10/12/09 02:54:26
10/12/09 02:54:28
10/12/09 02:54:30
10/12/09 02:54:32
10/12/09 02:54:34
10/12/09 02:54:36
10/12/09 02:54:38
10/12/09 02:54:40
10/12/09 02:54:42
10/12/09 02:54:44
10/12/09 02:54:46
10/12/09 02:54:48
10/12/09 02:54:50
10/12/09 02:54:52
10/12/09 02:54:54
10/12/09 02:54:56
10/12/09 02:54:58
10/12/09 02:55:00
10/12/09 02:55:02
10/12/09 02:55:04
10/12/09 02:55:06
10/12/09 02:55:08
10/12/09 02:55:10
10/12/09 02:55:12
10/12/09 02:55:14
10/12/09 02:55:16
10/12/09 02:55:18
10/12/09 02:55:20
10/12/09 02:55:22
10/12/09 02:55:24
10/12/09 02:55:26
10/12/09 02:55:28
10/12/09 02:55:30
10/12/09 02:55:32
10/12/09 02:55:34
10/12/09 02:55:36
10/12/09 02:55:38
10/12/09 02:55:40
10/12/09 02:55:42
10/12/09 02:55:44
10/12/09 02:55:46
10/12/09 02:55:48
10/12/09 02:55:50
10/12/09 02:55:52
10/12/09 02:55:54
59.986
59.987
59.99
59.986
59.985
59.984
59.983
59.982
59.982
59.98
59.978
59.977
59.975
59.973
59.975
59.976
59.976
59.979
59.982
59.979
59.979
59.977
59.977
59.978
59.978
59.978
59.979
59.983
59.981
59.98
59.978
59.979
59.978
59.979
59.983
59.987
59.99
59.992
59.993
59.99
59.988
59.988
59.99
59.993
59.994
59.993
59.994
59.994
59.993
3684.51
3684.333
3683.911
3683.735
3684.208
3683.811
3683.473
3684.258
3684.884
3685.092
3685.654
3685.087
3685.491
3685.196
3687.412
3688.417
3688.599
3687.848
3686.678
3685.782
3684.89
3685.143
3684.549
3684.093
3684.555
3682.814
3682.318
3682.366
3682.647
3682.855
3683.557
3684.052
3684.318
3686.049
3686.629
3685.286
3683.415
3682.416
3681.403
3679.012
3679.436
3671.761
3670.717
3670.159
3679
3680.176
3681.799
3682.7
3684.116
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
634.5
635
635.5
636
636.5
637
637.5
638
638.5
639
639.5
640
640.5
641
641.5
642
642.5
643
643.5
644
644.5
645
645.5
646
646.5
647
647.5
648
648.5
649
649.5
650
650.5
651
651.5
652
652.5
653
653.5
654
654.5
655
655.5
656
656.5
657
657.5
658
658.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7918.77
7919.1
7919.43
7919.76
7920.09
7920.42
7920.75
7921.08
7921.41
7921.74
7922.07
7922.4
7922.73
7923.06
7923.39
7923.72
7924.05
7924.38
7924.71
7925.04
7925.37
7925.7
7926.03
7926.36
7926.69
7927.02
7927.35
7927.68
7928.01
7928.34
7928.67
7929
7929.33
7929.66
7929.99
7930.32
7930.65
7930.98
7931.31
7931.64
7931.97
7932.3
7932.63
7932.96
7933.29
7933.62
7933.95
7934.28
7934.61
001968
10/12/09 02:55:56
10/12/09 02:55:58
10/12/09 02:56:00
10/12/09 02:56:02
10/12/09 02:56:04
10/12/09 02:56:06
10/12/09 02:56:08
10/12/09 02:56:10
10/12/09 02:56:12
10/12/09 02:56:14
10/12/09 02:56:16
10/12/09 02:56:18
10/12/09 02:56:20
10/12/09 02:56:22
10/12/09 02:56:24
10/12/09 02:56:26
10/12/09 02:56:28
10/12/09 02:56:30
10/12/09 02:56:32
10/12/09 02:56:34
10/12/09 02:56:36
10/12/09 02:56:38
10/12/09 02:56:40
10/12/09 02:56:42
10/12/09 02:56:44
10/12/09 02:56:46
10/12/09 02:56:48
10/12/09 02:56:50
10/12/09 02:56:52
10/12/09 02:56:54
10/12/09 02:56:56
10/12/09 02:56:58
10/12/09 02:57:00
10/12/09 02:57:02
10/12/09 02:57:04
10/12/09 02:57:06
10/12/09 02:57:08
10/12/09 02:57:10
10/12/09 02:57:12
10/12/09 02:57:14
10/12/09 02:57:16
10/12/09 02:57:18
10/12/09 02:57:20
10/12/09 02:57:22
10/12/09 02:57:24
10/12/09 02:57:26
10/12/09 02:57:28
10/12/09 02:57:30
10/12/09 02:57:32
59.989
59.984
59.986
59.985
59.988
59.987
59.986
59.987
59.985
59.982
59.981
59.982
59.987
59.992
59.997
60
60.003
60.003
60.003
60.002
60.003
60.002
60.003
60.004
60.005
60.006
60.009
60.012
60.017
60.021
60.022
60.021
60.02
60.018
60.021
60.02
60.02
60.018
60.018
60.019
60.019
60.018
60.017
60.016
60.016
60.016
60.015
60.014
60.014
3685.03
3684.878
3684.165
3684.478
3685.584
3685.148
3684.587
3684.976
3683.674
3684.872
3684.245
3684.711
3685.589
3683.736
3682.579
3682.234
3682.138
3682.224
3681.689
3681.458
3681.65
3681.013
3680.167
3679.943
3679.429
3679.669
3678.981
3678.267
3676.796
3676.81
3674.798
3673.906
3671.145
3670.51
3673.648
3673.684
3675.865
3676.676
3676.404
3676.437
3677.185
3677.659
3678.828
3679.289
3678.915
3679.276
3678.599
3678.367
3678.25
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
659
659.5
660
660.5
661
661.5
662
662.5
663
663.5
664
664.5
665
665.5
666
666.5
667
667.5
668
668.5
669
669.5
670
670.5
671
671.5
672
672.5
673
673.5
674
674.5
675
675.5
676
676.5
677
677.5
678
678.5
679
679.5
680
680.5
681
681.5
682
682.5
683
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7934.94
7935.27
7935.6
7935.93
7936.26
7936.59
7936.92
7937.25
7937.58
7937.91
7938.24
7938.57
7938.9
7939.23
7939.56
7939.89
7940.22
7940.55
7940.88
7941.21
7941.54
7941.87
7942.2
7942.53
7942.86
7943.19
7943.52
7943.85
7944.18
7944.51
7944.84
7945.17
7945.5
7945.83
7946.16
7946.49
7946.82
7947.15
7947.48
7947.81
7948.14
7948.47
7948.8
7949.13
7949.46
7949.79
7950.12
7950.45
7950.78
001969
10/12/09 02:57:34
10/12/09 02:57:36
10/12/09 02:57:38
10/12/09 02:57:40
10/12/09 02:57:42
10/12/09 02:57:44
10/12/09 02:57:46
10/12/09 02:57:48
10/12/09 02:57:50
10/12/09 02:57:52
10/12/09 02:57:54
10/12/09 02:57:56
10/12/09 02:57:58
10/12/09 02:58:00
10/12/09 02:58:02
10/12/09 02:58:04
10/12/09 02:58:06
10/12/09 02:58:08
10/12/09 02:58:10
10/12/09 02:58:12
10/12/09 02:58:14
10/12/09 02:58:16
10/12/09 02:58:18
10/12/09 02:58:20
10/12/09 02:58:22
10/12/09 02:58:24
10/12/09 02:58:26
10/12/09 02:58:28
10/12/09 02:58:30
10/12/09 02:58:32
10/12/09 02:58:34
10/12/09 02:58:36
10/12/09 02:58:38
10/12/09 02:58:40
10/12/09 02:58:42
10/12/09 02:58:44
10/12/09 02:58:46
10/12/09 02:58:48
10/12/09 02:58:50
10/12/09 02:58:52
10/12/09 02:58:54
10/12/09 02:58:56
10/12/09 02:58:58
10/12/09 02:59:00
10/12/09 02:59:02
10/12/09 02:59:04
10/12/09 02:59:06
10/12/09 02:59:08
10/12/09 02:59:10
60.013
60.013
60.015
60.017
60.016
60.019
60.021
60.021
60.02
60.022
60.024
60.026
60.025
60.026
60.022
60.021
60.022
60.024
60.027
60.029
60.028
60.028
60.032
60.035
60.03
60.028
60.021
60.021
60.024
60.025
60.024
60.022
60.023
60.021
60.02
60.02
60.02
60.02
60.017
60.014
60.012
60.01
60.011
60.01
60.01
60.01
60.012
60.012
60.013
3678.589
3677.251
3675.698
3674.669
3674.87
3674.402
3674.546
3672.969
3671.914
3671.982
3670.946
3670.821
3671.06
3671.539
3673.794
3674.01
3675.102
3675.284
3676.051
3675.704
3672.583
3671.343
3670.232
3668.654
3668.767
3666.312
3667.322
3657.164
3657.714
3668.637
3669.309
3670.112
3670.735
3671.332
3672.095
3672.683
3673.833
3674.645
3675.641
3675.971
3677.009
3678.314
3679.393
3680.02
3679.792
3679.597
3680.315
3680.11
3679.062
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
683.5
684
684.5
685
685.5
686
686.5
687
687.5
688
688.5
689
689.5
690
690.5
691
691.5
692
692.5
693
693.5
694
694.5
695
695.5
696
696.5
697
697.5
698
698.5
699
699.5
700
700.5
701
701.5
702
702.5
703
703.5
704
704.5
705
705.5
706
706.5
707
707.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7951.11
7951.44
7951.77
7952.1
7952.43
7952.76
7953.09
7953.42
7953.75
7954.08
7954.41
7954.74
7955.07
7955.4
7955.73
7956.06
7956.39
7956.72
7957.05
7957.38
7957.71
7958.04
7958.37
7958.7
7959.03
7959.36
7959.69
7960.02
7960.35
7960.68
7961.01
7961.34
7961.67
7962
7962.33
7962.66
7962.99
7963.32
7963.65
7963.98
7964.31
7964.64
7964.97
7965.3
7965.63
7965.96
7966.29
7966.62
7966.95
001970
10/12/09 02:59:12
10/12/09 02:59:14
10/12/09 02:59:16
10/12/09 02:59:18
10/12/09 02:59:20
10/12/09 02:59:22
10/12/09 02:59:24
10/12/09 02:59:26
10/12/09 02:59:28
10/12/09 02:59:30
10/12/09 02:59:32
10/12/09 02:59:34
10/12/09 02:59:36
10/12/09 02:59:38
10/12/09 02:59:40
10/12/09 02:59:42
10/12/09 02:59:44
10/12/09 02:59:46
10/12/09 02:59:48
10/12/09 02:59:50
10/12/09 02:59:52
10/12/09 02:59:54
10/12/09 02:59:56
10/12/09 02:59:58
10/12/09 03:00:00
10/12/09 03:00:02
10/12/09 03:00:04
10/12/09 03:00:06
10/12/09 03:00:08
10/12/09 03:00:10
10/12/09 03:00:12
10/12/09 03:00:14
10/12/09 03:00:16
10/12/09 03:00:18
10/12/09 03:00:20
10/12/09 03:00:22
10/12/09 03:00:24
10/12/09 03:00:26
10/12/09 03:00:28
10/12/09 03:00:30
10/12/09 03:00:32
10/12/09 03:00:34
10/12/09 03:00:36
10/12/09 03:00:38
10/12/09 03:00:40
10/12/09 03:00:42
10/12/09 03:00:44
10/12/09 03:00:46
10/12/09 03:00:48
60.014
60.013
60.012
60.011
60.01
60.008
60.01
60.011
60.013
60.016
60.018
60.019
60.019
60.019
60.02
60.02
60.018
60.018
60.016
60.016
60.019
60.023
60.022
60.018
60.015
60.016
60.017
60.015
60.01
60.004
59.999
59.995
59.99
59.982
59.974
59.97
59.97
59.968
59.968
59.968
59.972
59.967
59.966
59.964
59.965
59.966
59.963
59.963
59.965
3679.127
3679.587
3679.637
3679.02
3678.418
3679.383
3679.681
3679.932
3679.138
3678.469
3678.499
3678.456
3677.615
3677.446
3677.431
3677.451
3677.315
3678.151
3678.362
3678.874
3680.771
3681.058
3680.353
3679.167
3679.553
3680.672
3682.73
3682.714
3681.915
3682.01
3682.483
3683.813
3685.306
3684.846
3684.643
3687.527
3689.404
3692.287
3692.966
3693.793
3694.397
3694.974
3697.407
3698.502
3698.617
3698.992
3699.85
3702.645
3701.989
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
708
708.5
709
709.5
710
710.5
711
711.5
712
712.5
713
713.5
714
714.5
715
715.5
716
716.5
717
717.5
718
718.5
719
719.5
720
720.5
721
721.5
722
722.5
723
723.5
724
724.5
725
725.5
726
726.5
727
727.5
728
728.5
729
729.5
730
730.5
731
731.5
732
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7967.28
7967.61
7967.94
7968.27
7968.6
7968.93
7969.26
7969.59
7969.92
7970.25
7970.58
7970.91
7971.24
7971.57
7971.9
7972.23
7972.56
7972.89
7973.22
7973.55
7973.88
7974.21
7974.54
7974.87
7975.2
7975.53
7975.86
7976.19
7976.52
7976.85
7977.18
7977.51
7977.84
7978.17
7978.5
7978.83
7979.16
7979.49
7979.82
7980.15
7980.48
7980.81
7981.14
7981.47
7981.8
7982.13
7982.46
7982.79
7983.12
001971
10/12/09 03:00:50
10/12/09 03:00:52
10/12/09 03:00:54
10/12/09 03:00:56
10/12/09 03:00:58
10/12/09 03:01:00
10/12/09 03:01:02
10/12/09 03:01:04
10/12/09 03:01:06
10/12/09 03:01:08
10/12/09 03:01:10
10/12/09 03:01:12
10/12/09 03:01:14
10/12/09 03:01:16
10/12/09 03:01:18
10/12/09 03:01:20
10/12/09 03:01:22
10/12/09 03:01:24
10/12/09 03:01:26
10/12/09 03:01:28
10/12/09 03:01:30
10/12/09 03:01:32
10/12/09 03:01:34
10/12/09 03:01:36
10/12/09 03:01:38
10/12/09 03:01:40
10/12/09 03:01:42
10/12/09 03:01:44
10/12/09 03:01:46
10/12/09 03:01:48
10/12/09 03:01:50
10/12/09 03:01:52
10/12/09 03:01:54
10/12/09 03:01:56
10/12/09 03:01:58
10/12/09 03:02:00
10/12/09 03:02:02
10/12/09 03:02:04
10/12/09 03:02:06
10/12/09 03:02:08
10/12/09 03:02:10
10/12/09 03:02:12
10/12/09 03:02:14
10/12/09 03:02:16
10/12/09 03:02:18
10/12/09 03:02:20
10/12/09 03:02:22
10/12/09 03:02:24
10/12/09 03:02:26
59.968
59.97
59.97
59.97
59.973
59.972
59.976
59.975
59.975
59.977
59.976
59.976
59.974
59.975
59.974
59.974
59.976
59.977
59.979
59.981
59.983
59.985
59.983
59.98
59.979
59.983
59.987
59.986
59.984
59.98
59.982
59.984
59.985
59.987
59.989
59.992
59.996
59.999
59.997
59.997
59.997
59.997
59.996
59.997
59.996
59.998
60.003
60.009
60.01
3702.218
3704.023
3703.365
3702.988
3703.814
3704.899
3705.625
3704.293
3702.094
3701.944
3703.142
3704.669
3705.376
3705.662
3705.855
3706.776
3707.514
3706.928
3706.446
3706.335
3706.771
3705.943
3704.127
3704.777
3705.974
3705.968
3705.356
3704.683
3703.913
3704.361
3704.988
3705.05
3704.893
3703.741
3701.831
3701.795
3700.07
3701.308
3700.429
3700.913
3700.541
3699.927
3700.858
3700.549
3700.614
3700.224
3699.5
3698.032
3697.96
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
732.5
733
733.5
734
734.5
735
735.5
736
736.5
737
737.5
738
738.5
739
739.5
740
740.5
741
741.5
742
742.5
743
743.5
744
744.5
745
745.5
746
746.5
747
747.5
748
748.5
749
749.5
750
750.5
751
751.5
752
752.5
753
753.5
754
754.5
755
755.5
756
756.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7983.45
7983.78
7984.11
7984.44
7984.77
7985.1
7985.43
7985.76
7986.09
7986.42
7986.75
7987.08
7987.41
7987.74
7988.07
7988.4
7988.73
7989.06
7989.39
7989.72
7990.05
7990.38
7990.71
7991.04
7991.37
7991.7
7992.03
7992.36
7992.69
7993.02
7993.35
7993.68
7994.01
7994.34
7994.67
7995
7995.33
7995.66
7995.99
7996.32
7996.65
7996.98
7997.31
7997.64
7997.97
7998.3
7998.63
7998.96
7999.29
001972
10/12/09 03:02:28
10/12/09 03:02:30
10/12/09 03:02:32
10/12/09 03:02:34
10/12/09 03:02:36
10/12/09 03:02:38
10/12/09 03:02:40
10/12/09 03:02:42
10/12/09 03:02:44
10/12/09 03:02:46
10/12/09 03:02:48
10/12/09 03:02:50
10/12/09 03:02:52
10/12/09 03:02:54
10/12/09 03:02:56
10/12/09 03:02:58
10/12/09 03:03:00
10/12/09 03:03:02
10/12/09 03:03:04
10/12/09 03:03:06
10/12/09 03:03:08
10/12/09 03:03:10
10/12/09 03:03:12
10/12/09 03:03:14
10/12/09 03:03:16
10/12/09 03:03:18
10/12/09 03:03:20
10/12/09 03:03:22
10/12/09 03:03:24
10/12/09 03:03:26
10/12/09 03:03:28
10/12/09 03:03:30
10/12/09 03:03:32
10/12/09 03:03:34
10/12/09 03:03:36
10/12/09 03:03:38
10/12/09 03:03:40
10/12/09 03:03:42
10/12/09 03:03:44
10/12/09 03:03:46
10/12/09 03:03:48
10/12/09 03:03:50
10/12/09 03:03:52
10/12/09 03:03:54
10/12/09 03:03:56
10/12/09 03:03:58
10/12/09 03:04:00
10/12/09 03:04:02
10/12/09 03:04:04
60.008
60.005
60.004
60.006
60.003
60.001
60.002
60.004
60.007
60.007
60.008
60.008
60.006
60.006
60.006
60.005
60
59.999
60
60
60.004
60.008
60.013
60.015
60.015
60.012
60.009
60.005
60.008
60.011
60.011
60.013
60.016
60.018
60.018
60.019
60.018
60.013
60.011
60.009
60.009
60.008
60.009
60.011
60.015
60.02
60.021
60.018
60.017
3699.409
3699.241
3700.738
3701.11
3701.238
3699.998
3700.22
3701.823
3702.554
3702.276
3701.026
3701.923
3702.943
3704.093
3703.96
3703.819
3704.455
3704.346
3705.329
3704.93
3704.405
3703.675
3702.748
3702.669
3703.017
3703.416
3703.297
3705.189
3705.279
3704.646
3704.051
3703.438
3704.255
3703.708
3703.83
3704.524
3704.139
3704.27
3705.429
3705.942
3705.54
3705.634
3705.749
3707.267
3706.945
3706.63
3705.655
3703.895
3704.224
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
757
757.5
758
758.5
759
759.5
760
760.5
761
761.5
762
762.5
763
763.5
764
764.5
765
765.5
766
766.5
767
767.5
768
768.5
769
769.5
770
770.5
771
771.5
772
772.5
773
773.5
774
774.5
775
775.5
776
776.5
777
777.5
778
778.5
779
779.5
780
780.5
781
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7999.62
7999.95
8000.28
8000.61
8000.94
8001.27
8001.6
8001.93
8002.26
8002.59
8002.92
8003.25
8003.58
8003.91
8004.24
8004.57
8004.9
8005.23
8005.56
8005.89
8006.22
8006.55
8006.88
8007.21
8007.54
8007.87
8008.2
8008.53
8008.86
8009.19
8009.52
8009.85
8010.18
8010.51
8010.84
8011.17
8011.5
8011.83
8012.16
8012.49
8012.82
8013.15
8013.48
8013.81
8014.14
8014.47
8014.8
8015.13
8015.46
001973
10/12/09 03:04:06
10/12/09 03:04:08
10/12/09 03:04:10
10/12/09 03:04:12
10/12/09 03:04:14
10/12/09 03:04:16
10/12/09 03:04:18
10/12/09 03:04:20
10/12/09 03:04:22
10/12/09 03:04:24
10/12/09 03:04:26
10/12/09 03:04:28
10/12/09 03:04:30
10/12/09 03:04:32
10/12/09 03:04:34
10/12/09 03:04:36
10/12/09 03:04:38
10/12/09 03:04:40
10/12/09 03:04:42
10/12/09 03:04:44
10/12/09 03:04:46
10/12/09 03:04:48
10/12/09 03:04:50
10/12/09 03:04:52
10/12/09 03:04:54
10/12/09 03:04:56
10/12/09 03:04:58
10/12/09 03:05:00
10/12/09 03:05:02
10/12/09 03:05:04
10/12/09 03:05:06
10/12/09 03:05:08
10/12/09 03:05:10
10/12/09 03:05:12
10/12/09 03:05:14
10/12/09 03:05:16
10/12/09 03:05:18
10/12/09 03:05:20
10/12/09 03:05:22
10/12/09 03:05:24
10/12/09 03:05:26
10/12/09 03:05:28
10/12/09 03:05:30
10/12/09 03:05:32
10/12/09 03:05:34
10/12/09 03:05:36
10/12/09 03:05:38
10/12/09 03:05:40
10/12/09 03:05:42
60.019
60.019
60.021
60.022
60.025
60.027
60.03
60.027
60.023
60.021
60.023
60.023
60.02
60.024
60.024
60.022
60.022
60.024
60.025
60.023
60.024
60.02
60.018
60.013
60.008
60.012
60.017
60.019
60.019
60.015
60.016
60.015
60.016
60.014
60.016
60.018
60.019
60.016
60.014
60.014
60.018
60.022
60.023
60.024
60.026
60.026
60.024
60.022
60.02
3703.887
3704.648
3704.795
3704.167
3702.764
3702.008
3700.36
3701.063
3700.34
3699.369
3701.568
3702.959
3704.25
3703.621
3703.374
3703.036
3703.931
3704.947
3704.208
3703.541
3703.16
3703.397
3704.376
3705.441
3706.995
3710.072
3707.971
3707.767
3707.609
3708.831
3709.465
3709.813
3709.817
3709.99
3709.094
3709.642
3709.812
3709.933
3710.677
3710.591
3709.354
3707.696
3707.38
3707.12
3706.99
3705.848
3704.185
3704.406
3704.963
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
781.5
782
782.5
783
783.5
784
784.5
785
785.5
786
786.5
787
787.5
788
788.5
789
789.5
790
790.5
791
791.5
792
792.5
793
793.5
794
794.5
795
795.5
796
796.5
797
797.5
798
798.5
799
799.5
800
800.5
801
801.5
802
802.5
803
803.5
804
804.5
805
805.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8015.79
8016.12
8016.45
8016.78
8017.11
8017.44
8017.77
8018.1
8018.43
8018.76
8019.09
8019.42
8019.75
8020.08
8020.41
8020.74
8021.07
8021.4
8021.73
8022.06
8022.39
8022.72
8023.05
8023.38
8023.71
8024.04
8024.37
8024.7
8025.03
8025.36
8025.69
8026.02
8026.35
8026.68
8027.01
8027.34
8027.67
8028
8028.33
8028.66
8028.99
8029.32
8029.65
8029.98
8030.31
8030.64
8030.97
8031.3
8031.63
001974
10/12/09 03:05:44
10/12/09 03:05:46
10/12/09 03:05:48
10/12/09 03:05:50
10/12/09 03:05:52
10/12/09 03:05:54
10/12/09 03:05:56
10/12/09 03:05:58
10/12/09 03:06:00
10/12/09 03:06:02
10/12/09 03:06:04
10/12/09 03:06:06
10/12/09 03:06:08
10/12/09 03:06:10
10/12/09 03:06:12
10/12/09 03:06:14
10/12/09 03:06:16
10/12/09 03:06:18
10/12/09 03:06:20
10/12/09 03:06:22
10/12/09 03:06:24
10/12/09 03:06:26
10/12/09 03:06:28
10/12/09 03:06:30
10/12/09 03:06:32
10/12/09 03:06:34
10/12/09 03:06:36
10/12/09 03:06:38
10/12/09 03:06:40
10/12/09 03:06:42
10/12/09 03:06:44
10/12/09 03:06:46
10/12/09 03:06:48
10/12/09 03:06:50
10/12/09 03:06:52
10/12/09 03:06:54
10/12/09 03:06:56
10/12/09 03:06:58
10/12/09 03:07:00
10/12/09 03:07:02
10/12/09 03:07:04
10/12/09 03:07:06
10/12/09 03:07:08
10/12/09 03:07:10
10/12/09 03:07:12
10/12/09 03:07:14
10/12/09 03:07:16
10/12/09 03:07:18
10/12/09 03:07:20
60.019
60.022
60.025
60.028
60.03
60.031
60.029
60.026
60.026
60.029
60.03
60.033
60.03
60.022
60.016
60.019
60.03
60.028
60.021
60.015
60.015
60.012
60.011
60.014
60.013
60.014
60.016
60.016
60.015
60.013
60.007
59.997
59.994
59.993
59.99
59.993
59.994
59.993
59.994
59.993
59.996
59.988
59.985
59.983
59.982
59.98
59.977
59.981
59.982
3706.567
3705.516
3704.869
3704.428
3704.773
3703.532
3702.686
3702.093
3703.169
3703.676
3701.52
3700.106
3698.222
3698.009
3700.28
3703.192
3703.815
3701.863
3699.956
3700.816
3703.802
3706.943
3708.527
3707.49
3707.647
3706.991
3707.495
3705.584
3705.398
3707.12
3709.144
3708.99
3708.291
3706.193
3707.304
3707.903
3706.76
3706.921
3706.683
3706.888
3704.934
3705.678
3706.481
3707.071
3706.696
3707.479
3708.246
3709.436
3710.419
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
806
806.5
807
807.5
808
808.5
809
809.5
810
810.5
811
811.5
812
812.5
813
813.5
814
814.5
815
815.5
816
816.5
817
817.5
818
818.5
819
819.5
820
820.5
821
821.5
822
822.5
823
823.5
824
824.5
825
825.5
826
826.5
827
827.5
828
828.5
829
829.5
830
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8031.96
8032.29
8032.62
8032.95
8033.28
8033.61
8033.94
8034.27
8034.6
8034.93
8035.26
8035.59
8035.92
8036.25
8036.58
8036.91
8037.24
8037.57
8037.9
8038.23
8038.56
8038.89
8039.22
8039.55
8039.88
8040.21
8040.54
8040.87
8041.2
8041.53
8041.86
8042.19
8042.52
8042.85
8043.18
8043.51
8043.84
8044.17
8044.5
8044.83
8045.16
8045.49
8045.82
8046.15
8046.48
8046.81
8047.14
8047.47
8047.8
001975
10/12/09 03:07:22
10/12/09 03:07:24
10/12/09 03:07:26
10/12/09 03:07:28
10/12/09 03:07:30
10/12/09 03:07:32
10/12/09 03:07:34
10/12/09 03:07:36
10/12/09 03:07:38
10/12/09 03:07:40
10/12/09 03:07:42
10/12/09 03:07:44
10/12/09 03:07:46
10/12/09 03:07:48
10/12/09 03:07:50
10/12/09 03:07:52
10/12/09 03:07:54
10/12/09 03:07:56
10/12/09 03:07:58
10/12/09 03:08:00
10/12/09 03:08:02
10/12/09 03:08:04
10/12/09 03:08:06
10/12/09 03:08:08
10/12/09 03:08:10
10/12/09 03:08:12
10/12/09 03:08:14
10/12/09 03:08:16
10/12/09 03:08:18
10/12/09 03:08:20
10/12/09 03:08:22
10/12/09 03:08:24
10/12/09 03:08:26
10/12/09 03:08:28
10/12/09 03:08:30
10/12/09 03:08:32
10/12/09 03:08:34
10/12/09 03:08:36
10/12/09 03:08:38
10/12/09 03:08:40
10/12/09 03:08:42
10/12/09 03:08:44
10/12/09 03:08:46
10/12/09 03:08:48
10/12/09 03:08:50
10/12/09 03:08:52
10/12/09 03:08:54
10/12/09 03:08:56
10/12/09 03:08:58
59.978
59.98
59.98
59.977
59.98
59.983
59.984
59.981
59.981
59.98
59.981
59.981
59.981
59.98
59.978
59.978
59.979
59.978
59.976
59.976
59.975
59.976
59.975
59.979
59.978
59.975
59.976
59.981
59.977
59.975
59.976
59.979
59.98
59.979
59.978
59.979
59.982
59.983
59.987
59.988
59.984
59.98
59.979
59.98
59.979
59.978
59.975
59.979
59.982
3710.134
3708.708
3710.024
3709.192
3708.335
3709.399
3707.911
3709.004
3707.638
3709.689
3708.945
3706.541
3711.256
3711.362
3712.303
3712.012
3711.703
3712.093
3713.992
3714.612
3715.083
3715.323
3714.794
3714.717
3715.161
3715.001
3713.996
3714.063
3714.335
3715.631
3715.688
3715.567
3715.725
3714.848
3713.142
3713.358
3712.275
3712.619
3712.153
3710.05
3709.082
3710.472
3710.624
3710.946
3710.2
3710.475
3709.462
3710.803
3709.286
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
830.5
831
831.5
832
832.5
833
833.5
834
834.5
835
835.5
836
836.5
837
837.5
838
838.5
839
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8048.13
8048.46
8048.79
8049.12
8049.45
8049.78
8050.11
8050.44
8050.77
8051.1
8051.43
8051.76
8052.09
8052.42
8052.75
8053.08
8053.41
8053.74
8054.07
8054.4
8054.73
8055.06
8055.39
8055.72
8056.05
8056.38
8056.71
8057.04
8057.37
8057.7
8058.03
8058.36
8058.69
8059.02
8059.35
8059.68
8060.01
8060.34
8060.67
8061
8061.33
8061.66
8061.99
8062.32
8062.65
8062.98
8063.31
8063.64
8063.97
001976
10/12/09 03:09:00
10/12/09 03:09:02
10/12/09 03:09:04
10/12/09 03:09:06
10/12/09 03:09:08
10/12/09 03:09:10
10/12/09 03:09:12
10/12/09 03:09:14
10/12/09 03:09:16
10/12/09 03:09:18
10/12/09 03:09:20
10/12/09 03:09:22
10/12/09 03:09:24
10/12/09 03:09:26
10/12/09 03:09:28
10/12/09 03:09:30
10/12/09 03:09:32
10/12/09 03:09:34
10/12/09 03:09:36
10/12/09 03:09:38
10/12/09 03:09:40
10/12/09 03:09:42
10/12/09 03:09:44
10/12/09 03:09:46
10/12/09 03:09:48
10/12/09 03:09:50
10/12/09 03:09:52
10/12/09 03:09:54
10/12/09 03:09:56
10/12/09 03:09:58
10/12/09 03:10:00
10/12/09 03:10:02
10/12/09 03:10:04
10/12/09 03:10:06
10/12/09 03:10:08
10/12/09 03:10:10
10/12/09 03:10:12
10/12/09 03:10:14
10/12/09 03:10:16
10/12/09 03:10:18
10/12/09 03:10:20
10/12/09 03:10:22
10/12/09 03:10:24
10/12/09 03:10:26
10/12/09 03:10:28
10/12/09 03:10:30
10/12/09 03:10:32
10/12/09 03:10:34
10/12/09 03:10:36
59.983
59.983
59.985
59.99
59.987
59.984
59.976
59.979
59.985
59.983
59.979
59.981
59.978
59.975
59.978
59.989
59.999
59.994
59.989
59.986
59.984
59.983
59.982
59.98
59.99
59.995
59.995
59.99
59.989
59.991
59.996
60
60.002
60.004
60.004
60.002
59.999
59.998
59.995
59.996
60.001
60.002
60.001
60.003
60.005
60.004
60.004
60.004
60.006
3710.573
3709.525
3708.371
3708.527
3706.512
3707.49
3708.962
3709.894
3712.303
3711.35
3711.627
3712.076
3712.393
3712.999
3713.51
3716.626
3715.443
3712.092
3713.906
3714.894
3714.953
3716.122
3716.308
3715.438
3714.764
3714.714
3715.068
3715.927
3715.791
3716.285
3715.324
3714.46
3711.708
3712.698
3712.851
3713.362
3716.641
3718.292
3719.079
3718.233
3717.815
3717.889
3718.56
3718.195
3719.021
3718.821
3719.897
3719.299
3719.643
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
8064.3
8064.63
8064.96
8065.29
8065.62
8065.95
8066.28
8066.61
8066.94
8067.27
8067.6
8067.93
8068.26
8068.59
8068.92
8069.25
8069.58
8069.91
8070.24
8070.57
8070.9
8071.23
8071.56
8071.89
8072.22
8072.55
8072.88
8073.21
8073.54
8073.87
8074.2
8074.53
8074.86
8075.19
8075.52
8075.85
8076.18
8076.51
8076.84
8077.17
8077.5
8077.83
8078.16
8078.49
8078.82
8079.15
8079.48
8079.81
8080.14
001977
10/12/09 03:10:38
10/12/09 03:10:40
10/12/09 03:10:42
10/12/09 03:10:44
10/12/09 03:10:46
10/12/09 03:10:48
10/12/09 03:10:50
10/12/09 03:10:52
10/12/09 03:10:54
10/12/09 03:10:56
10/12/09 03:10:58
10/12/09 03:11:00
10/12/09 03:11:02
10/12/09 03:11:04
10/12/09 03:11:06
10/12/09 03:11:08
10/12/09 03:11:10
10/12/09 03:11:12
10/12/09 03:11:14
10/12/09 03:11:16
10/12/09 03:11:18
10/12/09 03:11:20
10/12/09 03:11:22
10/12/09 03:11:24
10/12/09 03:11:26
10/12/09 03:11:28
10/12/09 03:11:30
10/12/09 03:11:32
10/12/09 03:11:34
10/12/09 03:11:36
10/12/09 03:11:38
10/12/09 03:11:40
10/12/09 03:11:42
10/12/09 03:11:44
10/12/09 03:11:46
10/12/09 03:11:48
10/12/09 03:11:50
10/12/09 03:11:52
10/12/09 03:11:54
10/12/09 03:11:56
10/12/09 03:11:58
10/12/09 03:12:00
60.003
60.005
60.006
60.009
60.009
60.01
60.009
60.013
60.015
60.014
60.009
60.009
60.008
60.011
60.01
60.009
60.013
60.013
60.014
60.014
60.012
60.01
60.011
60.007
60.003
60.001
60
59.998
59.998
59.999
60.002
60.003
60.003
59.999
59.998
60.001
59.995
59.989
59.987
59.988
59.988
59.99
3719.527
3719.731
3720.279
3718.58
3718.976
3718.982
3720.034
3720.609
3720.811
3721.239
3720.38
3719.447
3720.807
3721.272
3720.592
3721.245
3721.594
3722.176
3721.999
3721.646
3721.678
3720.86
3721.645
3723.816
3725.07
3724.656
3724.869
3724.661
3723.696
3723.58
3723.405
3721.879
3722.401
3722.906
3724.142
3723.65
3723.201
3723.639
3723.881
3724.654
3725.361
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
8080.47
8080.8
8081.13
8081.46
8081.79
8082.12
8082.45
8082.78
8083.11
8083.44
8083.77
8084.1
8084.43
8084.76
8085.09
8085.42
8085.75
8086.08
8086.41
8086.74
8087.07
8087.4
8087.73
8088.06
8088.39
8088.72
8089.05
8089.38
8089.71
8090.04
8090.37
8090.7
8091.03
8091.36
8091.69
8092.02
8092.35
8092.68
8093.01
8093.34
8093.67
8094
001978
Balancing Authority Name: My BA
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-80
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Step 4.
Enter MW output of generator or load that caused event (+ for gen loss, - for load loss)
(Value from NERC Event List. If multiple units, enter total MW loss.)
If MW loss value is not known, enter a default 1000 MW.
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 5. worksheet.
2:27:26
2:32:54
633 MW
Event Frequency Data
60.1
60.05
60
Copy Form 2 data for
Pasting into Form 1
59.95
59.9
59.85
59.8
59.75
Step 6. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Step 7. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
2:12:00
2:14:00
2:16:00
2:18:00
2:20:00
2:22:00
2:24:00
2:26:00
2:28:00
2:30:00
2:32:00
2:34:00
2:36:00
2:38:00
2:40:00
2:42:00
2:44:00
2:46:00
2:48:00
2:50:00
2:52:00
2:54:00
2:56:00
2:58:00
3:00:00
3:02:00
3:04:00
3:06:00
3:08:00
3:10:00
3:12:00
59.7
Hz
001979
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
Interchange
MW
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
Value B
20 to 52 sec
Average
Frequency
Average
MW
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8891
-0.153
3645.73
3788.35
142.63
-15.40
-33.70
88.71
122.41
Balancing Authority My BA
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
3764.46
3774.78
3719.65
3640.68
92.16
0:05:28
No
134.10
123.78
No
Yes
Yes
41.94
31.61
Up
107.00 MW
Yes
1.333 P.U.
A Point
FPointA
A Value
C Value
Delta FCA
FR C
Slope A-C dF/dT
C Value Maximum Resource Loss
Secondary C Value
60.000 Hz
2400.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-80 MW/0.1 Hz
2:27:24
60.0390
2:27:24 AM
60.0421
59.8360
#N/A
-0.20612669
-307.1 MW/0.1 Hz
#N/A
Hz/second
633
No
n/a
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Tzero
2:27:24
FT+4 59.83599854
FT+10 59.89199829
FT+20 59.88299942
FT+60 59.88999939
Interconnection Evaluation
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
B Value Average Resource Loss
Interchange Target Relative Average Change - MW (Low Frequency Event)
B Value Average LaaR Loss
Interchange Actual Relative Average Change - MW (Low Frequency Event)
B Value Average Net Loss
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interconnection Bias Setting
Interchange Actual Relative Average Change - MW (High Frequency Event)
IPFR as a % of Bias Setting
Ramp Direction during frequency recovery period
Interconnection Total Energy
-660
0.00%
37446
Interconnection Peak Energy
62339
633
0
633
60.07%
0.923 P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-21.600
-20.801
-20.801
-17.599
-15.201
-13.599
-15.201
-16.000
-15.201
-16.800
-16.800
-16.800
-15.201
-14.401
-17.599
-24.799
-29.599
-29.599
-28.799
(TC)
Delayed
Delivery
Frequency
Response
-7.560
-12.194
-15.207
-16.044
-15.749
-14.996
-15.068
-15.394
-15.327
-15.842
-16.177
-16.395
-15.977
-15.426
-16.186
-19.201
-22.840
-25.206
-26.464
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average
Ramp
MW/scan
Recovery
Period
Target
MW
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
3666.787
3666.185
3665.976
3665.185
3664.573
3664.079
3664.221
3664.497
3663.460
3660.170
3656.254
3653.612
3652.078
Average
Output
During
Recovery
Period
MW
Average
Target
During
Recovery
Period
MW
Recovery
Period
Ramp
MW
Average
Ramp
During
Recovery
Period
MW
Generator Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
MW
633
LaaR
Trip
MW
001980
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
3660.672
3651.492
3649.190
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3734.673
3737.157
3761.250
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.500
3784.962
3784.730
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
-29.599
-36.801
-38.400
-38.400
-34.399
-32.800
-32.800
-32.800
-31.201
-32.800
-34.399
-35.999
-36.801
-32.800
-32.800
-32.800
-31.201
17.599
118.399
131.201
104.800
104.800
86.401
87.201
95.999
99.200
100.000
93.600
90.399
91.199
92.001
90.399
89.600
88.000
84.000
84.799
85.599
84.799
84.799
87.201
88.000
92.001
92.001
89.600
90.399
89.600
89.600
88.000
88.800
94.400
101.599
114.401
120.801
118.399
113.599
109.601
107.199
107.999
106.400
107.199
103.201
100.800
-27.561
-30.795
-33.457
-35.187
-34.911
-34.172
-33.692
-33.380
-32.617
-32.681
-33.283
-34.233
-35.132
-34.316
-33.785
-33.441
-32.657
-15.067
31.646
66.490
79.899
88.614
87.840
87.616
90.550
93.578
95.826
95.047
93.420
92.643
92.418
91.712
90.972
89.932
87.856
86.786
86.370
85.821
85.463
86.071
86.747
88.586
89.781
89.718
89.956
89.831
89.750
89.138
89.020
90.903
94.646
101.561
108.295
111.831
112.450
111.453
109.964
109.276
108.269
107.895
106.252
104.344
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
-0.276
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
3752.731
0.000
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
3650.705
3647.195
3644.257
3642.250
3642.250
3642.713
3642.917
3642.953
3643.439
3643.099
3642.222
3640.995
3639.820
3640.360
3640.615
3640.683
3641.191
3658.781
3706.056
3741.462
3755.433
3764.710
3764.498
3764.836
3768.332
3771.921
3774.731
3774.514
3773.450
3773.234
3773.572
3773.427
3773.250
3772.772
3771.257
3770.749
3770.896
3770.908
3771.112
3772.282
3773.520
3775.921
3777.678
3778.177
3778.977
3779.414
3779.895
3779.845
3780.288
3782.733
3787.039
3794.515
3801.811
3805.910
3807.090
3806.655
3805.728
3805.602
3805.158
3805.345
3804.264
3802.918
3677.914
3696.910
3706.351
3712.015
3716.206
3722.640
3728.074
3732.310
3735.967
3739.054
3742.518
3745.523
3748.165
3750.618
3752.750
3754.613
3756.471
3758.148
3759.684
3761.055
3762.474
3763.805
3765.078
3766.452
3767.759
3768.952
3770.190
3771.319
3772.373
3773.406
3774.409
3775.354
3776.351
3777.355
3778.397
3779.410
3780.627
3781.792
3782.897
3783.986
3785.004
3785.975
3786.895
3787.758
3682.418
3702.100
3715.433
3725.288
3731.823
3736.539
3740.513
3744.003
3747.076
3749.570
3751.560
3753.228
3754.681
3755.930
3757.013
3757.940
3758.680
3759.315
3759.894
3760.418
3760.905
3761.399
3761.904
3762.465
3763.050
3763.610
3764.159
3764.685
3765.192
3765.665
3766.122
3766.625
3767.226
3768.005
3768.944
3769.943
3770.921
3771.837
3772.685
3773.487
3774.241
3774.965
3775.631
3776.237
3673.847
3674.409
3674.971
3675.533
3676.095
3676.656
3677.218
3677.780
3678.342
3678.904
3679.466
3680.028
3680.590
3681.152
3681.714
3682.276
3682.838
3683.400
3683.962
3684.524
3685.086
3685.648
3686.210
3686.772
3687.334
3687.896
3688.458
3689.020
3689.582
3690.144
3690.705
3691.267
3691.829
3692.391
3692.953
3693.515
3694.077
3694.639
3695.201
3695.763
3696.325
3696.887
3697.449
3698.011
3673.847
3674.128
3674.409
3674.690
3674.971
3675.252
3675.533
3675.814
3676.095
3676.375
3676.656
3676.937
3677.218
3677.499
3677.780
3678.061
3678.342
3678.623
3678.904
3679.185
3679.466
3679.747
3680.028
3680.309
3680.590
3680.871
3681.152
3681.433
3681.714
3681.995
3682.276
3682.557
3682.838
3683.119
3683.400
3683.681
3683.962
3684.243
3684.524
3684.805
3685.086
3685.367
3685.648
3685.929
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001981
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
3823.826
3822.505
3819.081
3818.055
3816.815
3815.010
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.670
3769.630
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
96.799
95.999
93.600
91.199
88.000
86.401
88.800
85.599
80.801
77.600
78.400
78.400
76.801
74.399
71.201
67.200
67.200
66.400
65.601
64.001
63.199
64.001
66.400
64.001
63.199
61.600
59.201
60.001
57.599
58.401
54.401
58.401
57.599
55.200
56.799
55.200
53.601
50.400
50.400
44.000
40.799
42.401
46.399
47.198
46.399
44.000
41.599
42.401
40.799
39.200
38.400
37.601
39.200
38.400
38.400
38.400
35.999
38.400
36.801
38.400
37.601
37.601
101.703
99.707
97.569
95.340
92.771
90.542
89.932
88.415
85.751
82.898
81.323
80.300
79.075
77.439
75.255
72.436
70.603
69.132
67.896
66.533
65.366
64.888
65.418
64.922
64.319
63.367
61.909
61.241
59.966
59.419
57.662
57.921
57.808
56.895
56.862
56.280
55.343
53.613
52.488
49.517
46.466
45.043
45.518
46.106
46.209
45.436
44.093
43.501
42.555
41.381
40.338
39.380
39.317
38.996
38.787
38.652
37.723
37.960
37.555
37.851
37.763
37.706
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
3800.839
3799.405
3797.830
3796.162
3794.155
3792.488
3792.440
3791.485
3789.382
3787.092
3786.079
3785.618
3784.955
3783.880
3782.259
3780.001
3778.731
3777.822
3777.148
3776.346
3775.741
3775.826
3776.917
3776.983
3776.942
3776.552
3775.656
3775.550
3774.837
3774.852
3773.657
3774.478
3774.927
3774.576
3775.105
3775.085
3774.709
3773.541
3772.979
3770.570
3768.081
3767.220
3768.256
3769.406
3770.071
3769.860
3769.079
3769.049
3768.665
3768.053
3767.572
3767.176
3767.675
3767.916
3768.270
3768.696
3768.329
3769.128
3769.284
3770.142
3770.617
3771.122
3788.542
3789.265
3789.886
3790.461
3790.988
3791.459
3791.888
3792.265
3792.587
3792.848
3793.076
3793.271
3793.319
3793.330
3793.311
3793.281
3793.221
3793.140
3793.006
3792.853
3792.684
3792.440
3792.193
3791.938
3791.672
3791.423
3791.163
3790.896
3790.608
3790.316
3790.018
3789.719
3789.433
3789.147
3788.861
3788.574
3788.301
3788.011
3787.738
3787.446
3787.108
3786.727
3786.308
3785.865
3785.443
3785.049
3784.654
3784.245
3783.871
3783.438
3782.989
3782.506
3781.984
3781.437
3780.882
3780.306
3779.720
3779.121
3778.534
3777.937
3777.330
3776.734
3776.772
3777.253
3777.682
3778.059
3778.381
3778.658
3778.923
3779.160
3779.349
3779.490
3779.608
3779.713
3779.803
3779.872
3779.912
3779.914
3779.895
3779.862
3779.819
3779.766
3779.705
3779.647
3779.607
3779.569
3779.531
3779.489
3779.436
3779.383
3779.321
3779.262
3779.188
3779.127
3779.073
3779.016
3778.967
3778.919
3778.868
3778.804
3778.735
3778.638
3778.516
3778.386
3778.271
3778.171
3778.081
3777.991
3777.894
3777.799
3777.702
3777.600
3777.496
3777.389
3777.290
3777.195
3777.106
3777.023
3776.938
3776.862
3776.789
3776.726
3776.668
3776.616
3698.573
3699.135
3699.697
3700.259
3700.821
3701.383
3701.945
3702.507
3703.069
3703.631
3704.193
3704.754
3705.316
3705.878
3706.440
3707.002
3707.564
3708.126
3708.688
3709.250
3709.812
3710.374
3710.936
3711.498
3712.060
3712.622
3713.184
3713.746
3714.308
3714.870
3715.432
3715.994
3716.556
3717.118
3717.680
3718.242
3718.803
3719.365
3719.927
3720.489
3721.051
3721.613
3722.175
3722.737
3723.299
3723.861
3724.423
3724.985
3725.547
3726.109
3726.671
3727.233
3727.795
3728.357
3728.919
3729.481
3730.043
3730.605
3731.167
3731.729
3732.291
3732.852
3686.210
3686.491
3686.772
3687.053
3687.334
3687.615
3687.896
3688.177
3688.458
3688.739
3689.020
3689.301
3689.582
3689.863
3690.144
3690.424
3690.705
3690.986
3691.267
3691.548
3691.829
3692.110
3692.391
3692.672
3692.953
3693.234
3693.515
3693.796
3694.077
3694.358
3694.639
3694.920
3695.201
3695.482
3695.763
3696.044
3696.325
3696.606
3696.887
3697.168
3697.449
3697.730
3698.011
3698.292
3698.573
3698.854
3699.135
3699.416
3699.697
3699.978
3700.259
3700.540
3700.821
3701.102
3701.383
3701.664
3701.945
3702.226
3702.507
3702.788
3703.069
3703.350
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001982
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
3710.848
3710.810
3712.092
3714.623
3715.130
3716.168
3716.461
3716.980
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.130
3732.530
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.300
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.420
3778.554
38.400
36.801
36.801
32.800
34.399
35.199
36.801
35.199
35.999
33.600
31.201
30.399
30.399
25.601
27.200
27.200
25.601
23.999
20.801
23.999
24.799
24.799
23.999
23.199
21.600
21.600
19.199
17.599
17.599
19.199
17.599
19.199
17.599
18.399
16.000
14.401
15.201
16.000
16.800
16.000
16.800
13.599
13.599
12.799
9.601
8.801
10.400
10.400
7.199
5.600
6.400
7.199
8.801
11.200
13.599
13.599
9.601
5.600
3.201
1.599
0.800
-0.800
37.949
37.547
37.286
35.716
35.255
35.236
35.784
35.579
35.726
34.982
33.659
32.518
31.776
29.615
28.770
28.220
27.304
26.147
24.276
24.179
24.396
24.537
24.349
23.946
23.125
22.592
21.404
20.072
19.207
19.204
18.642
18.837
18.404
18.402
17.562
16.455
16.016
16.011
16.287
16.187
16.401
15.420
14.783
14.088
12.518
11.217
10.931
10.745
9.504
8.138
7.529
7.414
7.899
9.055
10.645
11.679
10.951
9.078
7.021
5.124
3.610
2.067
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.562
0.000
0.000
0.000
0.000
3771.927
3772.087
3772.388
3771.380
3771.481
3772.023
3773.133
3773.490
3774.199
3774.017
3773.256
3772.677
3772.497
3770.898
3770.615
3770.628
3770.273
3769.678
3768.369
3768.834
3769.613
3770.316
3770.689
3770.849
3770.590
3770.618
3769.993
3769.223
3768.920
3769.479
3769.479
3770.236
3770.364
3770.925
3770.646
3770.102
3770.225
3770.781
3771.619
3772.081
3772.857
3772.438
3772.363
3772.230
3771.222
3770.483
3770.759
3771.135
3770.456
3769.651
3769.605
3770.051
3771.099
3772.816
3774.969
3776.564
3776.399
3775.088
3773.031
3771.133
3769.620
3768.076
3776.124
3775.525
3774.948
3774.404
3773.875
3773.364
3772.865
3772.379
3771.908
3771.485
3771.065
3770.659
3770.255
3769.859
3769.465
3769.088
3768.724
3768.362
3768.009
3767.673
3767.357
3767.052
3766.776
3766.514
3766.263
3766.039
3765.822
3765.607
3765.409
3765.223
3765.047
3764.880
3764.739
3764.611
3764.496
3764.399
3764.310
3764.230
3764.171
3764.119
3764.070
3764.046
3764.025
3764.008
3764.000
3763.994
3764.001
3764.014
3764.030
3764.050
3764.074
3764.102
3764.146
3764.198
3764.257
3764.321
3764.391
3764.457
3764.520
3764.586
3764.656
3764.738
3776.573
3776.532
3776.494
3776.448
3776.404
3776.365
3776.336
3776.312
3776.293
3776.274
3776.248
3776.218
3776.187
3776.144
3776.098
3776.054
3776.007
3775.957
3775.896
3775.841
3775.792
3775.750
3775.711
3775.674
3775.635
3775.597
3775.556
3775.509
3775.460
3775.417
3775.374
3775.337
3775.301
3775.270
3775.237
3775.202
3775.167
3775.137
3775.113
3775.092
3775.077
3775.059
3775.041
3775.023
3774.998
3774.968
3774.941
3774.916
3774.888
3774.854
3774.821
3774.791
3774.768
3774.756
3774.757
3774.768
3774.778
3774.780
3774.770
3774.748
3774.717
3774.678
3733.414
3733.976
3734.538
3735.100
3735.662
3736.224
3736.786
3737.348
3737.910
3738.472
3739.034
3739.596
3740.158
3740.720
3741.282
3741.844
3742.406
3742.968
3743.530
3744.092
3744.654
3745.216
3745.778
3746.340
3746.901
3747.463
3748.025
3748.587
3749.149
3749.711
3750.273
3750.835
3751.397
3751.959
3752.521
3753.083
3753.645
3754.207
3754.769
3755.331
3755.893
3756.455
3757.017
3757.579
3758.141
3758.703
3759.265
3759.827
3760.389
3760.950
3761.512
3762.074
3762.636
3763.198
3763.760
3764.322
3764.884
3765.446
3765.446
3765.446
3765.446
3765.446
3703.631
3703.912
3704.193
3704.473
3704.754
3705.035
3705.316
3705.597
3705.878
3706.159
3706.440
3706.721
3707.002
3707.283
3707.564
3707.845
3708.126
3708.407
3708.688
3708.969
3709.250
3709.531
3709.812
3710.093
3710.374
3710.655
3710.936
3711.217
3711.498
3711.779
3712.060
3712.341
3712.622
3712.903
3713.184
3713.465
3713.746
3714.027
3714.308
3714.589
3714.870
3715.151
3715.432
3715.713
3715.994
3716.275
3716.556
3716.837
3717.118
3717.399
3717.680
3717.961
3718.242
3718.522
3718.803
3719.084
3719.365
3719.646
3719.924
3720.198
3720.469
3720.737
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001983
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.850
3786.304
3787.259
3787.516
3787.955
3788.030
3788.607
3789.216
3787.537
3785.842
3786.077
3787.930
3788.760
3786.875
3786.550
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.540
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
0.800
0.800
0.800
-1.599
-4.001
-5.600
-6.400
-8.801
-11.200
-13.599
-15.201
-16.800
-13.599
-13.599
-15.201
-18.399
-19.199
-20.001
-16.800
-15.201
-19.199
-19.199
-16.800
-16.000
-20.001
-19.199
-16.000
-16.000
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-18.399
-17.599
-15.201
-12.799
-14.401
-14.401
-14.401
-15.201
-15.201
-12.799
-12.000
-12.799
-11.200
-10.400
-9.601
-9.601
-7.999
-5.600
-5.600
-7.199
-7.199
-7.999
-2.399
0.800
4.001
6.400
7.199
6.400
1.623
1.335
1.148
0.186
-1.279
-2.792
-4.054
-5.716
-7.635
-9.722
-11.640
-13.446
-13.499
-13.534
-14.117
-15.616
-16.870
-17.966
-17.558
-16.733
-17.596
-18.157
-17.682
-17.093
-18.111
-18.492
-17.620
-17.053
-17.244
-17.369
-17.449
-17.222
-17.074
-17.538
-17.839
-17.755
-16.861
-15.440
-15.076
-14.840
-14.686
-14.866
-14.983
-14.219
-13.442
-13.217
-12.511
-11.772
-11.012
-10.518
-9.636
-8.224
-7.305
-7.268
-7.244
-7.508
-5.720
-3.438
-0.834
1.697
3.623
4.595
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3767.633
3767.344
3767.157
3766.196
3764.730
3763.218
3761.955
3760.294
3758.374
3756.287
3754.370
3752.564
3752.510
3752.475
3751.892
3750.393
3749.140
3748.044
3748.452
3749.277
3748.414
3747.853
3748.328
3748.916
3747.898
3747.518
3748.390
3748.956
3748.765
3748.641
3748.560
3748.787
3748.935
3748.471
3748.170
3748.254
3749.148
3750.570
3750.933
3751.170
3751.323
3751.143
3751.026
3751.791
3752.567
3752.792
3753.498
3754.237
3754.997
3755.491
3756.373
3757.786
3758.704
3758.741
3758.765
3758.501
3760.290
3762.571
3765.175
3767.707
3769.632
3770.604
3764.826
3764.922
3765.014
3765.118
3765.226
3765.336
3765.452
3765.565
3765.684
3765.800
3765.919
3766.038
3766.159
3766.278
3766.399
3766.523
3766.636
3766.738
3766.841
3766.953
3767.068
3767.171
3767.272
3767.376
3767.467
3767.560
3767.654
3767.746
3767.843
3767.938
3768.025
3768.113
3768.203
3768.290
3768.376
3768.463
3768.553
3768.645
3768.745
3768.845
3768.943
3769.036
3769.131
3769.226
3769.318
3769.408
3769.499
3769.596
3769.693
3769.788
3769.879
3769.977
3770.080
3770.174
3770.269
3770.363
3770.453
3770.541
3770.627
3770.710
3770.787
3770.862
3774.637
3774.594
3774.551
3774.502
3774.446
3774.382
3774.311
3774.232
3774.143
3774.043
3773.934
3773.816
3773.699
3773.583
3773.465
3773.340
3773.210
3773.076
3772.945
3772.819
3772.691
3772.561
3772.435
3772.313
3772.187
3772.061
3771.940
3771.823
3771.707
3771.591
3771.476
3771.363
3771.252
3771.139
3771.027
3770.916
3770.810
3770.712
3770.617
3770.524
3770.433
3770.341
3770.250
3770.164
3770.081
3770.001
3769.925
3769.852
3769.784
3769.719
3769.658
3769.604
3769.555
3769.507
3769.459
3769.410
3769.370
3769.340
3769.322
3769.315
3769.316
3769.322
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3721.001
3721.263
3721.521
3721.777
3722.029
3722.279
3722.525
3722.769
3723.010
3723.249
3723.484
3723.717
3723.948
3724.176
3724.402
3724.625
3724.845
3725.064
3725.280
3725.493
3725.705
3725.914
3726.121
3726.326
3726.528
3726.729
3726.927
3727.124
3727.318
3727.511
3727.702
3727.890
3728.077
3728.262
3728.445
3728.627
3728.806
3728.984
3729.160
3729.335
3729.508
3729.679
3729.848
3730.016
3730.183
3730.347
3730.511
3730.672
3730.833
3730.991
3731.149
3731.305
3731.459
3731.612
3731.764
3731.914
3732.063
3732.211
3732.357
3732.502
3732.646
3732.789
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001984
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
3788.057
3788.189
3788.497
3788.540
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.410
3790.467
3790.665
3790.420
3789.674
3789.267
3789.148
3790.430
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.080
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.690
3784.831
3785.010
3784.320
3782.809
3782.110
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
6.400
9.601
11.200
12.000
12.799
12.000
12.799
14.401
15.201
14.401
16.800
18.399
19.199
19.199
16.800
14.401
17.599
19.199
20.801
19.199
18.399
18.399
20.001
21.600
24.799
23.999
23.199
21.600
17.599
15.201
17.599
20.001
22.400
19.199
20.001
21.600
24.799
27.200
28.000
27.200
24.799
23.999
25.601
28.000
28.799
23.999
22.400
26.401
26.401
24.799
25.601
24.799
26.401
26.401
27.200
28.000
23.199
26.401
28.000
30.399
28.799
23.999
5.226
6.757
8.312
9.603
10.722
11.169
11.739
12.671
13.556
13.852
14.884
16.114
17.194
17.895
17.512
16.423
16.835
17.662
18.761
18.914
18.734
18.617
19.101
19.976
21.664
22.481
22.733
22.336
20.678
18.761
18.355
18.931
20.145
19.814
19.879
20.482
21.993
23.815
25.280
25.952
25.548
25.006
25.214
26.189
27.103
26.017
24.751
25.328
25.704
25.387
25.462
25.230
25.640
25.906
26.359
26.933
25.626
25.897
26.633
27.951
28.248
26.761
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3771.236
3772.767
3774.322
3775.612
3776.731
3777.178
3777.749
3778.681
3779.566
3779.862
3780.893
3782.124
3783.203
3783.905
3783.521
3782.433
3782.844
3783.672
3784.770
3784.923
3784.743
3784.626
3785.111
3785.985
3787.673
3788.491
3788.742
3788.346
3786.688
3784.771
3784.364
3784.940
3786.155
3785.823
3785.889
3786.491
3788.002
3789.825
3791.289
3791.962
3791.558
3791.016
3791.224
3792.199
3793.112
3792.026
3790.760
3791.338
3791.713
3791.396
3791.471
3791.239
3791.649
3791.915
3792.368
3792.943
3791.636
3791.907
3792.643
3793.961
3794.257
3792.770
3770.936
3771.010
3771.085
3771.159
3771.233
3771.304
3771.371
3771.434
3771.502
3771.574
3771.647
3771.715
3771.784
3771.860
3771.936
3772.011
3772.082
3772.151
3772.219
3772.292
3772.362
3772.417
3772.476
3772.541
3772.611
3772.686
3772.764
3772.840
3772.903
3772.961
3773.018
3773.071
3773.125
3773.177
3773.230
3773.280
3773.332
3773.391
3773.454
3773.520
3773.588
3773.652
3773.707
3773.763
3773.819
3773.868
3773.910
3773.950
3773.989
3774.026
3774.057
3774.085
3774.104
3774.121
3774.137
3774.155
3774.173
3774.181
3774.186
3774.194
3774.202
3774.208
3769.330
3769.345
3769.366
3769.392
3769.423
3769.456
3769.491
3769.530
3769.571
3769.614
3769.661
3769.712
3769.767
3769.825
3769.881
3769.931
3769.983
3770.038
3770.097
3770.156
3770.214
3770.271
3770.330
3770.391
3770.459
3770.529
3770.599
3770.668
3770.730
3770.783
3770.835
3770.889
3770.947
3771.003
3771.059
3771.116
3771.180
3771.249
3771.323
3771.399
3771.473
3771.545
3771.617
3771.692
3771.769
3771.842
3771.910
3771.980
3772.050
3772.119
3772.188
3772.255
3772.324
3772.392
3772.462
3772.533
3772.600
3772.667
3772.736
3772.808
3772.882
3772.950
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3732.930
3733.070
3733.209
3733.347
3733.484
3733.619
3733.754
3733.887
3734.019
3734.150
3734.280
3734.408
3734.536
3734.663
3734.788
3734.913
3735.037
3735.159
3735.281
3735.402
3735.521
3735.640
3735.758
3735.875
3735.991
3736.106
3736.220
3736.333
3736.446
3736.557
3736.668
3736.778
3736.887
3736.995
3737.102
3737.209
3737.314
3737.419
3737.524
3737.627
3737.730
3737.832
3737.933
3738.033
3738.133
3738.232
3738.330
3738.428
3738.524
3738.621
3738.716
3738.811
3738.905
3738.998
3739.091
3739.183
3739.275
3739.366
3739.456
3739.546
3739.635
3739.723
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001985
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
3773.170
3771.730
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.250
3758.041
3760.965
3762.022
3763.822
3763.100
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.570
3761.920
3759.627
3758.522
3752.429
3750.102
3753.830
3753.510
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.370
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
26.401
24.799
25.601
29.599
28.000
23.999
21.600
25.601
28.000
25.601
24.799
26.401
28.799
27.200
16.800
7.999
13.599
20.801
26.401
28.000
30.399
30.399
31.201
31.201
32.001
29.599
32.800
35.199
39.200
37.601
36.801
34.399
35.199
31.201
29.599
31.201
32.800
29.599
29.599
28.000
25.601
25.601
25.601
23.999
21.600
23.199
28.000
26.401
26.401
22.400
19.199
20.001
24.799
21.600
20.801
17.599
15.201
15.201
15.201
14.401
14.401
12.799
26.635
25.992
25.855
27.166
27.458
26.247
24.621
24.964
26.026
25.878
25.500
25.815
26.860
26.979
23.416
18.020
16.473
17.987
20.932
23.406
25.853
27.444
28.759
29.614
30.449
30.152
31.079
32.521
34.858
35.818
36.162
35.545
35.424
33.946
32.425
31.996
32.278
31.340
30.731
29.775
28.314
27.365
26.747
25.785
24.321
23.928
25.353
25.720
25.958
24.713
22.783
21.809
22.856
22.416
21.851
20.363
18.556
17.382
16.618
15.842
15.338
14.449
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3792.644
3792.002
3791.865
3793.175
3793.467
3792.257
3790.630
3790.973
3792.036
3791.887
3791.509
3791.825
3792.869
3792.988
3789.426
3784.030
3782.482
3783.997
3786.942
3789.415
3791.863
3793.454
3794.769
3795.623
3796.459
3796.161
3797.088
3798.530
3800.868
3801.828
3802.172
3801.555
3801.434
3799.955
3798.434
3798.006
3798.287
3797.350
3796.740
3795.784
3794.324
3793.374
3792.757
3791.795
3790.330
3789.938
3791.363
3791.729
3791.968
3790.722
3788.792
3787.819
3788.865
3788.426
3787.860
3786.372
3784.566
3783.391
3782.628
3781.852
3781.347
3780.459
3774.205
3774.196
3774.178
3774.159
3774.141
3774.119
3774.088
3774.042
3773.994
3773.954
3773.914
3773.870
3773.825
3773.780
3773.733
3773.682
3773.616
3773.550
3773.480
3773.417
3773.368
3773.323
3773.275
3773.236
3773.201
3773.171
3773.140
3773.111
3773.083
3773.062
3773.047
3773.032
3773.014
3772.992
3772.960
3772.926
3772.892
3772.852
3772.809
3772.748
3772.680
3772.624
3772.567
3772.510
3772.452
3772.395
3772.337
3772.281
3772.225
3772.167
3772.101
3772.029
3771.938
3771.849
3771.777
3771.702
3771.621
3771.536
3771.447
3771.354
3771.262
3771.167
3773.017
3773.081
3773.145
3773.212
3773.280
3773.343
3773.401
3773.459
3773.521
3773.582
3773.641
3773.700
3773.763
3773.825
3773.876
3773.909
3773.937
3773.969
3774.011
3774.060
3774.116
3774.178
3774.243
3774.310
3774.380
3774.448
3774.519
3774.594
3774.676
3774.760
3774.844
3774.926
3775.008
3775.084
3775.155
3775.225
3775.295
3775.361
3775.426
3775.487
3775.543
3775.596
3775.647
3775.695
3775.739
3775.780
3775.826
3775.873
3775.920
3775.963
3776.000
3776.035
3776.072
3776.107
3776.141
3776.170
3776.194
3776.215
3776.233
3776.249
3776.263
3776.275
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3739.811
3739.898
3739.985
3740.071
3740.156
3740.241
3740.325
3740.409
3740.492
3740.575
3740.657
3740.738
3740.819
3740.900
3740.980
3741.059
3741.138
3741.217
3741.295
3741.372
3741.449
3741.525
3741.601
3741.677
3741.752
3741.826
3741.900
3741.974
3742.047
3742.120
3742.192
3742.264
3742.335
3742.406
3742.476
3742.546
3742.616
3742.685
3742.754
3742.822
3742.890
3742.958
3743.025
3743.092
3743.158
3743.224
3743.289
3743.355
3743.419
3743.484
3743.548
3743.611
3743.675
3743.738
3743.800
3743.862
3743.924
3743.986
3744.047
3744.108
3744.168
3744.228
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001986
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
3737.273
3736.308
3736.272
3735.448
3735.650
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.860
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.340
3750.700
3749.750
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.830
3737.583
3736.229
3734.897
3733.434
3733.115
3730.510
3729.180
3725.459
14.401
15.201
16.800
16.000
17.599
17.599
16.000
15.201
16.000
17.599
19.199
22.400
23.199
24.799
20.801
20.001
19.199
22.400
24.799
23.199
20.801
22.400
22.400
22.400
18.399
14.401
17.599
19.199
21.600
20.801
18.399
18.399
17.599
16.800
15.201
18.399
20.801
23.199
23.199
23.199
22.400
25.601
27.200
27.200
23.199
21.600
22.400
24.799
22.400
20.801
21.600
23.999
23.199
20.801
14.401
12.000
12.000
12.000
10.400
8.801
8.801
11.200
14.433
14.701
15.436
15.633
16.322
16.769
16.500
16.045
16.030
16.579
17.496
19.212
20.608
22.075
21.629
21.059
20.408
21.105
22.398
22.678
22.021
22.154
22.240
22.296
20.932
18.646
18.280
18.601
19.651
20.053
19.474
19.098
18.574
17.953
16.990
17.483
18.644
20.239
21.275
21.948
22.106
23.330
24.684
25.565
24.737
23.639
23.205
23.763
23.286
22.416
22.131
22.785
22.930
22.185
19.460
16.849
15.152
14.048
12.772
11.382
10.479
10.731
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3780.442
3780.711
3781.445
3781.643
3782.331
3782.778
3782.509
3782.055
3782.039
3782.588
3783.505
3785.222
3786.617
3788.084
3787.638
3787.069
3786.417
3787.115
3788.407
3788.688
3788.031
3788.163
3788.249
3788.305
3786.941
3784.656
3784.289
3784.611
3785.660
3786.063
3785.484
3785.107
3784.583
3783.962
3782.999
3783.492
3784.654
3786.248
3787.284
3787.958
3788.116
3789.339
3790.694
3791.574
3790.746
3789.649
3789.215
3789.772
3789.295
3788.426
3788.140
3788.794
3788.939
3788.194
3785.470
3782.859
3781.161
3780.058
3778.781
3777.391
3776.488
3776.741
3771.071
3770.974
3770.877
3770.778
3770.681
3770.589
3770.499
3770.406
3770.313
3770.220
3770.126
3770.035
3769.949
3769.865
3769.782
3769.698
3769.612
3769.525
3769.441
3769.362
3769.285
3769.213
3769.142
3769.072
3769.001
3768.930
3768.854
3768.780
3768.705
3768.633
3768.566
3768.495
3768.421
3768.346
3768.270
3768.194
3768.122
3768.046
3767.971
3767.909
3767.847
3767.790
3767.735
3767.684
3767.641
3767.597
3767.543
3767.487
3767.428
3767.368
3767.301
3767.233
3767.150
3767.064
3766.992
3766.917
3766.839
3766.758
3766.677
3766.590
3766.500
3766.401
3776.287
3776.299
3776.314
3776.329
3776.345
3776.363
3776.380
3776.396
3776.411
3776.428
3776.447
3776.471
3776.499
3776.530
3776.560
3776.589
3776.615
3776.643
3776.675
3776.707
3776.737
3776.767
3776.798
3776.828
3776.855
3776.875
3776.894
3776.915
3776.937
3776.961
3776.983
3777.004
3777.024
3777.042
3777.057
3777.073
3777.093
3777.116
3777.142
3777.169
3777.197
3777.227
3777.261
3777.297
3777.331
3777.361
3777.391
3777.422
3777.451
3777.478
3777.504
3777.532
3777.560
3777.586
3777.605
3777.618
3777.627
3777.633
3777.635
3777.635
3777.632
3777.630
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3744.288
3744.347
3744.406
3744.465
3744.524
3744.582
3744.640
3744.697
3744.754
3744.811
3744.868
3744.924
3744.980
3745.035
3745.091
3745.146
3745.200
3745.255
3745.309
3745.363
3745.416
3745.470
3745.523
3745.575
3745.628
3745.680
3745.732
3745.783
3745.835
3745.886
3745.937
3745.987
3746.037
3746.088
3746.137
3746.187
3746.236
3746.285
3746.334
3746.382
3746.431
3746.479
3746.526
3746.574
3746.621
3746.668
3746.715
3746.762
3746.808
3746.854
3746.900
3746.946
3746.991
3747.036
3747.081
3747.126
3747.171
3747.215
3747.259
3747.303
3747.347
3747.390
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001987
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.560
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.100
3690.477
3696.865
3696.877
10.400
7.999
4.800
3.201
-0.800
-2.399
-3.201
-4.800
-9.601
-11.200
-15.201
-16.800
-20.001
-20.801
-21.600
-23.199
-23.199
-29.599
-28.799
-29.599
-29.599
-28.799
-32.800
-34.399
-35.199
-34.399
-36.801
-38.400
-36.801
-36.801
-34.399
-34.399
-35.199
-34.399
10.615
9.700
7.985
6.311
3.822
1.645
-0.051
-1.714
-4.474
-6.828
-9.759
-12.223
-14.945
-16.995
-18.607
-20.214
-21.259
-24.178
-25.796
-27.127
-27.992
-28.275
-29.859
-31.448
-32.761
-33.334
-34.548
-35.896
-36.213
-36.419
-35.712
-35.253
-35.234
-34.942
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3776.625
3775.709
3773.994
3772.320
3769.831
3767.654
3765.958
3764.296
3761.535
3759.181
3756.251
3753.786
3751.064
3749.015
3747.403
3745.795
3744.750
3741.831
3740.214
3738.883
3738.017
3737.735
3736.151
3734.562
3733.249
3732.675
3731.462
3730.113
3729.797
3729.591
3730.297
3730.757
3730.776
3731.068
3766.302
3766.192
3766.084
3765.988
3765.892
3765.802
3765.713
3765.623
3765.533
3765.438
3765.347
3765.255
3765.148
3765.035
3764.924
3764.815
3764.705
3764.591
3764.474
3764.350
3764.227
3764.079
3763.930
3763.796
3763.659
3763.521
3763.380
3763.240
3763.097
3762.955
3762.793
3762.632
3762.485
3762.340
3777.627
3777.623
3777.614
3777.602
3777.583
3777.560
3777.532
3777.501
3777.464
3777.421
3777.371
3777.316
3777.255
3777.190
3777.121
3777.049
3776.974
3776.893
3776.809
3776.722
3776.634
3776.546
3776.454
3776.359
3776.261
3776.163
3776.062
3775.959
3775.855
3775.752
3775.650
3775.550
3775.451
3775.352
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3765.446
3747.434
3747.477
3747.520
3747.562
3747.605
3747.647
3747.689
3747.731
3747.773
3747.814
3747.856
3747.897
3747.938
3747.978
3748.019
3748.059
3748.099
3748.139
3748.179
3748.219
3748.258
3748.297
3748.336
3748.375
3748.414
3748.453
3748.491
3748.529
3748.567
3748.605
3748.643
3748.680
3748.718
3748.755
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
001988
A Point
FPointA
A Value
C Value
Delta FC
Time
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:24
60.03900146
60.04212523
59.83599854
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
2:27:24
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
59.8826
59.8844
59.8891
59.8883
59.8891
-0.1596
-397.200
-0.1577
-401.670
-0.1530
-414.405
-0.1538
-411.996
-0.1530
-413.952
-0.00797768
-0.00788482
-0.0076504
-0.0076896
-0.0076504
77.4056
76.5046
74.2298
74.6103
74.2298
-0.0172
-0.0190
-0.0237
-0.0229
-0.0237
n Evaluation
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
Frequency and Interconnection Frequency Response @ different Average periods of B
Total Interconnection FR B
Generation Primary
20 to 52 sec
Trip
Frequency
Average
MW
Response
MW
Value B
12 to 24 sec
Average
Frequency
FR B
Value B
12 to 24 sec 18 to 30 sec
Average
Average
MW
Frequency
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
FR B
Value B
FR B
Value B
FR B
Value B
FR B
18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
MW
Frequency
MW
Frequency
MW
Frequency
MW
T
Frequency
Hz
Net
Actual
Interchange
MW
60.0270
60.0260
60.0260
60.0220
60.0190
60.0170
60.0190
60.0200
60.0190
60.0210
60.0210
60.0210
60.0190
60.0180
60.0220
60.0310
60.0370
60.0370
60.0360
3671.19
3668.61
3665.23
3664.50
3666.06
3666.82
3666.79
3670.45
3670.27
3671.67
3672.49
3672.69
3672.86
3672.16
3671.41
3669.98
3666.47
3663.76
3661.60
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
NonConforming
Load
Load (-)
MW
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
MW/0.1 Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
157.63
155.53
155.53
155.53
155.53
155.53
160.45
160.45
160.45
160.45
160.45
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
213.50
214.00
214.50
215.00
215.50
216.00
216.50
217.00
217.50
218.00
218.50
219.00
219.50
220.00
220.50
221.00
221.50
222.00
222.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001989
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-987.1409
-332.9405
-307.0927
-365.6302
-365.6302
-421.6432
-418.8547
-390.4415
-381.0366
-378.7579
-397.7985
-408.0602
-405.4479
-402.8591
-408.0602
-410.7063
-416.1029
-430.2471
-427.344
-424.4799
-427.344
-427.344
-418.8547
-416.1029
-402.8591
-402.8591
-410.7063
-408.0602
-410.7063
-410.7063
-416.1029
-413.387
-395.3155
-374.2813
-341.9278
-327.765
-332.9405
-343.791
-353.382
-359.4057
-357.3777
-361.4568
-359.4057
-369.9011
-376.5063
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
-413.951533
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.8826
59.8826
59.8826
59.8826
59.8826
59.8826
59.8826
-397.200
-397.200
-397.200
-397.200
-397.200
-397.200
-397.200
59.8844
59.8844
59.8844
59.8844
59.8844
59.8844
59.8844
-401.670
-401.670
-401.670
-401.670
-401.670
-401.670
-401.670
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
-414.405
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
-411.996
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
59.8891
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
-413.952
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
60.0370
60.0460
60.0480
60.0480
60.0430
60.0410
60.0410
60.0410
60.0390
60.0410
60.0430
60.0450
60.0460
60.0410
60.0410
60.0410
60.0390
59.9780
59.8520
59.8360
59.8690
59.8690
59.8920
59.8910
59.8800
59.8760
59.8750
59.8830
59.8870
59.8860
59.8850
59.8870
59.8880
59.8900
59.8950
59.8940
59.8930
59.8940
59.8940
59.8910
59.8900
59.8850
59.8850
59.8880
59.8870
59.8880
59.8880
59.8900
59.8890
59.8820
59.8730
59.8570
59.8490
59.8520
59.8580
59.8630
59.8660
59.8650
59.8670
59.8660
59.8710
59.8740
3660.67
3651.49
3649.19
3650.03
3648.25
3649.51
3654.29
3655.01
3651.87
3651.06
3649.19
3648.24
3645.39
3644.63
3645.45
3640.68
3641.19
3659.46
3696.36
3734.90
3734.67
3734.67
3737.16
3761.25
3766.11
3766.19
3768.88
3769.93
3780.62
3781.59
3782.50
3784.96
3784.73
3784.42
3788.07
3788.33
3788.87
3788.47
3792.28
3793.07
3794.37
3799.43
3800.43
3799.96
3803.63
3802.93
3802.95
3804.39
3805.50
3805.62
3809.24
3811.50
3814.86
3815.89
3825.64
3826.05
3826.00
3827.52
3826.75
3826.78
3826.45
3825.71
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
166.07
166.07
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
223.00
223.50
224.00
224.50
225.00
225.50
226.00
226.50
227.00
227.50
228.00
228.50
229.00
229.50
230.00
230.50
231.00
231.50
232.00
232.50
233.00
233.00
233.50
234.00
234.50
235.00
235.50
236.00
236.50
237.00
237.50
238.00
238.50
239.00
239.50
240.00
240.50
241.00
241.50
242.00
242.50
243.00
243.50
244.00
244.50
245.00
245.50
246.00
246.50
247.00
247.50
248.00
248.50
249.00
249.50
250.00
250.50
251.00
251.50
252.00
252.50
253.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001990
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-388.0493
-390.4415
-397.7985
-405.4479
-416.1029
-421.6432
-413.387
-424.4799
-442.2647
-454.9854
-451.7402
-451.7402
-458.2776
-468.4595
-482.7421
-501.8836
-501.8836
-505.8925
-509.9659
-518.3127
-522.6058
-518.3127
-505.8925
-518.3127
-522.6058
-531.3751
-545.095
-540.4437
-554.6607
-549.8272
-574.796
-549.8272
-554.6607
-569.6264
-559.5611
-569.6264
-580.0604
-602.1406
-602.1406
-651.7339
-679.7395
-665.4288
-632.2168
-625.9683
-632.2168
-651.7339
-672.5217
-665.4288
-679.7395
-694.6501
-702.3535
-710.2296
-694.6501
-702.3535
-702.3535
-702.3535
-726.5557
-702.3535
-718.2843
-702.3535
-710.2296
-710.2296
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
59.8790
59.8800
59.8830
59.8860
59.8900
59.8920
59.8890
59.8930
59.8990
59.9030
59.9020
59.9020
59.9040
59.9070
59.9110
59.9160
59.9160
59.9170
59.9180
59.9200
59.9210
59.9200
59.9170
59.9200
59.9210
59.9230
59.9260
59.9250
59.9280
59.9270
59.9320
59.9270
59.9280
59.9310
59.9290
59.9310
59.9330
59.9370
59.9370
59.9450
59.9490
59.9470
59.9420
59.9410
59.9420
59.9450
59.9480
59.9470
59.9490
59.9510
59.9520
59.9530
59.9510
59.9520
59.9520
59.9520
59.9550
59.9520
59.9540
59.9520
59.9530
59.9530
3823.83
3822.51
3819.08
3818.06
3816.81
3815.01
3813.78
3811.84
3809.65
3806.97
3805.59
3804.19
3796.08
3793.98
3792.17
3791.50
3789.53
3788.13
3784.56
3783.03
3781.70
3776.36
3775.64
3774.60
3773.33
3773.96
3772.72
3771.67
3769.63
3768.71
3767.64
3767.02
3767.41
3766.79
3766.26
3765.67
3766.12
3764.24
3765.10
3762.94
3758.39
3753.92
3749.87
3746.89
3747.88
3749.59
3748.66
3746.71
3749.08
3742.74
3740.26
3736.14
3731.38
3727.84
3725.95
3722.65
3720.58
3718.00
3718.14
3715.75
3713.69
3713.48
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
227.66
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
229.47
229.47
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
229.09
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
218.62
218.62
213.54
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
253.50
254.00
254.50
255.00
255.50
256.00
256.50
257.00
257.50
258.00
258.50
259.00
259.50
260.00
260.50
261.00
261.50
262.00
262.50
263.00
263.50
264.00
264.50
265.00
265.50
266.00
266.50
267.00
267.50
268.00
268.50
269.00
269.50
270.00
270.50
271.00
271.50
272.00
272.50
273.00
273.50
274.00
274.50
275.00
275.50
276.00
276.50
277.00
277.50
278.00
278.50
279.00
279.50
280.00
280.50
281.00
281.50
282.00
282.50
283.00
283.50
284.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001991
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-702.3535
-718.2843
-718.2843
-761.4983
-743.6168
-734.9872
-718.2843
-734.9872
-726.5557
-752.4513
-780.2611
-790.0311
-790.0311
-853.9431
-831.5203
-831.5203
-853.9431
-877.6551
-929.1579
-877.6551
-865.6593
-865.6593
-877.6551
-889.988
-915.7237
-915.7237
-957.2998
-987.1409
-987.1409
-957.2998
-987.1409
-957.2998
-987.1409
-971.9914
-1018.902
-1052.775
-1035.562
-1018.902
-1002.77
-1018.902
-1002.77
-1070.64
-1070.64
-1089.05
-1169.488
-1191.489
-1148.284
-1148.284
-1238.164
-1288.545
-1262.852
-1238.164
-1191.489
-1127.836
-1070.64
-1070.64
-1169.488
-1288.545
-1372.303
-1434.589
-1467.837
-1539.181
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
59.9520
59.9540
59.9540
59.9590
59.9570
59.9560
59.9540
59.9560
59.9550
59.9580
59.9610
59.9620
59.9620
59.9680
59.9660
59.9660
59.9680
59.9700
59.9740
59.9700
59.9690
59.9690
59.9700
59.9710
59.9730
59.9730
59.9760
59.9780
59.9780
59.9760
59.9780
59.9760
59.9780
59.9770
59.9800
59.9820
59.9810
59.9800
59.9790
59.9800
59.9790
59.9830
59.9830
59.9840
59.9880
59.9890
59.9870
59.9870
59.9910
59.9930
59.9920
59.9910
59.9890
59.9860
59.9830
59.9830
59.9880
59.9930
59.9960
59.9980
59.9990
60.0010
3710.85
3710.81
3712.09
3714.62
3715.13
3716.17
3716.46
3716.98
3717.76
3722.36
3721.97
3722.66
3722.27
3722.28
3721.79
3723.09
3723.98
3723.43
3723.89
3725.40
3727.12
3728.05
3731.13
3732.53
3733.33
3736.54
3736.91
3736.82
3738.70
3739.94
3740.88
3741.79
3745.23
3746.61
3748.30
3750.72
3751.56
3752.75
3755.60
3756.41
3756.98
3760.41
3760.98
3761.41
3762.74
3763.21
3764.96
3766.09
3766.43
3767.25
3767.79
3768.63
3771.15
3772.44
3773.69
3774.67
3775.84
3775.36
3774.87
3775.49
3776.42
3778.55
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
212.57
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
221.46
221.46
221.46
221.46
221.46
241.27
241.27
241.27
241.27
241.27
243.07
243.07
243.07
243.07
243.07
241.67
241.67
241.67
241.67
241.67
228.15
228.15
228.15
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
284.50
285.00
285.50
286.00
286.50
287.00
287.50
288.00
288.50
289.00
289.50
290.00
290.50
291.00
291.50
292.00
292.50
293.00
293.50
294.00
294.50
295.00
295.50
296.00
296.50
297.00
297.50
298.00
298.50
299.00
299.50
300.00
300.50
301.00
301.50
302.00
302.50
303.00
303.50
304.00
304.50
305.00
305.50
306.00
306.50
307.00
307.50
308.00
308.50
309.00
309.50
310.00
310.50
311.00
311.50
312.00
312.50
313.00
313.50
314.00
314.50
315.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001992
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1467.837
-1467.837
-1467.837
-1577.518
-1705.089
-1802.122
-1854.901
-2033.824
-2250.644
-2519.209
-2737.39
-2996.405
-2519.209
-2519.209
-2737.39
-3309.559
-3492.035
-3696.631
-2996.405
-2737.39
-3492.035
-3492.035
-2996.405
-2861.047
-3696.631
-3492.035
-2861.047
-2861.047
-3145.206
-3145.206
-3145.206
-2996.405
-2996.405
-3309.559
-3309.559
-3145.206
-2737.39
-2422.838
-2623.979
-2623.979
-2623.979
-2737.39
-2737.39
-2422.838
-2333.569
-2422.838
-2250.644
-2173.41
-2101.301
-2101.301
-1970.311
-1802.122
-1802.122
-1910.865
-1910.865
-1970.311
-1617.814
-1467.837
-1343.199
-1262.852
-1238.164
-1262.852
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
59.9990
59.9990
59.9990
60.0020
60.0050
60.0070
60.0080
60.0110
60.0140
60.0170
60.0190
60.0210
60.0170
60.0170
60.0190
60.0230
60.0240
60.0250
60.0210
60.0190
60.0240
60.0240
60.0210
60.0200
60.0250
60.0240
60.0200
60.0200
60.0220
60.0220
60.0220
60.0210
60.0210
60.0230
60.0230
60.0220
60.0190
60.0160
60.0180
60.0180
60.0180
60.0190
60.0190
60.0160
60.0150
60.0160
60.0140
60.0130
60.0120
60.0120
60.0100
60.0070
60.0070
60.0090
60.0090
60.0100
60.0030
59.9990
59.9950
59.9920
59.9910
59.9920
3779.69
3781.26
3780.59
3783.09
3783.90
3784.42
3785.77
3785.46
3786.85
3786.30
3787.26
3787.52
3787.96
3788.03
3788.61
3789.22
3787.54
3785.84
3786.08
3787.93
3788.76
3786.87
3786.55
3787.36
3785.02
3785.61
3785.95
3785.80
3786.86
3786.88
3785.25
3785.73
3786.35
3785.82
3785.80
3786.28
3786.94
3787.63
3789.44
3789.67
3789.40
3788.48
3789.18
3789.37
3789.00
3788.66
3788.93
3790.67
3790.81
3790.41
3789.77
3791.54
3792.95
3791.03
3791.44
3791.43
3790.60
3790.46
3790.22
3789.58
3788.46
3788.10
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
228.15
228.15
235.13
235.13
235.13
235.13
235.13
246.43
246.43
246.43
246.43
246.43
236.55
236.55
236.55
236.55
236.55
230.30
230.30
230.30
230.30
230.30
231.18
231.18
231.18
231.18
231.18
225.62
225.62
225.62
225.62
225.62
230.73
230.73
230.73
230.73
230.73
234.85
234.85
234.85
234.85
234.85
228.96
228.96
228.96
228.96
228.96
231.18
231.18
231.18
231.18
231.18
236.49
236.49
236.49
236.49
236.49
245.04
245.04
245.04
245.04
245.04
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
315.50
316.00
316.50
317.00
317.50
318.00
318.50
319.00
319.50
320.00
320.50
321.00
321.50
322.00
322.50
323.00
323.50
324.00
324.50
325.00
325.50
326.00
326.50
327.00
327.50
328.00
328.50
329.00
329.50
330.00
330.50
331.00
331.50
332.00
332.50
333.00
333.50
334.00
334.50
335.00
335.50
336.00
336.50
337.00
337.50
338.00
338.50
339.00
339.50
340.00
340.50
341.00
341.50
342.00
342.50
343.00
343.50
344.00
344.50
345.00
345.50
346.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001993
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1262.852
-1169.488
-1127.836
-1108.104
-1089.05
-1108.104
-1089.05
-1052.775
-1035.562
-1052.775
-1002.77
-971.9914
-957.2998
-957.2998
-1002.77
-1052.775
-987.1409
-957.2998
-929.1579
-957.2998
-971.9914
-971.9914
-942.9922
-915.7237
-865.6593
-877.6551
-889.988
-915.7237
-987.1409
-1035.562
-987.1409
-942.9922
-902.6725
-957.2998
-942.9922
-915.7237
-865.6593
-831.5203
-820.7448
-831.5203
-865.6593
-877.6551
-853.9431
-820.7448
-810.2449
-877.6551
-902.6725
-842.5825
-842.5825
-865.6593
-853.9431
-865.6593
-842.5825
-842.5825
-831.5203
-820.7448
-889.988
-842.5825
-820.7448
-790.0311
-810.2449
-877.6551
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
59.9920
59.9880
59.9860
59.9850
59.9840
59.9850
59.9840
59.9820
59.9810
59.9820
59.9790
59.9770
59.9760
59.9760
59.9790
59.9820
59.9780
59.9760
59.9740
59.9760
59.9770
59.9770
59.9750
59.9730
59.9690
59.9700
59.9710
59.9730
59.9780
59.9810
59.9780
59.9750
59.9720
59.9760
59.9750
59.9730
59.9690
59.9660
59.9650
59.9660
59.9690
59.9700
59.9680
59.9650
59.9640
59.9700
59.9720
59.9670
59.9670
59.9690
59.9680
59.9690
59.9670
59.9670
59.9660
59.9650
59.9710
59.9670
59.9650
59.9620
59.9640
59.9700
3788.06
3788.19
3788.50
3788.54
3788.57
3788.10
3787.13
3786.45
3787.73
3788.81
3789.29
3788.26
3788.41
3790.47
3790.66
3790.42
3789.67
3789.27
3789.15
3790.43
3789.91
3786.24
3787.44
3788.96
3790.60
3791.88
3792.91
3792.31
3789.13
3788.08
3787.84
3787.14
3787.16
3787.00
3787.40
3786.49
3787.08
3789.21
3790.51
3791.22
3792.22
3790.96
3788.82
3789.03
3789.17
3787.39
3785.69
3784.83
3785.01
3784.32
3782.81
3782.11
3779.35
3779.06
3778.63
3779.21
3779.33
3776.43
3775.65
3776.60
3776.56
3776.02
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.61
223.61
223.61
223.61
223.61
231.12
231.12
231.12
231.12
231.12
237.21
237.21
237.21
237.21
237.21
240.52
240.52
240.52
240.52
240.52
237.57
237.57
237.57
237.57
237.57
231.58
231.58
231.58
231.58
231.58
235.85
235.85
235.85
235.85
235.85
233.56
233.56
233.56
233.56
233.56
219.01
219.01
219.01
219.01
219.01
205.34
205.34
205.34
205.34
205.34
236.29
236.29
236.29
236.29
236.29
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
346.50
347.00
347.50
348.00
348.50
349.00
349.50
350.00
350.50
351.00
351.50
352.00
352.50
353.00
353.50
354.00
354.50
355.00
355.50
356.00
356.50
357.00
357.50
358.00
358.50
359.00
359.50
360.00
360.50
361.00
361.50
362.00
362.50
363.00
363.50
364.00
364.50
365.00
365.50
366.00
366.50
367.00
367.50
368.00
368.50
369.00
369.50
370.00
370.50
371.00
371.50
372.00
372.50
373.00
373.50
374.00
374.50
375.00
375.50
376.00
376.50
377.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001994
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-842.5825
-865.6593
-853.9431
-800.0104
-820.7448
-877.6551
-915.7237
-853.9431
-820.7448
-853.9431
-865.6593
-842.5825
-810.2449
-831.5203
-1002.77
-1214.422
-1070.64
-929.1579
-842.5825
-820.7448
-790.0311
-790.0311
-780.2611
-780.2611
-770.7656
-800.0104
-761.4983
-734.9872
-694.6501
-710.2296
-718.2843
-743.6168
-734.9872
-780.2611
-800.0104
-780.2611
-761.4983
-800.0104
-800.0104
-820.7448
-853.9431
-853.9431
-853.9431
-877.6551
-915.7237
-889.988
-820.7448
-842.5825
-842.5825
-902.6725
-957.2998
-942.9922
-865.6593
-915.7237
-929.1579
-987.1409
-1035.562
-1035.562
-1035.562
-1052.775
-1052.775
-1089.05
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
59.9670
59.9690
59.9680
59.9630
59.9650
59.9700
59.9730
59.9680
59.9650
59.9680
59.9690
59.9670
59.9640
59.9660
59.9790
59.9900
59.9830
59.9740
59.9670
59.9650
59.9620
59.9620
59.9610
59.9610
59.9600
59.9630
59.9590
59.9560
59.9510
59.9530
59.9540
59.9570
59.9560
59.9610
59.9630
59.9610
59.9590
59.9630
59.9630
59.9650
59.9680
59.9680
59.9680
59.9700
59.9730
59.9710
59.9650
59.9670
59.9670
59.9720
59.9760
59.9750
59.9690
59.9730
59.9740
59.9780
59.9810
59.9810
59.9810
59.9820
59.9820
59.9840
3773.17
3771.73
3768.79
3768.50
3768.92
3767.37
3764.79
3760.30
3759.59
3761.89
3761.78
3760.58
3760.16
3759.78
3759.49
3757.77
3753.28
3753.09
3751.64
3753.75
3758.22
3759.25
3758.04
3760.96
3762.02
3763.82
3763.10
3763.86
3764.16
3766.13
3768.34
3767.97
3767.44
3765.61
3762.69
3761.57
3761.92
3759.63
3758.52
3752.43
3750.10
3753.83
3753.51
3753.52
3752.74
3753.18
3752.73
3753.29
3752.87
3752.36
3749.40
3747.48
3740.37
3741.29
3746.65
3745.74
3743.35
3741.62
3740.31
3738.48
3738.90
3737.40
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
377.50
378.00
378.50
379.00
379.50
380.00
380.50
381.00
381.50
382.00
382.50
383.00
383.50
384.00
384.50
385.00
385.50
386.00
386.50
387.00
387.50
388.00
388.50
389.00
389.50
390.00
390.50
391.00
391.50
392.00
392.50
393.00
393.50
394.00
394.50
395.00
395.50
396.00
396.50
397.00
397.50
398.00
398.50
399.00
399.50
400.00
400.50
401.00
401.50
402.00
402.50
403.00
403.50
404.00
404.50
405.00
405.50
406.00
406.50
407.00
407.50
408.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001995
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1052.775
-1035.562
-1002.77
-1018.902
-987.1409
-987.1409
-1018.902
-1035.562
-1018.902
-987.1409
-957.2998
-902.6725
-889.988
-865.6593
-929.1579
-942.9922
-957.2998
-902.6725
-865.6593
-889.988
-929.1579
-902.6725
-902.6725
-902.6725
-971.9914
-1052.775
-987.1409
-957.2998
-915.7237
-929.1579
-971.9914
-971.9914
-987.1409
-1002.77
-1035.562
-971.9914
-929.1579
-889.988
-889.988
-889.988
-902.6725
-853.9431
-831.5203
-831.5203
-889.988
-915.7237
-902.6725
-865.6593
-902.6725
-929.1579
-915.7237
-877.6551
-889.988
-929.1579
-1052.775
-1108.104
-1108.104
-1108.104
-1148.284
-1191.489
-1191.489
-1127.836
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
59.9820
59.9810
59.9790
59.9800
59.9780
59.9780
59.9800
59.9810
59.9800
59.9780
59.9760
59.9720
59.9710
59.9690
59.9740
59.9750
59.9760
59.9720
59.9690
59.9710
59.9740
59.9720
59.9720
59.9720
59.9770
59.9820
59.9780
59.9760
59.9730
59.9740
59.9770
59.9770
59.9780
59.9790
59.9810
59.9770
59.9740
59.9710
59.9710
59.9710
59.9720
59.9680
59.9660
59.9660
59.9710
59.9730
59.9720
59.9690
59.9720
59.9740
59.9730
59.9700
59.9710
59.9740
59.9820
59.9850
59.9850
59.9850
59.9870
59.9890
59.9890
59.9860
3737.27
3736.31
3736.27
3735.45
3735.65
3737.54
3738.01
3736.75
3736.69
3736.07
3736.09
3736.57
3738.57
3738.87
3738.93
3738.65
3737.68
3737.38
3737.89
3740.02
3740.33
3742.05
3742.42
3742.52
3742.25
3741.72
3740.09
3740.63
3739.96
3740.78
3742.83
3741.27
3739.78
3738.97
3738.71
3738.88
3739.86
3738.10
3738.56
3743.51
3743.42
3745.25
3745.74
3747.34
3750.70
3749.75
3746.22
3744.68
3743.75
3743.15
3740.30
3739.45
3733.38
3731.83
3737.58
3736.23
3734.90
3733.43
3733.12
3730.51
3729.18
3725.46
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
408.50
409.00
409.50
410.00
410.50
411.00
411.50
412.00
412.50
413.00
413.50
414.00
414.50
415.00
415.50
416.00
416.50
417.00
417.50
418.00
418.50
419.00
419.50
420.00
420.50
421.00
421.50
422.00
422.50
423.00
423.50
424.00
424.50
425.00
425.50
426.00
426.50
427.00
427.50
428.00
428.50
429.00
429.50
430.00
430.50
431.00
431.50
432.00
432.50
433.00
433.50
434.00
434.50
435.00
435.50
436.00
436.50
437.00
437.50
438.00
438.50
439.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001996
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1148.284
-1214.422
-1315.304
-1372.303
-1539.181
-1617.814
-1660.389
-1752.263
-2101.301
-2250.644
-2737.39
-2996.405
-3696.631
-3925.764
-4185.18
-4822.528
-4822.528
-12347.66
-10333.13
-12347.66
-12347.66
-10333.13
-56273.73
72422.11
33787.15
72422.11
16330.39
10774.27
16330.39
16330.39
72422.11
72422.11
33787.15
72422.11
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.9870
59.9900
59.9940
59.9960
60.0010
60.0030
60.0040
60.0060
60.0120
60.0140
60.0190
60.0210
60.0250
60.0260
60.0270
60.0290
60.0290
60.0370
60.0360
60.0370
60.0370
60.0360
60.0410
60.0430
60.0440
60.0430
60.0460
60.0480
60.0460
60.0460
60.0430
60.0430
60.0440
60.0430
3724.78
3720.11
3720.94
3725.66
3725.68
3727.75
3727.82
3727.68
3727.23
3725.01
3726.45
3726.02
3719.12
3716.37
3717.33
3717.56
3717.14
3715.17
3713.63
3710.28
3710.16
3699.36
3698.59
3704.59
3703.28
3702.48
3701.32
3700.83
3699.53
3699.73
3690.10
3690.48
3696.86
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
439.50
440.00
440.50
441.00
441.50
442.00
442.50
443.00
443.50
444.00
444.50
445.00
445.50
446.00
446.50
447.00
447.50
448.00
448.50
449.00
449.50
450.00
450.50
451.00
451.50
452.00
452.50
453.00
453.50
454.00
454.50
455.00
455.50
456.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
001997
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8826
-0.160
3645.73
3770.65
124.93
39.87
-33.70
93.94
127.64
167.51
350.00
165.34
0.00
229.25
-4.21
15.00
755.37
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
212.14
0.86
235.50
11.74
0.00
795.24
39.87
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.3890
120.9512
164.3402
76.02%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7651.305
7632.000
-19.305
-12.099
15.45%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
12 to 24 second Average Period Evaluation
BA
Load
MW
7640.91
7641.24
7641.57
7641.90
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.20
7645.53
7645.86
7646.19
7646.52
7646.85
Expected
Primary
Freq Response
MW
-21.600
-20.801
-20.801
-17.599
-15.201
-13.599
-15.201
-16.000
-15.201
-16.800
-16.800
-16.800
-15.201
-14.401
-17.599
-24.799
-29.599
-29.599
-28.799
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
0.979 P.U.
0.666 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
001998
7647.18
7647.51
7647.84
7648.17
7648.50
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.80
7652.13
7652.46
7652.79
7616.00
7626.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7623.00
7621.00
7623.00
7625.00
7627.00
7628.00
7628.00
7629.00
7630.00
7631.00
-29.599
-36.801
-38.400
-38.400
-34.399
-32.800
-32.800
-32.800
-31.201
-32.800
-34.399
-35.999
-36.801
-32.800
-32.800
-32.800
-31.201
17.599
118.399
131.201
104.800
104.800
86.401
87.201
95.999
99.200
100.000
93.600
90.399
91.199
92.001
90.399
89.600
88.000
84.000
84.799
85.599
84.799
84.799
87.201
88.000
92.001
92.001
89.600
90.399
89.600
89.600
88.000
88.800
94.400
101.599
114.401
120.801
118.399
113.599
109.601
107.199
107.999
106.400
107.199
103.201
100.800
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.883
59.883
59.883
59.883
59.883
59.883
59.883
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3770.653
3770.653
3770.653
3770.653
3770.653
3770.653
3770.653
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
212.139
212.139
212.139
212.139
212.139
212.139
212.139
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.857
0.857
0.857
0.857
0.857
0.857
0.857
229.250
229.250
229.250
229.250
229.250
229.250
229.250
229.250
235.500
235.500
235.500
235.500
235.500
235.500
235.500
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
93.943
93.943
93.943
93.943
93.943
93.943
93.943
3813.236
3813.236
3813.236
3813.236
3813.236
3813.236
3813.236
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
59.884
59.884
59.884
59.884
59.884
59.884
59.884
3779.029
3779.029
3779.029
3779.029
3779.029
3779.029
3779.029
335.000
335.000
335.000
335.000
335.000
335.000
335.000
213.464
213.464
213.464
213.464
213.464
213.464
213.464
001999
7635.00
7638.00
7639.00
7642.00
7644.00
7645.00
7647.00
7648.00
7649.00
7650.00
7651.00
7652.00
7653.00
7654.00
7655.00
7655.00
7656.00
7656.00
7657.00
7657.00
7658.00
7658.00
7659.00
7659.00
7659.00
7660.00
7660.00
7661.00
7661.00
7662.00
7662.00
7663.00
7663.00
7664.00
7664.00
7665.00
7666.00
7666.00
7667.00
7668.00
7668.00
7669.00
7669.00
7670.00
7670.00
7671.00
7671.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
96.799
95.999
93.600
91.199
88.000
86.401
88.800
85.599
80.801
77.600
78.400
78.400
76.801
74.399
71.201
67.200
67.200
66.400
65.601
64.001
63.199
64.001
66.400
64.001
63.199
61.600
59.201
60.001
57.599
58.401
54.401
58.401
57.599
55.200
56.799
55.200
53.601
50.400
50.400
44.000
40.799
42.401
46.399
47.198
46.399
44.000
41.599
42.401
40.799
39.200
38.400
37.601
39.200
38.400
38.400
38.400
35.999
38.400
36.801
38.400
37.601
37.601
002000
7673.00
7673.00
7674.00
7675.00
7676.00
7677.00
7678.00
7679.00
7680.00
7681.00
7682.00
7684.00
7685.00
7687.00
7689.00
7690.00
7692.00
7692.00
7693.00
7693.00
7694.00
7694.00
7695.00
7695.00
7695.00
7696.00
7696.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.30
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.60
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.90
38.400
36.801
36.801
32.800
34.399
35.199
36.801
35.199
35.999
33.600
31.201
30.399
30.399
25.601
27.200
27.200
25.601
23.999
20.801
23.999
24.799
24.799
23.999
23.199
21.600
21.600
19.199
17.599
17.599
19.199
17.599
19.199
17.599
18.399
16.000
14.401
15.201
16.000
16.800
16.000
16.800
13.599
13.599
12.799
9.601
8.801
10.400
10.400
7.199
5.600
6.400
7.199
8.801
11.200
13.599
13.599
9.601
5.600
3.201
1.599
0.800
-0.800
002001
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.20
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.50
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.80
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.10
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.40
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.70
7728.03
7728.36
0.800
0.800
0.800
-1.599
-4.001
-5.600
-6.400
-8.801
-11.200
-13.599
-15.201
-16.800
-13.599
-13.599
-15.201
-18.399
-19.199
-20.001
-16.800
-15.201
-19.199
-19.199
-16.800
-16.000
-20.001
-19.199
-16.000
-16.000
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-18.399
-17.599
-15.201
-12.799
-14.401
-14.401
-14.401
-15.201
-15.201
-12.799
-12.000
-12.799
-11.200
-10.400
-9.601
-9.601
-7.999
-5.600
-5.600
-7.199
-7.199
-7.999
-2.399
0.800
4.001
6.400
7.199
6.400
002002
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731.00
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.30
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.60
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.90
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.20
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.50
7747.83
7748.16
7748.49
7748.82
6.400
9.601
11.200
12.000
12.799
12.000
12.799
14.401
15.201
14.401
16.800
18.399
19.199
19.199
16.800
14.401
17.599
19.199
20.801
19.199
18.399
18.399
20.001
21.600
24.799
23.999
23.199
21.600
17.599
15.201
17.599
20.001
22.400
19.199
20.001
21.600
24.799
27.200
28.000
27.200
24.799
23.999
25.601
28.000
28.799
23.999
22.400
26.401
26.401
24.799
25.601
24.799
26.401
26.401
27.200
28.000
23.199
26.401
28.000
30.399
28.799
23.999
002003
7749.15
7749.48
7749.81
7750.14
7750.47
7750.80
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.10
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.40
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.70
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764.00
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.30
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
26.401
24.799
25.601
29.599
28.000
23.999
21.600
25.601
28.000
25.601
24.799
26.401
28.799
27.200
16.800
7.999
13.599
20.801
26.401
28.000
30.399
30.399
31.201
31.201
32.001
29.599
32.800
35.199
39.200
37.601
36.801
34.399
35.199
31.201
29.599
31.201
32.800
29.599
29.599
28.000
25.601
25.601
25.601
23.999
21.600
23.199
28.000
26.401
26.401
22.400
19.199
20.001
24.799
21.600
20.801
17.599
15.201
15.201
15.201
14.401
14.401
12.799
002004
7769.61
7769.94
7770.27
7770.60
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.90
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.20
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.50
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.80
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.10
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
14.401
15.201
16.800
16.000
17.599
17.599
16.000
15.201
16.000
17.599
19.199
22.400
23.199
24.799
20.801
20.001
19.199
22.400
24.799
23.199
20.801
22.400
22.400
22.400
18.399
14.401
17.599
19.199
21.600
20.801
18.399
18.399
17.599
16.800
15.201
18.399
20.801
23.199
23.199
23.199
22.400
25.601
27.200
27.200
23.199
21.600
22.400
24.799
22.400
20.801
21.600
23.999
23.199
20.801
14.401
12.000
12.000
12.000
10.400
8.801
8.801
11.200
002005
7790.07
7790.40
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.70
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797.00
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.30
7800.63
7800.96
10.400
7.999
4.800
3.201
-0.800
-2.399
-3.201
-4.800
-9.601
-11.200
-15.201
-16.800
-20.001
-20.801
-21.600
-23.199
-23.199
-29.599
-28.799
-29.599
-29.599
-28.799
-32.800
-34.399
-35.199
-34.399
-36.801
-38.400
-36.801
-36.801
-34.399
-34.399
-35.199
-34.399
002006
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8844
-0.158
3645.73
3779.03
133.30
43.08
-33.70
92.46
126.16
169.23
350.00
165.34
0.00
229.25
-4.21
15.00
755.37
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -103.000 MW/0.1 Hz
Post-Perturbation Bias Setting -103.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -43.3890 MW
EPFR for Bias Setting Post-Perturbation Average 119.0383 MW
EPFR for Bias Setting Delta 162.4273 MW
Primary Frequency Response Delivery of Bias
82.07%
335.00
213.46
1.43
237.00
11.56
0.00
798.45
43.08
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8893
-0.153
3645.73
3783.86
138.14
45.82
-33.70
88.58
122.28
168.10
350.00
165.34
0.00
229.25
-4.21
15.00
755.37
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
213.08
3.55
238.50
11.07
0.00
801.20
45.82
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation BA Load 7651.305 MW
Post-Perturbation BA Load 7632.000 MW
Pre to Post Perturbation BA Load Change
-19.305 MW
Load Dampening Frequency Response
-12.242 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
14.48%
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.3890
114.0486
157.4376
87.74%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7651.305
7632.000
-19.305
-12.630
13.98%
MW
MW
MW
MW/0.1 Hz
20 to 40 second Average Period Evaluation
1.057 P.U.
0.715 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.130 P.U.
0.755 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002007
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1.429
1.429
1.429
1.429
1.429
1.429
1.429
229.250
229.250
229.250
229.250
229.250
229.250
229.250
229.250
237.000
237.000
237.000
237.000
237.000
237.000
237.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
92.457
92.457
92.457
92.457
92.457
92.457
92.457
3814.960
3814.960
3814.960
3814.960
3814.960
3814.960
3814.960
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
229.250
229.250
229.250
229.250
229.250
229.250
229.250
229.250
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
3783.863
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
213.078
213.078
213.078
213.078
213.078
213.078
213.078
213.078
213.078
213.078
213.078
3.545
3.545
3.545
3.545
3.545
3.545
3.545
3.545
3.545
3.545
3.545
238.500
238.500
238.500
238.500
238.500
238.500
238.500
238.500
238.500
238.500
238.500
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
88.581
88.581
88.581
88.581
88.581
88.581
88.581
88.581
88.581
88.581
88.581
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
3813.831
002008
002009
002010
002011
002012
002013
002014
002015
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8883
-0.154
3645.73
3787.27
141.55
50.57
-33.70
89.33
123.03
173.60
350.00
165.34
0.00
229.25
-4.21
15.00
755.37
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
213.97
6.06
239.75
11.17
0.00
805.94
50.57
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.3890
115.0166
158.4056
89.36%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7651.305
7632.000
-19.305
-12.553
13.64%
MW
MW
MW
MW/0.1 Hz
18 to 52 second Average Period Evaluation
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:26
2:32:54
60.0421
59.8891
-0.153
3645.73
3788.35
142.63
51.20
-33.70
88.71
122.41
173.60
350.00
165.34
0.00
229.25
-4.21
15.00
755.37
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
214.13
6.35
240.00
11.09
0.00
806.57
51.20
MW
MW
MW
MW
MW
MW
MW
MW
20 to 52 second Average Period Evaluation
1.150 P.U.
0.739 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.165 P.U.
0.747 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
002016
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
3787.272
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
213.968
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
6.056
229.250
229.250
229.250
229.250
229.250
229.250
229.250
229.250
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
239.750
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
89.333
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
3819.328
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
3645.727
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
229.250
229.250
229.250
229.250
229.250
229.250
229.250
229.250
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
3788.355
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
240.000
002017
002018
002019
002020
002021
002022
002023
002024
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.3890
114.2087
157.5977
90.50%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7651.305
7632.000
-19.305
-12.617
13.54%
MW
MW
MW
MW/0.1 Hz
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002025
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
7651.305
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
-33.700
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
7632.000
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
88.706
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
3819.329
002026
Monday, October 12, 2009
Balancing Authority
60.08
1.165
My BA
60.0421
Initial P.U. Performance
Initial P.U. Performance Adjusted
0.747
3850.0
20 to 52 second Average Period
60.06
60.04
3788.35
60.02
3800.0
60
59.98
59.96
3750.0
3819.329
59.92
MW
Frequency - Hz
59.94
59.9
3700.0
59.88
59.8891
59.86
59.84
3650.0
59.82
3645.73
59.8
59.78
3600.0
59.76
59.74
59.72
2:26:26
2:26:36
2:26:46
Hz
2:26:56
2:27:06
Average Frequency
2:27:16
2:27:26
MW
2:27:36
Average MW
2:27:46
2:27:56
2:28:06
EPFR for FRO Adjusted
2:28:16
3550.0
2:28:26
002027
Monday, October 12, 2009
0.923 Sustained P.U. Performance
My BA
60.08
3850.0
60.06
60.04
3800.0
60.02
60
59.98
3750.0
59.96
3700.0
59.92
MW
Frequency - Hz
59.94
59.9
59.88
3650.0
59.86
59.84
3600.0
59.82
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
Hz
2:30:26
2:31:26
2:32:26
Interchange MW
2:33:26
2:34:26
2:35:26
Recovery Period Target MW
2:36:26
2:37:26
2:38:26
2:39:26
Recovery Period Ramp MW
2:40:26
2:41:26
3500.0
2:42:26
002028
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:24
FPointA
Hz
60.0390
A Value
Hz
60.0421
t(0) Time
2:27:26
C Value
Hz
59.8360
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8825716 -397.19961 59.8844288 -401.66999 59.8891177 -414.40454 59.8883334 -411.99633 59.8891177 -413.95153
002029
Value A Data
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
60.042125
3645.73
350.00
165.34
0.00
229.25
-4.21
15.00
-103 7651.305
Value B
Bias
Setting
EPFR
Frequency
MW
Hz
-43.389 59.882572
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
Actual
Schedules
Load
Hydro
Units
Response
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+)
MW
MW
MW
MW
MW
MW
3770.65
335.00
212.14
0.86
235.50
11.74
002030
Value B
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
0.666
Initial
Performance
Unadjusted
P.U.
0.979
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.923
-103
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
7632 120.9512 59.884429
3779.03
335.00
213.46
1.43
237.00
11.56
0.00
BA
Load
Initial
Performance
Adjusted
P.U.
0.715
002031
Value B
Initial
Performance
Unadjusted
P.U.
1.057
Sustained
Performance
P.U.
0.923
BA
Bias
Setting
MW
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7632 119.0383 59.889273
20 to 40 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
3783.86
335.00
213.08
3.55
238.50
11.07
0.00
Initial
Performance
Adjusted
P.U.
0.755
Initial
Performance
Unadjusted
P.U.
1.130
Sustained
Performance
P.U.
0.923
002032
Value B
BA
Bias
Setting
MW
-103
18 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW
MW
7632 114.0486 59.888333
3787.27
335.00
213.97
6.06
239.75
11.17
0.00
Value B
Initial
Performance
Adjusted
P.U.
0.739
Initial
Performance
Unadjusted
P.U.
1.150
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.923
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7632 115.0166 59.889118
002033
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Ramping
Actual
Schedules
Load
Hydro
Units
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+)
MW
MW
MW
MW
MW
3788.35
335.00
165.34
6.35
240.00
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.09
0.00
Initial
Performance
Adjusted
P.U.
0.747
Initial
Performance
Unadjusted
P.U.
1.165
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.923
-103
BA
Load
Bias
Setting
EPFR
MW
MW
7632 114.2087
002034
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
C
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Ramping units
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 3 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with up to 60 minutes of data. Be sure "Data" worksheet is clear of any old data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data. The data must be numbers not text.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred.
Scroll through the "Data" worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 313 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A313"
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency of the event on the center vertical grid line of the graph (Red Trend).
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 427.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A427"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if you're interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar.
When set appropriately, the "Target" trend on the "Sustained" graph will model what Interchange Actual should have done during the event recovery period based on your minimum FRO.
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
002035
Time (T)
10/12/09 02:12:00
10/12/09 02:12:03
10/12/09 02:12:06
10/12/09 02:12:09
10/12/09 02:12:12
10/12/09 02:12:15
10/12/09 02:12:18
10/12/09 02:12:21
10/12/09 02:12:24
10/12/09 02:12:27
10/12/09 02:12:30
10/12/09 02:12:33
10/12/09 02:12:36
10/12/09 02:12:39
10/12/09 02:12:42
10/12/09 02:12:45
10/12/09 02:12:48
10/12/09 02:12:51
10/12/09 02:12:54
10/12/09 02:12:57
10/12/09 02:13:00
10/12/09 02:13:03
10/12/09 02:13:06
10/12/09 02:13:09
10/12/09 02:13:12
10/12/09 02:13:15
10/12/09 02:13:18
10/12/09 02:13:21
10/12/09 02:13:24
10/12/09 02:13:27
10/12/09 02:13:30
10/12/09 02:13:33
10/12/09 02:13:36
10/12/09 02:13:39
10/12/09 02:13:42
10/12/09 02:13:45
10/12/09 02:13:48
10/12/09 02:13:51
10/12/09 02:13:54
10/12/09 02:13:57
10/12/09 02:14:00
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
MW/0.1 Hz
59.981 3669.878
350 351.361511
0
0
10
15
-103
59.98
3671.7
350 351.361511
0
0.5
10
15
-103
59.982 3670.949
350 351.361511
0
1
10
15
-103
59.981 3671.548
350
357.94751
0
1.5
10
15
-103
59.981
3672.31
350
357.94751
0
2
10
15
-103
59.982 3672.174
350
357.94751
0
2.5
10
15
-103
59.979 3672.276
350
357.94751
0
3
10
15
-103
59.98 3674.508
350
357.94751
0
3.5
10
15
-103
59.983 3673.844
350 360.234741
0
4
10
15
-103
59.986 3672.106
350 360.234741
0
4.5
10
15
-103
59.98
3669.33
350 360.234741
0
5
10
15
-103
59.976
3671.5
350 360.234741
0
5.5
10
15
-103
59.979
3673.56
350 360.234741
0
6
10
15
-103
59.981 3673.834
350 346.525879
0
6.5
10
15
-103
59.987 3671.887
350 346.525879
0
7
10
15
-103
59.99
3671.22
350 346.525879
0
7.5
10
15
-103
59.994
3671.56
350 346.525879
0
8
10
15
-103
59.995 3670.772
350 346.525879
0
8.5
10
15
-103
59.995 3668.362
350 296.443359
0
9
10
15
-103
59.995 3668.245
350 296.443359
0
9.5
10
15
-103
59.994 3669.291
350 296.443359
0
10
10
15
-103
59.994 3671.254
350 296.443359
0
10.5
10
15
-103
59.997 3670.683
350 296.443359
0
11
10
15
-103
60.001 3670.212
350 341.061157
0
11.5
10
15
-103
60.001 3670.712
350 341.061157
0
12
10
15
-103
60.003 3671.184
350 341.061157
0
12.5
10
15
-103
60.005 3671.227
350 341.061157
0
13
10
15
-103
60.003
3670.19
350 341.061157
0
13.5
10
15
-103
60.001 3671.092
350 322.826294
0
14
10
15
-103
60.003
3670.67
350 322.826294
0
14.5
10
15
-103
60.005 3669.899
350 322.826294
0
15
10
15
-103
60.001 3670.199
350 322.826294
0
15.5
10
15
-103
60.001 3671.628
350 322.826294
0
16
10
15
-103
60.004 3671.968
350 321.544403
0
16.5
10
15
-103
60.004 3671.444
350 321.544403
0
17
10
15
-103
60.004 3671.875
350 321.544403
0
17.5
10
15
-103
60.003 3671.066
350 321.544403
0
18
10
15
-103
60.002 3673.235
350 321.544403
0
18.5
10
15
-103
60.001 3673.498
350 362.136261
0
19
10
15
-103
59.999
3672.75
350 362.136261
0
19.5
10
15
-103
59.997 3673.186
350 362.136261
0
20
10
15
-103
BA
Load
MW
7500
7500.33
7500.66
7500.99
7501.32
7501.65
7501.98
7502.31
7502.64
7502.97
7503.3
7503.63
7503.96
7504.29
7504.62
7504.95
7505.28
7505.61
7505.94
7506.27
7506.6
7506.93
7507.26
7507.59
7507.92
7508.25
7508.58
7508.91
7509.24
7509.57
7509.9
7510.23
7510.56
7510.89
7511.22
7511.55
7511.88
7512.21
7512.54
7512.87
7513.2
002036
10/12/09 02:14:03
10/12/09 02:14:06
10/12/09 02:14:09
10/12/09 02:14:12
10/12/09 02:14:15
10/12/09 02:14:18
10/12/09 02:14:21
10/12/09 02:14:24
10/12/09 02:14:27
10/12/09 02:14:30
10/12/09 02:14:33
10/12/09 02:14:36
10/12/09 02:14:39
10/12/09 02:14:42
10/12/09 02:14:45
10/12/09 02:14:48
10/12/09 02:14:51
10/12/09 02:14:54
10/12/09 02:14:57
10/12/09 02:15:00
10/12/09 02:15:03
10/12/09 02:15:06
10/12/09 02:15:09
10/12/09 02:15:12
10/12/09 02:15:15
10/12/09 02:15:18
10/12/09 02:15:21
10/12/09 02:15:24
10/12/09 02:15:27
10/12/09 02:15:30
10/12/09 02:15:33
10/12/09 02:15:36
10/12/09 02:15:39
10/12/09 02:15:42
10/12/09 02:15:45
10/12/09 02:15:48
10/12/09 02:15:51
10/12/09 02:15:54
10/12/09 02:15:57
10/12/09 02:16:00
10/12/09 02:16:03
10/12/09 02:16:06
10/12/09 02:16:09
10/12/09 02:16:12
10/12/09 02:16:15
10/12/09 02:16:18
59.998
59.995
59.993
59.996
59.999
60.005
60.007
60.005
60.002
59.997
59.999
60.007
60.01
60.009
60.003
59.995
59.994
60
60.001
59.998
59.995
59.986
59.986
59.988
59.989
59.987
59.985
59.983
59.982
59.984
59.985
59.987
59.99
59.987
59.983
59.979
59.983
59.986
59.988
59.983
59.978
59.979
59.989
59.988
59.983
59.991
3673.576
3673.365
3672.093
3671.998
3671.073
3670.957
3670.893
3670.162
3670.62
3672.713
3671.07
3670.826
3671.809
3673.363
3673.255
3674.415
3674.755
3674.29
3675.157
3675.166
3674.442
3674.906
3676.714
3677.791
3675.543
3676.593
3677.223
3677.067
3678.455
3679.228
3679.059
3677.627
3676.409
3677.528
3676.915
3678.086
3680.163
3679.213
3677.653
3677.678
3679.279
3678.729
3680.287
3679.026
3678.489
3678.72
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
362.136261
362.136261
336.311798
336.311798
336.311798
336.311798
336.311798
316.443054
316.443054
316.443054
316.443054
316.443054
325.464294
325.464294
325.464294
325.464294
325.464294
336.614166
336.614166
336.614166
336.614166
336.614166
316.726166
316.726166
316.726166
316.726166
316.726166
320.195526
320.195526
320.195526
320.195526
320.195526
341.86615
341.86615
341.86615
341.86615
341.86615
348.597839
348.597839
348.597839
348.597839
348.597839
329.085022
329.085022
329.085022
329.085022
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20.5
21
21.5
22
22.5
23
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
28.5
29
29.5
30
30.5
31
31.5
32
32.5
33
33.5
34
34.5
35
35.5
36
36.5
37
37.5
38
38.5
39
39.5
40
40.5
41
41.5
42
42.5
43
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7513.53
7513.86
7514.19
7514.52
7514.85
7515.18
7515.51
7515.84
7516.17
7516.5
7516.83
7517.16
7517.49
7517.82
7518.15
7518.48
7518.81
7519.14
7519.47
7519.8
7520.13
7520.46
7520.79
7521.12
7521.45
7521.78
7522.11
7522.44
7522.77
7523.1
7523.43
7523.76
7524.09
7524.42
7524.75
7525.08
7525.41
7525.74
7526.07
7526.4
7526.73
7527.06
7527.39
7527.72
7528.05
7528.38
002037
10/12/09 02:16:21
10/12/09 02:16:24
10/12/09 02:16:27
10/12/09 02:16:30
10/12/09 02:16:33
10/12/09 02:16:36
10/12/09 02:16:39
10/12/09 02:16:42
10/12/09 02:16:45
10/12/09 02:16:48
10/12/09 02:16:51
10/12/09 02:16:54
10/12/09 02:16:57
10/12/09 02:17:00
10/12/09 02:17:03
10/12/09 02:17:06
10/12/09 02:17:09
10/12/09 02:17:12
10/12/09 02:17:15
10/12/09 02:17:18
10/12/09 02:17:21
10/12/09 02:17:24
10/12/09 02:17:27
10/12/09 02:17:30
10/12/09 02:17:33
10/12/09 02:17:36
10/12/09 02:17:39
10/12/09 02:17:42
10/12/09 02:17:45
10/12/09 02:17:48
10/12/09 02:17:51
10/12/09 02:17:54
10/12/09 02:17:57
10/12/09 02:18:00
10/12/09 02:18:03
10/12/09 02:18:06
10/12/09 02:18:09
10/12/09 02:18:12
10/12/09 02:18:15
10/12/09 02:18:18
10/12/09 02:18:21
10/12/09 02:18:24
10/12/09 02:18:27
10/12/09 02:18:30
10/12/09 02:18:33
10/12/09 02:18:36
59.989
59.993
59.995
59.998
59.998
59.999
59.995
59.992
59.995
60.001
60.003
60.009
60.009
60.012
60.011
60.008
60.007
60.012
60.013
60.01
60.007
60.009
60.006
60.009
60.009
60.009
60.009
60.004
60.001
59.993
59.991
59.992
59.994
59.994
59.995
59.99
59.99
59.983
59.977
59.989
59.995
59.994
59.989
59.986
59.984
59.985
3678.971
3679.39
3678.33
3678.49
3676.763
3678.951
3679.148
3679.903
3678.997
3677.86
3678.267
3677.686
3678.364
3679.209
3678.653
3679.057
3680.604
3679.806
3680.263
3679.851
3679.946
3679.44
3679.517
3679.888
3679.06
3679.261
3679.025
3679.152
3678.295
3678.249
3677.83
3677.955
3676.666
3677.093
3676.401
3678.516
3680.197
3678.743
3677.921
3680.254
3681.329
3678.656
3677.78
3678.427
3678.278
3677.822
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
329.085022
342.418243
342.418243
342.418243
342.418243
342.418243
338.794647
338.794647
338.794647
338.794647
338.794647
335.931
335.931
335.931
335.931
335.931
339.712402
339.712402
339.712402
339.712402
339.712402
332.024658
332.024658
332.024658
332.024658
332.024658
330.759033
330.759033
330.759033
330.759033
330.759033
323.419952
323.419952
323.419952
323.419952
323.419952
342.350922
342.350922
342.350922
342.350922
342.350922
345.081818
345.081818
345.081818
345.081818
345.081818
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
43.5
44
44.5
45
45.5
46
46.5
47
47.5
48
48.5
49
49.5
50
50.5
51
51.5
52
52.5
53
53.5
54
54.5
55
55.5
56
56.5
57
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
63
63.5
64
64.5
65
65.5
66
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7528.71
7529.04
7529.37
7529.7
7530.03
7530.36
7530.69
7531.02
7531.35
7531.68
7532.01
7532.34
7532.67
7533
7533.33
7533.66
7533.99
7534.32
7534.65
7534.98
7535.31
7535.64
7535.97
7536.3
7536.63
7536.96
7537.29
7537.62
7537.95
7538.28
7538.61
7538.94
7539.27
7539.6
7539.93
7540.26
7540.59
7540.92
7541.25
7541.58
7541.91
7542.24
7542.57
7542.9
7543.23
7543.56
002038
10/12/09 02:18:39
10/12/09 02:18:42
10/12/09 02:18:45
10/12/09 02:18:48
10/12/09 02:18:51
10/12/09 02:18:54
10/12/09 02:18:57
10/12/09 02:19:00
10/12/09 02:19:03
10/12/09 02:19:06
10/12/09 02:19:09
10/12/09 02:19:12
10/12/09 02:19:15
10/12/09 02:19:18
10/12/09 02:19:21
10/12/09 02:19:24
10/12/09 02:19:27
10/12/09 02:19:30
10/12/09 02:19:33
10/12/09 02:19:36
10/12/09 02:19:39
10/12/09 02:19:42
10/12/09 02:19:45
10/12/09 02:19:48
10/12/09 02:19:51
10/12/09 02:19:54
10/12/09 02:19:57
10/12/09 02:20:00
10/12/09 02:20:03
10/12/09 02:20:06
10/12/09 02:20:09
10/12/09 02:20:12
10/12/09 02:20:15
10/12/09 02:20:18
10/12/09 02:20:21
10/12/09 02:20:24
10/12/09 02:20:27
10/12/09 02:20:30
10/12/09 02:20:33
10/12/09 02:20:36
10/12/09 02:20:39
10/12/09 02:20:42
10/12/09 02:20:45
10/12/09 02:20:48
10/12/09 02:20:51
10/12/09 02:20:54
59.986
59.986
59.98
59.981
59.989
60.007
60.007
59.986
59.981
59.974
59.976
59.974
59.977
59.979
59.982
59.987
59.988
59.987
59.987
59.985
59.984
59.983
59.989
59.988
59.984
59.983
59.981
59.983
59.986
59.987
59.985
59.98
59.983
59.979
59.979
59.981
59.98
59.981
59.98
59.977
59.979
59.979
59.976
59.972
59.971
59.973
3677.397
3677.917
3678.617
3678.963
3680.737
3680.045
3674.076
3676.222
3677.497
3677.49
3675.437
3680.451
3683.829
3682.843
3680.566
3678.229
3675.759
3671.942
3670.476
3670.129
3672.048
3671.576
3672.414
3671.882
3671.336
3670.726
3671.364
3671.401
3672.181
3670.296
3668.59
3669.908
3670.263
3669.382
3670.438
3671.403
3672.372
3671.947
3670.705
3670.137
3672.391
3672.558
3672.626
3671.8
3673.874
3676.263
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
346.537384
346.537384
346.537384
346.537384
346.537384
342.905762
342.905762
342.905762
342.905762
342.905762
340.094391
340.094391
340.094391
340.094391
340.094391
342.771179
342.771179
342.771179
342.771179
342.771179
342.909912
342.909912
342.909912
342.909912
342.909912
343.286011
343.286011
343.286011
343.286011
343.286011
331.852966
331.852966
331.852966
331.852966
331.852966
329.98822
329.98822
329.98822
329.98822
329.98822
255.444168
255.444168
255.444168
255.444168
255.444168
254.838303
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
66.5
67
67.5
68
68.5
69
69.5
70
70.5
71
71.5
72
72.5
73
73.5
74
74.5
75
75.5
76
76.5
77
77.5
78
78.5
79
79.5
80
80.5
81
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7543.89
7544.22
7544.55
7544.88
7545.21
7545.54
7545.87
7546.2
7546.53
7546.86
7547.19
7547.52
7547.85
7548.18
7548.51
7548.84
7549.17
7549.5
7549.83
7550.16
7550.49
7550.82
7551.15
7551.48
7551.81
7552.14
7552.47
7552.8
7553.13
7553.46
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
002039
10/12/09 02:20:57
10/12/09 02:21:00
10/12/09 02:21:03
10/12/09 02:21:06
10/12/09 02:21:09
10/12/09 02:21:12
10/12/09 02:21:15
10/12/09 02:21:18
10/12/09 02:21:21
10/12/09 02:21:24
10/12/09 02:21:27
10/12/09 02:21:30
10/12/09 02:21:33
10/12/09 02:21:36
10/12/09 02:21:39
10/12/09 02:21:42
10/12/09 02:21:45
10/12/09 02:21:48
10/12/09 02:21:51
10/12/09 02:21:54
10/12/09 02:21:57
10/12/09 02:22:00
10/12/09 02:22:03
10/12/09 02:22:06
10/12/09 02:22:09
10/12/09 02:22:12
10/12/09 02:22:15
10/12/09 02:22:18
10/12/09 02:22:21
10/12/09 02:22:24
10/12/09 02:22:27
10/12/09 02:22:30
10/12/09 02:22:33
10/12/09 02:22:36
10/12/09 02:22:39
10/12/09 02:22:42
10/12/09 02:22:45
10/12/09 02:22:48
10/12/09 02:22:51
10/12/09 02:22:54
10/12/09 02:22:57
10/12/09 02:23:00
10/12/09 02:23:03
10/12/09 02:23:06
10/12/09 02:23:09
10/12/09 02:23:12
59.973
59.971
59.975
59.977
59.975
59.98
59.979
59.982
59.982
59.982
59.981
59.984
59.985
59.989
59.993
59.998
59.998
60.007
60.01
60.014
60.013
60.008
60.01
60.019
60.023
60.02
60.021
60.02
60.019
60.022
60.025
60.026
60.02
60.018
60.018
60.019
60.019
60.022
60.022
60.02
60.02
60.02
60.02
60.021
60.018
60.014
3676.87
3676.543
3675.752
3675.256
3671.277
3671.593
3669.963
3669.54
3668.706
3667.677
3666.599
3666.911
3666.405
3667.456
3665.262
3664.031
3663.229
3662.055
3662.076
3662.224
3663.794
3664.139
3664.159
3663.265
3661.929
3661.512
3658.661
3656.785
3658.126
3657.71
3660.228
3659.224
3658.669
3658.155
3659.778
3660.82
3662.387
3662.079
3662.678
3663.577
3662.959
3662.552
3663.601
3663.91
3662.791
3663.396
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
254.838303
254.838303
254.838303
254.838303
257.146973
257.146973
257.146973
257.146973
257.146973
262.289368
262.289368
262.289368
262.289368
262.289368
256.647949
256.647949
256.647949
256.647949
256.647949
256.307251
256.307251
256.307251
256.307251
256.307251
249.086395
249.086395
249.086395
249.086395
249.086395
253.742477
253.742477
253.742477
253.742477
253.742477
257.421204
257.421204
257.421204
257.421204
257.421204
261.73822
261.73822
261.73822
261.73822
261.73822
271.875977
271.875977
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
002040
10/12/09 02:23:15
10/12/09 02:23:18
10/12/09 02:23:21
10/12/09 02:23:24
10/12/09 02:23:27
10/12/09 02:23:30
10/12/09 02:23:33
10/12/09 02:23:36
10/12/09 02:23:39
10/12/09 02:23:42
10/12/09 02:23:45
10/12/09 02:23:48
10/12/09 02:23:51
10/12/09 02:23:54
10/12/09 02:23:57
10/12/09 02:24:00
10/12/09 02:24:03
10/12/09 02:24:06
10/12/09 02:24:09
10/12/09 02:24:12
10/12/09 02:24:15
10/12/09 02:24:18
10/12/09 02:24:21
10/12/09 02:24:24
10/12/09 02:24:27
10/12/09 02:24:30
10/12/09 02:24:33
10/12/09 02:24:36
10/12/09 02:24:39
10/12/09 02:24:42
10/12/09 02:24:45
10/12/09 02:24:48
10/12/09 02:24:51
10/12/09 02:24:54
10/12/09 02:24:57
10/12/09 02:25:00
10/12/09 02:25:03
10/12/09 02:25:06
10/12/09 02:25:09
10/12/09 02:25:12
10/12/09 02:25:15
10/12/09 02:25:18
10/12/09 02:25:21
10/12/09 02:25:24
10/12/09 02:25:27
10/12/09 02:25:30
60.014
60.013
60.01
60.011
60.011
60.012
60.009
60.009
60.009
60.002
59.999
59.995
59.997
59.998
59.998
59.995
59.995
59.993
59.988
59.982
59.982
59.982
59.984
59.978
59.978
59.975
59.974
59.979
59.98
59.98
59.984
59.988
59.988
59.992
59.991
59.991
59.993
59.996
60.002
60.003
60.004
60.004
60.002
60.008
60.01
60.01
3664.315
3665.313
3666.141
3666.726
3667.545
3666.688
3666.71
3667.696
3667.043
3666.624
3665.88
3665.403
3665.68
3665.352
3665.065
3666.133
3666.735
3667.084
3667.337
3667.853
3668.691
3669.399
3671.228
3670.25
3671.549
3673.243
3675.824
3676.418
3674.637
3675.329
3674.768
3674.399
3673.04
3672.442
3671.68
3671.493
3669.53
3670.028
3671.578
3672.625
3673.819
3673.25
3673.496
3672.418
3672.217
3672.261
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
271.875977
271.875977
271.875977
262.073486
262.073486
262.073486
262.073486
262.073486
260.36441
260.36441
260.36441
260.36441
260.36441
352.644379
352.644379
352.644379
352.644379
352.644379
354.89566
354.89566
354.89566
354.89566
354.89566
340.46936
340.46936
340.46936
340.46936
340.46936
337.642914
337.642914
337.642914
337.642914
337.642914
284.36084
284.36084
284.36084
284.36084
284.36084
260.467987
260.467987
260.467987
260.467987
260.467987
253.141541
253.141541
253.141541
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
002041
10/12/09 02:25:33
10/12/09 02:25:36
10/12/09 02:25:39
10/12/09 02:25:42
10/12/09 02:25:45
10/12/09 02:25:48
10/12/09 02:25:51
10/12/09 02:25:54
10/12/09 02:25:57
10/12/09 02:26:00
10/12/09 02:26:03
10/12/09 02:26:06
10/12/09 02:26:09
10/12/09 02:26:12
10/12/09 02:26:15
10/12/09 02:26:18
10/12/09 02:26:21
10/12/09 02:26:24
10/12/09 02:26:27
10/12/09 02:26:30
10/12/09 02:26:33
10/12/09 02:26:36
10/12/09 02:26:39
10/12/09 02:26:42
10/12/09 02:26:45
10/12/09 02:26:48
10/12/09 02:26:51
10/12/09 02:26:54
10/12/09 02:26:57
10/12/09 02:27:00
10/12/09 02:27:03
10/12/09 02:27:06
10/12/09 02:27:09
10/12/09 02:27:12
10/12/09 02:27:15
10/12/09 02:27:18
10/12/09 02:27:21
10/12/09 02:27:24
10/12/09 02:27:27
10/12/09 02:27:30
10/12/09 02:27:33
10/12/09 02:27:36
10/12/09 02:27:39
10/12/09 02:27:42
10/12/09 02:27:45
10/12/09 02:27:48
60.011
60.014
60.013
60.011
60.011
60.022
60.017
60.013
60.014
60.017
60.019
60.019
60.027
60.026
60.022
60.017
60.019
60.019
60.021
60.021
60.019
60.022
60.031
60.037
60.036
60.046
60.048
60.043
60.041
60.041
60.039
60.043
60.045
60.041
60.041
60.039
59.978
59.836
59.869
59.891
59.88
59.875
59.883
59.886
59.885
59.888
3673.603
3673.553
3674.537
3673.813
3672.563
3673.068
3672.52
3671.25
3672.989
3672.982
3671.952
3671.193
3671.189
3668.611
3664.495
3666.062
3666.787
3670.454
3671.668
3672.493
3672.857
3672.164
3669.983
3666.467
3661.599
3660.672
3649.19
3650.025
3649.512
3654.294
3651.874
3651.059
3648.236
3645.387
3645.446
3640.682
3659.465
3696.362
3734.673
3737.157
3766.113
3766.194
3769.925
3780.621
3782.5
3784.962
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
253.141541
253.141541
251.929871
251.929871
251.929871
251.929871
251.929871
250.674194
250.674194
250.674194
250.674194
250.674194
253.631866
253.631866
253.631866
253.631866
253.631866
246.957306
246.957306
246.957306
246.957306
246.957306
254.541779
254.541779
254.541779
254.541779
165.101685
165.101685
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7570
7569
7570
7570
7570
7570
7570
7570
7570
002042
10/12/09 02:27:51
10/12/09 02:27:54
10/12/09 02:27:57
10/12/09 02:28:00
10/12/09 02:28:03
10/12/09 02:28:06
10/12/09 02:28:09
10/12/09 02:28:12
10/12/09 02:28:15
10/12/09 02:28:18
10/12/09 02:28:21
10/12/09 02:28:24
10/12/09 02:28:27
10/12/09 02:28:30
10/12/09 02:28:33
10/12/09 02:28:36
10/12/09 02:28:39
10/12/09 02:28:42
10/12/09 02:28:45
10/12/09 02:28:48
10/12/09 02:28:51
10/12/09 02:28:54
10/12/09 02:28:57
10/12/09 02:29:00
10/12/09 02:29:03
10/12/09 02:29:06
10/12/09 02:29:09
10/12/09 02:29:12
10/12/09 02:29:15
10/12/09 02:29:18
10/12/09 02:29:21
10/12/09 02:29:24
10/12/09 02:29:27
10/12/09 02:29:30
10/12/09 02:29:33
10/12/09 02:29:36
10/12/09 02:29:39
10/12/09 02:29:42
10/12/09 02:29:45
10/12/09 02:29:48
10/12/09 02:29:51
10/12/09 02:29:54
10/12/09 02:29:57
10/12/09 02:30:00
10/12/09 02:30:03
10/12/09 02:30:06
59.89
59.894
59.893
59.894
59.891
59.885
59.885
59.887
59.888
59.89
59.889
59.873
59.857
59.852
59.858
59.866
59.865
59.866
59.871
59.879
59.88
59.886
59.89
59.889
59.893
59.903
59.902
59.904
59.907
59.916
59.916
59.918
59.92
59.92
59.917
59.921
59.923
59.925
59.928
59.932
59.927
59.931
59.929
59.931
59.937
59.945
3784.419
3788.072
3788.868
3788.472
3793.074
3794.374
3800.427
3799.959
3802.925
3802.951
3805.496
3805.617
3811.503
3814.862
3825.643
3826.053
3827.524
3826.753
3826.454
3825.713
3822.505
3819.081
3816.815
3815.01
3811.838
3809.652
3805.593
3804.188
3793.975
3792.169
3789.534
3788.132
3783.028
3781.701
3775.635
3774.604
3773.958
3772.722
3769.63
3768.707
3767.021
3767.408
3766.259
3765.672
3766.123
3765.105
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
0
0
0
0
0
0
0
0
0
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7568
7565
7560
7563
7564
7566
7570
7570
7570
7570
7570
7569
7575
7573
7571
7573
7575
7577
7577
7578
7579
7580
7581
7585
7588
7589
7589
7590
7590
7590
7591
7591
7591
7592
7592
002043
10/12/09 02:30:09
10/12/09 02:30:12
10/12/09 02:30:15
10/12/09 02:30:18
10/12/09 02:30:21
10/12/09 02:30:24
10/12/09 02:30:27
10/12/09 02:30:30
10/12/09 02:30:33
10/12/09 02:30:36
10/12/09 02:30:39
10/12/09 02:30:42
10/12/09 02:30:45
10/12/09 02:30:48
10/12/09 02:30:51
10/12/09 02:30:54
10/12/09 02:30:57
10/12/09 02:31:00
10/12/09 02:31:03
10/12/09 02:31:06
10/12/09 02:31:09
10/12/09 02:31:12
10/12/09 02:31:15
10/12/09 02:31:18
10/12/09 02:31:21
10/12/09 02:31:24
10/12/09 02:31:27
10/12/09 02:31:30
10/12/09 02:31:33
10/12/09 02:31:36
10/12/09 02:31:39
10/12/09 02:31:42
10/12/09 02:31:45
10/12/09 02:31:48
10/12/09 02:31:51
10/12/09 02:31:54
10/12/09 02:31:57
10/12/09 02:32:00
10/12/09 02:32:03
10/12/09 02:32:06
10/12/09 02:32:09
10/12/09 02:32:12
10/12/09 02:32:15
10/12/09 02:32:18
10/12/09 02:32:21
10/12/09 02:32:24
59.949
59.942
59.941
59.945
59.948
59.949
59.951
59.953
59.951
59.952
59.952
59.952
59.954
59.953
59.953
59.954
59.954
59.957
59.956
59.956
59.955
59.961
59.962
59.968
59.966
59.968
59.97
59.97
59.969
59.97
59.971
59.973
59.976
59.978
59.976
59.976
59.978
59.98
59.982
59.98
59.979
59.979
59.983
59.984
59.988
59.987
3758.387
3753.922
3746.889
3747.875
3748.661
3746.706
3742.741
3740.259
3731.382
3727.838
3722.649
3720.578
3718.142
3715.753
3713.484
3710.848
3712.092
3714.623
3716.168
3716.461
3717.759
3722.361
3722.658
3722.267
3721.787
3723.091
3723.435
3723.893
3727.121
3728.053
3732.53
3733.327
3736.907
3736.822
3739.944
3740.877
3745.234
3746.608
3750.716
3751.558
3755.599
3756.407
3760.405
3760.982
3762.737
3763.212
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
249.33757
249.33757
249.33757
249.33757
249.33757
258.278168
258.278168
258.278168
258.278168
258.278168
258.406372
258.406372
258.406372
258.406372
258.406372
260.538879
260.538879
260.538879
260.538879
260.538879
257.88208
257.88208
257.88208
257.88208
257.88208
258.588654
258.588654
258.588654
258.588654
258.588654
261.906158
261.906158
261.906158
261.906158
261.906158
256.747803
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7593
7594
7595
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
002044
10/12/09 02:32:27
10/12/09 02:32:30
10/12/09 02:32:33
10/12/09 02:32:36
10/12/09 02:32:39
10/12/09 02:32:42
10/12/09 02:32:45
10/12/09 02:32:48
10/12/09 02:32:51
10/12/09 02:32:54
10/12/09 02:32:57
10/12/09 02:33:00
10/12/09 02:33:03
10/12/09 02:33:06
10/12/09 02:33:09
10/12/09 02:33:12
10/12/09 02:33:15
10/12/09 02:33:18
10/12/09 02:33:21
10/12/09 02:33:24
10/12/09 02:33:27
10/12/09 02:33:30
10/12/09 02:33:33
10/12/09 02:33:36
10/12/09 02:33:39
10/12/09 02:33:42
10/12/09 02:33:45
10/12/09 02:33:48
10/12/09 02:33:51
10/12/09 02:33:54
10/12/09 02:33:57
10/12/09 02:34:00
10/12/09 02:34:03
10/12/09 02:34:06
10/12/09 02:34:09
10/12/09 02:34:12
10/12/09 02:34:15
10/12/09 02:34:18
10/12/09 02:34:21
10/12/09 02:34:24
10/12/09 02:34:27
10/12/09 02:34:30
10/12/09 02:34:33
10/12/09 02:34:36
10/12/09 02:34:39
10/12/09 02:34:42
59.987
59.993
59.992
59.989
59.986
59.983
59.988
59.996
59.998
60.001
59.999
59.999
60.002
60.007
60.008
60.014
60.017
60.021
60.017
60.019
60.023
60.025
60.021
60.024
60.024
60.02
60.025
60.02
60.02
60.022
60.022
60.021
60.023
60.022
60.019
60.018
60.018
60.019
60.019
60.015
60.016
60.013
60.012
60.01
60.007
60.009
3766.085
3766.433
3767.792
3768.634
3772.445
3773.695
3775.841
3775.363
3775.492
3776.42
3779.692
3781.256
3783.092
3783.896
3785.768
3785.463
3786.304
3787.259
3787.955
3788.03
3789.216
3787.537
3786.077
3787.93
3786.875
3786.55
3785.018
3785.614
3785.804
3786.864
3785.254
3785.726
3785.821
3785.798
3786.939
3787.627
3789.673
3789.404
3789.183
3789.369
3788.665
3788.933
3790.805
3790.411
3791.54
3792.945
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
256.747803
256.747803
256.747803
256.747803
167.431976
167.431976
167.431976
167.431976
167.431976
164.973404
164.973404
164.973404
164.973404
164.973404
157.628082
157.628082
157.628082
157.628082
157.628082
155.531708
155.531708
155.531708
155.531708
155.531708
160.447235
160.447235
160.447235
160.447235
160.447235
163.958603
163.958603
163.958603
163.958603
163.958603
166.072449
166.072449
166.072449
166.072449
166.072449
163.766586
163.766586
163.766586
163.766586
163.766586
165.101685
165.101685
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
002045
10/12/09 02:34:45
10/12/09 02:34:48
10/12/09 02:34:51
10/12/09 02:34:54
10/12/09 02:34:57
10/12/09 02:35:00
10/12/09 02:35:03
10/12/09 02:35:06
10/12/09 02:35:09
10/12/09 02:35:12
10/12/09 02:35:15
10/12/09 02:35:18
10/12/09 02:35:21
10/12/09 02:35:24
10/12/09 02:35:27
10/12/09 02:35:30
10/12/09 02:35:33
10/12/09 02:35:36
10/12/09 02:35:39
10/12/09 02:35:42
10/12/09 02:35:45
10/12/09 02:35:48
10/12/09 02:35:51
10/12/09 02:35:54
10/12/09 02:35:57
10/12/09 02:36:00
10/12/09 02:36:03
10/12/09 02:36:06
10/12/09 02:36:09
10/12/09 02:36:12
10/12/09 02:36:15
10/12/09 02:36:18
10/12/09 02:36:21
10/12/09 02:36:24
10/12/09 02:36:27
10/12/09 02:36:30
10/12/09 02:36:33
10/12/09 02:36:36
10/12/09 02:36:39
10/12/09 02:36:42
10/12/09 02:36:45
10/12/09 02:36:48
10/12/09 02:36:51
10/12/09 02:36:54
10/12/09 02:36:57
10/12/09 02:37:00
60.009
60.003
59.999
59.992
59.991
59.992
59.988
59.985
59.984
59.984
59.982
59.982
59.979
59.976
59.976
59.982
59.978
59.974
59.976
59.977
59.975
59.969
59.97
59.973
59.978
59.978
59.975
59.976
59.975
59.969
59.966
59.966
59.969
59.968
59.965
59.97
59.972
59.967
59.969
59.969
59.967
59.966
59.965
59.967
59.965
59.964
3791.443
3791.426
3790.457
3790.216
3788.457
3788.105
3788.189
3788.497
3788.571
3788.101
3786.453
3787.732
3789.285
3788.256
3790.467
3790.665
3789.674
3789.267
3790.43
3789.914
3787.442
3788.963
3791.877
3792.911
3789.125
3788.08
3787.135
3787.164
3787.405
3786.487
3789.214
3790.512
3792.218
3790.959
3789.026
3789.167
3785.69
3784.831
3784.32
3782.809
3779.352
3779.056
3779.212
3779.335
3775.647
3776.597
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
002046
10/12/09 02:37:03
10/12/09 02:37:06
10/12/09 02:37:09
10/12/09 02:37:12
10/12/09 02:37:15
10/12/09 02:37:18
10/12/09 02:37:21
10/12/09 02:37:24
10/12/09 02:37:27
10/12/09 02:37:30
10/12/09 02:37:33
10/12/09 02:37:36
10/12/09 02:37:39
10/12/09 02:37:42
10/12/09 02:37:45
10/12/09 02:37:48
10/12/09 02:37:51
10/12/09 02:37:54
10/12/09 02:37:57
10/12/09 02:38:00
10/12/09 02:38:03
10/12/09 02:38:06
10/12/09 02:38:09
10/12/09 02:38:12
10/12/09 02:38:15
10/12/09 02:38:18
10/12/09 02:38:21
10/12/09 02:38:24
10/12/09 02:38:27
10/12/09 02:38:30
10/12/09 02:38:33
10/12/09 02:38:36
10/12/09 02:38:39
10/12/09 02:38:42
10/12/09 02:38:45
10/12/09 02:38:48
10/12/09 02:38:51
10/12/09 02:38:54
10/12/09 02:38:57
10/12/09 02:39:00
10/12/09 02:39:03
10/12/09 02:39:06
10/12/09 02:39:09
10/12/09 02:39:12
10/12/09 02:39:15
10/12/09 02:39:18
59.97
59.969
59.968
59.965
59.97
59.968
59.965
59.969
59.967
59.966
59.979
59.983
59.974
59.965
59.962
59.961
59.961
59.963
59.959
59.951
59.953
59.957
59.956
59.963
59.961
59.963
59.963
59.968
59.968
59.97
59.973
59.965
59.967
59.972
59.976
59.969
59.973
59.978
59.981
59.981
59.982
59.984
59.982
59.979
59.98
59.978
3776.023
3773.17
3768.793
3768.503
3767.366
3764.786
3759.592
3761.894
3760.583
3760.157
3759.495
3757.773
3753.087
3751.637
3758.225
3759.25
3760.965
3762.022
3763.1
3763.858
3766.127
3768.339
3767.438
3765.606
3761.57
3761.92
3758.522
3752.429
3753.83
3753.51
3752.741
3753.178
3753.291
3752.872
3749.398
3747.476
3741.285
3746.651
3743.351
3741.618
3738.484
3738.901
3737.273
3736.308
3735.448
3735.65
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
229.466965
229.466965
229.466965
229.466965
228.980164
228.980164
228.980164
228.980164
228.980164
219.975555
219.975555
219.975555
219.975555
219.975555
229.089249
229.089249
229.089249
229.089249
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
002047
10/12/09 02:39:21
10/12/09 02:39:24
10/12/09 02:39:27
10/12/09 02:39:30
10/12/09 02:39:33
10/12/09 02:39:36
10/12/09 02:39:39
10/12/09 02:39:42
10/12/09 02:39:45
10/12/09 02:39:48
10/12/09 02:39:51
10/12/09 02:39:54
10/12/09 02:39:57
10/12/09 02:40:00
10/12/09 02:40:03
10/12/09 02:40:06
10/12/09 02:40:09
10/12/09 02:40:12
10/12/09 02:40:15
10/12/09 02:40:18
10/12/09 02:40:21
10/12/09 02:40:24
10/12/09 02:40:27
10/12/09 02:40:30
10/12/09 02:40:33
10/12/09 02:40:36
10/12/09 02:40:39
10/12/09 02:40:42
10/12/09 02:40:45
10/12/09 02:40:48
10/12/09 02:40:51
10/12/09 02:40:54
10/12/09 02:40:57
10/12/09 02:41:00
10/12/09 02:41:03
10/12/09 02:41:06
10/12/09 02:41:09
10/12/09 02:41:12
10/12/09 02:41:15
10/12/09 02:41:18
10/12/09 02:41:21
10/12/09 02:41:24
10/12/09 02:41:27
10/12/09 02:41:30
10/12/09 02:41:33
10/12/09 02:41:36
59.98
59.98
59.978
59.972
59.971
59.974
59.975
59.972
59.969
59.974
59.972
59.972
59.977
59.978
59.976
59.974
59.977
59.978
59.979
59.977
59.974
59.971
59.971
59.968
59.966
59.971
59.973
59.969
59.972
59.973
59.97
59.974
59.982
59.985
59.985
59.989
59.989
59.987
59.99
59.996
60.001
60.004
60.006
60.014
60.019
60.025
3738.012
3736.748
3736.067
3736.094
3738.571
3738.875
3738.647
3737.684
3737.892
3740.017
3742.053
3742.424
3742.245
3741.723
3740.629
3739.964
3742.833
3741.268
3738.966
3738.706
3739.86
3738.102
3743.507
3743.419
3745.744
3747.34
3749.75
3746.217
3743.745
3743.149
3739.453
3733.376
3737.583
3736.229
3733.434
3733.115
3729.18
3725.459
3720.108
3720.938
3725.677
3727.754
3727.683
3727.231
3726.446
3726.016
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
229.089249
229.663269
229.663269
229.663269
229.663269
229.663269
229.233856
229.233856
229.233856
229.233856
229.233856
231.409882
231.409882
231.409882
231.409882
231.409882
218.622284
218.622284
218.622284
218.622284
218.622284
213.535858
213.535858
213.535858
213.535858
213.535858
225.651855
225.651855
225.651855
225.651855
225.651855
212.573639
212.573639
212.573639
212.573639
212.573639
219.897293
219.897293
219.897293
219.897293
219.897293
231.1754
231.1754
231.1754
231.1754
231.1754
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
002048
10/12/09 02:41:39
10/12/09 02:41:42
10/12/09 02:41:45
10/12/09 02:41:48
10/12/09 02:41:51
10/12/09 02:41:54
10/12/09 02:41:57
10/12/09 02:42:00
10/12/09 02:42:03
10/12/09 02:42:06
10/12/09 02:42:09
10/12/09 02:42:12
10/12/09 02:42:15
10/12/09 02:42:18
10/12/09 02:42:21
10/12/09 02:42:24
10/12/09 02:42:27
10/12/09 02:42:30
10/12/09 02:42:33
10/12/09 02:42:36
10/12/09 02:42:39
10/12/09 02:42:42
10/12/09 02:42:45
10/12/09 02:42:48
10/12/09 02:42:51
10/12/09 02:42:54
10/12/09 02:42:57
10/12/09 02:43:00
10/12/09 02:43:03
10/12/09 02:43:06
10/12/09 02:43:09
10/12/09 02:43:12
10/12/09 02:43:15
10/12/09 02:43:18
10/12/09 02:43:21
10/12/09 02:43:24
10/12/09 02:43:27
10/12/09 02:43:30
10/12/09 02:43:33
10/12/09 02:43:36
10/12/09 02:43:39
10/12/09 02:43:42
10/12/09 02:43:45
10/12/09 02:43:48
10/12/09 02:43:51
10/12/09 02:43:54
60.026
60.029
60.029
60.036
60.037
60.036
60.041
60.044
60.043
60.048
60.046
60.043
60.043
60.043
60.043
60.04
60.041
60.039
60.036
60.033
60.034
60.037
60.035
60.033
60.036
60.034
60.032
60.034
60.033
60.035
60.035
60.039
60.037
60.036
60.034
60.037
60.037
60.038
60.04
60.045
60.045
60.043
60.04
60.046
60.042
60.039
3716.375
3717.333
3717.142
3715.166
3710.283
3710.158
3698.591
3704.591
3702.482
3701.316
3699.529
3699.726
3690.477
3696.865
3696.182
3696.541
3698.686
3699.631
3699.712
3700.106
3701.122
3701.865
3701.998
3702.913
3705.522
3704.967
3702.771
3703.706
3705.435
3704.36
3702.204
3701.942
3703.318
3702.457
3703.269
3703.844
3702.518
3702.28
3692.178
3700.276
3697.729
3696.916
3697.346
3698.429
3693.584
3693.241
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
226.634125
226.634125
226.634125
226.634125
226.634125
227.255066
227.255066
227.255066
227.255066
227.255066
229.290222
229.290222
229.290222
229.290222
229.290222
221.461365
221.461365
221.461365
221.461365
221.461365
241.274368
241.274368
241.274368
241.274368
241.274368
243.071854
243.071854
243.071854
243.071854
243.071854
241.670212
241.670212
241.670212
241.670212
241.670212
228.149307
228.149307
228.149307
228.149307
228.149307
235.128983
235.128983
235.128983
235.128983
235.128983
246.433136
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
296.5
297
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
317.5
318
318.5
319
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
002049
10/12/09 02:43:57
10/12/09 02:44:00
10/12/09 02:44:03
10/12/09 02:44:06
10/12/09 02:44:09
10/12/09 02:44:12
10/12/09 02:44:15
10/12/09 02:44:18
10/12/09 02:44:21
10/12/09 02:44:24
10/12/09 02:44:27
10/12/09 02:44:30
10/12/09 02:44:33
10/12/09 02:44:36
10/12/09 02:44:39
10/12/09 02:44:42
10/12/09 02:44:45
10/12/09 02:44:48
10/12/09 02:44:51
10/12/09 02:44:54
10/12/09 02:44:57
10/12/09 02:45:00
10/12/09 02:45:03
10/12/09 02:45:06
10/12/09 02:45:09
10/12/09 02:45:12
10/12/09 02:45:15
10/12/09 02:45:18
10/12/09 02:45:21
10/12/09 02:45:24
10/12/09 02:45:27
10/12/09 02:45:30
10/12/09 02:45:33
10/12/09 02:45:36
10/12/09 02:45:39
10/12/09 02:45:42
10/12/09 02:45:45
10/12/09 02:45:48
10/12/09 02:45:51
10/12/09 02:45:54
10/12/09 02:45:57
10/12/09 02:46:00
10/12/09 02:46:03
10/12/09 02:46:06
10/12/09 02:46:09
10/12/09 02:46:12
60.039
60.037
60.034
60.032
60.031
60.027
60.031
60.031
60.031
60.039
60.039
60.037
60.035
60.04
60.042
60.036
60.04
60.045
60.048
60.044
60.044
60.044
60.04
60.045
60.044
60.039
60.042
60.041
60.038
60.037
60.039
60.04
60.039
60.038
60.039
60.037
60.037
60.039
60.038
60.035
60.033
60.03
60.032
60.037
60.042
60.036
3699.364
3701.791
3700.753
3702.148
3707.521
3707.287
3707.34
3707.917
3706.857
3707.615
3703.746
3701.582
3701.208
3702.212
3700.397
3699.69
3700.827
3700.662
3695.688
3695.819
3694.799
3696.897
3696.023
3698.424
3700.177
3699.806
3697.681
3698.507
3698.466
3699.077
3701.592
3700.902
3700.27
3701.139
3700.264
3699.458
3700.458
3699.505
3699.216
3699.4
3702.173
3702.968
3704.952
3705.775
3703.744
3701.981
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
246.433136
246.433136
246.433136
246.433136
236.553543
236.553543
236.553543
236.553543
236.553543
230.297562
230.297562
230.297562
230.297562
230.297562
231.175537
231.175537
231.175537
231.175537
231.175537
225.61763
225.61763
225.61763
225.61763
225.61763
230.734421
230.734421
230.734421
230.734421
230.734421
234.847107
234.847107
234.847107
234.847107
234.847107
228.960922
228.960922
228.960922
228.960922
228.960922
231.177917
231.177917
231.177917
231.177917
231.177917
236.489288
236.489288
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
319.5
320
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
002050
10/12/09 02:46:15
10/12/09 02:46:18
10/12/09 02:46:21
10/12/09 02:46:24
10/12/09 02:46:27
10/12/09 02:46:30
10/12/09 02:46:33
10/12/09 02:46:36
10/12/09 02:46:39
10/12/09 02:46:42
10/12/09 02:46:45
10/12/09 02:46:48
10/12/09 02:46:51
10/12/09 02:46:54
10/12/09 02:46:57
10/12/09 02:47:00
10/12/09 02:47:03
10/12/09 02:47:06
10/12/09 02:47:09
10/12/09 02:47:12
10/12/09 02:47:15
10/12/09 02:47:18
10/12/09 02:47:21
10/12/09 02:47:24
10/12/09 02:47:27
10/12/09 02:47:30
10/12/09 02:47:33
10/12/09 02:47:36
10/12/09 02:47:39
10/12/09 02:47:42
10/12/09 02:47:45
10/12/09 02:47:48
10/12/09 02:47:51
10/12/09 02:47:54
10/12/09 02:47:57
10/12/09 02:48:00
10/12/09 02:48:03
10/12/09 02:48:06
10/12/09 02:48:09
10/12/09 02:48:12
10/12/09 02:48:15
10/12/09 02:48:18
10/12/09 02:48:21
10/12/09 02:48:24
10/12/09 02:48:27
10/12/09 02:48:30
60.031
60.031
60.034
60.032
60.038
60.044
60.042
60.04
60.04
60.043
60.041
60.038
60.043
60.042
60.036
60.041
60.042
60.043
60.036
60.039
60.037
60.035
60.035
60.036
60.03
60.03
60.031
60.032
60.031
60.032
60.032
60.037
60.04
60.042
60.036
60.041
60.04
60.036
60.038
60.041
60.04
60.033
60.034
60.04
60.041
60.037
3700.747
3702.213
3705.514
3704.449
3703.62
3702.795
3697.38
3696.25
3693.518
3693.577
3695.186
3693.786
3694.926
3694.938
3691.33
3692.686
3693.39
3692.357
3690.836
3692.042
3694.117
3695.258
3695.949
3695.491
3696.486
3697.336
3699.357
3699.251
3699.105
3699.126
3698.136
3698.277
3695.94
3693.736
3691.759
3691.919
3691.582
3692.374
3694.71
3694.331
3693.617
3694.324
3694.66
3693.748
3691.445
3691.012
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
236.489288
236.489288
236.489288
245.038925
245.038925
245.038925
245.038925
245.038925
223.605682
223.605682
223.605682
223.605682
223.605682
231.119354
231.119354
231.119354
231.119354
231.119354
237.20665
237.20665
237.20665
237.20665
237.20665
240.516373
240.516373
240.516373
240.516373
240.516373
237.566055
237.566055
237.566055
237.566055
237.566055
231.581421
231.581421
231.581421
231.581421
231.581421
235.850845
235.850845
235.850845
235.850845
235.850845
233.559982
233.559982
233.559982
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
002051
10/12/09 02:48:33
10/12/09 02:48:36
10/12/09 02:48:39
10/12/09 02:48:42
10/12/09 02:48:45
10/12/09 02:48:48
10/12/09 02:48:51
10/12/09 02:48:54
10/12/09 02:48:57
10/12/09 02:49:00
10/12/09 02:49:03
10/12/09 02:49:06
10/12/09 02:49:09
10/12/09 02:49:12
10/12/09 02:49:15
10/12/09 02:49:18
10/12/09 02:49:21
10/12/09 02:49:24
10/12/09 02:49:27
10/12/09 02:49:30
10/12/09 02:49:33
10/12/09 02:49:36
10/12/09 02:49:39
10/12/09 02:49:42
10/12/09 02:49:45
10/12/09 02:49:48
10/12/09 02:49:51
10/12/09 02:49:54
10/12/09 02:49:57
10/12/09 02:50:00
10/12/09 02:50:03
10/12/09 02:50:06
10/12/09 02:50:09
10/12/09 02:50:12
10/12/09 02:50:15
10/12/09 02:50:18
10/12/09 02:50:21
10/12/09 02:50:24
10/12/09 02:50:27
10/12/09 02:50:30
10/12/09 02:50:33
10/12/09 02:50:36
10/12/09 02:50:39
10/12/09 02:50:42
10/12/09 02:50:45
10/12/09 02:50:48
60.036
60.038
60.039
60.034
60.033
60.034
60.029
60.031
60.03
60.026
60.022
60.024
60.023
60.021
60.023
60.026
60.026
60.024
60.024
60.023
60.023
60.026
60.029
60.024
60.021
60.025
60.025
60.026
60.024
60.023
60.026
60.02
60.02
60.015
60.016
60.015
60.015
60.017
60.012
60.008
60.002
59.999
60.002
60.004
60.001
59.993
3693.077
3693.727
3692.641
3688.159
3688.208
3690.092
3693.321
3694.593
3694.609
3693.412
3696.026
3698.012
3699.414
3698.935
3700.544
3700.486
3697.961
3699.914
3701.301
3701.45
3701.094
3701.702
3701.965
3700.269
3701.09
3701.268
3700.587
3700.532
3700.295
3700.277
3700.863
3700.26
3699.926
3700.965
3703.516
3703.824
3703.689
3703.003
3703
3703.167
3703.616
3703.775
3701.534
3700.617
3700.625
3701.389
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
233.559982
233.559982
219.009995
219.009995
219.009995
219.009995
219.009995
205.338913
205.338913
205.338913
205.338913
205.338913
236.285355
236.285355
236.285355
236.285355
236.285355
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
371.5
372
372.5
373
373.5
374
374.5
375
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
002052
10/12/09 02:50:51
10/12/09 02:50:54
10/12/09 02:50:57
10/12/09 02:51:00
10/12/09 02:51:03
10/12/09 02:51:06
10/12/09 02:51:09
10/12/09 02:51:12
10/12/09 02:51:15
10/12/09 02:51:18
10/12/09 02:51:21
10/12/09 02:51:24
10/12/09 02:51:27
10/12/09 02:51:30
10/12/09 02:51:33
10/12/09 02:51:36
10/12/09 02:51:39
10/12/09 02:51:42
10/12/09 02:51:45
10/12/09 02:51:48
10/12/09 02:51:51
10/12/09 02:51:54
10/12/09 02:51:57
10/12/09 02:52:00
10/12/09 02:52:03
10/12/09 02:52:06
10/12/09 02:52:09
10/12/09 02:52:12
10/12/09 02:52:15
10/12/09 02:52:18
10/12/09 02:52:21
10/12/09 02:52:24
10/12/09 02:52:27
10/12/09 02:52:30
10/12/09 02:52:33
10/12/09 02:52:36
10/12/09 02:52:39
10/12/09 02:52:42
10/12/09 02:52:45
10/12/09 02:52:48
10/12/09 02:52:51
10/12/09 02:52:54
10/12/09 02:52:57
10/12/09 02:53:00
10/12/09 02:53:03
10/12/09 02:53:06
59.992
59.987
59.985
59.986
59.984
59.98
59.977
59.976
59.972
59.977
59.975
59.971
59.971
59.979
59.98
59.982
59.982
59.981
59.979
59.976
59.978
59.976
59.978
59.971
59.97
59.971
59.99
59.999
59.999
59.999
60.003
60.005
60.01
60.02
60.022
60.025
60.025
60.023
60.029
60.029
60.028
60.031
60.032
60.033
60.03
60.021
3700.671
3700.826
3700.7
3699.854
3700.342
3700.77
3701.625
3703.166
3704.785
3705.811
3706.688
3706.543
3707.027
3710.118
3708.701
3708.018
3706.343
3706.125
3706.119
3706.19
3709.409
3708.971
3708.071
3707.24
3709.961
3711.75
3710.695
3707.867
3705.639
3703.787
3702.071
3699.51
3698.137
3697.882
3698.604
3697.868
3693.912
3693.418
3688.021
3689.143
3687.878
3687.026
3685.276
3685.576
3685.985
3687.159
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
396
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
002053
10/12/09 02:53:09
10/12/09 02:53:12
10/12/09 02:53:15
10/12/09 02:53:18
10/12/09 02:53:21
10/12/09 02:53:24
10/12/09 02:53:27
10/12/09 02:53:30
10/12/09 02:53:33
10/12/09 02:53:36
10/12/09 02:53:39
10/12/09 02:53:42
10/12/09 02:53:45
10/12/09 02:53:48
10/12/09 02:53:51
10/12/09 02:53:54
10/12/09 02:53:57
10/12/09 02:54:00
10/12/09 02:54:03
10/12/09 02:54:06
10/12/09 02:54:09
10/12/09 02:54:12
10/12/09 02:54:15
10/12/09 02:54:18
10/12/09 02:54:21
10/12/09 02:54:24
10/12/09 02:54:27
10/12/09 02:54:30
10/12/09 02:54:33
10/12/09 02:54:36
10/12/09 02:54:39
10/12/09 02:54:42
10/12/09 02:54:45
10/12/09 02:54:48
10/12/09 02:54:51
10/12/09 02:54:54
10/12/09 02:54:57
10/12/09 02:55:00
10/12/09 02:55:03
10/12/09 02:55:06
10/12/09 02:55:09
10/12/09 02:55:12
10/12/09 02:55:15
10/12/09 02:55:18
10/12/09 02:55:21
10/12/09 02:55:24
60.019
60.017
60.017
60.015
60.015
60.009
60.008
60.005
60.005
59.999
59.997
60
59.998
59.994
59.992
59.988
59.985
59.988
59.988
59.983
59.983
59.986
59.987
59.986
59.985
59.983
59.982
59.98
59.978
59.975
59.973
59.976
59.976
59.982
59.979
59.977
59.977
59.978
59.978
59.983
59.981
59.978
59.979
59.979
59.983
59.99
3688.997
3690.426
3692.715
3692.578
3693.173
3693.249
3695.124
3694.681
3694.199
3693.75
3692.806
3691.15
3691.077
3690.588
3688.483
3689.445
3689.525
3689.736
3688.24
3687.494
3686.707
3685.66
3684.333
3683.911
3684.208
3683.811
3684.258
3684.884
3685.654
3685.087
3685.196
3687.412
3688.599
3687.848
3685.782
3684.89
3684.549
3684.093
3682.814
3682.318
3682.647
3682.855
3684.052
3684.318
3686.629
3685.286
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
411.5
412
412.5
413
413.5
414
414.5
415
415.5
416
416.5
417
417.5
418
418.5
419
419.5
420
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
002054
10/12/09 02:55:27
10/12/09 02:55:30
10/12/09 02:55:33
10/12/09 02:55:36
10/12/09 02:55:39
10/12/09 02:55:42
10/12/09 02:55:45
10/12/09 02:55:48
10/12/09 02:55:51
10/12/09 02:55:54
10/12/09 02:55:57
10/12/09 02:56:00
10/12/09 02:56:03
10/12/09 02:56:06
10/12/09 02:56:09
10/12/09 02:56:12
10/12/09 02:56:15
10/12/09 02:56:18
10/12/09 02:56:21
10/12/09 02:56:24
10/12/09 02:56:27
10/12/09 02:56:30
10/12/09 02:56:33
10/12/09 02:56:36
10/12/09 02:56:39
10/12/09 02:56:42
10/12/09 02:56:45
10/12/09 02:56:48
10/12/09 02:56:51
10/12/09 02:56:54
10/12/09 02:56:57
10/12/09 02:57:00
10/12/09 02:57:03
10/12/09 02:57:06
10/12/09 02:57:09
10/12/09 02:57:12
10/12/09 02:57:15
10/12/09 02:57:18
10/12/09 02:57:21
10/12/09 02:57:24
10/12/09 02:57:27
10/12/09 02:57:30
10/12/09 02:57:33
10/12/09 02:57:36
10/12/09 02:57:39
10/12/09 02:57:42
59.992
59.99
59.988
59.99
59.993
59.993
59.994
59.993
59.989
59.986
59.985
59.987
59.986
59.985
59.982
59.982
59.987
59.997
60
60.003
60.003
60.003
60.002
60.004
60.005
60.009
60.012
60.021
60.022
60.02
60.018
60.02
60.02
60.018
60.019
60.018
60.017
60.016
60.016
60.014
60.014
60.013
60.015
60.016
60.019
60.021
3682.416
3681.403
3679.436
3671.761
3670.159
3679
3681.799
3682.7
3685.03
3684.878
3684.478
3685.584
3684.587
3684.976
3684.872
3684.245
3685.589
3683.736
3682.234
3682.138
3681.689
3681.458
3681.013
3680.167
3679.429
3679.669
3678.267
3676.796
3674.798
3673.906
3670.51
3673.648
3675.865
3676.676
3676.437
3677.185
3678.828
3679.289
3679.276
3678.599
3678.25
3678.589
3675.698
3674.669
3674.402
3674.546
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
434.5
435
435.5
436
436.5
437
437.5
438
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
002055
10/12/09 02:57:45
10/12/09 02:57:48
10/12/09 02:57:51
10/12/09 02:57:54
10/12/09 02:57:57
10/12/09 02:58:00
10/12/09 02:58:03
10/12/09 02:58:06
10/12/09 02:58:09
10/12/09 02:58:12
10/12/09 02:58:15
10/12/09 02:58:18
10/12/09 02:58:21
10/12/09 02:58:24
10/12/09 02:58:27
10/12/09 02:58:30
10/12/09 02:58:33
10/12/09 02:58:36
10/12/09 02:58:39
10/12/09 02:58:42
10/12/09 02:58:45
10/12/09 02:58:48
10/12/09 02:58:51
10/12/09 02:58:54
10/12/09 02:58:57
10/12/09 02:59:00
10/12/09 02:59:03
10/12/09 02:59:06
10/12/09 02:59:09
10/12/09 02:59:12
10/12/09 02:59:15
10/12/09 02:59:18
10/12/09 02:59:21
10/12/09 02:59:24
10/12/09 02:59:27
10/12/09 02:59:30
10/12/09 02:59:33
10/12/09 02:59:36
10/12/09 02:59:39
10/12/09 02:59:42
10/12/09 02:59:45
10/12/09 02:59:48
10/12/09 02:59:51
10/12/09 02:59:54
10/12/09 02:59:57
10/12/09 03:00:00
60.02
60.024
60.026
60.026
60.022
60.022
60.024
60.029
60.028
60.032
60.035
60.028
60.021
60.024
60.025
60.022
60.023
60.02
60.02
60.02
60.017
60.012
60.01
60.01
60.01
60.012
60.012
60.014
60.013
60.011
60.01
60.01
60.011
60.016
60.018
60.019
60.019
60.02
60.018
60.016
60.016
60.023
60.022
60.015
60.016
60.017
3671.914
3671.982
3670.821
3671.06
3673.794
3674.01
3675.284
3676.051
3672.583
3671.343
3668.654
3668.767
3667.322
3657.164
3668.637
3669.309
3670.735
3671.332
3672.683
3673.833
3675.641
3675.971
3678.314
3679.393
3679.792
3679.597
3680.11
3679.062
3679.587
3679.637
3678.418
3679.383
3679.932
3679.138
3678.499
3678.456
3677.446
3677.431
3677.315
3678.151
3678.874
3680.771
3680.353
3679.167
3680.672
3682.73
002056
10/12/09 03:00:03
10/12/09 03:00:06
10/12/09 03:00:09
10/12/09 03:00:12
10/12/09 03:00:15
10/12/09 03:00:18
10/12/09 03:00:21
10/12/09 03:00:24
10/12/09 03:00:27
10/12/09 03:00:30
10/12/09 03:00:33
10/12/09 03:00:36
10/12/09 03:00:39
10/12/09 03:00:42
10/12/09 03:00:45
10/12/09 03:00:48
10/12/09 03:00:51
10/12/09 03:00:54
10/12/09 03:00:57
10/12/09 03:01:00
10/12/09 03:01:03
10/12/09 03:01:06
10/12/09 03:01:09
10/12/09 03:01:12
10/12/09 03:01:15
10/12/09 03:01:18
10/12/09 03:01:21
10/12/09 03:01:24
10/12/09 03:01:27
10/12/09 03:01:30
10/12/09 03:01:33
10/12/09 03:01:36
10/12/09 03:01:39
10/12/09 03:01:42
10/12/09 03:01:45
10/12/09 03:01:48
10/12/09 03:01:51
10/12/09 03:01:54
10/12/09 03:01:57
10/12/09 03:02:00
10/12/09 03:02:03
10/12/09 03:02:06
10/12/09 03:02:09
10/12/09 03:02:12
10/12/09 03:02:15
10/12/09 03:02:18
60.01
60.004
59.995
59.982
59.974
59.97
59.968
59.968
59.972
59.966
59.964
59.966
59.963
59.965
59.968
59.97
59.97
59.972
59.976
59.975
59.977
59.976
59.974
59.974
59.974
59.977
59.979
59.983
59.985
59.98
59.979
59.987
59.986
59.98
59.982
59.985
59.987
59.992
59.996
59.997
59.997
59.997
59.996
59.996
59.998
60.009
3682.714
3682.01
3682.483
3685.306
3684.643
3687.527
3692.287
3692.966
3693.793
3694.974
3698.502
3698.617
3699.85
3702.645
3702.218
3704.023
3702.988
3703.814
3705.625
3704.293
3701.944
3703.142
3705.376
3705.662
3706.776
3707.514
3706.446
3706.335
3705.943
3704.127
3705.974
3705.968
3704.683
3703.913
3704.988
3705.05
3703.741
3701.831
3700.07
3701.308
3700.913
3700.541
3700.858
3700.549
3700.224
3699.5
002057
10/12/09 03:02:21
10/12/09 03:02:24
10/12/09 03:02:27
10/12/09 03:02:30
10/12/09 03:02:33
10/12/09 03:02:36
10/12/09 03:02:39
10/12/09 03:02:42
10/12/09 03:02:45
10/12/09 03:02:48
10/12/09 03:02:51
10/12/09 03:02:54
10/12/09 03:02:57
10/12/09 03:03:00
10/12/09 03:03:03
10/12/09 03:03:06
10/12/09 03:03:09
10/12/09 03:03:12
10/12/09 03:03:15
10/12/09 03:03:18
10/12/09 03:03:21
10/12/09 03:03:24
10/12/09 03:03:27
10/12/09 03:03:30
10/12/09 03:03:33
10/12/09 03:03:36
10/12/09 03:03:39
10/12/09 03:03:42
10/12/09 03:03:45
10/12/09 03:03:48
10/12/09 03:03:51
10/12/09 03:03:54
10/12/09 03:03:57
10/12/09 03:04:00
10/12/09 03:04:03
10/12/09 03:04:06
10/12/09 03:04:09
10/12/09 03:04:12
10/12/09 03:04:15
10/12/09 03:04:18
10/12/09 03:04:21
10/12/09 03:04:24
10/12/09 03:04:27
10/12/09 03:04:30
10/12/09 03:04:33
10/12/09 03:04:36
60.01
60.005
60.004
60.003
60.001
60.004
60.007
60.008
60.008
60.006
60.006
60
59.999
60
60.004
60.013
60.015
60.012
60.009
60.008
60.011
60.013
60.016
60.018
60.019
60.013
60.011
60.009
60.008
60.011
60.015
60.021
60.018
60.019
60.019
60.022
60.025
60.03
60.027
60.021
60.023
60.02
60.024
60.022
60.022
60.025
3697.96
3699.409
3700.738
3701.11
3699.998
3700.22
3702.554
3702.276
3701.923
3702.943
3703.96
3703.819
3704.346
3705.329
3704.405
3703.675
3702.669
3703.017
3703.297
3705.189
3704.646
3704.051
3704.255
3703.708
3704.524
3704.139
3705.429
3705.942
3705.634
3705.749
3706.945
3706.63
3703.895
3704.224
3704.648
3704.795
3702.764
3702.008
3701.063
3700.34
3701.568
3702.959
3703.621
3703.374
3703.931
3704.947
002058
10/12/09 03:04:39
10/12/09 03:04:42
10/12/09 03:04:45
10/12/09 03:04:48
10/12/09 03:04:51
10/12/09 03:04:54
10/12/09 03:04:57
10/12/09 03:05:00
10/12/09 03:05:03
10/12/09 03:05:06
10/12/09 03:05:09
10/12/09 03:05:12
10/12/09 03:05:15
10/12/09 03:05:18
10/12/09 03:05:21
10/12/09 03:05:24
10/12/09 03:05:27
10/12/09 03:05:30
10/12/09 03:05:33
10/12/09 03:05:36
10/12/09 03:05:39
10/12/09 03:05:42
10/12/09 03:05:45
10/12/09 03:05:48
10/12/09 03:05:51
10/12/09 03:05:54
10/12/09 03:05:57
10/12/09 03:06:00
10/12/09 03:06:03
10/12/09 03:06:06
10/12/09 03:06:09
10/12/09 03:06:12
10/12/09 03:06:15
10/12/09 03:06:18
10/12/09 03:06:21
10/12/09 03:06:24
10/12/09 03:06:27
10/12/09 03:06:30
10/12/09 03:06:33
10/12/09 03:06:36
10/12/09 03:06:39
10/12/09 03:06:42
10/12/09 03:06:45
10/12/09 03:06:48
10/12/09 03:06:51
10/12/09 03:06:54
60.023
60.02
60.018
60.008
60.012
60.019
60.019
60.016
60.015
60.014
60.016
60.019
60.016
60.014
60.018
60.023
60.024
60.026
60.024
60.02
60.019
60.025
60.028
60.031
60.029
60.026
60.029
60.033
60.03
60.016
60.019
60.028
60.021
60.015
60.012
60.014
60.013
60.016
60.016
60.013
60.007
59.994
59.993
59.993
59.994
59.994
3703.541
3703.16
3704.376
3705.441
3710.072
3707.971
3707.609
3708.831
3709.813
3709.817
3709.094
3709.642
3709.933
3710.677
3709.354
3707.696
3707.12
3706.99
3704.185
3704.406
3706.567
3705.516
3704.428
3704.773
3702.686
3702.093
3703.676
3701.52
3698.222
3698.009
3703.192
3703.815
3699.956
3700.816
3706.943
3708.527
3707.647
3706.991
3705.584
3705.398
3709.144
3708.99
3706.193
3707.304
3706.76
3706.921
002059
10/12/09 03:06:57
10/12/09 03:07:00
10/12/09 03:07:03
10/12/09 03:07:06
10/12/09 03:07:09
10/12/09 03:07:12
10/12/09 03:07:15
10/12/09 03:07:18
10/12/09 03:07:21
10/12/09 03:07:24
10/12/09 03:07:27
10/12/09 03:07:30
10/12/09 03:07:33
10/12/09 03:07:36
10/12/09 03:07:39
10/12/09 03:07:42
10/12/09 03:07:45
10/12/09 03:07:48
10/12/09 03:07:51
10/12/09 03:07:54
10/12/09 03:07:57
10/12/09 03:08:00
10/12/09 03:08:03
10/12/09 03:08:06
10/12/09 03:08:09
10/12/09 03:08:12
10/12/09 03:08:15
10/12/09 03:08:18
10/12/09 03:08:21
10/12/09 03:08:24
10/12/09 03:08:27
10/12/09 03:08:30
10/12/09 03:08:33
10/12/09 03:08:36
10/12/09 03:08:39
10/12/09 03:08:42
10/12/09 03:08:45
10/12/09 03:08:48
10/12/09 03:08:51
10/12/09 03:08:54
10/12/09 03:08:57
10/12/09 03:09:00
10/12/09 03:09:03
10/12/09 03:09:06
10/12/09 03:09:09
10/12/09 03:09:12
59.993
59.988
59.985
59.982
59.98
59.981
59.982
59.98
59.98
59.98
59.983
59.981
59.981
59.981
59.981
59.98
59.978
59.979
59.978
59.976
59.975
59.975
59.979
59.975
59.976
59.977
59.975
59.979
59.98
59.978
59.979
59.983
59.987
59.984
59.98
59.98
59.979
59.975
59.979
59.983
59.983
59.99
59.987
59.976
59.979
59.983
3706.888
3704.934
3706.481
3707.071
3707.479
3708.246
3710.419
3710.134
3710.024
3709.192
3709.399
3707.911
3707.638
3709.689
3706.541
3711.256
3712.303
3712.012
3712.093
3713.992
3715.083
3715.323
3714.717
3715.161
3713.996
3714.063
3715.631
3715.688
3715.725
3714.848
3713.358
3712.275
3712.153
3710.05
3710.472
3710.624
3710.2
3710.475
3710.803
3709.286
3709.525
3708.371
3706.512
3707.49
3709.894
3712.303
002060
10/12/09 03:09:15
10/12/09 03:09:18
10/12/09 03:09:21
10/12/09 03:09:24
10/12/09 03:09:27
10/12/09 03:09:30
10/12/09 03:09:33
10/12/09 03:09:36
10/12/09 03:09:39
10/12/09 03:09:42
10/12/09 03:09:45
10/12/09 03:09:48
10/12/09 03:09:51
10/12/09 03:09:54
10/12/09 03:09:57
10/12/09 03:10:00
10/12/09 03:10:03
10/12/09 03:10:06
10/12/09 03:10:09
10/12/09 03:10:12
10/12/09 03:10:15
10/12/09 03:10:18
10/12/09 03:10:21
10/12/09 03:10:24
10/12/09 03:10:27
10/12/09 03:10:30
10/12/09 03:10:33
10/12/09 03:10:36
10/12/09 03:10:39
10/12/09 03:10:42
10/12/09 03:10:45
10/12/09 03:10:48
10/12/09 03:10:51
10/12/09 03:10:54
10/12/09 03:10:57
10/12/09 03:11:00
10/12/09 03:11:03
10/12/09 03:11:06
10/12/09 03:11:09
10/12/09 03:11:12
10/12/09 03:11:15
10/12/09 03:11:18
10/12/09 03:11:21
10/12/09 03:11:24
10/12/09 03:11:27
10/12/09 03:11:30
59.979
59.978
59.975
59.989
59.999
59.989
59.986
59.983
59.982
59.99
59.995
59.99
59.989
59.996
60
60.004
60.004
59.999
59.998
59.996
60.001
60.001
60.003
60.004
60.004
60.006
60.003
60.006
60.009
60.01
60.009
60.015
60.014
60.009
60.008
60.01
60.009
60.013
60.014
60.012
60.01
60.007
60.003
60
59.998
59.999
3711.627
3712.076
3712.999
3713.51
3715.443
3712.092
3714.894
3714.953
3716.308
3715.438
3714.714
3715.068
3715.791
3716.285
3714.46
3711.708
3712.851
3713.362
3718.292
3719.079
3717.815
3717.889
3718.195
3719.021
3719.897
3719.299
3719.527
3719.731
3718.58
3718.976
3720.034
3720.609
3721.239
3720.38
3720.807
3721.272
3721.245
3721.594
3721.999
3721.646
3720.86
3721.645
3725.07
3724.656
3724.661
3723.696
002061
10/12/09 03:11:33
10/12/09 03:11:36
10/12/09 03:11:39
10/12/09 03:11:42
10/12/09 03:11:45
10/12/09 03:11:48
10/12/09 03:11:51
10/12/09 03:11:54
10/12/09 03:11:57
10/12/09 03:12:00
60.002
60.003
59.999
60.001
59.995
59.987
59.988
59.99
59.992
59.992
3723.405
3721.879
3722.906
3724.142
3723.201
3723.639
3724.654
3725.361
3725.046
3723.693
002062
Balancing Authority Name: My BA
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-80
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan of
frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Step 4.
Enter MW output of generator or load that caused event (+ for gen loss, - for load loss)
(Value from NERC Event List. If multiple units, enter total MW loss.)
If MW loss value is not known, enter a default 1000 MW.
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 5. worksheet.
2:27:21
2:33:03
633 MW
Event Frequency Data
60.1
60.05
60
Copy Form 2 Data for
Pasting into Form 1
59.95
59.9
59.85
59.8
59.75
59.7
Step 6. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Step 7. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
Series1
002063
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8887
-0.153
3647.05
3787.78
140.73
-12.59
-33.40
89.04
122.44
Balancing Authority My BA
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
109.84 MW
Yes
Initial Response P.U. Performance
1.281 P.U.
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
60.027
60.027
60.026
Interchange
MW
3671.189
3671.189
3668.611
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
3764.20
3776.17
3728.90
3645.45
101.48
0:05:42
No
130.73
118.75
No
Yes
Yes
29.25
17.27
Up
60.000 Hz
2400.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-80 MW/0.1 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.908 P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-21.600
-21.600
-20.801
(TC)
Delayed
Delivery
Frequency
Response
-7.560
-12.474
-15.389
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
633
002064
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
60.022
60.022
60.017
60.019
60.019
60.019
60.021
60.021
60.021
60.019
60.019
60.022
60.031
60.031
60.037
60.036
60.036
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.039
60.043
60.045
60.045
60.041
60.041
60.041
60.039
59.978
59.978
59.836
59.836
59.869
59.891
59.891
59.88
59.875
59.875
59.883
59.886
59.886
3664.495
3664.495
3666.062
3666.787
3666.787
3670.454
3671.668
3671.668
3672.493
3672.857
3672.857
3672.164
3669.983
3669.983
3666.467
3661.599
3661.599
3660.672
3649.190
3649.190
3650.025
3649.512
3649.512
3654.294
3651.874
3651.874
3651.059
3648.236
3648.236
3645.387
3645.446
3645.446
3640.682
3659.465
3659.465
3696.362
3696.362
3734.673
3737.157
3737.157
3766.113
3766.194
3766.194
3769.925
3780.621
3780.621
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
59.889 3787.775
59.889 3787.775
59.889 3787.775
-17.599
-17.599
-13.599
-15.201
-15.201
-15.201
-16.800
-16.800
-16.800
-15.201
-15.201
-17.599
-24.799
-24.799
-29.599
-28.799
-28.799
-36.801
-38.400
-38.400
-34.399
-32.800
-32.800
-32.800
-31.201
-31.201
-34.399
-35.999
-35.999
-32.800
-32.800
-32.800
-31.201
17.599
17.599
131.201
131.201
104.800
87.201
87.201
95.999
100.000
100.000
93.600
91.199
91.199
-16.162
-16.665
-15.592
-15.455
-15.366
-15.308
-15.830
-16.170
-16.390
-15.974
-15.703
-16.367
-19.318
-21.236
-24.163
-25.786
-26.841
-30.327
-33.153
-34.989
-34.783
-34.089
-33.638
-33.345
-32.594
-32.107
-32.909
-33.990
-34.693
-34.031
-33.600
-33.320
-32.579
-15.016
-3.601
43.580
74.247
84.941
85.732
86.246
89.660
93.279
95.631
94.920
93.618
92.771
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
-0.310
3756.890
3756.890
3756.890
0.000
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
3666.787
3666.567
3666.315
3665.483
3664.834
3664.304
3664.410
3664.371
3663.398
3660.137
3657.909
3654.672
3652.740
3651.375
3647.580
3644.444
3642.298
3642.194
3642.579
3642.720
3642.703
3643.144
3643.322
3642.210
3640.819
3639.806
3640.159
3640.280
3640.250
3640.682
3658.244
3670.253
3718.028
3749.288
3760.575
3761.960
3763.067
3767.074
3771.287
3774.233
3774.116
3773.407
3773.153
3659.465
3671.764
3677.914
3689.265
3697.247
3702.949
3710.844
3716.994
3721.914
3726.279
3730.807
3734.639
3664.249
3682.175
3698.953
3711.278
3719.725
3725.917
3731.061
3735.531
3739.401
3742.557
3745.128
3747.284
3678.456
3679.050
3679.643
3680.237
3680.830
3681.424
3682.017
3682.610
3683.204
3683.797
3684.391
3684.984
3678.456
3678.753
3679.050
3679.346
3679.643
3679.940
3680.237
3680.533
3680.830
3681.127
3681.424
3681.720
633
633
633
633
633
633
633
633
633
633
633
633
633
002065
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
2:28:43
2:28:45
2:28:47
2:28:49
2:28:51
2:28:53
2:28:55
2:28:57
2:28:59
2:29:01
2:29:03
2:29:05
2:29:07
2:29:09
2:29:11
2:29:13
2:29:15
59.885
59.888
59.888
59.89
59.894
59.894
59.893
59.894
59.894
59.891
59.885
59.885
59.885
59.887
59.887
59.888
59.89
59.89
59.889
59.873
59.873
59.857
59.852
59.852
59.858
59.866
59.866
59.865
59.866
59.866
59.871
59.879
59.879
59.88
59.886
59.886
59.89
59.889
59.889
59.893
59.903
59.903
59.902
59.904
59.904
3782.500
3784.962
3784.962
3784.419
3788.072
3788.072
3788.868
3788.472
3788.472
3793.074
3794.374
3794.374
3800.427
3799.959
3799.959
3802.925
3802.951
3802.951
3805.496
3805.617
3805.617
3811.503
3814.862
3814.862
3825.643
3826.053
3826.053
3827.524
3826.753
3826.753
3826.454
3825.713
3825.713
3822.505
3819.081
3819.081
3816.815
3815.010
3815.010
3811.838
3809.652
3809.652
3805.593
3804.188
3804.188
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
92.001
89.600
89.600
88.000
84.799
84.799
85.599
84.799
84.799
87.201
92.001
92.001
92.001
90.399
90.399
89.600
88.000
88.000
88.800
101.599
101.599
114.401
118.399
118.399
113.599
107.199
107.199
107.999
107.199
107.199
103.201
96.799
96.799
95.999
91.199
91.199
88.000
88.800
88.800
85.599
77.600
77.600
78.400
76.801
76.801
92.502
91.486
90.826
89.837
88.074
86.928
86.463
85.880
85.502
86.097
88.163
89.507
90.380
90.387
90.391
90.114
89.374
88.893
88.861
93.319
96.217
102.582
108.118
111.716
112.375
110.563
109.386
108.900
108.305
107.918
106.267
102.953
100.799
99.119
96.347
94.545
92.254
91.045
90.260
88.628
84.768
82.260
80.909
79.471
78.536
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
3756.890
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
3773.477
3773.055
3772.988
3772.593
3771.423
3770.870
3770.999
3771.010
3771.225
3772.413
3775.073
3777.010
3778.477
3779.077
3779.675
3779.991
3779.845
3779.958
3780.519
3785.570
3789.062
3796.020
3802.149
3806.341
3807.594
3806.375
3805.791
3805.899
3805.897
3806.104
3805.046
3802.326
3800.765
3799.679
3797.500
3796.292
3794.595
3793.979
3793.786
3792.749
3789.482
3787.567
3786.809
3785.965
3785.624
3738.058
3741.185
3743.921
3746.303
3748.623
3750.700
3752.608
3754.316
3755.868
3757.486
3759.023
3760.437
3761.975
3763.382
3764.688
3766.007
3767.238
3768.390
3769.550
3770.643
3771.672
3772.810
3773.978
3775.083
3776.413
3777.686
3778.895
3780.081
3781.193
3782.252
3783.257
3784.200
3785.103
3785.898
3786.590
3787.253
3787.844
3788.377
3788.889
3789.322
3789.698
3790.061
3790.339
3790.581
3790.816
3749.155
3750.748
3752.138
3753.341
3754.346
3755.215
3756.005
3756.719
3757.379
3758.032
3758.742
3759.473
3760.204
3760.903
3761.573
3762.208
3762.796
3763.350
3763.886
3764.544
3765.265
3766.143
3767.144
3768.203
3769.240
3770.192
3771.082
3771.931
3772.740
3773.516
3774.232
3774.856
3775.420
3775.936
3776.385
3776.791
3777.147
3777.477
3777.791
3778.073
3778.285
3778.453
3778.603
3778.732
3778.851
3685.578
3686.171
3686.765
3687.358
3687.952
3688.545
3689.138
3689.732
3690.325
3690.919
3691.512
3692.106
3692.699
3693.293
3693.886
3694.480
3695.073
3695.666
3696.260
3696.853
3697.447
3698.040
3698.634
3699.227
3699.821
3700.414
3701.008
3701.601
3702.195
3702.788
3703.381
3703.975
3704.568
3705.162
3705.755
3706.349
3706.942
3707.536
3708.129
3708.723
3709.316
3709.909
3710.503
3711.096
3711.690
3682.017
3682.314
3682.610
3682.907
3683.204
3683.501
3683.797
3684.094
3684.391
3684.688
3684.984
3685.281
3685.578
3685.874
3686.171
3686.468
3686.765
3687.061
3687.358
3687.655
3687.952
3688.248
3688.545
3688.842
3689.138
3689.435
3689.732
3690.029
3690.325
3690.622
3690.919
3691.216
3691.512
3691.809
3692.106
3692.402
3692.699
3692.996
3693.293
3693.589
3693.886
3694.183
3694.480
3694.776
3695.073
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002066
2:29:17
2:29:19
2:29:21
2:29:23
2:29:25
2:29:27
2:29:29
2:29:31
2:29:33
2:29:35
2:29:37
2:29:39
2:29:41
2:29:43
2:29:45
2:29:47
2:29:49
2:29:51
2:29:53
2:29:55
2:29:57
2:29:59
2:30:01
2:30:03
2:30:05
2:30:07
2:30:09
2:30:11
2:30:13
2:30:15
2:30:17
2:30:19
2:30:21
2:30:23
2:30:25
2:30:27
2:30:29
2:30:31
2:30:33
2:30:35
2:30:37
2:30:39
2:30:41
2:30:43
2:30:45
2:30:47
59.907
59.916
59.916
59.916
59.918
59.918
59.92
59.92
59.92
59.917
59.921
59.921
59.923
59.925
59.925
59.928
59.932
59.932
59.927
59.931
59.931
59.929
59.931
59.931
59.937
59.945
59.945
59.949
59.942
59.942
59.941
59.945
59.945
59.948
59.949
59.949
59.951
59.953
59.953
59.951
59.952
59.952
59.952
59.952
59.952
59.954
3793.975
3792.169
3792.169
3789.534
3788.132
3788.132
3783.028
3781.701
3781.701
3775.635
3774.604
3774.604
3773.958
3772.722
3772.722
3769.630
3768.707
3768.707
3767.021
3767.408
3767.408
3766.259
3765.672
3765.672
3766.123
3765.105
3765.105
3758.387
3753.922
3753.922
3746.889
3747.875
3747.875
3748.661
3746.706
3746.706
3742.741
3740.259
3740.259
3731.382
3727.838
3727.838
3722.649
3720.578
3720.578
3718.142
74.399
67.200
67.200
67.200
65.601
65.601
64.001
64.001
64.001
66.400
63.199
63.199
61.600
60.001
60.001
57.599
54.401
54.401
58.401
55.200
55.200
56.799
55.200
55.200
50.400
44.000
44.000
40.799
46.399
46.399
47.198
44.000
44.000
41.599
40.799
40.799
39.200
37.601
37.601
39.200
38.400
38.400
38.400
38.400
38.400
36.801
77.088
73.627
71.378
69.915
68.405
67.424
66.226
65.447
64.941
65.452
64.663
64.151
63.258
62.118
61.377
60.055
58.076
56.789
57.354
56.600
56.110
56.351
55.948
55.687
53.836
50.394
48.156
45.581
45.867
46.053
46.454
45.595
45.037
43.834
42.771
42.081
41.073
39.857
39.068
39.114
38.864
38.702
38.596
38.528
38.483
37.894
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
3784.769
3781.902
3780.246
3779.377
3778.460
3778.072
3777.468
3777.283
3777.370
3778.474
3778.279
3778.360
3778.061
3777.514
3777.366
3776.638
3775.252
3774.559
3775.717
3775.557
3775.660
3776.495
3776.686
3777.017
3775.760
3772.911
3771.267
3769.285
3770.165
3770.945
3771.939
3771.674
3771.709
3771.099
3770.630
3770.533
3770.118
3769.496
3769.300
3769.940
3770.284
3770.715
3771.203
3771.727
3772.276
3772.281
3790.870
3790.891
3790.912
3790.890
3790.846
3790.804
3790.684
3790.548
3790.416
3790.199
3789.973
3789.753
3789.531
3789.297
3789.070
3788.807
3788.539
3788.278
3788.002
3787.738
3787.481
3787.216
3786.950
3786.690
3786.443
3786.188
3785.940
3785.620
3785.256
3784.900
3784.473
3784.066
3783.668
3783.288
3782.894
3782.509
3782.091
3781.655
3781.228
3780.720
3780.185
3779.662
3779.098
3778.524
3777.961
3777.386
3778.951
3779.000
3779.020
3779.026
3779.017
3779.002
3778.979
3778.953
3778.930
3778.923
3778.914
3778.906
3778.894
3778.875
3778.854
3778.824
3778.776
3778.721
3778.682
3778.642
3778.604
3778.578
3778.554
3778.536
3778.502
3778.436
3778.351
3778.246
3778.153
3778.071
3778.002
3777.932
3777.863
3777.790
3777.713
3777.636
3777.557
3777.473
3777.389
3777.313
3777.242
3777.177
3777.118
3777.065
3777.018
3776.973
3712.283
3712.877
3713.470
3714.064
3714.657
3715.251
3715.844
3716.437
3717.031
3717.624
3718.218
3718.811
3719.405
3719.998
3720.592
3721.185
3721.779
3722.372
3722.965
3723.559
3724.152
3724.746
3725.339
3725.933
3726.526
3727.120
3727.713
3728.307
3728.900
3729.494
3730.087
3730.680
3731.274
3731.867
3732.461
3733.054
3733.648
3734.241
3734.835
3735.428
3736.022
3736.615
3737.208
3737.802
3738.395
3738.989
3695.370
3695.666
3695.963
3696.260
3696.557
3696.853
3697.150
3697.447
3697.744
3698.040
3698.337
3698.634
3698.931
3699.227
3699.524
3699.821
3700.117
3700.414
3700.711
3701.008
3701.304
3701.601
3701.898
3702.195
3702.491
3702.788
3703.085
3703.381
3703.678
3703.975
3704.272
3704.568
3704.865
3705.162
3705.459
3705.755
3706.052
3706.349
3706.645
3706.942
3707.239
3707.536
3707.832
3708.129
3708.426
3708.723
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002067
2:30:49
2:30:51
2:30:53
2:30:55
2:30:57
2:30:59
2:31:01
2:31:03
2:31:05
2:31:07
2:31:09
2:31:11
2:31:13
2:31:15
2:31:17
2:31:19
2:31:21
2:31:23
2:31:25
2:31:27
2:31:29
2:31:31
2:31:33
2:31:35
2:31:37
2:31:39
2:31:41
2:31:43
2:31:45
2:31:47
2:31:49
2:31:51
2:31:53
2:31:55
2:31:57
2:31:59
2:32:01
2:32:03
2:32:05
2:32:07
2:32:09
2:32:11
2:32:13
2:32:15
2:32:17
2:32:19
59.953
59.953
59.953
59.954
59.954
59.954
59.957
59.957
59.956
59.956
59.956
59.955
59.961
59.961
59.962
59.968
59.968
59.966
59.968
59.968
59.97
59.97
59.97
59.969
59.97
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.976
59.976
59.978
59.98
59.98
59.982
59.98
59.98
59.979
59.979
59.979
59.983
59.984
3715.753
3715.753
3713.484
3710.848
3710.848
3712.092
3714.623
3714.623
3716.168
3716.461
3716.461
3717.759
3722.361
3722.361
3722.658
3722.267
3722.267
3721.787
3723.091
3723.091
3723.435
3723.893
3723.893
3727.121
3728.053
3728.053
3732.530
3733.327
3733.327
3736.907
3736.822
3736.822
3739.944
3740.877
3740.877
3745.234
3746.608
3746.608
3750.716
3751.558
3751.558
3755.599
3756.407
3756.407
3760.405
3760.982
37.601
37.601
37.601
36.801
36.801
36.801
34.399
34.399
35.199
35.199
35.199
35.999
31.201
31.201
30.399
25.601
25.601
27.200
25.601
25.601
23.999
23.999
23.999
24.799
23.999
23.999
23.199
21.600
21.600
19.199
17.599
17.599
19.199
19.199
19.199
17.599
16.000
16.000
14.401
16.000
16.000
16.800
16.800
16.800
13.599
12.799
37.792
37.725
37.681
37.373
37.173
37.043
36.118
35.516
35.405
35.333
35.286
35.535
34.018
33.032
32.111
29.832
28.351
27.949
27.127
26.593
25.685
25.095
24.711
24.742
24.482
24.313
23.923
23.110
22.582
21.398
20.068
19.204
19.202
19.201
19.200
18.640
17.716
17.116
16.166
16.108
16.070
16.326
16.492
16.600
15.549
14.587
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
3772.772
3773.298
3773.848
3774.134
3774.527
3774.990
3774.659
3774.651
3775.133
3775.654
3776.201
3777.044
3776.120
3775.727
3775.399
3773.714
3772.827
3773.017
3772.789
3772.849
3772.534
3772.538
3772.748
3773.372
3773.705
3774.129
3774.333
3774.114
3774.179
3773.588
3772.852
3772.582
3773.173
3773.765
3774.358
3774.391
3774.061
3774.054
3773.697
3774.233
3774.789
3775.637
3776.397
3777.098
3776.641
3776.272
3776.799
3776.223
3775.637
3775.037
3774.448
3773.881
3773.347
3772.823
3772.322
3771.832
3771.350
3770.888
3770.473
3770.066
3769.667
3769.272
3768.884
3768.498
3768.129
3767.765
3767.411
3767.065
3766.725
3766.416
3766.119
3765.826
3765.572
3765.327
3765.087
3764.876
3764.669
3764.464
3764.285
3764.115
3763.948
3763.814
3763.692
3763.572
3763.482
3763.399
3763.318
3763.265
3763.218
3763.172
3763.154
3763.139
3776.933
3776.898
3776.870
3776.845
3776.823
3776.807
3776.787
3776.768
3776.754
3776.744
3776.739
3776.742
3776.737
3776.728
3776.717
3776.692
3776.660
3776.630
3776.599
3776.569
3776.536
3776.505
3776.475
3776.451
3776.430
3776.412
3776.396
3776.379
3776.362
3776.342
3776.316
3776.288
3776.265
3776.247
3776.234
3776.221
3776.205
3776.190
3776.173
3776.159
3776.150
3776.146
3776.148
3776.154
3776.158
3776.158
3739.582
3740.176
3740.769
3741.363
3741.956
3742.550
3743.143
3743.736
3744.330
3744.923
3745.517
3746.110
3746.704
3747.297
3747.891
3748.484
3749.078
3749.671
3750.265
3750.858
3751.451
3752.045
3752.638
3753.232
3753.825
3754.419
3755.012
3755.606
3756.199
3756.793
3757.386
3757.979
3758.573
3759.166
3759.760
3760.353
3760.947
3761.540
3762.134
3762.727
3763.321
3763.914
3764.507
3765.101
3765.694
3766.288
3709.019
3709.316
3709.613
3709.909
3710.206
3710.503
3710.800
3711.096
3711.393
3711.690
3711.987
3712.283
3712.580
3712.877
3713.173
3713.470
3713.767
3714.064
3714.360
3714.657
3714.954
3715.251
3715.547
3715.844
3716.141
3716.437
3716.734
3717.031
3717.328
3717.624
3717.921
3718.218
3718.515
3718.811
3719.108
3719.405
3719.701
3719.998
3720.295
3720.592
3720.888
3721.185
3721.482
3721.779
3722.075
3722.372
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002068
2:32:21
2:32:23
2:32:25
2:32:27
2:32:29
2:32:31
2:32:33
2:32:35
2:32:37
2:32:39
2:32:41
2:32:43
2:32:45
2:32:47
2:32:49
2:32:51
2:32:53
2:32:55
2:32:57
2:32:59
2:33:01
2:33:03
2:33:05
2:33:07
2:33:09
2:33:11
2:33:13
2:33:15
2:33:17
2:33:19
2:33:21
2:33:23
2:33:25
2:33:27
2:33:29
2:33:31
2:33:33
2:33:35
2:33:37
2:33:39
2:33:41
2:33:43
2:33:45
2:33:47
2:33:49
2:33:51
59.984
59.988
59.987
59.987
59.987
59.993
59.993
59.992
59.989
59.989
59.986
59.983
59.983
59.988
59.996
59.996
59.998
60.001
60.001
59.999
59.999
59.999
60.002
60.007
60.007
60.008
60.014
60.014
60.017
60.021
60.021
60.017
60.019
60.019
60.023
60.025
60.025
60.021
60.024
60.024
60.024
60.02
60.02
60.025
60.02
60.02
3760.982
3762.737
3763.212
3763.212
3766.085
3766.433
3766.433
3767.792
3768.634
3768.634
3772.445
3773.695
3773.695
3775.841
3775.363
3775.363
3775.492
3776.420
3776.420
3779.692
3781.256
3781.256
3783.092
3783.896
3783.896
3785.768
3785.463
3785.463
3786.304
3787.259
3787.259
3787.955
3788.030
3788.030
3789.216
3787.537
3787.537
3786.077
3787.930
3787.930
3786.875
3786.550
3786.550
3785.018
3785.614
3785.614
12.799
9.601
10.400
10.400
10.400
5.600
5.600
6.400
8.801
8.801
11.200
13.599
13.599
9.601
3.201
3.201
1.599
-0.800
-0.800
0.800
0.800
0.800
-1.599
-5.600
-5.600
-6.400
-11.200
-11.200
-13.599
-16.800
-16.800
-13.599
-15.201
-15.201
-18.399
-20.001
-20.001
-16.800
-19.199
-19.199
-19.199
-16.000
-16.000
-20.001
-16.000
-16.000
13.961
12.435
11.723
11.260
10.959
9.083
7.864
7.352
7.859
8.189
9.243
10.767
11.758
11.003
8.273
6.498
4.783
2.829
1.559
1.293
1.120
1.008
0.096
-1.898
-3.194
-4.316
-6.725
-8.291
-10.149
-12.477
-13.990
-13.853
-14.325
-14.631
-15.950
-17.368
-18.290
-17.768
-18.269
-18.594
-18.806
-17.824
-17.186
-18.171
-17.411
-16.918
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.593
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3776.240
3775.308
3775.189
3775.320
3775.612
3774.330
3773.704
3773.785
3774.886
3775.809
3777.456
3779.574
3781.159
3780.997
3778.860
3777.679
3776.558
3775.197
3774.520
3774.848
3775.269
3775.750
3774.837
3772.844
3771.548
3770.426
3768.017
3766.450
3764.593
3762.265
3760.752
3760.889
3760.417
3760.110
3758.792
3757.374
3756.452
3756.974
3756.473
3756.147
3755.936
3756.918
3757.556
3756.571
3757.330
3757.824
3763.125
3763.122
3763.123
3763.123
3763.143
3763.164
3763.184
3763.214
3763.248
3763.281
3763.338
3763.402
3763.465
3763.541
3763.612
3763.683
3763.754
3763.829
3763.904
3763.997
3764.098
3764.197
3764.307
3764.419
3764.531
3764.651
3764.769
3764.885
3765.005
3765.128
3765.251
3765.375
3765.499
3765.622
3765.749
3765.866
3765.982
3766.089
3766.205
3766.319
3766.427
3766.531
3766.635
3766.730
3766.827
3766.923
3776.159
3776.153
3776.147
3776.142
3776.138
3776.127
3776.111
3776.097
3776.089
3776.087
3776.096
3776.117
3776.148
3776.178
3776.194
3776.203
3776.205
3776.199
3776.189
3776.181
3776.176
3776.173
3776.166
3776.147
3776.120
3776.088
3776.042
3775.988
3775.925
3775.849
3775.765
3775.684
3775.600
3775.516
3775.426
3775.329
3775.228
3775.131
3775.032
3774.932
3774.833
3774.740
3774.651
3774.557
3774.469
3774.384
3766.881
3767.475
3768.068
3768.662
3769.255
3769.849
3770.442
3771.035
3771.629
3772.222
3772.816
3773.409
3774.003
3774.596
3775.190
3775.783
3776.377
3776.970
3777.564
3778.157
3778.750
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3722.669
3722.965
3723.262
3723.559
3723.856
3724.152
3724.449
3724.746
3725.043
3725.339
3725.636
3725.933
3726.230
3726.526
3726.823
3727.120
3727.416
3727.713
3728.010
3728.307
3728.603
3728.900
3729.193
3729.483
3729.770
3730.053
3730.333
3730.610
3730.884
3731.155
3731.422
3731.687
3731.949
3732.208
3732.464
3732.717
3732.968
3733.216
3733.461
3733.704
3733.944
3734.182
3734.417
3734.650
3734.881
3735.109
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002069
2:33:53
2:33:55
2:33:57
2:33:59
2:34:01
2:34:03
2:34:05
2:34:07
2:34:09
2:34:11
2:34:13
2:34:15
2:34:17
2:34:19
2:34:21
2:34:23
2:34:25
2:34:27
2:34:29
2:34:31
2:34:33
2:34:35
2:34:37
2:34:39
2:34:41
2:34:43
2:34:45
2:34:47
2:34:49
2:34:51
2:34:53
2:34:55
2:34:57
2:34:59
2:35:01
2:35:03
2:35:05
2:35:07
2:35:09
2:35:11
2:35:13
2:35:15
2:35:17
2:35:19
2:35:21
2:35:23
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.022
60.022
60.019
60.018
60.018
60.018
60.019
60.019
60.019
60.015
60.015
60.016
60.013
60.013
60.012
60.01
60.01
60.007
60.009
60.009
60.009
60.003
60.003
59.999
59.992
59.992
59.991
59.992
59.992
59.988
59.985
59.985
59.984
59.984
59.984
59.982
59.982
59.982
59.979
3785.804
3786.864
3786.864
3785.254
3785.726
3785.726
3785.821
3785.798
3785.798
3786.939
3787.627
3787.627
3789.673
3789.404
3789.404
3789.183
3789.369
3789.369
3788.665
3788.933
3788.933
3790.805
3790.411
3790.411
3791.540
3792.945
3792.945
3791.443
3791.426
3791.426
3790.457
3790.216
3790.216
3788.457
3788.105
3788.105
3788.189
3788.497
3788.497
3788.571
3788.101
3788.101
3786.453
3787.732
3787.732
3789.285
-16.000
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-17.599
-17.599
-15.201
-14.401
-14.401
-14.401
-15.201
-15.201
-15.201
-12.000
-12.000
-12.799
-10.400
-10.400
-9.601
-7.999
-7.999
-5.600
-7.199
-7.199
-7.199
-2.399
-2.399
0.800
6.400
6.400
7.199
6.400
6.400
9.601
12.000
12.000
12.799
12.799
12.799
14.401
14.401
14.401
16.800
-16.597
-16.948
-17.176
-17.324
-17.141
-17.021
-17.504
-17.537
-17.559
-16.734
-15.917
-15.387
-15.042
-15.097
-15.134
-15.157
-14.052
-13.334
-13.147
-12.185
-11.561
-10.875
-9.868
-9.214
-7.949
-7.687
-7.516
-7.405
-5.653
-4.514
-2.654
0.515
2.574
4.193
4.965
5.467
6.914
8.694
9.851
10.883
11.553
11.989
12.834
13.382
13.739
14.810
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3758.145
3757.794
3757.566
3757.418
3757.601
3757.720
3757.238
3757.205
3757.183
3758.008
3758.824
3759.355
3759.700
3759.644
3759.608
3759.585
3760.690
3761.408
3761.595
3762.556
3763.181
3763.867
3764.874
3765.528
3766.793
3767.055
3767.226
3767.337
3769.089
3770.228
3772.088
3775.256
3777.316
3778.935
3779.707
3780.209
3781.656
3783.436
3784.593
3785.624
3786.295
3786.731
3787.575
3788.124
3788.481
3789.552
3767.018
3767.119
3767.218
3767.308
3767.400
3767.490
3767.581
3767.670
3767.758
3767.852
3767.947
3768.042
3768.145
3768.246
3768.347
3768.445
3768.543
3768.641
3768.734
3768.827
3768.920
3769.020
3769.118
3769.215
3769.316
3769.422
3769.528
3769.625
3769.722
3769.818
3769.909
3769.998
3770.087
3770.167
3770.244
3770.321
3770.398
3770.475
3770.552
3770.628
3770.702
3770.775
3770.841
3770.911
3770.981
3771.056
3774.302
3774.218
3774.135
3774.051
3773.969
3773.889
3773.807
3773.725
3773.645
3773.569
3773.498
3773.430
3773.364
3773.299
3773.234
3773.169
3773.111
3773.056
3773.003
3772.954
3772.909
3772.868
3772.831
3772.798
3772.771
3772.745
3772.721
3772.696
3772.680
3772.670
3772.667
3772.678
3772.699
3772.726
3772.756
3772.788
3772.826
3772.872
3772.921
3772.975
3773.031
3773.089
3773.150
3773.212
3773.275
3773.343
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3735.334
3735.558
3735.779
3735.998
3736.214
3736.429
3736.641
3736.852
3737.060
3737.266
3737.471
3737.673
3737.873
3738.072
3738.268
3738.463
3738.656
3738.847
3739.036
3739.223
3739.409
3739.593
3739.776
3739.956
3740.135
3740.313
3740.489
3740.663
3740.835
3741.007
3741.176
3741.344
3741.511
3741.676
3741.840
3742.002
3742.163
3742.323
3742.481
3742.638
3742.793
3742.948
3743.101
3743.252
3743.403
3743.552
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002070
2:35:25
2:35:27
2:35:29
2:35:31
2:35:33
2:35:35
2:35:37
2:35:39
2:35:41
2:35:43
2:35:45
2:35:47
2:35:49
2:35:51
2:35:53
2:35:55
2:35:57
2:35:59
2:36:01
2:36:03
2:36:05
2:36:07
2:36:09
2:36:11
2:36:13
2:36:15
2:36:17
2:36:19
2:36:21
2:36:23
2:36:25
2:36:27
2:36:29
2:36:31
2:36:33
2:36:35
2:36:37
2:36:39
2:36:41
2:36:43
2:36:45
2:36:47
2:36:49
2:36:51
2:36:53
2:36:55
59.976
59.976
59.976
59.982
59.982
59.978
59.974
59.974
59.976
59.977
59.977
59.975
59.969
59.969
59.97
59.973
59.973
59.978
59.978
59.978
59.975
59.976
59.976
59.975
59.969
59.969
59.966
59.966
59.966
59.969
59.968
59.968
59.965
59.97
59.97
59.972
59.967
59.967
59.969
59.969
59.969
59.967
59.966
59.966
59.965
59.967
3788.256
3788.256
3790.467
3790.665
3790.665
3789.674
3789.267
3789.267
3790.430
3789.914
3789.914
3787.442
3788.963
3788.963
3791.877
3792.911
3792.911
3789.125
3788.080
3788.080
3787.135
3787.164
3787.164
3787.405
3786.487
3786.487
3789.214
3790.512
3790.512
3792.218
3790.959
3790.959
3789.026
3789.167
3789.167
3785.690
3784.831
3784.831
3784.320
3782.809
3782.809
3779.352
3779.056
3779.056
3779.212
3779.335
19.199
19.199
19.199
14.401
14.401
17.599
20.801
20.801
19.199
18.399
18.399
20.001
24.799
24.799
23.999
21.600
21.600
17.599
17.599
17.599
20.001
19.199
19.199
20.001
24.799
24.799
27.200
27.200
27.200
24.799
25.601
25.601
28.000
23.999
23.999
22.400
26.401
26.401
24.799
24.799
24.799
26.401
27.200
27.200
28.000
26.401
16.346
17.345
17.993
16.736
15.919
16.507
18.010
18.987
19.061
18.829
18.679
19.142
21.122
22.408
22.965
22.487
22.177
20.575
19.533
18.857
19.257
19.237
19.223
19.496
21.352
22.558
24.183
25.239
25.925
25.531
25.556
25.572
26.421
25.574
25.023
24.105
24.908
25.431
25.209
25.066
24.972
25.472
26.077
26.470
27.006
26.794
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3791.088
3792.086
3792.735
3791.478
3790.661
3791.249
3792.752
3793.728
3793.803
3793.571
3793.420
3793.883
3795.863
3797.150
3797.707
3797.229
3796.919
3795.317
3794.275
3793.598
3793.999
3793.978
3793.965
3794.237
3796.093
3797.300
3798.925
3799.981
3800.667
3800.273
3800.297
3800.313
3801.163
3800.315
3799.764
3798.846
3799.650
3800.172
3799.951
3799.807
3799.714
3800.214
3800.819
3801.212
3801.747
3801.536
3771.127
3771.197
3771.276
3771.355
3771.433
3771.507
3771.578
3771.649
3771.724
3771.796
3771.867
3771.929
3771.996
3772.062
3772.139
3772.219
3772.299
3772.364
3772.424
3772.484
3772.540
3772.595
3772.650
3772.706
3772.757
3772.808
3772.869
3772.935
3773.000
3773.070
3773.136
3773.201
3773.258
3773.316
3773.373
3773.418
3773.458
3773.499
3773.538
3773.570
3773.603
3773.623
3773.642
3773.661
3773.681
3773.700
3773.416
3773.492
3773.571
3773.643
3773.712
3773.783
3773.859
3773.939
3774.018
3774.095
3774.172
3774.249
3774.334
3774.423
3774.514
3774.602
3774.688
3774.767
3774.842
3774.914
3774.986
3775.058
3775.130
3775.202
3775.280
3775.362
3775.450
3775.540
3775.633
3775.724
3775.814
3775.903
3775.995
3776.083
3776.169
3776.250
3776.334
3776.419
3776.503
3776.586
3776.667
3776.750
3776.835
3776.920
3777.006
3777.092
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3743.700
3743.846
3743.992
3744.136
3744.279
3744.421
3744.562
3744.702
3744.840
3744.978
3745.114
3745.249
3745.384
3745.517
3745.649
3745.780
3745.910
3746.039
3746.167
3746.294
3746.421
3746.546
3746.670
3746.793
3746.916
3747.037
3747.158
3747.277
3747.396
3747.514
3747.631
3747.747
3747.863
3747.977
3748.091
3748.203
3748.315
3748.427
3748.537
3748.647
3748.756
3748.864
3748.971
3749.078
3749.183
3749.289
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002071
2:36:57
2:36:59
2:37:01
2:37:03
2:37:05
2:37:07
2:37:09
2:37:11
2:37:13
2:37:15
2:37:17
2:37:19
2:37:21
2:37:23
2:37:25
2:37:27
2:37:29
2:37:31
2:37:33
2:37:35
2:37:37
2:37:39
2:37:41
2:37:43
2:37:45
2:37:47
2:37:49
2:37:51
2:37:53
2:37:55
2:37:57
2:37:59
2:38:01
2:38:03
2:38:05
2:38:07
2:38:09
2:38:11
2:38:13
2:38:15
2:38:17
2:38:19
2:38:21
2:38:23
2:38:25
2:38:27
59.967
59.965
59.964
59.964
59.97
59.969
59.969
59.968
59.965
59.965
59.97
59.968
59.968
59.965
59.969
59.969
59.967
59.966
59.966
59.979
59.983
59.983
59.974
59.965
59.965
59.962
59.961
59.961
59.961
59.963
59.963
59.959
59.951
59.951
59.953
59.957
59.957
59.956
59.963
59.963
59.961
59.963
59.963
59.963
59.968
59.968
3779.335
3775.647
3776.597
3776.597
3776.023
3773.170
3773.170
3768.793
3768.503
3768.503
3767.366
3764.786
3764.786
3759.592
3761.894
3761.894
3760.583
3760.157
3760.157
3759.495
3757.773
3757.773
3753.087
3751.637
3751.637
3758.225
3759.250
3759.250
3760.965
3762.022
3762.022
3763.100
3763.858
3763.858
3766.127
3768.339
3768.339
3767.438
3765.606
3765.606
3761.570
3761.920
3761.920
3758.522
3752.429
3752.429
26.401
28.000
28.799
28.799
23.999
24.799
24.799
25.601
28.000
28.000
23.999
25.601
25.601
28.000
24.799
24.799
26.401
27.200
27.200
16.800
13.599
13.599
20.801
28.000
28.000
30.399
31.201
31.201
31.201
29.599
29.599
32.800
39.200
39.200
37.601
34.399
34.399
35.199
29.599
29.599
31.201
29.599
29.599
29.599
25.601
25.601
26.656
27.127
27.712
28.093
26.660
26.008
25.585
25.591
26.434
26.982
25.938
25.820
25.743
26.533
25.926
25.531
25.836
26.313
26.624
23.185
19.830
17.649
18.752
21.989
24.093
26.300
28.015
29.130
29.855
29.765
29.707
30.790
33.733
35.647
36.331
35.655
35.215
35.210
33.246
31.969
31.701
30.965
30.487
30.176
28.575
27.534
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3801.398
3801.868
3802.454
3802.834
3801.402
3800.750
3800.327
3800.332
3801.176
3801.724
3800.680
3800.562
3800.485
3801.275
3800.668
3800.273
3800.577
3801.055
3801.366
3797.927
3794.572
3792.391
3793.494
3796.731
3798.834
3801.041
3802.757
3803.872
3804.597
3804.507
3804.449
3805.532
3808.475
3810.388
3811.072
3810.396
3809.957
3809.951
3807.988
3806.711
3806.442
3805.707
3805.229
3804.918
3803.317
3802.276
3773.720
3773.726
3773.736
3773.746
3773.754
3773.752
3773.750
3773.733
3773.716
3773.698
3773.677
3773.647
3773.618
3773.571
3773.533
3773.495
3773.452
3773.409
3773.366
3773.321
3773.270
3773.220
3773.155
3773.087
3773.018
3772.971
3772.927
3772.884
3772.846
3772.812
3772.779
3772.748
3772.721
3772.693
3772.673
3772.659
3772.646
3772.630
3772.609
3772.587
3772.554
3772.522
3772.490
3772.447
3772.387
3772.328
3777.176
3777.261
3777.347
3777.435
3777.516
3777.595
3777.673
3777.749
3777.828
3777.908
3777.984
3778.060
3778.134
3778.211
3778.285
3778.357
3778.430
3778.504
3778.578
3778.641
3778.693
3778.737
3778.784
3778.842
3778.906
3778.976
3779.052
3779.130
3779.211
3779.290
3779.369
3779.451
3779.541
3779.637
3779.734
3779.829
3779.922
3780.014
3780.099
3780.181
3780.260
3780.337
3780.413
3780.486
3780.555
3780.620
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3749.393
3749.497
3749.599
3749.702
3749.803
3749.904
3750.004
3750.104
3750.202
3750.300
3750.398
3750.495
3750.591
3750.686
3750.781
3750.876
3750.969
3751.062
3751.155
3751.247
3751.338
3751.428
3751.518
3751.608
3751.697
3751.785
3751.873
3751.960
3752.047
3752.133
3752.218
3752.303
3752.388
3752.472
3752.555
3752.638
3752.721
3752.803
3752.884
3752.965
3753.045
3753.125
3753.205
3753.284
3753.362
3753.440
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002072
2:38:29
2:38:31
2:38:33
2:38:35
2:38:37
2:38:39
2:38:41
2:38:43
2:38:45
2:38:47
2:38:49
2:38:51
2:38:53
2:38:55
2:38:57
2:38:59
2:39:01
2:39:03
2:39:05
2:39:07
2:39:09
2:39:11
2:39:13
2:39:15
2:39:17
2:39:19
2:39:21
2:39:23
2:39:25
2:39:27
2:39:29
2:39:31
2:39:33
2:39:35
2:39:37
2:39:39
2:39:41
2:39:43
2:39:45
2:39:47
2:39:49
2:39:51
2:39:53
2:39:55
2:39:57
2:39:59
59.968
59.97
59.97
59.973
59.965
59.965
59.967
59.972
59.972
59.976
59.969
59.969
59.973
59.978
59.978
59.981
59.981
59.981
59.982
59.984
59.984
59.982
59.979
59.979
59.98
59.978
59.978
59.98
59.98
59.98
59.978
59.972
59.972
59.971
59.974
59.974
59.975
59.972
59.972
59.969
59.974
59.974
59.972
59.972
59.972
59.977
3753.830
3753.510
3753.510
3752.741
3753.178
3753.178
3753.291
3752.872
3752.872
3749.398
3747.476
3747.476
3741.285
3746.651
3746.651
3743.351
3741.618
3741.618
3738.484
3738.901
3738.901
3737.273
3736.308
3736.308
3735.448
3735.650
3735.650
3738.012
3736.748
3736.748
3736.067
3736.094
3736.094
3738.571
3738.875
3738.875
3738.647
3737.684
3737.684
3737.892
3740.017
3740.017
3742.053
3742.424
3742.424
3742.245
25.601
23.999
23.999
21.600
28.000
28.000
26.401
22.400
22.400
19.199
24.799
24.799
21.600
17.599
17.599
15.201
15.201
15.201
14.401
12.799
12.799
14.401
16.800
16.800
16.000
17.599
17.599
16.000
16.000
16.000
17.599
22.400
22.400
23.199
20.801
20.801
20.001
22.400
22.400
24.799
20.801
20.801
22.400
22.400
22.400
18.399
26.858
25.857
25.207
23.945
25.364
26.286
26.326
24.952
24.059
22.358
23.212
23.767
23.009
21.116
19.885
18.246
17.180
16.487
15.757
14.722
14.049
14.172
15.092
15.690
15.798
16.429
16.839
16.545
16.354
16.231
16.710
18.701
19.996
21.117
21.006
20.934
20.608
21.235
21.643
22.747
22.066
21.623
21.895
22.072
22.187
20.861
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3801.599
3800.599
3799.949
3798.686
3800.106
3801.028
3801.068
3799.694
3798.801
3797.100
3797.954
3798.509
3797.751
3795.857
3794.627
3792.987
3791.922
3791.229
3790.499
3789.464
3788.791
3788.914
3789.834
3790.431
3790.540
3791.171
3791.580
3791.287
3791.096
3790.972
3791.451
3793.443
3794.738
3795.859
3795.748
3795.676
3795.350
3795.977
3796.384
3797.489
3796.808
3796.365
3796.637
3796.813
3796.928
3795.603
3772.272
3772.217
3772.161
3772.104
3772.048
3771.992
3771.937
3771.882
3771.826
3771.761
3771.691
3771.621
3771.533
3771.462
3771.391
3771.311
3771.226
3771.142
3771.049
3770.959
3770.868
3770.774
3770.677
3770.581
3770.483
3770.387
3770.290
3770.201
3770.109
3770.017
3769.924
3769.832
3769.740
3769.655
3769.572
3769.489
3769.406
3769.321
3769.236
3769.152
3769.074
3768.997
3768.926
3768.855
3768.786
3768.716
3780.683
3780.742
3780.799
3780.852
3780.909
3780.968
3781.027
3781.081
3781.133
3781.179
3781.228
3781.278
3781.325
3781.367
3781.405
3781.438
3781.468
3781.496
3781.521
3781.544
3781.564
3781.585
3781.608
3781.633
3781.657
3781.684
3781.711
3781.738
3781.764
3781.789
3781.815
3781.847
3781.882
3781.920
3781.958
3781.995
3782.031
3782.068
3782.107
3782.148
3782.187
3782.225
3782.263
3782.301
3782.340
3782.375
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3753.518
3753.595
3753.672
3753.748
3753.823
3753.899
3753.974
3754.048
3754.122
3754.196
3754.269
3754.341
3754.414
3754.485
3754.557
3754.628
3754.698
3754.769
3754.839
3754.908
3754.977
3755.046
3755.114
3755.182
3755.249
3755.316
3755.383
3755.449
3755.515
3755.581
3755.646
3755.711
3755.776
3755.840
3755.904
3755.967
3756.031
3756.093
3756.156
3756.218
3756.280
3756.342
3756.403
3756.464
3756.524
3756.584
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002073
2:40:01
2:40:03
2:40:05
2:40:07
2:40:09
2:40:11
2:40:13
2:40:15
2:40:17
2:40:19
2:40:21
2:40:23
2:40:25
2:40:27
2:40:29
2:40:31
2:40:33
2:40:35
2:40:37
2:40:39
2:40:41
2:40:43
2:40:45
2:40:47
2:40:49
2:40:51
2:40:53
2:40:55
2:40:57
2:40:59
2:41:01
2:41:03
2:41:05
2:41:07
2:41:09
2:41:11
2:41:13
2:41:15
2:41:17
2:41:19
2:41:21
2:41:23
2:41:25
2:41:27
2:41:29
2:41:31
59.978
59.978
59.976
59.974
59.974
59.977
59.978
59.978
59.979
59.977
59.977
59.974
59.971
59.971
59.971
59.968
59.968
59.966
59.971
59.971
59.973
59.969
59.969
59.972
59.973
59.973
59.97
59.974
59.974
59.982
59.985
59.985
59.985
59.989
59.989
59.989
59.987
59.987
59.99
59.996
59.996
60.001
60.004
60.004
60.006
60.014
3741.723
3741.723
3740.629
3739.964
3739.964
3742.833
3741.268
3741.268
3738.966
3738.706
3738.706
3739.860
3738.102
3738.102
3743.507
3743.419
3743.419
3745.744
3747.340
3747.340
3749.750
3746.217
3746.217
3743.745
3743.149
3743.149
3739.453
3733.376
3733.376
3737.583
3736.229
3736.229
3733.434
3733.115
3733.115
3729.180
3725.459
3725.459
3720.108
3720.938
3720.938
3725.677
3727.754
3727.754
3727.683
3727.231
17.599
17.599
19.199
20.801
20.801
18.399
17.599
17.599
16.800
18.399
18.399
20.801
23.199
23.199
23.199
25.601
25.601
27.200
23.199
23.199
21.600
24.799
24.799
22.400
21.600
21.600
23.999
20.801
20.801
14.401
12.000
12.000
12.000
8.801
8.801
8.801
10.400
10.400
7.999
3.201
3.201
-0.800
-3.201
-3.201
-4.800
-11.200
19.719
18.977
19.055
19.666
20.063
19.481
18.822
18.394
17.836
18.033
18.161
19.085
20.525
21.461
22.070
23.306
24.109
25.191
24.494
24.041
23.187
23.751
24.118
23.516
22.846
22.410
22.966
22.208
21.716
19.156
16.651
15.023
13.965
12.158
10.983
10.219
10.283
10.324
9.510
7.302
5.867
3.534
1.176
-0.356
-1.911
-5.162
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3794.461
3793.719
3793.797
3794.408
3794.805
3794.222
3793.564
3793.136
3792.578
3792.775
3792.903
3793.827
3795.267
3796.203
3796.811
3798.047
3798.851
3799.933
3799.236
3798.783
3797.928
3798.493
3798.859
3798.258
3797.588
3797.152
3797.708
3796.950
3796.457
3793.897
3791.393
3789.765
3788.706
3786.899
3785.725
3784.961
3785.024
3785.066
3784.252
3782.044
3780.608
3778.275
3775.918
3774.386
3772.830
3769.579
3768.645
3768.575
3768.502
3768.427
3768.353
3768.287
3768.217
3768.148
3768.073
3767.998
3767.923
3767.851
3767.775
3767.700
3767.639
3767.578
3767.517
3767.462
3767.412
3767.362
3767.318
3767.265
3767.213
3767.155
3767.096
3767.037
3766.969
3766.886
3766.804
3766.733
3766.659
3766.585
3766.505
3766.424
3766.344
3766.255
3766.157
3766.059
3765.950
3765.843
3765.736
3765.641
3765.551
3765.462
3765.373
3765.284
3782.406
3782.436
3782.466
3782.497
3782.529
3782.559
3782.588
3782.615
3782.640
3782.666
3782.693
3782.721
3782.753
3782.787
3782.822
3782.861
3782.901
3782.944
3782.985
3783.024
3783.062
3783.100
3783.139
3783.176
3783.212
3783.246
3783.282
3783.315
3783.347
3783.373
3783.393
3783.408
3783.421
3783.429
3783.435
3783.439
3783.442
3783.446
3783.448
3783.445
3783.438
3783.426
3783.408
3783.387
3783.362
3783.330
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3756.644
3756.704
3756.763
3756.822
3756.881
3756.939
3756.997
3757.055
3757.112
3757.169
3757.226
3757.283
3757.339
3757.395
3757.451
3757.506
3757.561
3757.616
3757.671
3757.725
3757.779
3757.833
3757.886
3757.940
3757.993
3758.045
3758.098
3758.150
3758.202
3758.254
3758.305
3758.356
3758.407
3758.458
3758.508
3758.559
3758.609
3758.658
3758.708
3758.757
3758.806
3758.855
3758.903
3758.952
3759.000
3759.048
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002074
2:41:33
2:41:35
2:41:37
2:41:39
2:41:41
2:41:43
2:41:45
2:41:47
2:41:49
2:41:51
2:41:53
2:41:55
2:41:57
2:41:59
2:42:01
2:42:03
2:42:05
2:42:07
2:42:09
2:42:11
2:42:13
2:42:15
2:42:17
2:42:19
2:42:21
60.014
60.019
60.025
60.025
60.026
60.029
60.029
60.029
60.036
60.036
60.037
60.036
60.036
60.041
60.044
60.044
60.043
60.048
60.048
60.046
60.043
60.043
60.043
60.043
60.043
3727.231
3726.446
3726.016
3726.016
3716.375
3717.333
3717.333
3717.142
3715.166
3715.166
3710.283
3710.158
3710.158
3698.591
3704.591
3704.591
3702.482
3701.316
3701.316
3699.529
3699.726
3699.726
3690.477
3696.865
3696.865
-11.200
-15.201
-20.001
-20.001
-20.801
-23.199
-23.199
-23.199
-28.799
-28.799
-29.599
-28.799
-28.799
-32.800
-35.199
-35.199
-34.399
-38.400
-38.400
-36.801
-34.399
-34.399
-34.399
-34.399
-34.399
-7.276
-10.049
-13.533
-15.797
-17.548
-19.526
-20.812
-21.647
-24.151
-25.778
-27.115
-27.705
-28.088
-29.737
-31.649
-32.891
-33.419
-35.163
-36.296
-36.473
-35.747
-35.275
-34.969
-34.769
-34.640
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3767.466
3764.692
3761.209
3758.945
3757.194
3755.216
3753.930
3753.094
3750.591
3748.964
3747.627
3747.037
3746.654
3745.005
3743.093
3741.850
3741.323
3739.579
3738.446
3738.269
3738.995
3739.466
3739.773
3739.972
3740.102
3765.195
3765.104
3765.013
3764.922
3764.810
3764.700
3764.590
3764.481
3764.368
3764.255
3764.131
3764.008
3763.886
3763.737
3763.603
3763.469
3763.332
3763.192
3763.053
3762.911
3762.769
3762.629
3762.468
3762.322
3762.177
3783.293
3783.249
3783.198
3783.141
3783.081
3783.017
3782.949
3782.881
3782.806
3782.729
3782.648
3782.567
3782.485
3782.400
3782.311
3782.220
3782.127
3782.031
3781.933
3781.836
3781.740
3781.645
3781.552
3781.460
3781.368
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3779.344
3759.095
3759.143
3759.190
3759.237
3759.284
3759.330
3759.377
3759.423
3759.469
3759.514
3759.560
3759.605
3759.650
3759.695
3759.740
3759.784
3759.828
3759.872
3759.916
3759.960
3760.003
3760.047
3760.090
3760.133
3760.175
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002075
A Point
2:27:19
FPointA
60.0390
2:27:19 AM
A Value
60.0417
C Value
59.8360
#N/A
Delta FCA -0.205751419
FR C
-307.7 MW/0.1 Hz
Slope A-C dF/dT
#N/A
Hz/second
C Value Maximum Resource Loss
633
Secondary C Value
No
n/a Time
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:19
60.03900146
60.04174995
59.83599854
2:27:19
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
59.8823
59.8844
59.8887
59.8879
59.8887
-0.1595
-397.436
-0.1573
-402.634
-0.1530
-415.164
-0.1538
-411.959
-0.1530
-0.00797319
-0.00786606
-0.0076522
-0.0076903
-0.0076522
77.5032
76.4617
74.3829
74.7530
74.3829
-0.0172
-0.0193
-0.0236
-0.0228
-0.0236
Tzero
2:27:19
FT+4 59.83599854
FT+10 59.89099884
FT+20 59.88299942
FT+60 59.88999939
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss
B Value Average LaaR Loss
B Value Average Net Loss
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
633
0
633
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection FR B
Generation Primary
20 to 52 sec
Trip
Frequency
Average
MW
Response
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002076
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-992.952
T+0 sec
-992.952
T+02 sec
-307.653
T+04 sec
-307.653
T+06 sec
-366.424
T+08 sec
-419.897
T+10 sec
-419.897
T+12 sec
-391.347
T+14 sec
-379.61
T+16 sec
-379.61
T+18 sec
-398.739 -413.8616294 T+20 sec
-406.425 -413.8616294 T+22 sec
-406.425 -413.8616294 T+24 sec
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
-397.436
-397.436
-397.436
-397.436
-397.436
-397.436
-397.436
59.8844
59.8844
59.8844
59.8844
-402.634
-402.634
-402.634
-402.634
59.8887
59.8887
59.8887
-415.164
-415.164
-415.164
59.8879
59.8879
59.8879
59.8879
-411.959
-411.959
-411.959
-411.959
59.8887
59.8887
59.8887
002077
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-403.824
-411.709
-411.709
-417.132
-428.429
-428.429
-425.551
-428.429
-428.429
-419.897
-403.824
-403.824
-403.824
-409.05
-409.05
-411.709
-417.132
-417.132
-414.403
-375.114
-375.114
-342.622
-333.599
-333.599
-344.493
-360.173
-360.173
-358.136
-360.173
-360.173
-370.714
-388.944
-388.944
-391.347
-406.425
-406.425
-417.132
-414.403
-414.403
-425.551
-456.216
-456.216
-452.953
-459.526
-459.526
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8844
59.8844
59.8844
-402.634
-402.634
-402.634
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
002078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-469.764
-503.381
-503.381
-503.381
-511.512
-511.512
-519.91
-519.91
-519.91
-507.414
-524.23
-524.23
-533.054
-542.181
-542.181
-556.491
-576.761
-576.761
-551.625
-571.557
-571.557
-561.424
-571.557
-571.557
-604.298
-654.262
-654.262
-682.49
-634.595
-634.595
-628.3
-654.262
-654.262
-675.214
-682.49
-682.49
-697.523
-713.233
-713.233
-697.523
-705.29
-705.29
-705.29
-705.29
-705.29
-721.356
002079
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-713.233
-713.233
-713.233
-721.356
-721.356
-721.356
-746.91
-746.91
-738.204
-738.204
-738.204
-729.699
-783.887
-783.887
-793.749
-858.288
-858.288
-835.64
-858.288
-858.288
-882.246
-882.246
-882.246
-870.125
-882.246
-882.246
-894.709
-920.722
-920.722
-962.764
-992.952
-992.952
-962.764
-962.764
-962.764
-992.952
-1025.09
-1025.09
-1059.39
-1025.09
-1025.09
-1008.77
-1008.77
-1008.77
-1077.48
-1096.13
002080
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1096.13
-1177.65
-1156.16
-1156.16
-1156.16
-1298.46
-1298.46
-1272.38
-1199.96
-1199.96
-1135.43
-1077.48
-1077.48
-1177.65
-1383.56
-1383.56
-1446.89
-1553.36
-1553.36
-1480.72
-1480.72
-1480.72
-1592.41
-1821.58
-1821.58
-1875.53
-2281.08
-2281.08
-2557.4
-3050.6
-3050.6
-2557.4
-2782.55
-2782.55
-3375.79
-3779.46
-3779.46
-3050.6
-3565.86
-3565.86
-3565.86
-2910.41
-2910.41
-3779.46
-2910.41
-2910.41
002081
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2910.41
-3204.97
-3204.97
-3204.97
-3050.6
-3050.6
-3375.79
-3204.97
-3204.97
-2782.55
-2665.44
-2665.44
-2665.44
-2782.55
-2782.55
-2782.55
-2366.31
-2366.31
-2458.15
-2201.78
-2201.78
-2127.81
-1993.6
-1993.6
-1821.58
-1932.76
-1932.76
-1932.76
-1633.48
-1633.48
-1480.72
-1272.38
-1272.38
-1247.32
-1272.38
-1272.38
-1177.65
-1115.43
-1115.43
-1096.13
-1096.13
-1096.13
-1059.39
-1059.39
-1059.39
-1008.77
002082
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-962.764
-962.764
-962.764
-1059.39
-1059.39
-992.952
-934.305
-934.305
-962.764
-977.625
-977.625
-948.294
-870.125
-870.125
-882.246
-920.722
-920.722
-992.952
-992.952
-992.952
-948.294
-962.764
-962.764
-948.294
-870.125
-870.125
-835.64
-835.64
-835.64
-870.125
-858.288
-858.288
-824.758
-882.246
-882.246
-907.529
-846.813
-846.813
-870.125
-870.125
-870.125
-846.813
-835.64
-835.64
-824.758
-846.813
002083
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-846.813
-824.758
-814.156
-814.156
-882.246
-870.125
-870.125
-858.288
-824.758
-824.758
-882.246
-858.288
-858.288
-824.758
-870.125
-870.125
-846.813
-835.64
-835.64
-1008.77
-1077.48
-1077.48
-934.305
-824.758
-824.758
-793.749
-783.887
-783.887
-783.887
-803.823
-803.823
-764.952
-697.523
-697.523
-713.233
-746.91
-746.91
-738.204
-803.823
-803.823
-783.887
-803.823
-803.823
-803.823
-858.288
-858.288
002084
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-858.288
-882.246
-882.246
-920.722
-824.758
-824.758
-846.813
-907.529
-907.529
-962.764
-870.125
-870.125
-920.722
-992.952
-992.952
-1041.96
-1041.96
-1041.96
-1059.39
-1096.13
-1096.13
-1059.39
-1008.77
-1008.77
-1025.09
-992.952
-992.952
-1025.09
-1025.09
-1025.09
-992.952
-907.529
-907.529
-894.709
-934.305
-934.305
-948.294
-907.529
-907.529
-870.125
-934.305
-934.305
-907.529
-907.529
-907.529
-977.625
002085
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-992.952
-992.952
-962.764
-934.305
-934.305
-977.625
-992.952
-992.952
-1008.77
-977.625
-977.625
-934.305
-894.709
-894.709
-894.709
-858.288
-858.288
-835.64
-894.709
-894.709
-920.722
-870.125
-870.125
-907.529
-920.722
-920.722
-882.246
-934.305
-934.305
-1059.39
-1115.43
-1115.43
-1115.43
-1199.96
-1199.96
-1199.96
-1156.16
-1156.16
-1223.23
-1383.56
-1383.56
-1553.36
-1676.9
-1676.9
-1770.66
-2281.08
002086
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2281.08
-2782.55
-3779.46
-3779.46
-4019.31
-4964.46
-4964.46
-4964.46
-11007.4
-11007.4
-13322.9
-11007.4
-11007.4
-84446.4
28148.8
28148.8
50667.83
10127.38
10127.38
14888.93
50667.83
50667.83
50667.83
50667.83
50667.83
002087
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
Time of Frequency Recovery to 60 Hz or P
Value A Pre-Perturbation Average Frequen
Value B Post-Perturbation Average Frequen
Pre to Post Perturbation Delt
Value A Pre-Perturbation Average Interchange M
Value B Post-Perturbation Average Interchange MW
Pre to Post Perturbation Interchang
FR B
20 to 52 sec
-413.862
eriods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
FR B
20 to 52 sec
Average
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Net
Actual
Interchange
MW
60.0270
60.0270
60.0260
3671.19
3671.19
3668.61
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
-253.63
-253.63
-253.63
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
141.50
141.50
142.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
12 to 24 second Average Period Ev
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
BA
Load
MW
7593.39
7593.39
7593.72
Expected
Primary
Freq Response
MW
-21.600 T-72 sec
-21.600 T-70 sec
-20.801 T-68 sec
T
2:26:09
2:26:11
2:26:13
Frequency
Hz
002088
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-413.862 T+20 sec
-413.862 T+22 sec
-413.862 T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
60.0220
60.0220
60.0170
60.0190
60.0190
60.0190
60.0210
60.0210
60.0210
60.0190
60.0190
60.0220
60.0310
60.0310
60.0370
60.0360
60.0360
60.0460
60.0480
60.0480
60.0430
60.0410
60.0410
60.0410
60.0390
60.0390
60.0430
60.0450
60.0450
60.0410
60.0410
60.0410
60.0390
59.9780
59.9780
59.8360
59.8360
59.8690
59.8910
59.8910
59.8800
59.8750
59.8750
59.8830
59.8860
59.8860
3664.50
3664.50
3666.06
3666.79
3666.79
3670.45
3671.67
3671.67
3672.49
3672.86
3672.86
3672.16
3669.98
3669.98
3666.47
3661.60
3661.60
3660.67
3649.19
3649.19
3650.03
3649.51
3649.51
3654.29
3651.87
3651.87
3651.06
3648.24
3648.24
3645.39
3645.45
3645.45
3640.68
3659.46
3659.46
3696.36
3696.36
3734.67
3737.16
3737.16
3766.11
3766.19
3766.19
3769.93
3780.62
3780.62
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-253.63
-253.63
-253.63
-253.63
-253.63
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-211.26
-211.26
-211.26
-211.26
-211.26
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
142.50
142.50
143.00
143.50
143.50
144.00
144.50
144.50
145.00
145.50
145.50
146.00
146.50
146.50
147.00
147.50
147.50
148.00
148.50
148.50
149.00
149.50
149.50
150.00
150.50
150.50
151.00
151.50
151.50
152.00
152.50
152.50
153.00
153.50
153.50
154.00
154.00
154.50
155.00
155.00
155.50
156.00
156.00
156.50
157.00
157.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7594.05
7594.05
7594.38
7594.71
7594.71
7595.04
7595.37
7595.37
7595.70
7596.03
7596.03
7596.36
7596.69
7596.69
7597.02
7597.35
7597.35
7597.68
7598.01
7598.01
7598.34
7598.67
7598.67
7599.00
7599.33
7599.33
7599.66
7599.99
7599.99
7600.32
7600.65
7600.65
7600.98
7601.31
7601.31
7570.00
7570.00
7569.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
-17.599
-17.599
-13.599
-15.201
-15.201
-15.201
-16.800
-16.800
-16.800
-15.201
-15.201
-17.599
-24.799
-24.799
-29.599
-28.799
-28.799
-36.801
-38.400
-38.400
-34.399
-32.800
-32.800
-32.800
-31.201
-31.201
-34.399
-35.999
-35.999
-32.800
-32.800
-32.800
-31.201
17.599
17.599
131.201
131.201
104.800
87.201
87.201
95.999
100.000
100.000
93.600
91.199
91.199
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.882
59.882
59.882
59.882
59.882
59.882
59.882
002089
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
2:28:43
2:28:45
2:28:47
2:28:49
2:28:51
2:28:53
2:28:55
2:28:57
2:28:59
2:29:01
2:29:03
2:29:05
2:29:07
2:29:09
2:29:11
2:29:13
2:29:15
59.8850
59.8880
59.8880
59.8900
59.8940
59.8940
59.8930
59.8940
59.8940
59.8910
59.8850
59.8850
59.8850
59.8870
59.8870
59.8880
59.8900
59.8900
59.8890
59.8730
59.8730
59.8570
59.8520
59.8520
59.8580
59.8660
59.8660
59.8650
59.8660
59.8660
59.8710
59.8790
59.8790
59.8800
59.8860
59.8860
59.8900
59.8890
59.8890
59.8930
59.9030
59.9030
59.9020
59.9040
59.9040
3782.50
3784.96
3784.96
3784.42
3788.07
3788.07
3788.87
3788.47
3788.47
3793.07
3794.37
3794.37
3800.43
3799.96
3799.96
3802.93
3802.95
3802.95
3805.50
3805.62
3805.62
3811.50
3814.86
3814.86
3825.64
3826.05
3826.05
3827.52
3826.75
3826.75
3826.45
3825.71
3825.71
3822.51
3819.08
3819.08
3816.81
3815.01
3815.01
3811.84
3809.65
3809.65
3805.59
3804.19
3804.19
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-211.26
-211.26
-211.26
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-214.83
-214.83
-214.83
-214.83
-214.83
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
2.00
3.00
4.00
4.00
5.00
6.00
6.00
7.00
8.00
8.00
9.00
10.00
10.00
11.00
12.00
12.00
13.00
14.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
157.50
158.00
158.00
158.50
159.00
159.00
159.50
160.00
160.00
160.50
161.00
161.00
161.50
162.00
162.00
162.50
163.00
163.00
163.50
164.00
164.00
164.50
165.00
165.00
165.50
166.00
166.00
166.50
167.00
167.00
167.50
168.00
168.00
168.50
169.00
169.00
169.50
170.00
170.00
170.50
171.00
171.00
171.50
172.00
172.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7568.00
7568.00
7565.00
7560.00
7560.00
7563.00
7564.00
7564.00
7566.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7569.00
7575.00
7575.00
7573.00
7571.00
7571.00
7573.00
7575.00
7575.00
92.001
89.600
89.600
88.000
84.799
84.799
85.599
84.799
84.799
87.201
92.001
92.001
92.001
90.399
90.399
89.600
88.000
88.000
88.800
101.599
101.599
114.401
118.399
118.399
113.599
107.199
107.199
107.999
107.199
107.199
103.201
96.799
96.799
95.999
91.199
91.199
88.000
88.800
88.800
85.599
77.600
77.600
78.400
76.801
76.801
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
002090
2:29:17
2:29:19
2:29:21
2:29:23
2:29:25
2:29:27
2:29:29
2:29:31
2:29:33
2:29:35
2:29:37
2:29:39
2:29:41
2:29:43
2:29:45
2:29:47
2:29:49
2:29:51
2:29:53
2:29:55
2:29:57
2:29:59
2:30:01
2:30:03
2:30:05
2:30:07
2:30:09
2:30:11
2:30:13
2:30:15
2:30:17
2:30:19
2:30:21
2:30:23
2:30:25
2:30:27
2:30:29
2:30:31
2:30:33
2:30:35
2:30:37
2:30:39
2:30:41
2:30:43
2:30:45
2:30:47
59.9070
59.9160
59.9160
59.9160
59.9180
59.9180
59.9200
59.9200
59.9200
59.9170
59.9210
59.9210
59.9230
59.9250
59.9250
59.9280
59.9320
59.9320
59.9270
59.9310
59.9310
59.9290
59.9310
59.9310
59.9370
59.9450
59.9450
59.9490
59.9420
59.9420
59.9410
59.9450
59.9450
59.9480
59.9490
59.9490
59.9510
59.9530
59.9530
59.9510
59.9520
59.9520
59.9520
59.9520
59.9520
59.9540
3793.98
3792.17
3792.17
3789.53
3788.13
3788.13
3783.03
3781.70
3781.70
3775.64
3774.60
3774.60
3773.96
3772.72
3772.72
3769.63
3768.71
3768.71
3767.02
3767.41
3767.41
3766.26
3765.67
3765.67
3766.12
3765.10
3765.10
3758.39
3753.92
3753.92
3746.89
3747.88
3747.88
3748.66
3746.71
3746.71
3742.74
3740.26
3740.26
3731.38
3727.84
3727.84
3722.65
3720.58
3720.58
3718.14
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-214.83
-214.83
-214.83
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-229.47
-229.47
-249.34
-249.34
-249.34
-249.34
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
172.50
173.00
173.00
173.50
174.00
174.00
174.50
175.00
175.00
175.50
176.00
176.00
176.50
177.00
177.00
177.50
178.00
178.00
178.50
179.00
179.00
179.50
180.00
180.00
180.50
181.00
181.00
181.50
182.00
182.00
182.50
183.00
183.00
183.50
184.00
184.00
184.50
185.00
185.00
185.50
186.00
186.00
186.50
187.00
187.00
187.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7577.00
7577.00
7577.00
7578.00
7579.00
7579.00
7580.00
7581.00
7581.00
7585.00
7588.00
7588.00
7589.00
7589.00
7589.00
7590.00
7590.00
7590.00
7590.00
7591.00
7591.00
7591.00
7591.00
7591.00
7592.00
7592.00
7592.00
7593.00
7594.00
7594.00
7595.00
7655.00
7655.00
7656.00
7656.00
7656.00
7657.00
7657.00
7657.00
7658.00
7658.00
7658.00
7659.00
7659.00
7659.00
7659.00
74.399
67.200
67.200
67.200
65.601
65.601
64.001
64.001
64.001
66.400
63.199
63.199
61.600
60.001
60.001
57.599
54.401
54.401
58.401
55.200
55.200
56.799
55.200
55.200
50.400
44.000
44.000
40.799
46.399
46.399
47.198
44.000
44.000
41.599
40.799
40.799
39.200
37.601
37.601
39.200
38.400
38.400
38.400
38.400
38.400
36.801
002091
2:30:49
2:30:51
2:30:53
2:30:55
2:30:57
2:30:59
2:31:01
2:31:03
2:31:05
2:31:07
2:31:09
2:31:11
2:31:13
2:31:15
2:31:17
2:31:19
2:31:21
2:31:23
2:31:25
2:31:27
2:31:29
2:31:31
2:31:33
2:31:35
2:31:37
2:31:39
2:31:41
2:31:43
2:31:45
2:31:47
2:31:49
2:31:51
2:31:53
2:31:55
2:31:57
2:31:59
2:32:01
2:32:03
2:32:05
2:32:07
2:32:09
2:32:11
2:32:13
2:32:15
2:32:17
2:32:19
59.9530
59.9530
59.9530
59.9540
59.9540
59.9540
59.9570
59.9570
59.9560
59.9560
59.9560
59.9550
59.9610
59.9610
59.9620
59.9680
59.9680
59.9660
59.9680
59.9680
59.9700
59.9700
59.9700
59.9690
59.9700
59.9700
59.9710
59.9730
59.9730
59.9760
59.9780
59.9780
59.9760
59.9760
59.9760
59.9780
59.9800
59.9800
59.9820
59.9800
59.9800
59.9790
59.9790
59.9790
59.9830
59.9840
3715.75
3715.75
3713.48
3710.85
3710.85
3712.09
3714.62
3714.62
3716.17
3716.46
3716.46
3717.76
3722.36
3722.36
3722.66
3722.27
3722.27
3721.79
3723.09
3723.09
3723.43
3723.89
3723.89
3727.12
3728.05
3728.05
3732.53
3733.33
3733.33
3736.91
3736.82
3736.82
3739.94
3740.88
3740.88
3745.23
3746.61
3746.61
3750.72
3751.56
3751.56
3755.60
3756.41
3756.41
3760.41
3760.98
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-249.34
-249.34
-249.34
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-261.91
-261.91
-261.91
-261.91
-261.91
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
188.00
188.00
188.50
189.00
189.00
189.50
190.00
190.00
190.50
191.00
191.00
191.50
192.00
192.00
192.50
193.00
193.00
193.50
194.00
194.00
194.50
195.00
195.00
195.50
196.00
196.00
196.50
197.00
197.00
197.50
198.00
198.00
198.50
199.00
199.00
199.50
200.00
200.00
200.50
201.00
201.00
201.50
202.00
202.00
202.50
203.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7660.00
7660.00
7660.00
7661.00
7661.00
7661.00
7625.40
7625.40
7625.73
7626.06
7626.06
7626.39
7626.72
7626.72
7627.05
7627.38
7627.38
7627.71
7628.04
7628.04
7628.37
7628.70
7628.70
7629.03
7629.36
7629.36
7629.69
7630.02
7630.02
7630.35
7630.68
7630.68
7631.01
7631.34
7631.34
7631.67
7632.00
7632.00
7632.33
7632.66
7632.66
7632.99
7633.32
7633.32
7633.65
7633.98
37.601
37.601
37.601
36.801
36.801
36.801
34.399
34.399
35.199
35.199
35.199
35.999
31.201
31.201
30.399
25.601
25.601
27.200
25.601
25.601
23.999
23.999
23.999
24.799
23.999
23.999
23.199
21.600
21.600
19.199
17.599
17.599
19.199
19.199
19.199
17.599
16.000
16.000
14.401
16.000
16.000
16.800
16.800
16.800
13.599
12.799
002092
2:32:21
2:32:23
2:32:25
2:32:27
2:32:29
2:32:31
2:32:33
2:32:35
2:32:37
2:32:39
2:32:41
2:32:43
2:32:45
2:32:47
2:32:49
2:32:51
2:32:53
2:32:55
2:32:57
2:32:59
2:33:01
2:33:03
2:33:05
2:33:07
2:33:09
2:33:11
2:33:13
2:33:15
2:33:17
2:33:19
2:33:21
2:33:23
2:33:25
2:33:27
2:33:29
2:33:31
2:33:33
2:33:35
2:33:37
2:33:39
2:33:41
2:33:43
2:33:45
2:33:47
2:33:49
2:33:51
59.9840
59.9880
59.9870
59.9870
59.9870
59.9930
59.9930
59.9920
59.9890
59.9890
59.9860
59.9830
59.9830
59.9880
59.9960
59.9960
59.9980
60.0010
60.0010
59.9990
59.9990
59.9990
60.0020
60.0070
60.0070
60.0080
60.0140
60.0140
60.0170
60.0210
60.0210
60.0170
60.0190
60.0190
60.0230
60.0250
60.0250
60.0210
60.0240
60.0240
60.0240
60.0200
60.0200
60.0250
60.0200
60.0200
3760.98
3762.74
3763.21
3763.21
3766.09
3766.43
3766.43
3767.79
3768.63
3768.63
3772.44
3773.69
3773.69
3775.84
3775.36
3775.36
3775.49
3776.42
3776.42
3779.69
3781.26
3781.26
3783.09
3783.90
3783.90
3785.77
3785.46
3785.46
3786.30
3787.26
3787.26
3787.96
3788.03
3788.03
3789.22
3787.54
3787.54
3786.08
3787.93
3787.93
3786.87
3786.55
3786.55
3785.02
3785.61
3785.61
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-261.91
-261.91
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-164.97
-164.97
-164.97
-164.97
-164.97
-164.97
-164.97
-164.97
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
203.00
203.50
204.00
204.00
204.50
205.00
205.00
205.50
206.00
206.00
206.50
207.00
207.00
207.50
208.00
208.00
208.50
209.00
209.00
209.50
210.00
210.00
210.50
211.00
211.00
211.50
212.00
212.00
212.50
213.00
213.00
213.50
214.00
214.00
214.50
215.00
215.00
215.50
216.00
216.00
216.50
217.00
217.00
217.50
218.00
218.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7633.98
7634.31
7634.64
7634.64
7634.97
7635.30
7635.30
7635.63
7635.96
7635.96
7636.29
7636.62
7636.62
7636.95
7637.28
7637.28
7637.61
7637.94
7637.94
7638.27
7638.60
7638.60
7638.93
7639.26
7639.26
7639.59
7639.92
7639.92
7640.25
7640.58
7640.58
7640.91
7641.24
7641.24
7641.57
7641.90
7641.90
7642.23
7642.56
7642.56
7642.89
7643.22
7643.22
7643.55
7643.88
7643.88
12.799
9.601
10.400
10.400
10.400
5.600
5.600
6.400
8.801
8.801
11.200
13.599
13.599
9.601
3.201
3.201
1.599
-0.800
-0.800
0.800
0.800
0.800
-1.599
-5.600
-5.600
-6.400
-11.200
-11.200
-13.599
-16.800
-16.800
-13.599
-15.201
-15.201
-18.399
-20.001
-20.001
-16.800
-19.199
-19.199
-19.199
-16.000
-16.000
-20.001
-16.000
-16.000
002093
2:33:53
2:33:55
2:33:57
2:33:59
2:34:01
2:34:03
2:34:05
2:34:07
2:34:09
2:34:11
2:34:13
2:34:15
2:34:17
2:34:19
2:34:21
2:34:23
2:34:25
2:34:27
2:34:29
2:34:31
2:34:33
2:34:35
2:34:37
2:34:39
2:34:41
2:34:43
2:34:45
2:34:47
2:34:49
2:34:51
2:34:53
2:34:55
2:34:57
2:34:59
2:35:01
2:35:03
2:35:05
2:35:07
2:35:09
2:35:11
2:35:13
2:35:15
2:35:17
2:35:19
2:35:21
2:35:23
60.0200
60.0220
60.0220
60.0220
60.0210
60.0210
60.0230
60.0220
60.0220
60.0190
60.0180
60.0180
60.0180
60.0190
60.0190
60.0190
60.0150
60.0150
60.0160
60.0130
60.0130
60.0120
60.0100
60.0100
60.0070
60.0090
60.0090
60.0090
60.0030
60.0030
59.9990
59.9920
59.9920
59.9910
59.9920
59.9920
59.9880
59.9850
59.9850
59.9840
59.9840
59.9840
59.9820
59.9820
59.9820
59.9790
3785.80
3786.86
3786.86
3785.25
3785.73
3785.73
3785.82
3785.80
3785.80
3786.94
3787.63
3787.63
3789.67
3789.40
3789.40
3789.18
3789.37
3789.37
3788.66
3788.93
3788.93
3790.81
3790.41
3790.41
3791.54
3792.95
3792.95
3791.44
3791.43
3791.43
3790.46
3790.22
3790.22
3788.46
3788.10
3788.10
3788.19
3788.50
3788.50
3788.57
3788.10
3788.10
3786.45
3787.73
3787.73
3789.29
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-160.45
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
218.50
219.00
219.00
219.50
220.00
220.00
220.50
221.00
221.00
221.50
222.00
222.00
222.50
223.00
223.00
223.50
224.00
224.00
224.50
225.00
225.00
225.50
226.00
226.00
226.50
227.00
227.00
227.50
228.00
228.00
228.50
229.00
229.00
229.50
230.00
230.00
230.50
231.00
231.00
231.50
232.00
232.00
232.50
233.00
233.00
233.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7644.21
7644.54
7644.54
7644.87
7645.20
7645.20
7645.53
7645.86
7645.86
7646.19
7646.52
7646.52
7646.85
7647.18
7647.18
7647.51
7647.84
7647.84
7648.17
7648.50
7648.50
7648.83
7649.16
7649.16
7649.49
7649.82
7649.82
7650.15
7650.48
7650.48
7650.81
7651.14
7651.14
7651.47
7651.80
7651.80
7652.13
7652.46
7652.46
7652.79
7616.00
7616.00
7626.00
7632.00
7632.00
7632.00
-16.000
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-17.599
-17.599
-15.201
-14.401
-14.401
-14.401
-15.201
-15.201
-15.201
-12.000
-12.000
-12.799
-10.400
-10.400
-9.601
-7.999
-7.999
-5.600
-7.199
-7.199
-7.199
-2.399
-2.399
0.800
6.400
6.400
7.199
6.400
6.400
9.601
12.000
12.000
12.799
12.799
12.799
14.401
14.401
14.401
16.800
002094
2:35:25
2:35:27
2:35:29
2:35:31
2:35:33
2:35:35
2:35:37
2:35:39
2:35:41
2:35:43
2:35:45
2:35:47
2:35:49
2:35:51
2:35:53
2:35:55
2:35:57
2:35:59
2:36:01
2:36:03
2:36:05
2:36:07
2:36:09
2:36:11
2:36:13
2:36:15
2:36:17
2:36:19
2:36:21
2:36:23
2:36:25
2:36:27
2:36:29
2:36:31
2:36:33
2:36:35
2:36:37
2:36:39
2:36:41
2:36:43
2:36:45
2:36:47
2:36:49
2:36:51
2:36:53
2:36:55
59.9760
59.9760
59.9760
59.9820
59.9820
59.9780
59.9740
59.9740
59.9760
59.9770
59.9770
59.9750
59.9690
59.9690
59.9700
59.9730
59.9730
59.9780
59.9780
59.9780
59.9750
59.9760
59.9760
59.9750
59.9690
59.9690
59.9660
59.9660
59.9660
59.9690
59.9680
59.9680
59.9650
59.9700
59.9700
59.9720
59.9670
59.9670
59.9690
59.9690
59.9690
59.9670
59.9660
59.9660
59.9650
59.9670
3788.26
3788.26
3790.47
3790.66
3790.66
3789.67
3789.27
3789.27
3790.43
3789.91
3789.91
3787.44
3788.96
3788.96
3791.88
3792.91
3792.91
3789.13
3788.08
3788.08
3787.14
3787.16
3787.16
3787.40
3786.49
3786.49
3789.21
3790.51
3790.51
3792.22
3790.96
3790.96
3789.03
3789.17
3789.17
3785.69
3784.83
3784.83
3784.32
3782.81
3782.81
3779.35
3779.06
3779.06
3779.21
3779.33
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-214.83
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
2.00
3.00
4.00
4.00
5.00
6.00
6.00
7.00
8.00
8.00
9.00
10.00
10.00
11.00
12.00
12.00
13.00
14.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
234.00
234.00
234.50
235.00
235.00
235.50
236.00
236.00
236.50
237.00
237.00
237.50
238.00
238.00
238.50
239.00
239.00
239.50
240.00
240.00
240.50
241.00
241.00
241.50
242.00
242.00
242.50
243.00
243.00
243.50
244.00
244.00
244.50
245.00
245.00
245.50
246.00
246.00
246.50
247.00
247.00
247.50
248.00
248.00
248.50
249.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7625.00
7623.00
7621.00
19.199
19.199
19.199
14.401
14.401
17.599
20.801
20.801
19.199
18.399
18.399
20.001
24.799
24.799
23.999
21.600
21.600
17.599
17.599
17.599
20.001
19.199
19.199
20.001
24.799
24.799
27.200
27.200
27.200
24.799
25.601
25.601
28.000
23.999
23.999
22.400
26.401
26.401
24.799
24.799
24.799
26.401
27.200
27.200
28.000
26.401
002095
2:36:57
2:36:59
2:37:01
2:37:03
2:37:05
2:37:07
2:37:09
2:37:11
2:37:13
2:37:15
2:37:17
2:37:19
2:37:21
2:37:23
2:37:25
2:37:27
2:37:29
2:37:31
2:37:33
2:37:35
2:37:37
2:37:39
2:37:41
2:37:43
2:37:45
2:37:47
2:37:49
2:37:51
2:37:53
2:37:55
2:37:57
2:37:59
2:38:01
2:38:03
2:38:05
2:38:07
2:38:09
2:38:11
2:38:13
2:38:15
2:38:17
2:38:19
2:38:21
2:38:23
2:38:25
2:38:27
59.9670
59.9650
59.9640
59.9640
59.9700
59.9690
59.9690
59.9680
59.9650
59.9650
59.9700
59.9680
59.9680
59.9650
59.9690
59.9690
59.9670
59.9660
59.9660
59.9790
59.9830
59.9830
59.9740
59.9650
59.9650
59.9620
59.9610
59.9610
59.9610
59.9630
59.9630
59.9590
59.9510
59.9510
59.9530
59.9570
59.9570
59.9560
59.9630
59.9630
59.9610
59.9630
59.9630
59.9630
59.9680
59.9680
3779.33
3775.65
3776.60
3776.60
3776.02
3773.17
3773.17
3768.79
3768.50
3768.50
3767.37
3764.79
3764.79
3759.59
3761.89
3761.89
3760.58
3760.16
3760.16
3759.49
3757.77
3757.77
3753.09
3751.64
3751.64
3758.22
3759.25
3759.25
3760.96
3762.02
3762.02
3763.10
3763.86
3763.86
3766.13
3768.34
3768.34
3767.44
3765.61
3765.61
3761.57
3761.92
3761.92
3758.52
3752.43
3752.43
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-229.47
-229.47
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
249.00
249.50
250.00
250.00
250.50
251.00
251.00
251.50
252.00
252.00
252.50
253.00
253.00
253.50
254.00
254.00
254.50
255.00
255.00
255.50
256.00
256.00
256.50
257.00
257.00
257.50
258.00
258.00
258.50
259.00
259.00
259.50
260.00
260.00
260.50
261.00
261.00
261.50
262.00
262.00
262.50
263.00
263.00
263.50
264.00
264.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7621.00
7623.00
7625.00
7625.00
7627.00
7628.00
7628.00
7628.00
7629.00
7629.00
7630.00
7631.00
7631.00
7635.00
7638.00
7638.00
7639.00
7642.00
7642.00
7644.00
7645.00
7645.00
7647.00
7648.00
7648.00
7649.00
7650.00
7650.00
7651.00
7652.00
7652.00
7653.00
7654.00
7654.00
7655.00
7655.00
7655.00
7656.00
7656.00
7656.00
7657.00
7657.00
7657.00
7658.00
7658.00
7658.00
26.401
28.000
28.799
28.799
23.999
24.799
24.799
25.601
28.000
28.000
23.999
25.601
25.601
28.000
24.799
24.799
26.401
27.200
27.200
16.800
13.599
13.599
20.801
28.000
28.000
30.399
31.201
31.201
31.201
29.599
29.599
32.800
39.200
39.200
37.601
34.399
34.399
35.199
29.599
29.599
31.201
29.599
29.599
29.599
25.601
25.601
002096
2:38:29
2:38:31
2:38:33
2:38:35
2:38:37
2:38:39
2:38:41
2:38:43
2:38:45
2:38:47
2:38:49
2:38:51
2:38:53
2:38:55
2:38:57
2:38:59
2:39:01
2:39:03
2:39:05
2:39:07
2:39:09
2:39:11
2:39:13
2:39:15
2:39:17
2:39:19
2:39:21
2:39:23
2:39:25
2:39:27
2:39:29
2:39:31
2:39:33
2:39:35
2:39:37
2:39:39
2:39:41
2:39:43
2:39:45
2:39:47
2:39:49
2:39:51
2:39:53
2:39:55
2:39:57
2:39:59
59.9680
59.9700
59.9700
59.9730
59.9650
59.9650
59.9670
59.9720
59.9720
59.9760
59.9690
59.9690
59.9730
59.9780
59.9780
59.9810
59.9810
59.9810
59.9820
59.9840
59.9840
59.9820
59.9790
59.9790
59.9800
59.9780
59.9780
59.9800
59.9800
59.9800
59.9780
59.9720
59.9720
59.9710
59.9740
59.9740
59.9750
59.9720
59.9720
59.9690
59.9740
59.9740
59.9720
59.9720
59.9720
59.9770
3753.83
3753.51
3753.51
3752.74
3753.18
3753.18
3753.29
3752.87
3752.87
3749.40
3747.48
3747.48
3741.29
3746.65
3746.65
3743.35
3741.62
3741.62
3738.48
3738.90
3738.90
3737.27
3736.31
3736.31
3735.45
3735.65
3735.65
3738.01
3736.75
3736.75
3736.07
3736.09
3736.09
3738.57
3738.87
3738.87
3738.65
3737.68
3737.68
3737.89
3740.02
3740.02
3742.05
3742.42
3742.42
3742.25
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.23
-229.23
-229.23
-229.23
-229.23
-229.23
-229.23
-231.41
-231.41
-231.41
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
264.50
265.00
265.00
265.50
266.00
266.00
266.50
267.00
267.00
267.50
268.00
268.00
268.50
269.00
269.00
269.50
270.00
270.00
270.50
271.00
271.00
271.50
272.00
272.00
272.50
273.00
273.00
273.50
274.00
274.00
274.50
275.00
275.00
275.50
276.00
276.00
276.50
277.00
277.00
277.50
278.00
278.00
278.50
279.00
279.00
279.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7659.00
7659.00
7659.00
7659.00
7660.00
7660.00
7660.00
7661.00
7661.00
7661.00
7662.00
7662.00
7662.00
7663.00
7663.00
7663.00
7664.00
7664.00
7664.00
7665.00
7665.00
7666.00
7666.00
7666.00
7667.00
7668.00
7668.00
7668.00
7669.00
7669.00
7669.00
7670.00
7670.00
7670.00
7671.00
7671.00
7671.00
7672.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
25.601
23.999
23.999
21.600
28.000
28.000
26.401
22.400
22.400
19.199
24.799
24.799
21.600
17.599
17.599
15.201
15.201
15.201
14.401
12.799
12.799
14.401
16.800
16.800
16.000
17.599
17.599
16.000
16.000
16.000
17.599
22.400
22.400
23.199
20.801
20.801
20.001
22.400
22.400
24.799
20.801
20.801
22.400
22.400
22.400
18.399
002097
2:40:01
2:40:03
2:40:05
2:40:07
2:40:09
2:40:11
2:40:13
2:40:15
2:40:17
2:40:19
2:40:21
2:40:23
2:40:25
2:40:27
2:40:29
2:40:31
2:40:33
2:40:35
2:40:37
2:40:39
2:40:41
2:40:43
2:40:45
2:40:47
2:40:49
2:40:51
2:40:53
2:40:55
2:40:57
2:40:59
2:41:01
2:41:03
2:41:05
2:41:07
2:41:09
2:41:11
2:41:13
2:41:15
2:41:17
2:41:19
2:41:21
2:41:23
2:41:25
2:41:27
2:41:29
2:41:31
59.9780
59.9780
59.9760
59.9740
59.9740
59.9770
59.9780
59.9780
59.9790
59.9770
59.9770
59.9740
59.9710
59.9710
59.9710
59.9680
59.9680
59.9660
59.9710
59.9710
59.9730
59.9690
59.9690
59.9720
59.9730
59.9730
59.9700
59.9740
59.9740
59.9820
59.9850
59.9850
59.9850
59.9890
59.9890
59.9890
59.9870
59.9870
59.9900
59.9960
59.9960
60.0010
60.0040
60.0040
60.0060
60.0140
3741.72
3741.72
3740.63
3739.96
3739.96
3742.83
3741.27
3741.27
3738.97
3738.71
3738.71
3739.86
3738.10
3738.10
3743.51
3743.42
3743.42
3745.74
3747.34
3747.34
3749.75
3746.22
3746.22
3743.75
3743.15
3743.15
3739.45
3733.38
3733.38
3737.58
3736.23
3736.23
3733.43
3733.12
3733.12
3729.18
3725.46
3725.46
3720.11
3720.94
3720.94
3725.68
3727.75
3727.75
3727.68
3727.23
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-231.41
-231.41
-231.41
-231.41
-231.41
-218.62
-218.62
-218.62
-218.62
-218.62
-218.62
-218.62
-213.54
-213.54
-213.54
-213.54
-213.54
-213.54
-213.54
-213.54
-225.65
-225.65
-225.65
-225.65
-225.65
-225.65
-225.65
-212.57
-212.57
-212.57
-212.57
-212.57
-212.57
-212.57
-212.57
-219.90
-219.90
-219.90
-219.90
-219.90
-219.90
-219.90
-231.18
-231.18
-231.18
-231.18
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
280.00
280.00
280.50
281.00
281.00
281.50
282.00
282.00
282.50
283.00
283.00
283.50
284.00
284.00
284.50
285.00
285.00
285.50
286.00
286.00
286.50
287.00
287.00
287.50
288.00
288.00
288.50
289.00
289.00
289.50
290.00
290.00
290.50
291.00
291.00
291.50
292.00
292.00
292.50
293.00
293.00
293.50
294.00
294.00
294.50
295.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7675.00
7676.00
7677.00
7677.00
7678.00
7679.00
7679.00
7680.00
7681.00
7681.00
7682.00
7684.00
7684.00
7685.00
7687.00
7687.00
7689.00
7690.00
7690.00
7692.00
7692.00
7692.00
7693.00
7693.00
7693.00
7694.00
7694.00
17.599
17.599
19.199
20.801
20.801
18.399
17.599
17.599
16.800
18.399
18.399
20.801
23.199
23.199
23.199
25.601
25.601
27.200
23.199
23.199
21.600
24.799
24.799
22.400
21.600
21.600
23.999
20.801
20.801
14.401
12.000
12.000
12.000
8.801
8.801
8.801
10.400
10.400
7.999
3.201
3.201
-0.800
-3.201
-3.201
-4.800
-11.200
002098
2:41:33
2:41:35
2:41:37
2:41:39
2:41:41
2:41:43
2:41:45
2:41:47
2:41:49
2:41:51
2:41:53
2:41:55
2:41:57
2:41:59
2:42:01
2:42:03
2:42:05
2:42:07
2:42:09
2:42:11
2:42:13
2:42:15
2:42:17
2:42:19
2:42:21
60.0140
60.0190
60.0250
60.0250
60.0260
60.0290
60.0290
60.0290
60.0360
60.0360
60.0370
60.0360
60.0360
60.0410
60.0440
60.0440
60.0430
60.0480
60.0480
60.0460
60.0430
60.0430
60.0430
60.0430
60.0430
3727.23
3726.45
3726.02
3726.02
3716.37
3717.33
3717.33
3717.14
3715.17
3715.17
3710.28
3710.16
3710.16
3698.59
3704.59
3704.59
3702.48
3701.32
3701.32
3699.53
3699.73
3699.73
3690.48
3696.86
3696.86
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-231.18
-231.18
-231.18
-231.18
-226.63
-226.63
-226.63
-226.63
-226.63
-226.63
-226.63
-227.26
-227.26
-227.26
-227.26
-227.26
-227.26
-227.26
-227.26
-229.29
-229.29
-229.29
-229.29
-229.29
-229.29
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
295.00
295.50
296.00
296.00
296.50
297.00
297.00
297.50
298.00
298.00
298.50
299.00
299.00
299.50
300.00
300.00
300.50
301.00
301.00
301.50
302.00
302.00
302.50
303.00
303.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7694.00
7695.00
7695.00
7695.00
7695.00
7696.00
7696.00
7696.00
7697.00
7697.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.00
7698.33
7698.66
7698.66
7698.99
7699.32
7699.32
7699.65
7699.98
7699.98
-11.200
-15.201
-20.001
-20.001
-20.801
-23.199
-23.199
-23.199
-28.799
-28.799
-29.599
-28.799
-28.799
-32.800
-35.199
-35.199
-34.399
-38.400
-38.400
-36.801
-34.399
-34.399
-34.399
-34.399
-34.399
002099
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
lue B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8823
-0.159
3647.05
3766.69
119.64
-53.75
-33.40
94.17
127.57
73.82
350.00
-165.43
0.00
151.81
-4.17
15.00
347.21
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-209.89
0.43
156.14
11.77
0.00
293.46
-53.75
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.0025
121.2453
164.2478
72.84%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-18.936
25.24%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
24 second Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
0.938 P.U.
1.359 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002100
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3766.689
3766.689
3766.689
3766.689
3766.689
3766.689
3766.689
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-209.885
-209.885
-209.885
-209.885
-209.885
-209.885
-209.885
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.429
0.429
0.429
0.429
0.429
0.429
0.429
151.813
151.813
151.813
151.813
151.813
151.813
151.813
151.813
156.143
156.143
156.143
156.143
156.143
156.143
156.143
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
94.171
94.171
94.171
94.171
94.171
94.171
94.171
3720.866
3720.866
3720.866
3720.866
3720.866
3720.866
3720.866
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.884
59.884
59.884
59.884
3778.540
3778.540
3778.540
3778.540
335.000
335.000
335.000
335.000
002101
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.884
59.884
59.884
3778.540
3778.540
3778.540
335.000
335.000
335.000
002102
002103
002104
002105
002106
002107
002108
002109
002110
002111
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8844
-0.157
3647.05
3778.54
131.49
-53.91
-33.40
92.46
125.86
71.95
350.00
-165.43
0.00
151.81
-4.17
15.00
347.21
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-211.26
0.86
157.14
11.56
0.00
293.30
-53.91
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -103.000 MW/0.1 Hz
Post-Perturbation Bias Setting -103.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -43.0025 MW
EPFR for Bias Setting Post-Perturbation Average 119.0383 MW
EPFR for Bias Setting Delta 162.0407 MW
Primary Frequency Response Delivery of Bias
81.15%
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8892
-0.153
3647.05
3783.77
136.73
-54.51
-33.40
88.65
122.05
67.54
350.00
-165.43
0.00
151.81
-4.17
15.00
347.21
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-212.66
1.09
158.18
11.08
0.00
292.69
-54.51
Pre-Perturbation BA Load 7600.196 MW
Post-Perturbation BA Load 7570.000 MW
Pre to Post Perturbation BA Load Change
-30.196 MW
Load Dampening Frequency Response
-19.194 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
22.96%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
1.045 P.U.
1.473 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.120
1.567
Pumped
Hydro
Load (-) Gen (+)
MW
002112
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-211.256
-211.256
-211.256
-211.256
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.857
0.857
0.857
0.857
151.813
151.813
151.813
151.813
151.813
151.813
151.813
151.813
157.143
157.143
157.143
157.143
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
92.457
92.457
92.457
92.457
3718.996
3718.996
3718.996
3718.996
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.889
59.889
59.889
3783.772
3783.772
3783.772
335.000
335.000
335.000
-212.661
-212.661
-212.661
1.091
1.091
1.091
002113
-211.256
-211.256
-211.256
0.857
0.857
0.857
157.143
157.143
157.143
10.000
10.000
10.000
0.000
0.000
0.000
-103.000 7570.000
-103.000 7570.000
-103.000 7570.000
92.457
92.457
92.457
3718.996 T+26 sec
3718.996 T+28 sec
3718.996 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3783.772
3783.772
3783.772
3783.772
3783.772
3783.772
3783.772
3783.772
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-212.661
-212.661
-212.661
-212.661
-212.661
-212.661
-212.661
-212.661
1.091
1.091
1.091
1.091
1.091
1.091
1.091
1.091
002114
002115
002116
002117
002118
002119
002120
002121
002122
002123
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.0025
114.1422
157.1446
87.01%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.792
22.09%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8879
-0.154
3647.05
3786.58
139.53
-52.66
-33.40
89.64
123.04
70.38
350.00
-165.43
0.00
151.81
-4.17
15.00
347.21
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-212.66
2.00
159.00
11.21
0.00
294.54
-52.66
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.134 P.U.
1.562 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002124
151.813
151.813
151.813
151.813
151.813
151.813
151.813
151.813
158.182
158.182
158.182
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
88.654
88.654
88.654
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
3714.586 T+20 sec
3714.586 T+22 sec
3714.586 T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
151.813
151.813
151.813
151.813
151.813
151.813
151.813
151.813
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.888
59.888
59.888
59.888
3786.576
3786.576
3786.576
3786.576
335.000
335.000
335.000
335.000
-212.662
-212.662
-212.662
-212.662
2.000
2.000
2.000
2.000
159.000
159.000
159.000
159.000
10.000
10.000
10.000
10.000
002125
158.182
158.182
158.182
158.182
158.182
158.182
158.182
158.182
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
88.654
88.654
88.654
88.654
88.654
88.654
88.654
88.654
3714.586
3714.586
3714.586
3714.586
3714.586
3714.586
3714.586
3714.586
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
3786.576
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
-212.662
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
2.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
159.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
002126
002127
002128
002129
002130
002131
002132
002133
002134
002135
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.0025
115.4171
158.4196
88.08%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.633
21.64%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:33:03
60.0417
59.8887
-0.153
3647.05
3787.78
140.73
-52.53
-33.40
89.04
122.44
69.91
350.00
-165.43
0.00
151.81
-4.17
15.00
347.21
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-212.74
2.12
159.18
11.13
0.00
294.68
-52.53
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.149 P.U.
1.578 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002136
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
89.644
89.644
89.644
89.644
3717.426
3717.426
3717.426
3717.426
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
3647.046
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
-165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
151.813
151.813
151.813
151.813
151.813
151.813
151.813
151.813
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.889
59.889
59.889
3787.775
3787.775
3787.775
335.000
335.000
335.000
-212.744
-212.744
-212.744
2.118
2.118
2.118
159.176
159.176
159.176
10.000
10.000
10.000
0.000
0.000
0.000
002137
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
89.644
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
3717.426
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
3787.775
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
-212.744
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
2.118
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
159.176
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002138
002139
002140
002141
002142
002143
002144
002145
002146
002147
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-103.000
-103.000
-43.0025
114.6328
157.6353
89.28%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.730
21.46%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002148
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-33.400
-103.000
-103.000
-103.000
7570.000
7570.000
7570.000
89.035
89.035
89.035
3716.952
3716.952
3716.952
002149
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
89.035
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
3716.952
002150
Monday, October 12, 2009
Balancing Authority
60.08
1.149
My BA
60.0417
Initial P.U. Performance
Initial P.U. Performance Adjusted
1.578
3850.0
20 to 52 second Average Period
60.06
60.04
3787.78
60.02
3800.0
60
59.98
59.96
3750.0
3716.952
59.92
MW
Frequency - Hz
59.94
59.9
3700.0
59.88
59.8887
59.86
59.84
3650.0
59.82
3647.05
59.8
59.78
3600.0
59.76
59.74
59.72
2:26:21
2:26:31
2:26:41
Hz
2:26:51
2:27:01
Average Frequency
2:27:11
2:27:21
MW
2:27:31
Average MW
2:27:41
2:27:51
2:28:01
EPFR for FRO Adjusted
2:28:11
3550.0
2:28:21
002151
Monday, October 12, 2009
0.908 Sustained P.U. Performance
My BA
60.08
3850.0
60.06
60.04
3800.0
60.02
60
59.98
3750.0
59.96
3700.0
59.92
MW
Frequency - Hz
59.94
59.9
59.88
3650.0
59.86
59.84
3600.0
59.82
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:21
2:27:21
2:28:21
2:29:21
Hz
2:30:21
2:31:21
2:32:21
Interchange MW
2:33:21
2:34:21
2:35:21
Recovery Period Target MW
2:36:21
2:37:21
2:38:21
2:39:21
Recovery Period Ramp MW
2:40:21
2:41:21
3500.0
2:42:21
002152
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:19
FPointA
Hz
60.0390
A Value
Hz
60.0417
t(0) Time
2:27:21
C Value
Hz
59.8360
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8822861 -397.43625 59.8844288 -402.63425 59.888706 -415.16368 59.8879445 -411.95878 59.888706 -413.86163
002153
Value A Data
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
60.04175
3647.05
350.00
-165.43
0.00
151.81
-4.17
15.00
-103 7600.196
Value B
Bias
Setting
EPFR
Frequency
MW
Hz
-43.0025 59.882286
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
Actual
Schedules
Load
Hydro
Units
Response
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+)
MW
MW
MW
MW
MW
MW
3766.69
335.00
-209.89
0.43
156.14
11.77
002154
Value B
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
1.359
Initial
Performance
Unadjusted
P.U.
0.938
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.908
-103
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
7570 121.2453 59.884429
3778.54
335.00
-211.26
0.86
157.14
11.56
0.00
BA
Load
Initial
Performance
Adjusted
P.U.
1.473
002155
Value B
Initial
Performance
Unadjusted
P.U.
1.045
Sustained
Performance
P.U.
0.908
BA
Bias
Setting
MW
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7570 119.0383 59.889182
20 to 40 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
3783.77
335.00
-212.66
1.09
158.18
11.08
0.00
Initial
Performance
Adjusted
P.U.
1.567
Initial
Performance
Unadjusted
P.U.
1.120
Sustained
Performance
P.U.
0.908
002156
Value B
BA
Bias
Setting
MW
-103
18 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW
MW
7570 114.1422 59.887945
3786.58
335.00
-212.66
2.00
159.00
11.21
0.00
Value B
Initial
Performance
Adjusted
P.U.
1.562
Initial
Performance
Unadjusted
P.U.
1.134
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.908
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7570 115.4171 59.888706
002157
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Ramping
Actual
Schedules
Load
Hydro
Units
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+)
MW
MW
MW
MW
MW
3787.78
335.00
-165.43
2.12
159.18
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.13
0.00
Initial
Performance
Adjusted
P.U.
1.578
Initial
Performance
Unadjusted
P.U.
1.149
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.908
-103
BA
Load
Bias
Setting
EPFR
MW
MW
7570 114.6328
002158
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
C
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Ramping units
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 4 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with up to 60 minutes of data. Be sure "Data" worksheet is clear of any old data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 237 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A237"
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency of the event on the center vertical grid line of the graph (Red Trend).
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 323.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A323"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if you're interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar.
When set appropriately, the "Target" trend on the "Sustained" graph will model what Interchange Actual should have done during the event recovery period based on your minimum FRO.
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
002159
Time (T)
10/12/09 02:12:00
10/12/09 02:12:04
10/12/09 02:12:08
10/12/09 02:12:12
10/12/09 02:12:16
10/12/09 02:12:20
10/12/09 02:12:24
10/12/09 02:12:28
10/12/09 02:12:32
10/12/09 02:12:36
10/12/09 02:12:40
10/12/09 02:12:44
10/12/09 02:12:48
10/12/09 02:12:52
10/12/09 02:12:56
10/12/09 02:13:00
10/12/09 02:13:04
10/12/09 02:13:08
10/12/09 02:13:12
10/12/09 02:13:16
10/12/09 02:13:20
10/12/09 02:13:24
10/12/09 02:13:28
10/12/09 02:13:32
10/12/09 02:13:36
10/12/09 02:13:40
10/12/09 02:13:44
10/12/09 02:13:48
10/12/09 02:13:52
10/12/09 02:13:56
10/12/09 02:14:00
10/12/09 02:14:04
10/12/09 02:14:08
10/12/09 02:14:12
10/12/09 02:14:16
Hz
Net
Actual
Interchange
MW
59.981
59.981
59.98
59.981
59.981
59.979
59.98
59.983
59.986
59.976
59.979
59.982
59.99
59.994
59.995
59.995
59.994
59.995
60.001
60.001
60.003
60.003
60.001
60.004
60.001
60.001
60.004
60.004
60.003
60.003
59.999
59.997
59.996
59.993
59.996
3669.878418
3671.699707
3671.698486
3672.310303
3672.174072
3674.263428
3673.84375
3672.106201
3669.167969
3673.560303
3673.834229
3671.634521
3671.560303
3670.771973
3668.128906
3669.29126
3671.253906
3670.155762
3670.712402
3671.183594
3670.26709
3671.092285
3670.669922
3669.53418
3671.628418
3671.968262
3671.871582
3671.065674
3673.235107
3673.530518
3673.186279
3673.576416
3671.820557
3671.998047
3671.07251
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonTransferred
Contingent
Conforming
Pumped
Ramping
Frequency
BA
BA
Load
Hydro
Units
Response
Lost Generation
Bias
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW
MW/0.1 Hz
MW
MW/0.1 Hz
351.361511
0
0
10
15
-103
351.361511
0
0.5
10
15
-103
351.361511
0
1
10
15
-103
357.94751
0
1.5
10
15
-103
357.94751
0
2
10
15
-103
357.94751
0
2.5
10
15
-103
357.94751
0
3
10
15
-103
357.94751
0
3.5
10
15
-103
0
4
10
15
-103
360.234741
360.234741
0
4.5
10
15
-103
360.234741
0
5
10
15
-103
360.234741
0
5.5
10
15
-103
360.234741
0
6
10
15
-103
346.525879
0
6.5
10
15
-103
346.525879
0
7
10
15
-103
346.525879
0
7.5
10
15
-103
346.525879
0
8
10
15
-103
346.525879
0
8.5
10
15
-103
296.443359
0
9
10
15
-103
296.443359
0
9.5
10
15
-103
10
15
-103
296.443359
0
10
296.443359
0
10.5
10
15
-103
296.443359
0
11
10
15
-103
341.061157
0
11.5
10
15
-103
341.061157
0
12
10
15
-103
341.061157
0
12.5
10
15
-103
341.061157
0
13
10
15
-103
341.061157
0
13.5
10
15
-103
322.826294
0
14
10
15
-103
322.826294
0
14.5
10
15
-103
322.826294
0
15
10
15
-103
322.826294
0
15.5
10
15
-103
-103
322.826294
0
16
10
15
321.544403
0
16.5
10
15
-103
321.544403
0
17
10
15
-103
BA
Load
MW
7500
7500.33
7500.66
7500.99
7501.32
7501.65
7501.98
7502.31
7502.64
7502.97
7503.3
7503.63
7503.96
7504.29
7504.62
7504.95
7505.28
7505.61
7505.94
7506.27
7506.6
7506.93
7507.26
7507.59
7507.92
7508.25
7508.58
7508.91
7509.24
7509.57
7509.9
7510.23
7510.56
7510.89
7511.22
002160
10/12/09 02:14:20
10/12/09 02:14:24
10/12/09 02:14:28
10/12/09 02:14:32
10/12/09 02:14:36
10/12/09 02:14:40
10/12/09 02:14:44
10/12/09 02:14:48
10/12/09 02:14:52
10/12/09 02:14:56
10/12/09 02:15:00
10/12/09 02:15:04
10/12/09 02:15:08
10/12/09 02:15:12
10/12/09 02:15:16
10/12/09 02:15:20
10/12/09 02:15:24
10/12/09 02:15:28
10/12/09 02:15:32
10/12/09 02:15:36
10/12/09 02:15:40
10/12/09 02:15:44
10/12/09 02:15:48
10/12/09 02:15:52
10/12/09 02:15:56
10/12/09 02:16:00
10/12/09 02:16:04
10/12/09 02:16:08
10/12/09 02:16:12
10/12/09 02:16:16
10/12/09 02:16:20
10/12/09 02:16:24
10/12/09 02:16:28
10/12/09 02:16:32
10/12/09 02:16:36
10/12/09 02:16:40
10/12/09 02:16:44
10/12/09 02:16:48
10/12/09 02:16:52
10/12/09 02:16:56
60.001
60.007
60.005
59.999
59.999
60.007
60.011
60.003
59.995
59.994
60.001
59.998
59.992
59.986
59.988
59.988
59.985
59.983
59.984
59.985
59.987
59.99
59.983
59.979
59.987
59.988
59.983
59.979
59.989
59.988
59.989
59.989
59.993
59.996
59.998
59.999
59.991
59.995
60.001
60.006
3671.441406
3670.161865
3670.619873
3672.085693
3670.825684
3671.809082
3672.73584
3674.414551
3674.754639
3675.310547
3675.165527
3674.319092
3676.328613
3677.791016
3675.542969
3676.931396
3677.067139
3678.455322
3679.731445
3677.626953
3676.409424
3677.371094
3678.086426
3680.163086
3678.344238
3677.677734
3679.279053
3679.605713
3679.025879
3678.488525
3678.740234
3679.390137
3678.330078
3677.944336
3678.950928
3679.148438
3680.041016
3677.860352
3678.266846
3677.898682
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
321.544403
321.544403
321.544403
362.136261
362.136261
362.136261
362.136261
362.136261
336.311798
336.311798
336.311798
336.311798
336.311798
316.443054
316.443054
316.443054
316.443054
316.443054
325.464294
325.464294
325.464294
325.464294
325.464294
336.614166
336.614166
336.614166
336.614166
336.614166
316.726166
316.726166
316.726166
316.726166
316.726166
320.195526
320.195526
320.195526
320.195526
320.195526
341.86615
341.86615
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
17.5
18
18.5
19
19.5
20
20.5
21
21.5
22
22.5
23
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
28.5
29
29.5
30
30.5
31
31.5
32
32.5
33
33.5
34
34.5
35
35.5
36
36.5
37
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7511.55
7511.88
7512.21
7512.54
7512.87
7513.2
7513.53
7513.86
7514.19
7514.52
7514.85
7515.18
7515.51
7515.84
7516.17
7516.5
7516.83
7517.16
7517.49
7517.82
7518.15
7518.48
7518.81
7519.14
7519.47
7519.8
7520.13
7520.46
7520.79
7521.12
7521.45
7521.78
7522.11
7522.44
7522.77
7523.1
7523.43
7523.76
7524.09
7524.42
002161
10/12/09 02:17:00
10/12/09 02:17:04
10/12/09 02:17:08
10/12/09 02:17:12
10/12/09 02:17:16
10/12/09 02:17:20
10/12/09 02:17:24
10/12/09 02:17:28
10/12/09 02:17:32
10/12/09 02:17:36
10/12/09 02:17:40
10/12/09 02:17:44
10/12/09 02:17:48
10/12/09 02:17:52
10/12/09 02:17:56
10/12/09 02:18:00
10/12/09 02:18:04
10/12/09 02:18:08
10/12/09 02:18:12
10/12/09 02:18:16
10/12/09 02:18:20
10/12/09 02:18:24
10/12/09 02:18:28
10/12/09 02:18:32
10/12/09 02:18:36
10/12/09 02:18:40
10/12/09 02:18:44
10/12/09 02:18:48
10/12/09 02:18:52
10/12/09 02:18:56
10/12/09 02:19:00
10/12/09 02:19:04
10/12/09 02:19:08
10/12/09 02:19:12
10/12/09 02:19:16
10/12/09 02:19:20
10/12/09 02:19:24
10/12/09 02:19:28
10/12/09 02:19:32
10/12/09 02:19:36
60.009
60.012
60.01
60.007
60.012
60.01
60.007
60.009
60.006
60.009
60.009
60.005
60.001
59.993
59.994
59.994
59.994
59.993
59.99
59.983
59.977
59.995
59.994
59.987
59.984
59.985
59.985
59.98
59.981
59.998
60.007
59.986
59.977
59.976
59.974
59.979
59.982
59.987
59.988
59.987
3679.20874
3678.652588
3679.702637
3679.805908
3680.262695
3679.560791
3679.439941
3679.516602
3679.608154
3679.260742
3679.024658
3678.572266
3678.248779
3677.82959
3677.772217
3677.093262
3676.400635
3679.87207
3678.743164
3677.921143
3682.070068
3678.655518
3677.780029
3678.473145
3677.822266
3677.397461
3677.949707
3678.962646
3680.737305
3678.161377
3676.222168
3677.49707
3675.185791
3680.450928
3683.828613
3681.108398
3678.229004
3675.759277
3671.165527
3670.128662
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
341.86615
341.86615
341.86615
348.597839
348.597839
348.597839
348.597839
348.597839
329.085022
329.085022
329.085022
329.085022
329.085022
342.418243
342.418243
342.418243
342.418243
342.418243
338.794647
338.794647
338.794647
338.794647
338.794647
335.931
335.931
335.931
335.931
335.931
339.712402
339.712402
339.712402
339.712402
339.712402
332.024658
332.024658
332.024658
332.024658
332.024658
330.759033
330.759033
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
37.5
38
38.5
39
39.5
40
40.5
41
41.5
42
42.5
43
43.5
44
44.5
45
45.5
46
46.5
47
47.5
48
48.5
49
49.5
50
50.5
51
51.5
52
52.5
53
53.5
54
54.5
55
55.5
56
56.5
57
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7524.75
7525.08
7525.41
7525.74
7526.07
7526.4
7526.73
7527.06
7527.39
7527.72
7528.05
7528.38
7528.71
7529.04
7529.37
7529.7
7530.03
7530.36
7530.69
7531.02
7531.35
7531.68
7532.01
7532.34
7532.67
7533
7533.33
7533.66
7533.99
7534.32
7534.65
7534.98
7535.31
7535.64
7535.97
7536.3
7536.63
7536.96
7537.29
7537.62
002162
10/12/09 02:19:40
10/12/09 02:19:44
10/12/09 02:19:48
10/12/09 02:19:52
10/12/09 02:19:56
10/12/09 02:20:00
10/12/09 02:20:04
10/12/09 02:20:08
10/12/09 02:20:12
10/12/09 02:20:16
10/12/09 02:20:20
10/12/09 02:20:24
10/12/09 02:20:28
10/12/09 02:20:32
10/12/09 02:20:36
10/12/09 02:20:40
10/12/09 02:20:44
10/12/09 02:20:48
10/12/09 02:20:52
10/12/09 02:20:56
10/12/09 02:21:00
10/12/09 02:21:04
10/12/09 02:21:08
10/12/09 02:21:12
10/12/09 02:21:16
10/12/09 02:21:20
10/12/09 02:21:24
10/12/09 02:21:28
10/12/09 02:21:32
10/12/09 02:21:36
10/12/09 02:21:40
10/12/09 02:21:44
10/12/09 02:21:48
10/12/09 02:21:52
10/12/09 02:21:56
10/12/09 02:22:00
10/12/09 02:22:04
10/12/09 02:22:08
10/12/09 02:22:12
10/12/09 02:22:16
59.985
59.982
59.989
59.988
59.982
59.981
59.983
59.989
59.985
59.98
59.98
59.979
59.981
59.98
59.98
59.977
59.981
59.976
59.972
59.973
59.973
59.971
59.977
59.975
59.98
59.981
59.982
59.982
59.982
59.985
59.989
59.996
59.998
60.007
60.013
60.013
60.008
60.019
60.023
60.02
3672.047852
3672.103516
3671.882324
3671.335938
3670.37207
3671.400879
3672.181396
3668.070801
3669.908203
3670.262695
3670.102051
3671.402588
3672.371826
3670.9375
3670.137207
3672.390869
3674.051758
3671.800293
3673.873535
3676.623291
3676.542969
3675.752441
3674.869629
3671.593262
3669.962891
3669.496826
3667.676514
3666.599365
3666.44165
3667.456299
3665.261719
3663.824951
3662.054932
3662.076172
3662.959473
3664.13916
3664.158691
3663.183594
3661.512207
3658.661377
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
330.759033
330.759033
330.759033
323.419952
323.419952
323.419952
323.419952
323.419952
342.350922
342.350922
342.350922
342.350922
342.350922
345.081818
345.081818
345.081818
345.081818
345.081818
346.537384
346.537384
346.537384
346.537384
346.537384
342.905762
342.905762
342.905762
342.905762
342.905762
340.094391
340.094391
340.094391
340.094391
340.094391
342.771179
342.771179
342.771179
342.771179
342.771179
342.909912
342.909912
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
63
63.5
64
64.5
65
65.5
66
66.5
67
67.5
68
68.5
69
69.5
70
70.5
71
71.5
72
72.5
73
73.5
74
74.5
75
75.5
76
76.5
77
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7537.95
7538.28
7538.61
7538.94
7539.27
7539.6
7539.93
7540.26
7540.59
7540.92
7541.25
7541.58
7541.91
7542.24
7542.57
7542.9
7543.23
7543.56
7543.89
7544.22
7544.55
7544.88
7545.21
7545.54
7545.87
7546.2
7546.53
7546.86
7547.19
7547.52
7547.85
7548.18
7548.51
7548.84
7549.17
7549.5
7549.83
7550.16
7550.49
7550.82
002163
10/12/09 02:22:20
10/12/09 02:22:24
10/12/09 02:22:28
10/12/09 02:22:32
10/12/09 02:22:36
10/12/09 02:22:40
10/12/09 02:22:44
10/12/09 02:22:48
10/12/09 02:22:52
10/12/09 02:22:56
10/12/09 02:23:00
10/12/09 02:23:04
10/12/09 02:23:08
10/12/09 02:23:12
10/12/09 02:23:16
10/12/09 02:23:20
10/12/09 02:23:24
10/12/09 02:23:28
10/12/09 02:23:32
10/12/09 02:23:36
10/12/09 02:23:40
10/12/09 02:23:44
10/12/09 02:23:48
10/12/09 02:23:52
10/12/09 02:23:56
10/12/09 02:24:00
10/12/09 02:24:04
10/12/09 02:24:08
10/12/09 02:24:12
10/12/09 02:24:16
10/12/09 02:24:20
10/12/09 02:24:24
10/12/09 02:24:28
10/12/09 02:24:32
10/12/09 02:24:36
10/12/09 02:24:40
10/12/09 02:24:44
10/12/09 02:24:48
10/12/09 02:24:52
10/12/09 02:24:56
60.021
60.019
60.022
60.025
60.02
60.018
60.02
60.019
60.022
60.025
60.02
60.02
60.021
60.018
60.014
60.013
60.01
60.011
60.012
60.009
60.009
60.005
59.999
59.995
59.998
59.998
59.995
59.992
59.988
59.982
59.982
59.984
59.978
59.976
59.974
59.979
59.981
59.984
59.988
59.99
3657.571045
3657.710449
3660.227539
3658.698242
3658.154541
3659.777588
3662.531494
3662.078857
3662.678223
3663.538574
3662.55249
3663.600586
3663.689941
3663.395752
3664.31543
3665.797607
3666.72583
3667.54541
3666.44873
3667.696045
3667.042969
3666.222656
3665.40332
3665.679688
3664.94751
3666.133301
3666.734619
3667.557373
3667.853271
3668.690918
3669.606201
3670.25
3671.548828
3674.262939
3676.418213
3674.637451
3675.226074
3674.399414
3673.039551
3673.056396
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
342.909912
342.909912
342.909912
343.286011
343.286011
343.286011
343.286011
343.286011
331.852966
331.852966
331.852966
331.852966
331.852966
329.98822
329.98822
329.98822
329.98822
329.98822
255.444168
255.444168
255.444168
255.444168
255.444168
254.838303
254.838303
254.838303
254.838303
254.838303
257.146973
257.146973
257.146973
257.146973
257.146973
262.289368
262.289368
262.289368
262.289368
262.289368
256.647949
256.647949
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
77.5
78
78.5
79
79.5
80
80.5
81
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7551.15
7551.48
7551.81
7552.14
7552.47
7552.8
7553.13
7553.46
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
002164
10/12/09 02:25:00
10/12/09 02:25:04
10/12/09 02:25:08
10/12/09 02:25:12
10/12/09 02:25:16
10/12/09 02:25:20
10/12/09 02:25:24
10/12/09 02:25:28
10/12/09 02:25:32
10/12/09 02:25:36
10/12/09 02:25:40
10/12/09 02:25:44
10/12/09 02:25:48
10/12/09 02:25:52
10/12/09 02:25:56
10/12/09 02:26:00
10/12/09 02:26:04
10/12/09 02:26:08
10/12/09 02:26:12
10/12/09 02:26:16
10/12/09 02:26:20
10/12/09 02:26:24
10/12/09 02:26:28
10/12/09 02:26:32
10/12/09 02:26:36
10/12/09 02:26:40
10/12/09 02:26:44
10/12/09 02:26:48
10/12/09 02:26:52
10/12/09 02:26:56
10/12/09 02:27:00
10/12/09 02:27:04
10/12/09 02:27:08
10/12/09 02:27:12
10/12/09 02:27:16
10/12/09 02:27:20
10/12/09 02:27:24
10/12/09 02:27:28
10/12/09 02:27:32
10/12/09 02:27:36
59.991
59.991
59.993
60.002
60.003
60.005
60.002
60.008
60.01
60.011
60.014
60.012
60.011
60.022
60.014
60.014
60.017
60.019
60.027
60.026
60.019
60.019
60.019
60.021
60.019
60.022
60.037
60.036
60.046
60.048
60.041
60.041
60.041
60.045
60.041
60.041
59.978
59.836
59.892
59.88
3671.493164
3670.066162
3671.744141
3672.625488
3673.818604
3673.182129
3672.417969
3672.216797
3673.182129
3673.553467
3674.537109
3673.203613
3673.067627
3672.519531
3671.288086
3672.981689
3671.95166
3671.627197
3668.610596
3664.495117
3666.820801
3670.453613
3671.667969
3672.685059
3672.164063
3669.98291
3663.758057
3660.672363
3649.19043
3648.246338
3654.294434
3651.874268
3649.187012
3645.386963
3645.445801
3641.191162
3696.362305
3734.672607
3761.249512
3766.193848
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
256.647949
256.647949
256.647949
256.307251
256.307251
256.307251
256.307251
256.307251
249.086395
249.086395
249.086395
249.086395
249.086395
253.742477
253.742477
253.742477
253.742477
253.742477
257.421204
257.421204
257.421204
257.421204
257.421204
261.73822
261.73822
165.101685
165.476395
165.476395
165.476395
165.476395
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
97.5
98
98.5
99
99.5
100
100.5
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
002165
10/12/09 02:27:40
10/12/09 02:27:44
10/12/09 02:27:48
10/12/09 02:27:52
10/12/09 02:27:56
10/12/09 02:28:00
10/12/09 02:28:04
10/12/09 02:28:08
10/12/09 02:28:12
10/12/09 02:28:16
10/12/09 02:28:20
10/12/09 02:28:24
10/12/09 02:28:28
10/12/09 02:28:32
10/12/09 02:28:36
10/12/09 02:28:40
10/12/09 02:28:44
10/12/09 02:28:48
10/12/09 02:28:52
10/12/09 02:28:56
10/12/09 02:29:00
10/12/09 02:29:04
10/12/09 02:29:08
10/12/09 02:29:12
10/12/09 02:29:16
10/12/09 02:29:20
10/12/09 02:29:24
10/12/09 02:29:28
10/12/09 02:29:32
10/12/09 02:29:36
10/12/09 02:29:40
10/12/09 02:29:44
10/12/09 02:29:48
10/12/09 02:29:52
10/12/09 02:29:56
10/12/09 02:30:00
10/12/09 02:30:04
10/12/09 02:30:08
10/12/09 02:30:12
10/12/09 02:30:16
59.875
59.887
59.885
59.888
59.895
59.893
59.894
59.89
59.885
59.887
59.888
59.889
59.873
59.849
59.858
59.866
59.867
59.871
59.879
59.883
59.89
59.889
59.899
59.902
59.904
59.911
59.916
59.918
59.921
59.917
59.921
59.926
59.928
59.932
59.928
59.929
59.933
59.937
59.949
59.942
3769.925049
3781.591797
3784.961914
3784.418945
3788.327637
3788.471924
3793.074463
3799.427734
3799.959229
3802.925049
3804.387939
3805.616699
3811.50293
3815.888916
3826.053223
3827.523926
3826.783447
3825.713379
3822.505371
3818.055176
3815.009766
3811.838379
3806.972168
3804.188477
3793.975098
3791.501953
3788.13208
3783.02832
3776.358398
3774.604248
3773.957764
3771.67041
3768.707031
3767.020996
3766.788086
3765.671631
3764.242676
3762.935303
3753.922363
3746.888672
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
0
0
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
002166
10/12/09 02:30:20
10/12/09 02:30:24
10/12/09 02:30:28
10/12/09 02:30:32
10/12/09 02:30:36
10/12/09 02:30:40
10/12/09 02:30:44
10/12/09 02:30:48
10/12/09 02:30:52
10/12/09 02:30:56
10/12/09 02:31:00
10/12/09 02:31:04
10/12/09 02:31:08
10/12/09 02:31:12
10/12/09 02:31:16
10/12/09 02:31:20
10/12/09 02:31:24
10/12/09 02:31:28
10/12/09 02:31:32
10/12/09 02:31:36
10/12/09 02:31:40
10/12/09 02:31:44
10/12/09 02:31:48
10/12/09 02:31:52
10/12/09 02:31:56
10/12/09 02:32:00
10/12/09 02:32:04
10/12/09 02:32:08
10/12/09 02:32:12
10/12/09 02:32:16
10/12/09 02:32:20
10/12/09 02:32:24
10/12/09 02:32:28
10/12/09 02:32:32
10/12/09 02:32:36
10/12/09 02:32:40
10/12/09 02:32:44
10/12/09 02:32:48
10/12/09 02:32:52
10/12/09 02:32:56
59.942
59.948
59.949
59.952
59.951
59.952
59.955
59.954
59.953
59.952
59.954
59.957
59.954
59.955
59.961
59.962
59.966
59.968
59.974
59.969
59.97
59.973
59.976
59.978
59.978
59.978
59.98
59.981
59.979
59.979
59.983
59.988
59.987
59.991
59.992
59.989
59.983
59.988
59.996
59.999
3749.593262
3746.706055
3742.741455
3736.13916
3727.838379
3722.648926
3717.996094
3715.752686
3713.483643
3710.810059
3714.622559
3716.168213
3716.97998
3722.361328
3722.657959
3722.277588
3723.09082
3723.43457
3725.402832
3728.052979
3732.530029
3736.535156
3736.821777
3739.943848
3741.793701
3746.60791
3750.716309
3752.747559
3756.407227
3760.405273
3761.406982
3763.212158
3766.085205
3767.250977
3768.633545
3772.44458
3774.668457
3775.363281
3775.491699
3778.553711
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
229.466965
229.466965
229.466965
229.466965
228.980164
228.980164
228.980164
228.980164
228.980164
219.975555
219.975555
219.975555
219.975555
219.975555
229.089249
229.089249
229.089249
229.089249
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
002167
10/12/09 02:33:00
10/12/09 02:33:04
10/12/09 02:33:08
10/12/09 02:33:12
10/12/09 02:33:16
10/12/09 02:33:20
10/12/09 02:33:24
10/12/09 02:33:28
10/12/09 02:33:32
10/12/09 02:33:36
10/12/09 02:33:40
10/12/09 02:33:44
10/12/09 02:33:48
10/12/09 02:33:52
10/12/09 02:33:56
10/12/09 02:34:00
10/12/09 02:34:04
10/12/09 02:34:08
10/12/09 02:34:12
10/12/09 02:34:16
10/12/09 02:34:20
10/12/09 02:34:24
10/12/09 02:34:28
10/12/09 02:34:32
10/12/09 02:34:36
10/12/09 02:34:40
10/12/09 02:34:44
10/12/09 02:34:48
10/12/09 02:34:52
10/12/09 02:34:56
10/12/09 02:35:00
10/12/09 02:35:04
10/12/09 02:35:08
10/12/09 02:35:12
10/12/09 02:35:16
10/12/09 02:35:20
10/12/09 02:35:24
10/12/09 02:35:28
10/12/09 02:35:32
10/12/09 02:35:36
59.999
59.999
60.005
60.008
60.014
60.019
60.017
60.019
60.024
60.021
60.024
60.021
60.025
60.02
60.022
60.022
60.021
60.023
60.019
60.018
60.018
60.019
60.015
60.014
60.012
60.01
60.007
60.009
60.003
59.995
59.991
59.992
59.986
59.984
59.984
59.981
59.979
59.976
59.979
59.978
3781.255859
3783.092041
3784.420898
3785.462646
3786.304199
3787.515869
3788.030273
3789.21582
3785.841797
3787.93042
3786.874756
3787.357666
3785.614014
3785.803711
3786.877197
3785.726074
3785.821045
3786.28418
3787.627441
3789.67334
3788.47876
3789.368896
3788.664551
3790.666992
3790.411133
3791.539795
3791.0271
3791.426025
3790.457275
3789.584961
3788.10498
3788.189453
3788.540039
3788.101074
3786.452881
3788.813477
3788.256348
3790.467285
3790.42041
3789.26709
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
229.089249
229.663269
229.663269
229.663269
229.663269
229.663269
229.233856
229.233856
229.233856
229.233856
262.1026
262.1026
262.1026
262.71701
262.71701
262.71701
262.71701
262.71701
260.016479
260.016479
260.016479
260.016479
260.016479
263.87323
263.87323
263.87323
263.87323
263.87323
264.5979
264.5979
264.5979
264.5979
264.5979
262.415924
262.415924
262.415924
262.415924
262.415924
259.685242
259.685242
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
7615.83
7616.16
7616.49
7616.82
002168
10/12/09 02:35:40
10/12/09 02:35:44
10/12/09 02:35:48
10/12/09 02:35:52
10/12/09 02:35:56
10/12/09 02:36:00
10/12/09 02:36:04
10/12/09 02:36:08
10/12/09 02:36:12
10/12/09 02:36:16
10/12/09 02:36:20
10/12/09 02:36:24
10/12/09 02:36:28
10/12/09 02:36:32
10/12/09 02:36:36
10/12/09 02:36:40
10/12/09 02:36:44
10/12/09 02:36:48
10/12/09 02:36:52
10/12/09 02:36:56
10/12/09 02:37:00
10/12/09 02:37:04
10/12/09 02:37:08
10/12/09 02:37:12
10/12/09 02:37:16
10/12/09 02:37:20
10/12/09 02:37:24
10/12/09 02:37:28
10/12/09 02:37:32
10/12/09 02:37:36
10/12/09 02:37:40
10/12/09 02:37:44
10/12/09 02:37:48
10/12/09 02:37:52
10/12/09 02:37:56
10/12/09 02:38:00
10/12/09 02:38:04
10/12/09 02:38:08
10/12/09 02:38:12
10/12/09 02:38:16
59.974
59.977
59.975
59.969
59.971
59.978
59.978
59.972
59.975
59.969
59.965
59.969
59.968
59.964
59.972
59.967
59.968
59.967
59.966
59.971
59.965
59.964
59.967
59.968
59.965
59.973
59.965
59.969
59.964
59.979
59.983
59.967
59.962
59.961
59.96
59.959
59.951
59.954
59.956
59.963
3790.43042
3786.243164
3788.962891
3791.876953
3792.311279
3788.07959
3787.13501
3786.996094
3786.486816
3789.213867
3791.221191
3790.959473
3789.026367
3787.394043
3784.830566
3784.320313
3782.109863
3779.056152
3779.21167
3776.429199
3776.59668
3776.022949
3771.730469
3768.50293
3767.366211
3760.29541
3761.893799
3760.58252
3759.781006
3757.772949
3753.087402
3753.750977
3759.249756
3760.964844
3763.822266
3763.858154
3766.126709
3767.972168
3765.606445
3761.570313
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
259.685242
259.685242
259.685242
255.911011
255.911011
255.911011
255.911011
255.911011
258.148193
258.148193
258.148193
258.148193
258.148193
258.873596
258.873596
258.873596
258.873596
258.873596
249.33757
249.33757
249.33757
249.33757
249.33757
258.278168
258.278168
258.278168
258.278168
258.278168
258.406372
258.406372
258.406372
258.406372
258.406372
260.538879
260.538879
260.538879
260.538879
260.538879
257.88208
257.88208
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
002169
10/12/09 02:38:20
10/12/09 02:38:24
10/12/09 02:38:28
10/12/09 02:38:32
10/12/09 02:38:36
10/12/09 02:38:40
10/12/09 02:38:44
10/12/09 02:38:48
10/12/09 02:38:52
10/12/09 02:38:56
10/12/09 02:39:00
10/12/09 02:39:04
10/12/09 02:39:08
10/12/09 02:39:12
10/12/09 02:39:16
10/12/09 02:39:20
10/12/09 02:39:24
10/12/09 02:39:28
10/12/09 02:39:32
10/12/09 02:39:36
10/12/09 02:39:40
10/12/09 02:39:44
10/12/09 02:39:48
10/12/09 02:39:52
10/12/09 02:39:56
10/12/09 02:40:00
10/12/09 02:40:04
10/12/09 02:40:08
10/12/09 02:40:12
10/12/09 02:40:16
10/12/09 02:40:20
10/12/09 02:40:24
10/12/09 02:40:28
10/12/09 02:40:32
10/12/09 02:40:36
10/12/09 02:40:40
10/12/09 02:40:44
10/12/09 02:40:48
10/12/09 02:40:52
10/12/09 02:40:56
59.959
59.963
59.968
59.968
59.973
59.965
59.967
59.976
59.969
59.974
59.981
59.981
59.982
59.982
59.979
59.978
59.98
59.98
59.976
59.971
59.974
59.976
59.969
59.974
59.972
59.977
59.978
59.973
59.977
59.978
59.981
59.974
59.971
59.972
59.966
59.971
59.972
59.972
59.973
59.971
3759.626953
3752.428711
3753.82959
3753.522949
3753.178223
3753.290527
3752.358643
3747.47583
3741.285156
3745.738281
3741.618164
3738.484375
3737.403564
3736.30835
3735.448242
3737.540527
3736.747559
3736.067383
3736.574951
3738.874756
3738.646973
3737.38208
3740.016846
3742.052734
3742.524414
3741.723145
3740.62915
3740.775146
3741.267822
3738.96582
3738.878662
3738.101563
3743.506836
3745.250732
3747.3396
3749.75
3744.682617
3743.148926
3739.452637
3731.82959
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
257.88208
257.88208
257.88208
258.588654
258.588654
258.588654
258.588654
258.588654
261.906158
261.906158
261.906158
261.906158
261.906158
256.747803
256.747803
256.747803
256.747803
256.747803
167.431976
167.431976
167.431976
167.431976
167.431976
164.973404
164.973404
164.973404
164.973404
164.973404
157.628082
157.628082
157.628082
157.628082
157.628082
155.531708
155.531708
155.531708
155.531708
155.531708
160.447235
160.447235
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
197.5
198
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
002170
10/12/09 02:41:00
10/12/09 02:41:04
10/12/09 02:41:08
10/12/09 02:41:12
10/12/09 02:41:16
10/12/09 02:41:20
10/12/09 02:41:24
10/12/09 02:41:28
10/12/09 02:41:32
10/12/09 02:41:36
10/12/09 02:41:40
10/12/09 02:41:44
10/12/09 02:41:48
10/12/09 02:41:52
10/12/09 02:41:56
10/12/09 02:42:00
10/12/09 02:42:04
10/12/09 02:42:08
10/12/09 02:42:12
10/12/09 02:42:16
10/12/09 02:42:20
10/12/09 02:42:24
10/12/09 02:42:28
10/12/09 02:42:32
10/12/09 02:42:36
10/12/09 02:42:40
10/12/09 02:42:44
10/12/09 02:42:48
10/12/09 02:42:52
10/12/09 02:42:56
10/12/09 02:43:00
10/12/09 02:43:04
10/12/09 02:43:08
10/12/09 02:43:12
10/12/09 02:43:16
10/12/09 02:43:20
10/12/09 02:43:24
10/12/09 02:43:28
10/12/09 02:43:32
10/12/09 02:43:36
59.982
59.985
59.987
59.989
59.987
59.994
60.001
60.004
60.012
60.019
60.025
60.027
60.029
60.036
60.037
60.041
60.044
60.046
60.046
60.043
60.044
60.043
60.04
60.039
60.036
60.033
60.037
60.035
60.033
60.033
60.032
60.034
60.037
60.035
60.039
60.039
60.034
60.037
60.037
60.04
3736.229492
3733.433838
3730.509766
3725.45874
3720.10791
3725.661377
3727.75415
3727.68335
3725.012207
3726.015625
3716.374512
3717.559814
3715.166016
3710.283447
3699.355713
3704.591309
3702.482422
3700.825928
3699.726074
3690.477295
3696.877197
3696.54126
3698.686035
3698.786865
3700.105713
3701.121826
3701.61377
3702.912598
3705.522461
3704.087402
3703.706299
3705.435303
3702.587891
3701.941895
3703.317871
3702.524902
3703.843506
3702.517578
3692.427002
3700.275879
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
160.447235
160.447235
160.447235
163.958603
163.958603
163.958603
163.958603
163.958603
166.072449
166.072449
166.072449
166.072449
166.072449
163.766586
163.766586
163.766586
163.766586
163.766586
165.101685
165.101685
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7643.55
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
002171
10/12/09 02:43:40
10/12/09 02:43:44
10/12/09 02:43:48
10/12/09 02:43:52
10/12/09 02:43:56
10/12/09 02:44:00
10/12/09 02:44:04
10/12/09 02:44:08
10/12/09 02:44:12
10/12/09 02:44:16
10/12/09 02:44:20
10/12/09 02:44:24
10/12/09 02:44:28
10/12/09 02:44:32
10/12/09 02:44:36
10/12/09 02:44:40
10/12/09 02:44:44
10/12/09 02:44:48
10/12/09 02:44:52
10/12/09 02:44:56
10/12/09 02:45:00
10/12/09 02:45:04
10/12/09 02:45:08
10/12/09 02:45:12
10/12/09 02:45:16
10/12/09 02:45:20
10/12/09 02:45:24
10/12/09 02:45:28
10/12/09 02:45:32
10/12/09 02:45:36
10/12/09 02:45:40
10/12/09 02:45:44
10/12/09 02:45:48
10/12/09 02:45:52
10/12/09 02:45:56
10/12/09 02:46:00
10/12/09 02:46:04
10/12/09 02:46:08
10/12/09 02:46:12
10/12/09 02:46:16
60.045
60.042
60.04
60.046
60.034
60.039
60.037
60.033
60.031
60.027
60.032
60.031
60.039
60.038
60.035
60.04
60.035
60.04
60.045
60.042
60.044
60.041
60.04
60.044
60.039
60.042
60.038
60.037
60.038
60.039
60.038
60.04
60.037
60.039
60.036
60.033
60.03
60.032
60.042
60.036
3697.728516
3697.368408
3698.429199
3693.58374
3696.79834
3701.791016
3700.753418
3705.212646
3707.286621
3707.340332
3707.383789
3707.615234
3703.746094
3700.847412
3702.212158
3700.397461
3700.366455
3700.661621
3695.688232
3693.824219
3696.896973
3697.502441
3699.426758
3699.806396
3697.680664
3698.358887
3699.077148
3701.591797
3700.142822
3701.139404
3700.264404
3699.721191
3699.505127
3699.216064
3700.661377
3702.967529
3704.95166
3705.621338
3701.981201
3700.74707
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
002172
10/12/09 02:46:20
10/12/09 02:46:24
10/12/09 02:46:28
10/12/09 02:46:32
10/12/09 02:46:36
10/12/09 02:46:40
10/12/09 02:46:44
10/12/09 02:46:48
10/12/09 02:46:52
10/12/09 02:46:56
10/12/09 02:47:00
10/12/09 02:47:04
10/12/09 02:47:08
10/12/09 02:47:12
10/12/09 02:47:16
10/12/09 02:47:20
10/12/09 02:47:24
10/12/09 02:47:28
10/12/09 02:47:32
10/12/09 02:47:36
10/12/09 02:47:40
10/12/09 02:47:44
10/12/09 02:47:48
10/12/09 02:47:52
10/12/09 02:47:56
10/12/09 02:48:00
10/12/09 02:48:04
10/12/09 02:48:08
10/12/09 02:48:12
10/12/09 02:48:16
10/12/09 02:48:20
10/12/09 02:48:24
10/12/09 02:48:28
10/12/09 02:48:32
10/12/09 02:48:36
10/12/09 02:48:40
10/12/09 02:48:44
10/12/09 02:48:48
10/12/09 02:48:52
10/12/09 02:48:56
60.032
60.034
60.032
60.043
60.042
60.04
60.043
60.041
60.038
60.044
60.036
60.041
60.043
60.036
60.039
60.034
60.035
60.036
60.03
60.031
60.032
60.032
60.032
60.037
60.039
60.036
60.041
60.035
60.038
60.041
60.036
60.034
60.04
60.037
60.036
60.038
60.038
60.033
60.034
60.029
3705.059326
3704.44873
3703.619629
3701.431641
3696.249512
3693.518066
3695.197021
3693.786133
3694.92627
3694.159424
3692.686279
3693.390137
3690.951416
3692.042236
3694.117188
3695.580811
3695.491211
3696.486328
3699.170898
3699.251221
3699.105225
3698.954346
3698.277344
3695.94043
3693.223633
3691.918945
3691.581543
3693.301758
3694.331299
3693.617188
3694.27002
3693.747559
3691.445313
3691.798828
3693.727051
3692.640625
3689.019531
3690.091797
3693.320801
3695.224854
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
229.466965
229.466965
229.466965
229.466965
228.980164
228.980164
228.980164
228.980164
228.980164
219.975555
219.975555
219.975555
219.975555
219.975555
229.089249
229.089249
229.089249
229.089249
229.089249
229.663269
229.663269
229.663269
229.663269
229.663269
229.233856
229.233856
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
273.5
274
274.5
275
275.5
276
276.5
277
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
7671
7672
002173
10/12/09 02:49:00
10/12/09 02:49:04
10/12/09 02:49:08
10/12/09 02:49:12
10/12/09 02:49:16
10/12/09 02:49:20
10/12/09 02:49:24
10/12/09 02:49:28
10/12/09 02:49:32
10/12/09 02:49:36
10/12/09 02:49:40
10/12/09 02:49:44
10/12/09 02:49:48
10/12/09 02:49:52
10/12/09 02:49:56
10/12/09 02:50:00
10/12/09 02:50:04
10/12/09 02:50:08
10/12/09 02:50:12
10/12/09 02:50:16
10/12/09 02:50:20
10/12/09 02:50:24
10/12/09 02:50:28
10/12/09 02:50:32
10/12/09 02:50:36
10/12/09 02:50:40
10/12/09 02:50:44
10/12/09 02:50:48
10/12/09 02:50:52
10/12/09 02:50:56
10/12/09 02:51:00
10/12/09 02:51:04
10/12/09 02:51:08
10/12/09 02:51:12
10/12/09 02:51:16
10/12/09 02:51:20
10/12/09 02:51:24
10/12/09 02:51:28
10/12/09 02:51:32
10/12/09 02:51:36
60.03
60.026
60.021
60.023
60.021
60.025
60.026
60.024
60.025
60.023
60.026
60.026
60.021
60.025
60.023
60.024
60.023
60.025
60.02
60.015
60.017
60.015
60.017
60.01
60.002
59.999
60.003
60.001
59.993
59.989
59.985
59.986
59.981
59.977
59.976
59.974
59.975
59.971
59.976
59.98
3693.411621
3696.025879
3699.061523
3698.935059
3700.544189
3698.595703
3699.913818
3701.30127
3701.348633
3701.70166
3701.964844
3700.241211
3701.268066
3700.587402
3700.176758
3700.277344
3700.862793
3700.05249
3700.964844
3703.516113
3703.672363
3703.003418
3702.999512
3703.918213
3703.775391
3701.533691
3700.880371
3701.388916
3700.671387
3700.977051
3699.85376
3700.342285
3700.789307
3703.165771
3704.784668
3706.958008
3706.542969
3707.026611
3710.53125
3708.018066
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
229.233856
229.233856
229.233856
231.409882
231.409882
231.409882
231.409882
231.409882
218.622284
218.622284
218.622284
218.622284
218.622284
213.535858
213.535858
213.535858
213.535858
213.535858
225.651855
225.651855
225.651855
225.651855
225.651855
212.573639
212.573639
212.573639
212.573639
212.573639
219.897293
219.897293
219.897293
219.897293
219.897293
231.1754
231.1754
231.1754
231.1754
231.1754
226.634125
226.634125
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
002174
10/12/09 02:51:40
10/12/09 02:51:44
10/12/09 02:51:48
10/12/09 02:51:52
10/12/09 02:51:56
10/12/09 02:52:00
10/12/09 02:52:04
10/12/09 02:52:08
10/12/09 02:52:12
10/12/09 02:52:16
10/12/09 02:52:20
10/12/09 02:52:24
10/12/09 02:52:28
10/12/09 02:52:32
10/12/09 02:52:36
10/12/09 02:52:40
10/12/09 02:52:44
10/12/09 02:52:48
10/12/09 02:52:52
10/12/09 02:52:56
10/12/09 02:53:00
10/12/09 02:53:04
10/12/09 02:53:08
10/12/09 02:53:12
10/12/09 02:53:16
10/12/09 02:53:20
10/12/09 02:53:24
10/12/09 02:53:28
10/12/09 02:53:32
10/12/09 02:53:36
10/12/09 02:53:40
10/12/09 02:53:44
10/12/09 02:53:48
10/12/09 02:53:52
10/12/09 02:53:56
10/12/09 02:54:00
10/12/09 02:54:04
10/12/09 02:54:08
10/12/09 02:54:12
10/12/09 02:54:16
59.982
59.983
59.979
59.976
59.977
59.978
59.971
59.97
59.99
59.999
59.998
60.003
60.005
60.013
60.022
60.025
60.024
60.029
60.029
60.028
60.032
60.031
60.022
60.019
60.017
60.016
60.015
60.009
60.008
60.005
59.999
59.999
59.998
59.994
59.993
59.985
59.988
59.985
59.983
59.986
3706.342529
3706.310547
3706.19043
3709.408936
3708.530518
3707.23999
3709.961182
3711.980469
3707.866699
3705.63916
3703.190918
3699.51001
3698.136719
3698.668213
3697.868408
3693.912109
3688.30127
3689.143066
3687.87793
3686.683105
3685.576172
3686.417969
3687.873047
3690.425781
3692.715332
3692.46167
3693.248779
3695.124268
3694.740723
3693.749512
3692.806152
3691.406738
3690.587646
3688.482666
3689.553467
3689.735596
3688.240234
3687.475342
3685.659668
3684.333496
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
226.634125
226.634125
226.634125
227.255066
227.255066
227.255066
227.255066
227.255066
229.290222
229.290222
229.290222
229.290222
229.290222
221.461365
221.461365
221.461365
221.461365
221.461365
241.274368
241.274368
241.274368
241.274368
241.274368
243.071854
243.071854
243.071854
243.071854
243.071854
241.670212
241.670212
241.670212
241.670212
241.670212
228.149307
228.149307
228.149307
228.149307
228.149307
235.128983
235.128983
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
002175
10/12/09 02:54:20
10/12/09 02:54:24
10/12/09 02:54:28
10/12/09 02:54:32
10/12/09 02:54:36
10/12/09 02:54:40
10/12/09 02:54:44
10/12/09 02:54:48
10/12/09 02:54:52
10/12/09 02:54:56
10/12/09 02:55:00
10/12/09 02:55:04
10/12/09 02:55:08
10/12/09 02:55:12
10/12/09 02:55:16
10/12/09 02:55:20
10/12/09 02:55:24
10/12/09 02:55:28
10/12/09 02:55:32
10/12/09 02:55:36
10/12/09 02:55:40
10/12/09 02:55:44
10/12/09 02:55:48
10/12/09 02:55:52
10/12/09 02:55:56
10/12/09 02:56:00
10/12/09 02:56:04
10/12/09 02:56:08
10/12/09 02:56:12
10/12/09 02:56:16
10/12/09 02:56:20
10/12/09 02:56:24
10/12/09 02:56:28
10/12/09 02:56:32
10/12/09 02:56:36
10/12/09 02:56:40
10/12/09 02:56:44
10/12/09 02:56:48
10/12/09 02:56:52
10/12/09 02:56:56
59.99
59.985
59.983
59.982
59.978
59.975
59.975
59.976
59.982
59.979
59.977
59.978
59.979
59.981
59.978
59.978
59.983
59.99
59.993
59.988
59.99
59.994
59.994
59.993
59.984
59.985
59.987
59.987
59.982
59.982
59.992
60
60.003
60.002
60.002
60.004
60.006
60.012
60.021
60.021
3683.734863
3683.811035
3684.257813
3685.091797
3685.086914
3685.196045
3688.416992
3687.847656
3685.782227
3685.142578
3684.093262
3682.814209
3682.365723
3682.855469
3684.051758
3686.048828
3685.286377
3682.416016
3679.012451
3671.76123
3670.159424
3680.17627
3682.700439
3685.030273
3684.165039
3685.58374
3684.58667
3683.674316
3684.244629
3685.589111
3682.578857
3682.137695
3681.688965
3681.650391
3680.166992
3679.429199
3678.981201
3676.796143
3674.797607
3671.14502
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
235.128983
235.128983
235.128983
246.433136
246.433136
246.433136
246.433136
246.433136
236.553543
236.553543
236.553543
236.553543
236.553543
230.297562
230.297562
230.297562
230.297562
230.297562
231.175537
231.175537
231.175537
231.175537
231.175537
225.61763
225.61763
225.61763
225.61763
225.61763
230.734421
230.734421
230.734421
230.734421
230.734421
234.847107
234.847107
234.847107
234.847107
234.847107
228.960922
228.960922
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
002176
10/12/09 02:57:00
10/12/09 02:57:04
10/12/09 02:57:08
10/12/09 02:57:12
10/12/09 02:57:16
10/12/09 02:57:20
10/12/09 02:57:24
10/12/09 02:57:28
10/12/09 02:57:32
10/12/09 02:57:36
10/12/09 02:57:40
10/12/09 02:57:44
10/12/09 02:57:48
10/12/09 02:57:52
10/12/09 02:57:56
10/12/09 02:58:00
10/12/09 02:58:04
10/12/09 02:58:08
10/12/09 02:58:12
10/12/09 02:58:16
10/12/09 02:58:20
10/12/09 02:58:24
10/12/09 02:58:28
10/12/09 02:58:32
10/12/09 02:58:36
10/12/09 02:58:40
10/12/09 02:58:44
10/12/09 02:58:48
10/12/09 02:58:52
10/12/09 02:58:56
10/12/09 02:59:00
10/12/09 02:59:04
10/12/09 02:59:08
10/12/09 02:59:12
10/12/09 02:59:16
10/12/09 02:59:20
10/12/09 02:59:24
10/12/09 02:59:28
10/12/09 02:59:32
10/12/09 02:59:36
60.018
60.02
60.018
60.019
60.018
60.016
60.016
60.014
60.013
60.015
60.016
60.021
60.02
60.024
60.025
60.022
60.022
60.027
60.028
60.032
60.03
60.021
60.024
60.024
60.023
60.02
60.02
60.017
60.012
60.011
60.01
60.012
60.013
60.013
60.011
60.008
60.011
60.016
60.019
60.019
3673.647949
3675.864746
3676.403809
3677.184814
3678.828369
3678.914551
3678.598633
3678.250488
3677.250977
3674.669434
3674.401855
3672.96875
3671.981934
3670.821045
3671.538574
3674.009521
3675.28418
3675.703613
3671.342773
3668.653809
3666.312256
3657.164063
3668.637451
3670.112305
3671.332031
3672.683105
3674.644775
3675.970703
3678.313721
3680.020264
3679.59668
3680.110352
3679.127197
3679.636719
3678.417725
3679.680908
3679.138184
3678.498535
3677.615234
3677.431396
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
228.960922
228.960922
228.960922
231.177917
231.177917
231.177917
231.177917
231.177917
236.489288
236.489288
236.489288
236.489288
236.489288
245.038925
245.038925
245.038925
245.038925
245.038925
223.605682
223.605682
223.605682
223.605682
223.605682
231.119354
231.119354
231.119354
231.119354
231.119354
237.20665
237.20665
237.20665
237.20665
237.20665
240.516373
240.516373
240.516373
240.516373
240.516373
237.566055
237.566055
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
354.5
355
355.5
356
356.5
357
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
002177
10/12/09 02:59:40
10/12/09 02:59:44
10/12/09 02:59:48
10/12/09 02:59:52
10/12/09 02:59:56
10/12/09 03:00:00
10/12/09 03:00:04
10/12/09 03:00:08
10/12/09 03:00:12
10/12/09 03:00:16
10/12/09 03:00:20
10/12/09 03:00:24
10/12/09 03:00:28
10/12/09 03:00:32
10/12/09 03:00:36
10/12/09 03:00:40
10/12/09 03:00:44
10/12/09 03:00:48
10/12/09 03:00:52
10/12/09 03:00:56
10/12/09 03:01:00
10/12/09 03:01:04
10/12/09 03:01:08
10/12/09 03:01:12
10/12/09 03:01:16
10/12/09 03:01:20
10/12/09 03:01:24
10/12/09 03:01:28
10/12/09 03:01:32
10/12/09 03:01:36
10/12/09 03:01:40
10/12/09 03:01:44
10/12/09 03:01:48
10/12/09 03:01:52
10/12/09 03:01:56
10/12/09 03:02:00
10/12/09 03:02:04
10/12/09 03:02:08
10/12/09 03:02:12
10/12/09 03:02:16
60.02
60.018
60.016
60.023
60.018
60.016
60.015
60.004
59.995
59.982
59.97
59.968
59.968
59.967
59.964
59.966
59.963
59.968
59.97
59.973
59.976
59.975
59.976
59.974
59.974
59.976
59.979
59.983
59.983
59.979
59.987
59.984
59.982
59.985
59.989
59.996
59.997
59.997
59.996
59.996
3677.31543
3678.362061
3680.770752
3680.353027
3679.553223
3682.729736
3681.914551
3682.483398
3685.306396
3684.642578
3689.403809
3692.966309
3694.397217
3697.406982
3698.616943
3699.850098
3701.988525
3704.023438
3702.988281
3704.899414
3704.293457
3701.943848
3704.668945
3705.662354
3706.776367
3706.928223
3706.334961
3705.943115
3704.777344
3705.967529
3704.683105
3704.360596
3705.049805
3703.740723
3701.795166
3701.308105
3700.912842
3699.926514
3700.548584
3700.223877
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
237.566055
237.566055
237.566055
231.581421
231.581421
231.581421
231.581421
231.581421
235.850845
235.850845
235.850845
235.850845
235.850845
233.559982
233.559982
233.559982
233.559982
233.559982
219.009995
219.009995
219.009995
219.009995
219.009995
205.338913
205.338913
205.338913
205.338913
205.338913
236.285355
236.285355
236.285355
236.285355
236.285355
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
371.5
372
372.5
373
373.5
374
374.5
375
375.5
376
376.5
377
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
002178
10/12/09 03:02:20
10/12/09 03:02:24
10/12/09 03:02:28
10/12/09 03:02:32
10/12/09 03:02:36
10/12/09 03:02:40
10/12/09 03:02:44
10/12/09 03:02:48
10/12/09 03:02:52
10/12/09 03:02:56
10/12/09 03:03:00
10/12/09 03:03:04
10/12/09 03:03:08
10/12/09 03:03:12
10/12/09 03:03:16
10/12/09 03:03:20
10/12/09 03:03:24
10/12/09 03:03:28
10/12/09 03:03:32
10/12/09 03:03:36
10/12/09 03:03:40
10/12/09 03:03:44
10/12/09 03:03:48
10/12/09 03:03:52
10/12/09 03:03:56
10/12/09 03:04:00
10/12/09 03:04:04
10/12/09 03:04:08
10/12/09 03:04:12
10/12/09 03:04:16
10/12/09 03:04:20
10/12/09 03:04:24
10/12/09 03:04:28
10/12/09 03:04:32
10/12/09 03:04:36
10/12/09 03:04:40
10/12/09 03:04:44
10/12/09 03:04:48
10/12/09 03:04:52
10/12/09 03:04:56
60.003
60.01
60.005
60.006
60.001
60.004
60.007
60.008
60.006
60.005
59.999
60
60.008
60.015
60.012
60.005
60.011
60.013
60.018
60.019
60.013
60.009
60.008
60.011
60.02
60.018
60.019
60.021
60.025
60.03
60.023
60.023
60.02
60.024
60.022
60.025
60.024
60.018
60.008
60.017
3698.031738
3699.408691
3700.738281
3701.237793
3700.220215
3702.554199
3701.026367
3702.943115
3703.960449
3704.455078
3705.329102
3704.404785
3702.748047
3703.016602
3703.297363
3705.279053
3704.05127
3704.255127
3703.830322
3704.13916
3705.429443
3705.539795
3705.748535
3706.945313
3705.654541
3704.223877
3704.648438
3704.166504
3702.008301
3701.062988
3699.369385
3702.95874
3703.621094
3703.035889
3704.947266
3703.54126
3703.397461
3705.441162
3710.072021
3707.76709
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
396
396.5
397
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
7761.69
7762.02
002179
10/12/09 03:05:00
10/12/09 03:05:04
10/12/09 03:05:08
10/12/09 03:05:12
10/12/09 03:05:16
10/12/09 03:05:20
10/12/09 03:05:24
10/12/09 03:05:28
10/12/09 03:05:32
10/12/09 03:05:36
10/12/09 03:05:40
10/12/09 03:05:44
10/12/09 03:05:48
10/12/09 03:05:52
10/12/09 03:05:56
10/12/09 03:06:00
10/12/09 03:06:04
10/12/09 03:06:08
10/12/09 03:06:12
10/12/09 03:06:16
10/12/09 03:06:20
10/12/09 03:06:24
10/12/09 03:06:28
10/12/09 03:06:32
10/12/09 03:06:36
10/12/09 03:06:40
10/12/09 03:06:44
10/12/09 03:06:48
10/12/09 03:06:52
10/12/09 03:06:56
10/12/09 03:07:00
10/12/09 03:07:04
10/12/09 03:07:08
10/12/09 03:07:12
10/12/09 03:07:16
10/12/09 03:07:20
10/12/09 03:07:24
10/12/09 03:07:28
10/12/09 03:07:32
10/12/09 03:07:36
60.019
60.016
60.016
60.016
60.019
60.014
60.018
60.023
60.026
60.024
60.02
60.022
60.028
60.031
60.026
60.029
60.033
60.022
60.019
60.028
60.015
60.012
60.014
60.014
60.016
60.013
59.997
59.993
59.993
59.993
59.993
59.988
59.983
59.98
59.981
59.978
59.98
59.98
59.984
59.981
3708.831055
3709.813477
3709.990479
3709.641602
3709.933105
3710.591064
3707.696045
3707.120117
3705.848145
3704.405762
3706.567383
3704.868652
3704.773438
3702.685547
3703.169189
3701.519531
3698.22168
3700.279785
3703.814697
3699.956055
3703.802246
3708.527344
3707.647461
3707.494873
3705.397949
3709.144043
3708.291016
3707.303711
3706.760254
3706.683105
3704.933594
3706.480957
3706.696289
3708.24585
3710.419434
3708.707764
3709.191895
3709.399414
3709.003906
3709.688965
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
413
413.5
414
414.5
415
415.5
416
416.5
417
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
002180
10/12/09 03:07:40
10/12/09 03:07:44
10/12/09 03:07:48
10/12/09 03:07:52
10/12/09 03:07:56
10/12/09 03:08:00
10/12/09 03:08:04
10/12/09 03:08:08
10/12/09 03:08:12
10/12/09 03:08:16
10/12/09 03:08:20
10/12/09 03:08:24
10/12/09 03:08:28
10/12/09 03:08:32
10/12/09 03:08:36
10/12/09 03:08:40
10/12/09 03:08:44
10/12/09 03:08:48
10/12/09 03:08:52
10/12/09 03:08:56
10/12/09 03:09:00
10/12/09 03:09:04
10/12/09 03:09:08
10/12/09 03:09:12
10/12/09 03:09:16
10/12/09 03:09:20
10/12/09 03:09:24
10/12/09 03:09:28
10/12/09 03:09:32
10/12/09 03:09:36
10/12/09 03:09:40
10/12/09 03:09:44
10/12/09 03:09:48
10/12/09 03:09:52
10/12/09 03:09:56
10/12/09 03:10:00
10/12/09 03:10:04
10/12/09 03:10:08
10/12/09 03:10:12
10/12/09 03:10:16
59.981
59.981
59.978
59.979
59.976
59.975
59.975
59.978
59.976
59.977
59.976
59.98
59.978
59.982
59.987
59.984
59.979
59.979
59.975
59.982
59.983
59.99
59.984
59.979
59.983
59.981
59.975
59.989
59.994
59.986
59.983
59.98
59.995
59.99
59.991
60
60.004
60.002
59.998
59.996
3706.541016
3711.362061
3712.012207
3712.092773
3714.612061
3715.322754
3714.717285
3715.001221
3714.062744
3715.631104
3715.567383
3714.848145
3713.358398
3712.619385
3710.050293
3710.471924
3710.946289
3710.474609
3710.802979
3710.572998
3708.371094
3706.511963
3708.962402
3712.303467
3711.627197
3712.392578
3713.510254
3715.442871
3713.906006
3714.953125
3716.30835
3714.763672
3715.067627
3715.79126
3715.324463
3711.708496
3712.850586
3716.641357
3719.079102
3717.815186
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
417.5
418
418.5
419
419.5
420
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
002181
10/12/09 03:10:20
10/12/09 03:10:24
10/12/09 03:10:28
10/12/09 03:10:32
10/12/09 03:10:36
10/12/09 03:10:40
10/12/09 03:10:44
10/12/09 03:10:48
10/12/09 03:10:52
10/12/09 03:10:56
10/12/09 03:11:00
10/12/09 03:11:04
10/12/09 03:11:08
10/12/09 03:11:12
10/12/09 03:11:16
10/12/09 03:11:20
10/12/09 03:11:24
10/12/09 03:11:28
10/12/09 03:11:32
10/12/09 03:11:36
10/12/09 03:11:40
10/12/09 03:11:44
10/12/09 03:11:48
10/12/09 03:11:52
10/12/09 03:11:56
10/12/09 03:12:00
60.002
60.003
60.004
60.004
60.003
60.006
60.009
60.009
60.015
60.009
60.008
60.01
60.013
60.014
60.012
60.011
60.003
60
59.998
60.002
60.003
59.998
59.995
59.987
59.988
59.992
3718.560303
3719.02124
3719.897461
3719.642822
3719.730957
3718.57959
3718.982178
3720.608887
3721.23877
3719.447266
3721.272217
3721.244629
3722.17627
3721.645996
3720.859619
3723.815674
3724.656006
3724.660645
3723.580078
3721.878906
3722.906494
3723.650391
3723.638916
3724.654297
3724.943848
3723.692627
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
437.5
438
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7788.75
7789.08
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
002182
Balancing Authority Name: My BA
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-80
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Step 4.
Enter MW output of generator or load that caused event (+ for gen loss, - for load loss)
(Value from NERC Event List. If multiple units, enter total MW loss.)
If MW loss value is not known, enter a default 1000 MW.
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 5. worksheet.
2:27:24
2:33:08
633 MW
Event Frequency Data
60.1
60.05
60
Copy Form 2 Data for
Pasting into Form 1
59.95
59.9
59.85
59.8
59.75
59.7
Step 6. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Hz
Step 7. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
002183
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8888
-0.153
3645.30
3788.85
143.54
-17.26
-33.60
88.99
122.59
Balancing Authority My BA
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
105.32 MW
Yes
Initial Response P.U. Performance
1.363 P.U.
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
60.027
60.027
60.026
Interchange
MW
3668.611
3668.611
3664.495
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
3765.22
3779.78
3727.48
3641.19
107.36
0:05:44
No
138.59
124.03
No
Yes
Yes
31.23
16.68
Up
60.000 Hz
2400.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-80 MW/0.1 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.895 P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-21.600
-21.600
-20.801
(TC)
Delayed
Delivery
Frequency
Response
-7.560
-12.474
-15.389
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
633
002184
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
60.026
60.019
60.019
60.019
60.019
60.019
60.019
60.021
60.021
60.019
60.019
60.022
60.022
60.037
60.037
60.036
60.036
60.046
60.046
60.048
60.048
60.041
60.041
60.041
60.041
60.041
60.041
60.045
60.045
60.041
60.041
60.041
60.041
59.978
59.978
59.978
59.836
59.836
59.892
59.892
59.88
59.88
59.875
59.875
59.887
59.887
3664.495
3666.821
3666.821
3670.454
3670.454
3671.668
3671.668
3672.685
3672.685
3672.164
3672.164
3669.983
3669.983
3663.758
3663.758
3660.672
3660.672
3649.190
3649.190
3648.246
3648.246
3654.294
3654.294
3651.874
3651.874
3649.187
3649.187
3645.387
3645.387
3645.446
3645.446
3641.191
3641.191
3696.362
3696.362
3696.362
3734.673
3734.673
3761.250
3761.250
3766.194
3766.194
3769.925
3769.925
3781.592
3781.592
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
59.889 3788.847
59.889 3788.847
59.889 3788.847
-20.801
-15.201
-15.201
-15.201
-15.201
-15.201
-15.201
-16.800
-16.800
-15.201
-15.201
-17.599
-17.599
-29.599
-29.599
-28.799
-28.799
-36.801
-36.801
-38.400
-38.400
-32.800
-32.800
-32.800
-32.800
-32.800
-32.800
-35.999
-35.999
-32.800
-32.800
-32.800
-32.800
17.599
17.599
17.599
131.201
131.201
86.401
86.401
95.999
95.999
100.000
100.000
90.399
90.399
-17.283
-16.554
-16.080
-15.773
-15.572
-15.442
-15.358
-15.863
-16.191
-15.844
-15.619
-16.312
-16.763
-21.255
-24.176
-25.794
-26.846
-30.330
-32.595
-34.627
-35.948
-34.846
-34.130
-33.665
-33.362
-33.165
-33.038
-34.074
-34.748
-34.066
-33.623
-33.335
-33.148
-15.386
-3.841
3.663
48.301
77.316
80.496
82.563
87.266
90.322
93.710
95.911
93.982
92.728
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
-0.410
3750.626
3750.626
3750.626
0.000
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
3670.454
3670.244
3669.964
3669.639
3668.724
3667.986
3667.923
3667.738
3666.635
3665.774
3660.872
3657.542
3655.513
3654.052
3650.157
3647.483
3645.041
3643.310
3644.002
3644.308
3644.364
3644.256
3644.043
3643.761
3642.315
3641.231
3641.503
3641.536
3641.414
3641.191
3658.953
3671.122
3679.250
3724.513
3754.152
3757.956
3760.647
3765.974
3769.655
3773.666
3776.492
3775.187
3774.557
3696.362
3696.362
3705.940
3711.686
3719.947
3725.847
3730.891
3734.813
3738.324
3741.197
3744.563
3747.412
3665.037
3669.775
3683.459
3697.598
3707.658
3715.228
3721.571
3726.914
3731.589
3735.671
3738.964
3741.702
3674.116
3674.740
3675.365
3675.989
3676.613
3677.237
3677.861
3678.486
3679.110
3679.734
3680.358
3680.982
3674.116
3674.428
3674.740
3675.053
3675.365
3675.677
3675.989
3676.301
3676.613
3676.925
3677.237
3677.549
633
633
633
633
633
633
633
633
633
633
633
633
633
002185
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
59.885
59.885
59.888
59.888
59.895
59.895
59.893
59.893
59.894
59.894
59.89
59.89
59.885
59.885
59.887
59.887
59.888
59.888
59.889
59.889
59.873
59.873
59.849
59.849
59.858
59.858
59.866
59.866
59.867
59.867
59.871
59.871
59.879
59.879
59.883
59.883
59.89
59.89
59.889
59.889
59.899
59.899
59.902
59.902
59.904
3784.962
3784.962
3784.419
3784.419
3788.328
3788.328
3788.472
3788.472
3793.074
3793.074
3799.428
3799.428
3799.959
3799.959
3802.925
3802.925
3804.388
3804.388
3805.617
3805.617
3811.503
3811.503
3815.889
3815.889
3826.053
3826.053
3827.524
3827.524
3826.783
3826.783
3825.713
3825.713
3822.505
3822.505
3818.055
3818.055
3815.010
3815.010
3811.838
3811.838
3806.972
3806.972
3804.188
3804.188
3793.975
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
92.001
92.001
89.600
89.600
84.000
84.000
85.599
85.599
84.799
84.799
88.000
88.000
92.001
92.001
90.399
90.399
89.600
89.600
88.800
88.800
101.599
101.599
120.801
120.801
113.599
113.599
107.199
107.199
106.400
106.400
103.201
103.201
96.799
96.799
93.600
93.600
88.000
88.000
88.800
88.800
80.801
80.801
78.400
78.400
76.801
92.474
92.308
91.360
90.744
88.384
86.849
86.412
86.127
85.662
85.360
86.284
86.885
88.676
89.840
90.035
90.163
89.966
89.838
89.474
89.238
93.565
96.377
104.925
110.482
111.573
112.282
110.503
109.346
108.315
107.645
106.089
105.079
102.181
100.297
97.953
96.430
93.479
91.562
90.595
89.967
86.759
84.674
82.478
81.050
79.563
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
3750.626
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
3774.927
3775.386
3775.062
3775.070
3773.333
3772.423
3772.610
3772.950
3773.109
3773.431
3774.979
3776.204
3778.619
3780.407
3781.227
3781.979
3782.406
3782.902
3783.163
3783.551
3788.501
3791.938
3801.110
3807.291
3809.006
3810.339
3809.184
3808.652
3808.245
3808.199
3807.268
3806.881
3804.607
3803.348
3801.628
3800.729
3798.403
3797.109
3796.767
3796.763
3794.179
3792.718
3791.146
3790.343
3789.480
3750.094
3752.418
3754.418
3756.183
3757.969
3759.567
3761.012
3762.320
3763.718
3764.994
3766.429
3767.749
3768.988
3770.135
3771.306
3772.396
3773.462
3774.460
3775.434
3776.348
3777.382
3778.357
3779.400
3780.386
3781.588
3782.728
3783.848
3784.913
3785.910
3786.860
3787.743
3788.587
3789.325
3790.031
3790.614
3791.174
3791.651
3792.109
3792.489
3792.854
3793.115
3793.367
3793.560
3793.747
3793.751
3744.075
3746.162
3747.969
3749.563
3750.883
3752.017
3753.047
3753.994
3754.863
3755.671
3756.475
3757.264
3758.086
3758.912
3759.709
3760.477
3761.208
3761.908
3762.572
3763.208
3763.952
3764.751
3765.761
3766.884
3767.992
3769.078
3770.081
3771.022
3771.908
3772.752
3773.536
3774.277
3774.937
3775.541
3776.085
3776.588
3777.024
3777.418
3777.790
3778.148
3778.445
3778.704
3778.926
3779.127
3779.305
3681.606
3682.231
3682.855
3683.479
3684.103
3684.727
3685.351
3685.976
3686.600
3687.224
3687.848
3688.472
3689.096
3689.721
3690.345
3690.969
3691.593
3692.217
3692.841
3693.466
3694.090
3694.714
3695.338
3695.962
3696.586
3697.211
3697.835
3698.459
3699.083
3699.707
3700.331
3700.956
3701.580
3702.204
3702.828
3703.452
3704.077
3704.701
3705.325
3705.949
3706.573
3707.197
3707.822
3708.446
3709.070
3677.861
3678.173
3678.486
3678.798
3679.110
3679.422
3679.734
3680.046
3680.358
3680.670
3680.982
3681.294
3681.606
3681.918
3682.231
3682.543
3682.855
3683.167
3683.479
3683.791
3684.103
3684.415
3684.727
3685.039
3685.351
3685.663
3685.976
3686.288
3686.600
3686.912
3687.224
3687.536
3687.848
3688.160
3688.472
3688.784
3689.096
3689.408
3689.721
3690.033
3690.345
3690.657
3690.969
3691.281
3691.593
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002186
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
59.904
59.911
59.911
59.916
59.916
59.918
59.918
59.921
59.921
59.917
59.917
59.921
59.921
59.926
59.926
59.928
59.928
59.932
59.932
59.928
59.928
59.929
59.929
59.933
59.933
59.937
59.937
59.949
59.949
59.942
59.942
59.942
59.942
59.948
59.948
59.949
59.949
59.952
59.952
59.951
59.951
59.952
59.952
59.955
59.955
59.954
3793.975
3791.502
3791.502
3788.132
3788.132
3783.028
3783.028
3776.358
3776.358
3774.604
3774.604
3773.958
3773.958
3771.670
3771.670
3768.707
3768.707
3767.021
3767.021
3766.788
3766.788
3765.672
3765.672
3764.243
3764.243
3762.935
3762.935
3753.922
3753.922
3746.889
3746.889
3749.593
3749.593
3746.706
3746.706
3742.741
3742.741
3736.139
3736.139
3727.838
3727.838
3722.649
3722.649
3717.996
3717.996
3715.753
76.801
71.201
71.201
67.200
67.200
65.601
65.601
63.199
63.199
66.400
66.400
63.199
63.199
59.201
59.201
57.599
57.599
54.401
54.401
57.599
57.599
56.799
56.799
53.601
53.601
50.400
50.400
40.799
40.799
46.399
46.399
46.399
46.399
41.599
41.599
40.799
40.799
38.400
38.400
39.200
39.200
38.400
38.400
35.999
35.999
36.801
78.596
76.008
74.325
71.831
70.210
68.597
67.548
66.026
65.036
65.514
65.824
64.905
64.308
62.521
61.359
60.043
59.187
57.512
56.423
56.835
57.102
56.996
56.927
55.763
55.006
53.394
52.346
48.305
45.678
45.930
46.094
46.201
46.270
44.635
43.572
42.602
41.971
40.721
39.909
39.661
39.499
39.115
38.865
37.861
37.209
37.067
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
3789.137
3787.173
3786.114
3784.245
3783.248
3782.259
3781.834
3780.936
3780.571
3781.672
3782.607
3782.312
3782.339
3781.176
3780.638
3779.946
3779.715
3778.664
3778.199
3779.235
3780.126
3780.645
3781.200
3780.660
3780.527
3779.539
3779.115
3775.698
3773.695
3774.572
3775.360
3776.091
3776.785
3775.774
3775.335
3774.989
3774.982
3774.356
3774.168
3774.544
3775.007
3775.247
3775.621
3775.242
3775.214
3775.695
3793.755
3793.717
3793.681
3793.591
3793.505
3793.341
3793.182
3792.927
3792.680
3792.414
3792.156
3791.896
3791.643
3791.366
3791.096
3790.794
3790.499
3790.190
3789.889
3789.593
3789.304
3789.009
3788.721
3788.422
3788.131
3787.831
3787.538
3787.147
3786.766
3786.312
3785.869
3785.466
3785.072
3784.655
3784.247
3783.805
3783.373
3782.881
3782.399
3781.843
3781.297
3780.711
3780.136
3779.527
3778.929
3778.322
3779.472
3779.600
3779.707
3779.780
3779.835
3779.873
3779.903
3779.919
3779.929
3779.954
3779.993
3780.026
3780.058
3780.074
3780.082
3780.080
3780.075
3780.056
3780.032
3780.022
3780.023
3780.031
3780.046
3780.053
3780.059
3780.053
3780.042
3779.991
3779.919
3779.858
3779.807
3779.766
3779.733
3779.690
3779.643
3779.594
3779.545
3779.491
3779.436
3779.387
3779.342
3779.301
3779.265
3779.225
3779.186
3779.153
3709.694
3710.318
3710.942
3711.567
3712.191
3712.815
3713.439
3714.063
3714.687
3715.312
3715.936
3716.560
3717.184
3717.808
3718.432
3719.057
3719.681
3720.305
3720.929
3721.553
3722.177
3722.802
3723.426
3724.050
3724.674
3725.298
3725.922
3726.547
3727.171
3727.795
3728.419
3729.043
3729.667
3730.292
3730.916
3731.540
3732.164
3732.788
3733.413
3734.037
3734.661
3735.285
3735.909
3736.533
3737.158
3737.782
3691.905
3692.217
3692.529
3692.841
3693.154
3693.466
3693.778
3694.090
3694.402
3694.714
3695.026
3695.338
3695.650
3695.962
3696.274
3696.586
3696.899
3697.211
3697.523
3697.835
3698.147
3698.459
3698.771
3699.083
3699.395
3699.707
3700.019
3700.331
3700.644
3700.956
3701.268
3701.580
3701.892
3702.204
3702.516
3702.828
3703.140
3703.452
3703.764
3704.077
3704.389
3704.701
3705.013
3705.325
3705.637
3705.949
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002187
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
59.954
59.953
59.953
59.952
59.952
59.954
59.954
59.957
59.957
59.954
59.954
59.955
59.955
59.961
59.961
59.962
59.962
59.966
59.966
59.968
59.968
59.974
59.974
59.969
59.969
59.97
59.97
59.973
59.973
59.976
59.976
59.978
59.978
59.978
59.978
59.978
59.978
59.98
59.98
59.981
59.981
59.979
59.979
59.979
59.979
59.983
3715.753
3713.484
3713.484
3710.810
3710.810
3714.623
3714.623
3716.168
3716.168
3716.980
3716.980
3722.361
3722.361
3722.658
3722.658
3722.278
3722.278
3723.091
3723.091
3723.435
3723.435
3725.403
3725.403
3728.053
3728.053
3732.530
3732.530
3736.535
3736.535
3736.822
3736.822
3739.944
3739.944
3741.794
3741.794
3746.608
3746.608
3750.716
3750.716
3752.748
3752.748
3756.407
3756.407
3760.405
3760.405
3761.407
36.801
37.601
37.601
38.400
38.400
36.801
36.801
34.399
34.399
36.801
36.801
35.999
35.999
31.201
31.201
30.399
30.399
27.200
27.200
25.601
25.601
20.801
20.801
24.799
24.799
23.999
23.999
21.600
21.600
19.199
19.199
17.599
17.599
17.599
17.599
17.599
17.599
16.000
16.000
15.201
15.201
16.800
16.800
16.800
16.800
13.599
36.974
37.193
37.336
37.708
37.951
37.548
37.287
36.276
35.619
36.033
36.302
36.196
36.127
34.403
33.282
32.273
31.617
30.071
29.066
27.854
27.065
24.873
23.448
23.920
24.228
24.148
24.096
23.222
22.655
21.445
20.659
19.588
18.892
18.440
18.146
17.954
17.830
17.190
16.773
16.223
15.865
16.192
16.405
16.543
16.633
15.571
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
3776.226
3777.070
3777.837
3778.834
3779.700
3779.922
3780.285
3779.898
3779.865
3780.903
3781.796
3782.314
3782.869
3781.770
3781.273
3780.888
3780.856
3779.935
3779.554
3778.966
3778.801
3777.233
3776.432
3777.529
3778.461
3779.005
3779.577
3779.328
3779.384
3778.799
3778.637
3778.190
3778.118
3778.290
3778.620
3779.053
3779.553
3779.537
3779.745
3779.818
3780.085
3781.036
3781.873
3782.635
3783.349
3782.911
3777.726
3777.120
3776.525
3775.917
3775.319
3774.767
3774.226
3773.707
3773.198
3772.705
3772.220
3771.791
3771.368
3770.955
3770.549
3770.147
3769.751
3769.369
3768.993
3768.625
3768.264
3767.924
3767.589
3767.280
3766.976
3766.711
3766.450
3766.223
3766.000
3765.782
3765.568
3765.379
3765.194
3765.024
3764.857
3764.727
3764.598
3764.501
3764.404
3764.323
3764.243
3764.190
3764.137
3764.112
3764.087
3764.069
3779.125
3779.106
3779.094
3779.091
3779.097
3779.104
3779.115
3779.122
3779.129
3779.144
3779.167
3779.194
3779.226
3779.247
3779.264
3779.278
3779.291
3779.296
3779.298
3779.296
3779.292
3779.275
3779.253
3779.240
3779.233
3779.232
3779.234
3779.235
3779.236
3779.233
3779.229
3779.221
3779.213
3779.206
3779.202
3779.201
3779.203
3779.206
3779.209
3779.214
3779.220
3779.232
3779.250
3779.273
3779.300
3779.324
3738.406
3739.030
3739.654
3740.278
3740.903
3741.527
3742.151
3742.775
3743.399
3744.023
3744.648
3745.272
3745.896
3746.520
3747.144
3747.768
3748.393
3749.017
3749.641
3750.265
3750.889
3751.513
3752.138
3752.762
3753.386
3754.010
3754.634
3755.258
3755.883
3756.507
3757.131
3757.755
3758.379
3759.003
3759.628
3760.252
3760.876
3761.500
3762.124
3762.749
3763.373
3763.997
3764.621
3765.245
3765.869
3766.494
3706.261
3706.573
3706.885
3707.197
3707.509
3707.822
3708.134
3708.446
3708.758
3709.070
3709.382
3709.694
3710.006
3710.318
3710.630
3710.942
3711.254
3711.567
3711.879
3712.191
3712.503
3712.815
3713.127
3713.439
3713.751
3714.063
3714.375
3714.687
3714.999
3715.312
3715.624
3715.936
3716.248
3716.560
3716.872
3717.184
3717.496
3717.808
3718.120
3718.432
3718.745
3719.057
3719.369
3719.681
3719.993
3720.305
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002188
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
59.983
59.988
59.988
59.987
59.987
59.991
59.991
59.992
59.992
59.989
59.989
59.983
59.983
59.988
59.988
59.996
59.996
59.999
59.999
59.999
59.999
59.999
59.999
60.005
60.005
60.008
60.008
60.014
60.014
60.019
60.019
60.017
60.017
60.019
60.019
60.024
60.024
60.021
60.021
60.024
60.024
60.021
60.021
60.025
60.025
60.02
3761.407
3763.212
3763.212
3766.085
3766.085
3767.251
3767.251
3768.634
3768.634
3772.445
3772.445
3774.668
3774.668
3775.363
3775.363
3775.492
3775.492
3778.554
3778.554
3781.256
3781.256
3783.092
3783.092
3784.421
3784.421
3785.463
3785.463
3786.304
3786.304
3787.516
3787.516
3788.030
3788.030
3789.216
3789.216
3785.842
3785.842
3787.930
3787.930
3786.875
3786.875
3787.358
3787.358
3785.614
3785.614
3785.804
13.599
9.601
9.601
10.400
10.400
7.199
7.199
6.400
6.400
8.801
8.801
13.599
13.599
9.601
9.601
3.201
3.201
0.800
0.800
0.800
0.800
0.800
0.800
-4.001
-4.001
-6.400
-6.400
-11.200
-11.200
-15.201
-15.201
-13.599
-13.599
-15.201
-15.201
-19.199
-19.199
-16.800
-16.800
-19.199
-19.199
-16.800
-16.800
-20.001
-20.001
-16.000
14.881
13.033
11.832
11.331
11.005
9.673
8.807
7.964
7.417
7.901
8.216
10.100
11.325
10.721
10.329
7.834
6.213
4.318
3.087
2.286
1.766
1.428
1.208
-0.615
-1.800
-3.410
-4.456
-6.817
-8.351
-10.748
-12.307
-12.759
-13.053
-13.805
-14.293
-16.010
-17.126
-17.012
-16.938
-17.729
-18.243
-17.738
-17.410
-18.317
-18.906
-17.889
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.624
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3782.845
3781.622
3781.045
3781.168
3781.466
3780.758
3780.517
3780.298
3780.375
3781.483
3782.423
3784.931
3786.779
3786.800
3787.032
3785.162
3784.164
3782.894
3782.286
3782.110
3782.214
3782.500
3782.904
3781.081
3779.896
3778.286
3777.240
3774.880
3773.346
3770.948
3769.390
3768.938
3768.644
3767.892
3767.403
3765.686
3764.570
3764.684
3764.759
3763.967
3763.453
3763.958
3764.287
3763.380
3762.790
3763.807
3764.051
3764.046
3764.040
3764.053
3764.067
3764.087
3764.107
3764.136
3764.164
3764.216
3764.267
3764.331
3764.395
3764.461
3764.528
3764.594
3764.659
3764.742
3764.823
3764.920
3765.015
3765.121
3765.224
3765.335
3765.444
3765.558
3765.670
3765.786
3765.901
3766.021
3766.139
3766.260
3766.379
3766.503
3766.626
3766.729
3766.831
3766.943
3767.054
3767.159
3767.262
3767.367
3767.470
3767.564
3767.656
3767.749
3779.348
3779.363
3779.374
3779.385
3779.399
3779.407
3779.415
3779.420
3779.426
3779.439
3779.458
3779.491
3779.536
3779.580
3779.625
3779.659
3779.686
3779.705
3779.720
3779.734
3779.749
3779.765
3779.783
3779.790
3779.791
3779.782
3779.768
3779.741
3779.705
3779.656
3779.599
3779.541
3779.481
3779.418
3779.353
3779.280
3779.201
3779.124
3779.048
3778.969
3778.887
3778.810
3778.734
3778.655
3778.574
3778.499
3767.118
3767.742
3768.366
3768.990
3769.614
3770.239
3770.863
3771.487
3772.111
3772.735
3773.359
3773.984
3774.608
3775.232
3775.856
3776.480
3777.104
3777.729
3778.353
3778.977
3779.601
3780.225
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3720.617
3720.929
3721.241
3721.553
3721.865
3722.177
3722.490
3722.802
3723.114
3723.426
3723.738
3724.050
3724.362
3724.674
3724.986
3725.298
3725.610
3725.922
3726.235
3726.547
3726.859
3727.171
3727.483
3727.791
3728.096
3728.398
3728.696
3728.990
3729.282
3729.570
3729.855
3730.136
3730.415
3730.691
3730.963
3731.233
3731.500
3731.764
3732.025
3732.283
3732.539
3732.792
3733.042
3733.290
3733.535
3733.777
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002189
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
60.02
60.022
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.019
60.019
60.018
60.018
60.018
60.018
60.019
60.019
60.015
60.015
60.014
60.014
60.012
60.012
60.01
60.01
60.007
60.007
60.009
60.009
60.003
60.003
59.995
59.995
59.991
59.991
59.992
59.992
59.986
59.986
59.984
59.984
59.984
59.984
59.981
59.981
59.979
3785.804
3786.877
3786.877
3785.726
3785.726
3785.821
3785.821
3786.284
3786.284
3787.627
3787.627
3789.673
3789.673
3788.479
3788.479
3789.369
3789.369
3788.665
3788.665
3790.667
3790.667
3790.411
3790.411
3791.540
3791.540
3791.027
3791.027
3791.426
3791.426
3790.457
3790.457
3789.585
3789.585
3788.105
3788.105
3788.189
3788.189
3788.540
3788.540
3788.101
3788.101
3786.453
3786.453
3788.813
3788.813
3788.256
-16.000
-17.599
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-18.399
-15.201
-15.201
-14.401
-14.401
-14.401
-14.401
-15.201
-15.201
-12.000
-12.000
-11.200
-11.200
-9.601
-9.601
-7.999
-7.999
-5.600
-5.600
-7.199
-7.199
-2.399
-2.399
4.001
4.001
7.199
7.199
6.400
6.400
11.200
11.200
12.799
12.799
12.799
12.799
15.201
15.201
16.800
-17.228
-17.358
-17.443
-17.498
-17.533
-17.277
-17.110
-17.561
-17.854
-16.926
-16.322
-15.650
-15.213
-14.929
-14.744
-14.904
-15.008
-13.955
-13.271
-12.546
-12.075
-11.209
-10.646
-9.719
-9.117
-7.886
-7.086
-7.126
-7.151
-5.488
-4.407
-1.464
0.449
2.811
4.347
5.065
5.532
7.516
8.805
10.203
11.112
11.702
12.086
13.176
13.885
14.905
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3764.468
3764.338
3764.254
3764.199
3764.163
3764.420
3764.587
3764.135
3763.842
3764.771
3765.374
3766.047
3766.484
3766.768
3766.952
3766.792
3766.689
3767.741
3768.426
3769.151
3769.622
3770.487
3771.050
3771.977
3772.579
3773.810
3774.610
3774.571
3774.545
3776.208
3777.290
3780.232
3782.145
3784.508
3786.043
3786.762
3787.229
3789.212
3790.502
3791.900
3792.808
3793.399
3793.783
3794.873
3795.581
3796.602
3767.840
3767.937
3768.032
3768.120
3768.208
3768.295
3768.381
3768.469
3768.556
3768.649
3768.740
3768.841
3768.941
3769.034
3769.126
3769.221
3769.316
3769.406
3769.496
3769.594
3769.691
3769.786
3769.880
3769.979
3770.076
3770.171
3770.264
3770.359
3770.452
3770.541
3770.629
3770.712
3770.794
3770.869
3770.944
3771.018
3771.092
3771.167
3771.240
3771.312
3771.383
3771.446
3771.509
3771.581
3771.652
3771.721
3778.427
3778.356
3778.285
3778.215
3778.145
3778.077
3778.011
3777.943
3777.874
3777.810
3777.750
3777.694
3777.640
3777.588
3777.538
3777.487
3777.437
3777.391
3777.350
3777.312
3777.276
3777.245
3777.217
3777.193
3777.172
3777.157
3777.146
3777.134
3777.123
3777.119
3777.119
3777.133
3777.155
3777.187
3777.225
3777.266
3777.309
3777.360
3777.416
3777.477
3777.542
3777.608
3777.676
3777.748
3777.822
3777.899
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3734.018
3734.255
3734.491
3734.724
3734.954
3735.183
3735.409
3735.632
3735.854
3736.074
3736.291
3736.506
3736.719
3736.931
3737.140
3737.347
3737.552
3737.755
3737.957
3738.156
3738.354
3738.550
3738.744
3738.936
3739.127
3739.315
3739.502
3739.688
3739.872
3740.054
3740.234
3740.413
3740.590
3740.766
3740.941
3741.113
3741.285
3741.454
3741.623
3741.790
3741.955
3742.119
3742.282
3742.443
3742.603
3742.762
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002190
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
59.979
59.976
59.976
59.979
59.979
59.978
59.978
59.974
59.974
59.977
59.977
59.975
59.975
59.969
59.969
59.971
59.971
59.978
59.978
59.978
59.978
59.972
59.972
59.975
59.975
59.969
59.969
59.965
59.965
59.969
59.969
59.968
59.968
59.964
59.964
59.972
59.972
59.967
59.967
59.968
59.968
59.967
59.967
59.966
59.966
59.971
3788.256
3790.467
3790.467
3790.420
3790.420
3789.267
3789.267
3790.430
3790.430
3786.243
3786.243
3788.963
3788.963
3791.877
3791.877
3792.311
3792.311
3788.080
3788.080
3787.135
3787.135
3786.996
3786.996
3786.487
3786.487
3789.214
3789.214
3791.221
3791.221
3790.959
3790.959
3789.026
3789.026
3787.394
3787.394
3784.831
3784.831
3784.320
3784.320
3782.110
3782.110
3779.056
3779.056
3779.212
3779.212
3776.429
16.800
19.199
19.199
16.800
16.800
17.599
17.599
20.801
20.801
18.399
18.399
20.001
20.001
24.799
24.799
23.199
23.199
17.599
17.599
17.599
17.599
22.400
22.400
20.001
20.001
24.799
24.799
28.000
28.000
24.799
24.799
25.601
25.601
28.799
28.799
22.400
22.400
26.401
26.401
25.601
25.601
26.401
26.401
27.200
27.200
23.199
15.568
16.839
17.665
17.362
17.165
17.317
17.416
18.601
19.371
19.031
18.810
19.227
19.498
21.353
22.559
22.783
22.929
21.064
19.851
19.063
18.551
19.898
20.774
20.503
20.328
21.892
22.910
24.691
25.849
25.482
25.242
25.368
25.450
26.622
27.384
25.640
24.506
25.169
25.600
25.600
25.601
25.881
26.063
26.461
26.720
25.488
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3797.265
3798.535
3799.361
3799.058
3798.862
3799.014
3799.112
3800.297
3801.067
3800.727
3800.506
3800.923
3801.194
3803.049
3804.255
3804.480
3804.625
3802.760
3801.548
3800.759
3800.247
3801.594
3802.470
3802.200
3802.024
3803.589
3804.606
3806.388
3807.546
3807.178
3806.939
3807.064
3807.146
3808.318
3809.081
3807.336
3806.202
3806.865
3807.296
3807.297
3807.297
3807.577
3807.759
3808.157
3808.416
3807.184
3771.789
3771.866
3771.942
3772.017
3772.091
3772.160
3772.229
3772.302
3772.374
3772.429
3772.484
3772.549
3772.613
3772.688
3772.763
3772.839
3772.914
3772.972
3773.030
3773.084
3773.137
3773.190
3773.242
3773.292
3773.341
3773.400
3773.459
3773.525
3773.590
3773.654
3773.718
3773.773
3773.829
3773.878
3773.927
3773.966
3774.005
3774.042
3774.078
3774.107
3774.135
3774.153
3774.170
3774.187
3774.205
3774.213
3777.979
3778.063
3778.150
3778.235
3778.319
3778.402
3778.485
3778.573
3778.662
3778.750
3778.836
3778.923
3779.010
3779.104
3779.202
3779.300
3779.398
3779.487
3779.572
3779.653
3779.731
3779.814
3779.899
3779.983
3780.066
3780.154
3780.245
3780.341
3780.442
3780.540
3780.637
3780.733
3780.829
3780.929
3781.030
3781.125
3781.215
3781.307
3781.399
3781.491
3781.582
3781.674
3781.765
3781.857
3781.950
3782.038
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3742.920
3743.076
3743.230
3743.384
3743.536
3743.687
3743.837
3743.986
3744.133
3744.280
3744.425
3744.569
3744.711
3744.853
3744.994
3745.133
3745.272
3745.409
3745.545
3745.681
3745.815
3745.948
3746.080
3746.212
3746.342
3746.471
3746.599
3746.727
3746.853
3746.978
3747.103
3747.227
3747.349
3747.471
3747.592
3747.712
3747.831
3747.950
3748.067
3748.184
3748.300
3748.415
3748.529
3748.642
3748.755
3748.867
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002191
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
59.971
59.965
59.965
59.964
59.964
59.967
59.967
59.968
59.968
59.965
59.965
59.973
59.973
59.965
59.965
59.969
59.969
59.964
59.964
59.979
59.979
59.983
59.983
59.967
59.967
59.962
59.962
59.961
59.961
59.96
59.96
59.959
59.959
59.951
59.951
59.954
59.954
59.956
59.956
59.963
59.963
59.959
59.959
59.963
59.963
59.968
3776.429
3776.597
3776.597
3776.023
3776.023
3771.730
3771.730
3768.503
3768.503
3767.366
3767.366
3760.295
3760.295
3761.894
3761.894
3760.583
3760.583
3759.781
3759.781
3757.773
3757.773
3753.087
3753.087
3753.751
3753.751
3759.250
3759.250
3760.965
3760.965
3763.822
3763.822
3763.858
3763.858
3766.127
3766.127
3767.972
3767.972
3765.606
3765.606
3761.570
3761.570
3759.627
3759.627
3752.429
3752.429
3753.830
23.199
28.000
28.000
28.799
28.799
26.401
26.401
25.601
25.601
28.000
28.000
21.600
21.600
28.000
28.000
24.799
24.799
28.799
28.799
16.800
16.800
13.599
13.599
26.401
26.401
30.399
30.399
31.201
31.201
32.001
32.001
32.800
32.800
39.200
39.200
36.801
36.801
35.199
35.199
29.599
29.599
32.800
32.800
29.599
29.599
25.601
24.687
25.846
26.600
27.370
27.870
27.356
27.022
26.524
26.201
26.831
27.240
25.266
23.983
25.389
26.303
25.776
25.434
26.612
27.378
23.675
21.269
18.584
16.839
20.186
22.361
25.174
27.003
28.472
29.427
30.328
30.913
31.574
32.003
34.522
36.159
36.384
36.530
36.064
35.761
33.604
32.203
32.412
32.548
31.516
30.845
29.010
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3806.383
3807.543
3808.296
3809.066
3809.567
3809.052
3808.718
3808.221
3807.898
3808.527
3808.936
3806.962
3805.679
3807.085
3807.999
3807.473
3807.130
3808.308
3809.074
3805.372
3802.965
3800.281
3798.536
3801.882
3804.057
3806.871
3808.699
3810.169
3811.124
3812.024
3812.610
3813.270
3813.699
3816.218
3817.856
3818.080
3818.226
3817.760
3817.458
3815.301
3813.899
3814.108
3814.244
3813.212
3812.541
3810.706
3774.220
3774.228
3774.237
3774.243
3774.249
3774.240
3774.232
3774.212
3774.193
3774.170
3774.147
3774.101
3774.055
3774.015
3773.975
3773.931
3773.887
3773.841
3773.795
3773.743
3773.692
3773.625
3773.559
3773.496
3773.433
3773.387
3773.343
3773.303
3773.265
3773.235
3773.205
3773.176
3773.147
3773.125
3773.104
3773.088
3773.072
3773.049
3773.026
3772.991
3772.957
3772.916
3772.876
3772.815
3772.753
3772.697
3782.122
3782.209
3782.299
3782.391
3782.484
3782.574
3782.663
3782.749
3782.834
3782.920
3783.007
3783.087
3783.162
3783.241
3783.323
3783.402
3783.480
3783.561
3783.644
3783.715
3783.777
3783.830
3783.877
3783.935
3783.999
3784.072
3784.151
3784.233
3784.318
3784.405
3784.493
3784.583
3784.674
3784.772
3784.874
3784.977
3785.079
3785.179
3785.278
3785.370
3785.456
3785.543
3785.630
3785.713
3785.793
3785.868
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3748.978
3749.088
3749.198
3749.306
3749.414
3749.522
3749.628
3749.734
3749.839
3749.944
3750.047
3750.150
3750.253
3750.354
3750.455
3750.556
3750.655
3750.754
3750.853
3750.950
3751.047
3751.144
3751.240
3751.335
3751.429
3751.523
3751.617
3751.710
3751.802
3751.893
3751.985
3752.075
3752.165
3752.254
3752.343
3752.431
3752.519
3752.606
3752.693
3752.779
3752.865
3752.950
3753.034
3753.118
3753.202
3753.285
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002192
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
59.968
59.968
59.968
59.973
59.973
59.965
59.965
59.967
59.967
59.976
59.976
59.969
59.969
59.974
59.974
59.981
59.981
59.981
59.981
59.982
59.982
59.982
59.982
59.979
59.979
59.978
59.978
59.98
59.98
59.98
59.98
59.976
59.976
59.971
59.971
59.974
59.974
59.976
59.976
59.969
59.969
59.974
59.974
59.972
59.972
59.977
3753.830
3753.523
3753.523
3753.178
3753.178
3753.291
3753.291
3752.359
3752.359
3747.476
3747.476
3741.285
3741.285
3745.738
3745.738
3741.618
3741.618
3738.484
3738.484
3737.404
3737.404
3736.308
3736.308
3735.448
3735.448
3737.541
3737.541
3736.748
3736.748
3736.067
3736.067
3736.575
3736.575
3738.875
3738.875
3738.647
3738.647
3737.382
3737.382
3740.017
3740.017
3742.053
3742.053
3742.524
3742.524
3741.723
25.601
25.601
25.601
21.600
21.600
28.000
28.000
26.401
26.401
19.199
19.199
24.799
24.799
20.801
20.801
15.201
15.201
15.201
15.201
14.401
14.401
14.401
14.401
16.800
16.800
17.599
17.599
16.000
16.000
16.000
16.000
19.199
19.199
23.199
23.199
20.801
20.801
19.199
19.199
24.799
24.799
20.801
20.801
22.400
22.400
18.399
27.817
27.041
26.537
24.809
23.686
25.196
26.177
26.256
26.306
23.819
22.202
23.111
23.701
22.686
22.026
19.637
18.085
17.075
16.419
15.713
15.254
14.955
14.761
15.475
15.939
16.520
16.898
16.584
16.380
16.247
16.161
17.224
17.915
19.765
20.967
20.909
20.871
20.286
19.905
21.618
22.731
22.055
21.616
21.891
22.069
20.784
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3809.513
3808.738
3808.234
3806.506
3805.383
3806.892
3807.874
3807.952
3808.003
3805.515
3803.898
3804.807
3805.398
3804.383
3803.723
3801.334
3799.781
3798.772
3798.116
3797.409
3796.950
3796.652
3796.458
3797.171
3797.635
3798.216
3798.594
3798.280
3798.076
3797.943
3797.857
3798.920
3799.611
3801.461
3802.663
3802.605
3802.567
3801.982
3801.602
3803.314
3804.427
3803.752
3803.313
3803.587
3803.765
3802.481
3772.640
3772.584
3772.527
3772.470
3772.413
3772.357
3772.301
3772.242
3772.184
3772.113
3772.041
3771.952
3771.864
3771.789
3771.714
3771.628
3771.543
3771.449
3771.355
3771.259
3771.164
3771.066
3770.969
3770.870
3770.771
3770.679
3770.587
3770.493
3770.400
3770.306
3770.212
3770.120
3770.029
3769.944
3769.860
3769.776
3769.692
3769.605
3769.519
3769.440
3769.361
3769.289
3769.216
3769.146
3769.076
3769.004
3785.939
3786.006
3786.072
3786.133
3786.190
3786.251
3786.314
3786.377
3786.440
3786.496
3786.546
3786.599
3786.653
3786.704
3786.753
3786.794
3786.831
3786.865
3786.897
3786.927
3786.955
3786.982
3787.009
3787.037
3787.067
3787.098
3787.130
3787.160
3787.191
3787.220
3787.249
3787.281
3787.315
3787.353
3787.395
3787.436
3787.477
3787.516
3787.553
3787.595
3787.640
3787.683
3787.725
3787.767
3787.809
3787.847
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3753.367
3753.449
3753.531
3753.612
3753.693
3753.773
3753.852
3753.931
3754.010
3754.088
3754.166
3754.244
3754.320
3754.397
3754.473
3754.548
3754.624
3754.698
3754.773
3754.846
3754.920
3754.993
3755.066
3755.138
3755.210
3755.281
3755.352
3755.423
3755.493
3755.563
3755.632
3755.701
3755.770
3755.838
3755.906
3755.974
3756.041
3756.108
3756.175
3756.241
3756.307
3756.372
3756.437
3756.502
3756.566
3756.630
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002193
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
59.977
59.978
59.978
59.973
59.973
59.977
59.977
59.978
59.978
59.981
59.981
59.974
59.974
59.971
59.971
59.972
59.972
59.966
59.966
59.971
59.971
59.972
59.972
59.972
59.972
59.973
59.973
59.971
59.971
59.982
59.982
59.985
59.985
59.987
59.987
59.989
59.989
59.987
59.987
59.994
59.994
60.001
60.001
60.004
60.004
60.012
3741.723
3740.629
3740.629
3740.775
3740.775
3741.268
3741.268
3738.966
3738.966
3738.879
3738.879
3738.102
3738.102
3743.507
3743.507
3745.251
3745.251
3747.340
3747.340
3749.750
3749.750
3744.683
3744.683
3743.149
3743.149
3739.453
3739.453
3731.830
3731.830
3736.229
3736.229
3733.434
3733.434
3730.510
3730.510
3725.459
3725.459
3720.108
3720.108
3725.661
3725.661
3727.754
3727.754
3727.683
3727.683
3725.012
18.399
17.599
17.599
21.600
21.600
18.399
18.399
17.599
17.599
15.201
15.201
20.801
20.801
23.199
23.199
22.400
22.400
27.200
27.200
23.199
23.199
22.400
22.400
22.400
22.400
21.600
21.600
23.199
23.199
14.401
14.401
12.000
12.000
10.400
10.400
8.801
8.801
10.400
10.400
4.800
4.800
-0.800
-0.800
-3.201
-3.201
-9.601
19.950
19.127
18.592
19.645
20.329
19.654
19.215
18.649
18.282
17.204
16.503
18.007
18.985
20.460
21.419
21.762
21.985
23.811
24.997
24.368
23.959
23.413
23.059
22.828
22.678
22.301
22.056
22.456
22.716
19.806
17.914
15.844
14.499
13.064
12.132
10.966
10.208
10.276
10.319
8.388
7.132
4.356
2.552
0.538
-0.771
-3.861
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3801.646
3800.823
3800.289
3801.342
3802.026
3801.350
3800.911
3800.346
3799.978
3798.900
3798.199
3799.703
3800.681
3802.156
3803.115
3803.459
3803.682
3805.507
3806.693
3806.064
3805.655
3805.110
3804.755
3804.524
3804.375
3803.997
3803.752
3804.152
3804.413
3801.502
3799.611
3797.541
3796.195
3794.761
3793.828
3792.663
3791.905
3791.972
3792.016
3790.084
3788.829
3786.052
3784.248
3782.234
3780.926
3777.835
3768.932
3768.858
3768.784
3768.711
3768.639
3768.568
3768.497
3768.421
3768.345
3768.270
3768.195
3768.118
3768.041
3767.979
3767.917
3767.860
3767.803
3767.752
3767.700
3767.656
3767.611
3767.554
3767.497
3767.437
3767.377
3767.308
3767.240
3767.153
3767.067
3766.991
3766.916
3766.835
3766.754
3766.667
3766.580
3766.481
3766.382
3766.272
3766.162
3766.065
3765.969
3765.879
3765.788
3765.699
3765.609
3765.514
3787.884
3787.918
3787.950
3787.985
3788.021
3788.056
3788.089
3788.121
3788.151
3788.179
3788.204
3788.234
3788.265
3788.300
3788.338
3788.376
3788.415
3788.458
3788.503
3788.547
3788.590
3788.631
3788.671
3788.710
3788.749
3788.786
3788.823
3788.861
3788.899
3788.930
3788.956
3788.976
3788.994
3789.008
3789.019
3789.028
3789.035
3789.042
3789.049
3789.052
3789.051
3789.044
3789.033
3789.017
3788.998
3788.971
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3756.694
3756.757
3756.821
3756.883
3756.946
3757.008
3757.070
3757.131
3757.192
3757.253
3757.313
3757.374
3757.434
3757.493
3757.552
3757.611
3757.670
3757.728
3757.787
3757.844
3757.902
3757.959
3758.016
3758.073
3758.129
3758.185
3758.241
3758.297
3758.352
3758.407
3758.462
3758.516
3758.570
3758.624
3758.678
3758.731
3758.784
3758.837
3758.890
3758.942
3758.995
3759.046
3759.098
3759.150
3759.201
3759.252
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002194
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
60.012
60.019
60.019
60.025
60.025
60.027
60.027
60.029
60.029
60.036
60.036
60.037
60.037
60.041
60.041
60.044
60.044
60.046
60.046
60.046
60.046
60.043
60.043
60.044
60.044
3725.012
3726.016
3726.016
3716.375
3716.375
3717.560
3717.560
3715.166
3715.166
3710.283
3710.283
3699.356
3699.356
3704.591
3704.591
3702.482
3702.482
3700.826
3700.826
3699.726
3699.726
3690.477
3690.477
3696.877
3696.877
-9.601
-15.201
-15.201
-20.001
-20.001
-21.600
-21.600
-23.199
-23.199
-28.799
-28.799
-29.599
-29.599
-32.800
-32.800
-35.199
-35.199
-36.801
-36.801
-36.801
-36.801
-34.399
-34.399
-35.199
-35.199
-5.870
-9.136
-11.259
-14.319
-16.307
-18.160
-19.364
-20.706
-21.579
-24.106
-25.749
-27.096
-27.972
-29.662
-30.760
-32.314
-33.324
-34.541
-35.332
-35.846
-36.180
-35.557
-35.152
-35.168
-35.179
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3775.826
3772.561
3770.438
3767.378
3765.389
3763.536
3762.332
3760.990
3760.117
3757.590
3755.948
3754.600
3753.724
3752.034
3750.936
3749.382
3748.373
3747.156
3746.364
3745.850
3745.516
3746.139
3746.544
3746.528
3746.517
3765.419
3765.327
3765.235
3765.122
3765.009
3764.899
3764.789
3764.675
3764.561
3764.437
3764.313
3764.165
3764.017
3763.882
3763.747
3763.609
3763.471
3763.330
3763.189
3763.047
3762.905
3762.744
3762.583
3762.437
3762.291
3788.941
3788.902
3788.859
3788.809
3788.755
3788.697
3788.636
3788.572
3788.507
3788.436
3788.361
3788.284
3788.206
3788.123
3788.039
3787.952
3787.862
3787.771
3787.678
3787.584
3787.490
3787.397
3787.306
3787.216
3787.125
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3780.849
3759.302
3759.353
3759.403
3759.453
3759.503
3759.552
3759.602
3759.651
3759.700
3759.748
3759.797
3759.845
3759.893
3759.940
3759.988
3760.035
3760.082
3760.129
3760.176
3760.222
3760.269
3760.315
3760.361
3760.406
3760.452
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002195
A Point
2:27:22
FPointA
60.0410
2:27:22 AM
A Value
60.0420
C Value
59.8360
2:27:32 AM
Delta FCA -0.206001282
FR C
-307.3 MW/0.1 Hz
Slope A-C dF/dT
-0.020500 Hz/second
C Value Maximum Resource Loss
633
Secondary C Value
No
n/a Time
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:22
60.04100037
60.04199982
59.83599854
2:27:22
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
59.8823
59.8831
59.8888
59.8880
59.8888
-0.1597
-396.907
-0.1589
-398.895
-0.1532
-412.288
-0.1540
-411.604
-0.1532
-0.00798569
-0.00794285
-0.0076618
-0.0077
-0.0076618
77.5305
77.1146
74.3855
74.7567
74.3855
-0.0153
-0.0161
-0.0218
-0.0210
-0.0218
Tzero
2:27:22
FT+4 59.97800064
FT+10 59.89199829
FT+20
59.875
FT+60 59.88800049
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss
B Value Average LaaR Loss
B Value Average Net Loss
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
633
0
633
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection FR B
Generation Primary
20 to 52 sec
Trip
Frequency
Average
MW
Response
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002196
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-989.075
T+0 sec
-989.075
T+02 sec
-989.075
T+04 sec
-307.28
T+06 sec
-307.28
T+08 sec
-421.996
T+10 sec
-421.996
T+12 sec
-390.744
T+14 sec
-390.744
T+16 sec
-379.042
T+18 sec
-379.042 -413.5197194 T+20 sec
-408.39 -413.5197194 T+22 sec
-408.39 -413.5197194 T+24 sec
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
-396.907
-396.907
-396.907
-396.907
-396.907
-396.907
-396.907
59.8831
59.8831
59.8831
59.8831
-398.895
-398.895
-398.895
-398.895
59.8888
59.8888
59.8888
-412.288
-412.288
-412.288
59.8880
59.8880
59.8880
59.8880
-411.604
-411.604
-411.604
-411.604
59.8888
59.8888
59.8888
002197
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-403.181
-403.181
-411.041
-411.041
-430.614
-430.614
-424.837
-424.837
-427.706
-427.706
-416.446
-416.446
-403.181
-403.181
-408.39
-408.39
-411.041
-411.041
-413.726
-413.726
-374.559
-374.559
-327.978
-327.978
-344.025
-344.025
-359.662
-359.662
-361.716
-361.716
-370.172
-370.172
-388.348
-388.348
-398.112
-398.112
-416.446
-416.446
-413.726
-413.726
-442.653
-442.653
-452.145
-452.145
-458.694
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
-413.5197194
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8831
59.8831
59.8831
-398.895
-398.895
-398.895
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
-412.288
-412.288
-412.288
-412.288
-412.288
-412.288
-412.288
-412.288
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
-411.604
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
59.8888
002198
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-458.694
-483.204
-483.204
-502.383
-502.383
-510.482
-510.482
-523.147
-523.147
-506.4
-506.4
-523.147
-523.147
-545.684
-545.684
-555.271
-555.271
-575.451
-575.451
-555.271
-555.271
-560.182
-560.182
-580.728
-580.728
-602.86
-602.86
-680.656
-680.656
-633.01
-633.01
-633.01
-633.01
-673.419
-673.419
-680.656
-680.656
-703.332
-703.332
-695.607
-695.607
-703.332
-703.332
-727.603
-727.603
-719.308
002199
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-719.308
-711.23
-711.23
-703.332
-703.332
-719.308
-719.308
-744.714
-744.714
-719.308
-719.308
-727.603
-727.603
-781.469
-781.469
-791.27
-791.27
-832.892
-832.892
-855.39
-855.39
-930.871
-930.871
-867.146
-867.146
-879.184
-879.184
-917.388
-917.388
-959.119
-959.119
-989.075
-989.075
-989.075
-989.075
-989.075
-989.075
-1020.96
-1020.96
-1037.69
-1037.69
-1004.77
-1004.77
-1004.77
-1004.77
-1072.92
002200
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1072.92
-1172.2
-1172.2
-1150.9
-1150.9
-1241.21
-1241.21
-1266.02
-1266.02
-1194.31
-1194.31
-1072.92
-1072.92
-1172.2
-1172.2
-1376.04
-1376.04
-1472.12
-1472.12
-1472.12
-1472.12
-1472.12
-1472.12
-1710.87
-1710.87
-1861.74
-1861.74
-2260.72
-2260.72
-2752.32
-2752.32
-2531.85
-2531.85
-2752.32
-2752.32
-3516.36
-3516.36
-3014.3
-3014.3
-3516.36
-3516.36
-3014.3
-3014.3
-3723.9
-3723.9
-2877.36
002201
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2877.36
-3164.93
-3164.93
-3164.93
-3164.93
-3014.3
-3014.3
-3331.4
-3331.4
-2752.32
-2752.32
-2637.69
-2637.69
-2637.69
-2637.69
-2752.32
-2752.32
-2344.41
-2344.41
-2260.72
-2260.72
-2110.09
-2110.09
-1978.03
-1978.03
-1808.58
-1808.58
-1918.13
-1918.13
-1623.02
-1623.02
-1346.78
-1346.78
-1241.21
-1241.21
-1266.02
-1266.02
-1130.36
-1130.36
-1091.4
-1091.4
-1091.4
-1091.4
-1037.69
-1037.69
-1004.77
002202
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1004.77
-959.119
-959.119
-1004.77
-1004.77
-989.075
-989.075
-930.871
-930.871
-973.867
-973.867
-944.757
-944.757
-867.146
-867.146
-891.56
-891.56
-989.075
-989.075
-989.075
-989.075
-904.29
-904.29
-944.757
-944.757
-867.146
-867.146
-822.082
-822.082
-867.146
-867.146
-855.39
-855.39
-811.548
-811.548
-904.29
-904.29
-843.991
-843.991
-855.39
-855.39
-843.991
-843.991
-832.892
-832.892
-891.56
002203
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-891.56
-822.082
-822.082
-811.548
-811.548
-843.991
-843.991
-855.39
-855.39
-822.082
-822.082
-917.388
-917.388
-822.082
-822.082
-867.146
-867.146
-811.548
-811.548
-1004.77
-1004.77
-1072.92
-1072.92
-843.991
-843.991
-791.27
-791.27
-781.469
-781.469
-771.944
-771.944
-762.649
-762.649
-695.607
-695.607
-719.308
-719.308
-736.059
-736.059
-801.28
-801.28
-762.649
-762.649
-801.28
-801.28
-855.39
002204
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-855.39
-855.39
-855.39
-917.388
-917.388
-822.082
-822.082
-843.991
-843.991
-959.119
-959.119
-867.146
-867.146
-930.871
-930.871
-1037.69
-1037.69
-1037.69
-1037.69
-1054.98
-1054.98
-1054.98
-1054.98
-1004.77
-1004.77
-989.075
-989.075
-1020.96
-1020.96
-1020.96
-1020.96
-959.119
-959.119
-891.56
-891.56
-930.871
-930.871
-959.119
-959.119
-867.146
-867.146
-930.871
-930.871
-904.29
-904.29
-973.867
002205
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-973.867
-989.075
-989.075
-917.388
-917.388
-973.867
-973.867
-989.075
-989.075
-1037.69
-1037.69
-930.871
-930.871
-891.56
-891.56
-904.29
-904.29
-832.892
-832.892
-891.56
-891.56
-904.29
-904.29
-904.29
-904.29
-917.388
-917.388
-891.56
-891.56
-1054.98
-1054.98
-1110.54
-1110.54
-1150.9
-1150.9
-1194.31
-1194.31
-1150.9
-1150.9
-1318.74
-1318.74
-1543.89
-1543.89
-1665.87
-1665.87
-2110.09
002206
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633 -2110.09
633 -2752.32
633 -2752.32
633
-3723.9
633
-3723.9
633 -4220.17
633 -4220.17
633 -4869.05
633 -4869.05
633 -10549.1
633 -10549.1
633 -12657.3
633 -12657.3
633 -63334.8
633 -63334.8
633 31667.4
633 31667.4
633 15818.6
633 15818.6
633 15818.6
633 15818.6
633 63334.79
633 63334.79
633 31667.4
633 31667.4
002207
Non-Conforming Load sign convention
+
(If Data is positive for Load then enter "+" else "-")
Time of Frequency Recovery to 60 Hz or P
Value A Pre-Perturbation Average Frequen
Value B Post-Perturbation Average Frequen
Pre to Post Perturbation Delt
Value A Pre-Perturbation Average Interchange M
Value B Post-Perturbation Average Interchange MW
Pre to Post Perturbation Interchang
FR B
20 to 52 sec
-413.520
eriods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
FR B
20 to 52 sec
Average
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Net
Actual
Interchange
MW
60.0270
60.0270
60.0260
3668.61
3668.61
3664.50
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
-257.42
-257.42
-257.42
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
106.50
106.50
107.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
12 to 24 second Average Period Ev
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
BA
Load
MW
7570.29
7570.29
7570.62
Expected
Primary
Freq Response
MW
-21.600 T-72 sec
-21.600 T-70 sec
-20.801 T-68 sec
T
2:26:12
2:26:14
2:26:16
Frequency
Hz
002208
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-413.520 T+20 sec
-413.520 T+22 sec
-413.520 T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
60.0260
60.0190
60.0190
60.0190
60.0190
60.0190
60.0190
60.0210
60.0210
60.0190
60.0190
60.0220
60.0220
60.0370
60.0370
60.0360
60.0360
60.0460
60.0460
60.0480
60.0480
60.0410
60.0410
60.0410
60.0410
60.0410
60.0410
60.0450
60.0450
60.0410
60.0410
60.0410
60.0410
59.9780
59.9780
59.9780
59.8360
59.8360
59.8920
59.8920
59.8800
59.8800
59.8750
59.8750
59.8870
59.8870
3664.50
3666.82
3666.82
3670.45
3670.45
3671.67
3671.67
3672.69
3672.69
3672.16
3672.16
3669.98
3669.98
3663.76
3663.76
3660.67
3660.67
3649.19
3649.19
3648.25
3648.25
3654.29
3654.29
3651.87
3651.87
3649.19
3649.19
3645.39
3645.39
3645.45
3645.45
3641.19
3641.19
3696.36
3696.36
3696.36
3734.67
3734.67
3761.25
3761.25
3766.19
3766.19
3769.93
3769.93
3781.59
3781.59
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-261.74
-261.74
-261.74
-261.74
-165.10
-165.10
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.10
-165.10
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-211.26
-211.26
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
107.00
107.50
107.50
108.00
108.00
108.50
108.50
109.00
109.00
109.50
109.50
110.00
110.00
110.50
110.50
111.00
111.00
111.50
111.50
112.00
112.00
112.50
112.50
113.00
113.00
113.50
113.50
114.00
114.00
114.50
114.50
115.00
115.00
115.50
115.50
115.50
116.00
116.00
116.50
116.50
117.00
117.00
117.50
117.50
118.00
118.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7570.62
7570.95
7570.95
7571.28
7571.28
7571.61
7571.61
7571.94
7571.94
7572.27
7572.27
7572.60
7572.60
7572.93
7572.93
7573.26
7573.26
7573.59
7573.59
7573.92
7573.92
7574.25
7574.25
7574.58
7574.58
7574.91
7574.91
7575.24
7575.24
7575.57
7575.57
7575.90
7575.90
7576.23
7576.23
7576.23
7576.56
7576.56
7576.89
7576.89
7577.22
7577.22
7577.55
7577.55
7577.88
7577.88
-20.801
-15.201
-15.201
-15.201
-15.201
-15.201
-15.201
-16.800
-16.800
-15.201
-15.201
-17.599
-17.599
-29.599
-29.599
-28.799
-28.799
-36.801
-36.801
-38.400
-38.400
-32.800
-32.800
-32.800
-32.800
-32.800
-32.800
-35.999
-35.999
-32.800
-32.800
-32.800
-32.800
17.599
17.599
17.599
131.201
131.201
86.401
86.401
95.999
95.999
100.000
100.000
90.399
90.399
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.882
59.882
59.882
59.882
59.882
59.882
59.882
002209
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
-413.520
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
59.8850
59.8850
59.8880
59.8880
59.8950
59.8950
59.8930
59.8930
59.8940
59.8940
59.8900
59.8900
59.8850
59.8850
59.8870
59.8870
59.8880
59.8880
59.8890
59.8890
59.8730
59.8730
59.8490
59.8490
59.8580
59.8580
59.8660
59.8660
59.8670
59.8670
59.8710
59.8710
59.8790
59.8790
59.8830
59.8830
59.8900
59.8900
59.8890
59.8890
59.8990
59.8990
59.9020
59.9020
59.9040
3784.96
3784.96
3784.42
3784.42
3788.33
3788.33
3788.47
3788.47
3793.07
3793.07
3799.43
3799.43
3799.96
3799.96
3802.93
3802.93
3804.39
3804.39
3805.62
3805.62
3811.50
3811.50
3815.89
3815.89
3826.05
3826.05
3827.52
3827.52
3826.78
3826.78
3825.71
3825.71
3822.51
3822.51
3818.06
3818.06
3815.01
3815.01
3811.84
3811.84
3806.97
3806.97
3804.19
3804.19
3793.98
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
1.00
1.00
2.00
2.00
3.00
3.00
4.00
4.00
5.00
5.00
6.00
6.00
7.00
7.00
8.00
8.00
9.00
9.00
10.00
10.00
11.00
11.00
12.00
12.00
13.00
13.00
14.00
14.00
15.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
118.50
118.50
119.00
119.00
119.50
119.50
120.00
120.00
120.50
120.50
121.00
121.00
121.50
121.50
122.00
122.00
122.50
122.50
123.00
123.00
123.50
123.50
124.00
124.00
124.50
124.50
125.00
125.00
125.50
125.50
126.00
126.00
126.50
126.50
127.00
127.00
127.50
127.50
128.00
128.00
128.50
128.50
129.00
129.00
129.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7578.21
7578.21
7578.54
7578.54
7578.87
7578.87
7579.20
7579.20
7579.53
7579.53
7579.86
7579.86
7580.19
7580.19
7580.52
7580.52
7580.85
7580.85
7581.18
7581.18
7581.51
7581.51
7581.84
7581.84
7582.17
7582.17
7582.50
7582.50
7582.83
7582.83
7583.16
7583.16
7583.49
7583.49
7583.82
7583.82
7584.15
7584.15
7584.48
7584.48
7584.81
7584.81
7585.14
7585.14
7585.47
92.001
92.001
89.600
89.600
84.000
84.000
85.599
85.599
84.799
84.799
88.000
88.000
92.001
92.001
90.399
90.399
89.600
89.600
88.800
88.800
101.599
101.599
120.801
120.801
113.599
113.599
107.199
107.199
106.400
106.400
103.201
103.201
96.799
96.799
93.600
93.600
88.000
88.000
88.800
88.800
80.801
80.801
78.400
78.400
76.801
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
002210
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
59.9040
59.9110
59.9110
59.9160
59.9160
59.9180
59.9180
59.9210
59.9210
59.9170
59.9170
59.9210
59.9210
59.9260
59.9260
59.9280
59.9280
59.9320
59.9320
59.9280
59.9280
59.9290
59.9290
59.9330
59.9330
59.9370
59.9370
59.9490
59.9490
59.9420
59.9420
59.9420
59.9420
59.9480
59.9480
59.9490
59.9490
59.9520
59.9520
59.9510
59.9510
59.9520
59.9520
59.9550
59.9550
59.9540
3793.98
3791.50
3791.50
3788.13
3788.13
3783.03
3783.03
3776.36
3776.36
3774.60
3774.60
3773.96
3773.96
3771.67
3771.67
3768.71
3768.71
3767.02
3767.02
3766.79
3766.79
3765.67
3765.67
3764.24
3764.24
3762.94
3762.94
3753.92
3753.92
3746.89
3746.89
3749.59
3749.59
3746.71
3746.71
3742.74
3742.74
3736.14
3736.14
3727.84
3727.84
3722.65
3722.65
3718.00
3718.00
3715.75
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-218.33
-218.33
-218.33
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-228.37
-228.37
-228.37
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
129.50
130.00
130.00
130.50
130.50
131.00
131.00
131.50
131.50
132.00
132.00
132.50
132.50
133.00
133.00
133.50
133.50
134.00
134.00
134.50
134.50
135.00
135.00
135.50
135.50
136.00
136.00
136.50
136.50
137.00
137.00
137.50
137.50
138.00
138.00
138.50
138.50
139.00
139.00
139.50
139.50
140.00
140.00
140.50
140.50
141.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7585.47
7585.80
7585.80
7586.13
7586.13
7586.46
7586.46
7586.79
7586.79
7587.12
7587.12
7587.45
7587.45
7587.78
7587.78
7588.11
7588.11
7588.44
7588.44
7588.77
7588.77
7589.10
7589.10
7589.43
7589.43
7589.76
7589.76
7590.09
7590.09
7590.42
7590.42
7590.75
7590.75
7591.08
7591.08
7591.41
7591.41
7591.74
7591.74
7592.07
7592.07
7592.40
7592.40
7592.73
7592.73
7593.06
76.801
71.201
71.201
67.200
67.200
65.601
65.601
63.199
63.199
66.400
66.400
63.199
63.199
59.201
59.201
57.599
57.599
54.401
54.401
57.599
57.599
56.799
56.799
53.601
53.601
50.400
50.400
40.799
40.799
46.399
46.399
46.399
46.399
41.599
41.599
40.799
40.799
38.400
38.400
39.200
39.200
38.400
38.400
35.999
35.999
36.801
002211
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
59.9540
59.9530
59.9530
59.9520
59.9520
59.9540
59.9540
59.9570
59.9570
59.9540
59.9540
59.9550
59.9550
59.9610
59.9610
59.9620
59.9620
59.9660
59.9660
59.9680
59.9680
59.9740
59.9740
59.9690
59.9690
59.9700
59.9700
59.9730
59.9730
59.9760
59.9760
59.9780
59.9780
59.9780
59.9780
59.9780
59.9780
59.9800
59.9800
59.9810
59.9810
59.9790
59.9790
59.9790
59.9790
59.9830
3715.75
3713.48
3713.48
3710.81
3710.81
3714.62
3714.62
3716.17
3716.17
3716.98
3716.98
3722.36
3722.36
3722.66
3722.66
3722.28
3722.28
3723.09
3723.09
3723.43
3723.43
3725.40
3725.40
3728.05
3728.05
3732.53
3732.53
3736.54
3736.54
3736.82
3736.82
3739.94
3739.94
3741.79
3741.79
3746.61
3746.61
3750.72
3750.72
3752.75
3752.75
3756.41
3756.41
3760.41
3760.41
3761.41
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-228.80
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-229.47
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
-228.98
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
141.00
141.50
141.50
142.00
142.00
142.50
142.50
143.00
143.00
143.50
143.50
144.00
144.00
144.50
144.50
145.00
145.00
145.50
145.50
146.00
146.00
146.50
146.50
147.00
147.00
147.50
147.50
148.00
148.00
148.50
148.50
149.00
149.00
149.50
149.50
150.00
150.00
150.50
150.50
151.00
151.00
151.50
151.50
152.00
152.00
152.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7593.06
7593.39
7593.39
7593.72
7593.72
7594.05
7594.05
7594.38
7594.38
7594.71
7594.71
7595.04
7595.04
7595.37
7595.37
7595.70
7595.70
7596.03
7596.03
7596.36
7596.36
7596.69
7596.69
7597.02
7597.02
7597.35
7597.35
7597.68
7597.68
7598.01
7598.01
7598.34
7598.34
7598.67
7598.67
7599.00
7599.00
7599.33
7599.33
7599.66
7599.66
7599.99
7599.99
7600.32
7600.32
7600.65
36.801
37.601
37.601
38.400
38.400
36.801
36.801
34.399
34.399
36.801
36.801
35.999
35.999
31.201
31.201
30.399
30.399
27.200
27.200
25.601
25.601
20.801
20.801
24.799
24.799
23.999
23.999
21.600
21.600
19.199
19.199
17.599
17.599
17.599
17.599
17.599
17.599
16.000
16.000
15.201
15.201
16.800
16.800
16.800
16.800
13.599
002212
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
59.9830
59.9880
59.9880
59.9870
59.9870
59.9910
59.9910
59.9920
59.9920
59.9890
59.9890
59.9830
59.9830
59.9880
59.9880
59.9960
59.9960
59.9990
59.9990
59.9990
59.9990
59.9990
59.9990
60.0050
60.0050
60.0080
60.0080
60.0140
60.0140
60.0190
60.0190
60.0170
60.0170
60.0190
60.0190
60.0240
60.0240
60.0210
60.0210
60.0240
60.0240
60.0210
60.0210
60.0250
60.0250
60.0200
3761.41
3763.21
3763.21
3766.09
3766.09
3767.25
3767.25
3768.63
3768.63
3772.44
3772.44
3774.67
3774.67
3775.36
3775.36
3775.49
3775.49
3778.55
3778.55
3781.26
3781.26
3783.09
3783.09
3784.42
3784.42
3785.46
3785.46
3786.30
3786.30
3787.52
3787.52
3788.03
3788.03
3789.22
3789.22
3785.84
3785.84
3787.93
3787.93
3786.87
3786.87
3787.36
3787.36
3785.61
3785.61
3785.80
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-228.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-219.98
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.09
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.66
-229.23
-229.23
-229.23
-229.23
-229.23
-229.23
-229.23
-229.23
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.72
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
152.50
153.00
153.00
153.50
153.50
154.00
154.00
154.50
154.50
155.00
155.00
155.50
155.50
156.00
156.00
156.50
156.50
157.00
157.00
157.50
157.50
158.00
158.00
158.50
158.50
159.00
159.00
159.50
159.50
160.00
160.00
160.50
160.50
161.00
161.00
161.50
161.50
162.00
162.00
162.50
162.50
163.00
163.00
163.50
163.50
164.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7600.65
7600.98
7600.98
7601.31
7601.31
7601.64
7601.64
7601.97
7601.97
7602.30
7602.30
7602.63
7602.63
7602.96
7602.96
7603.29
7603.29
7603.62
7603.62
7603.95
7603.95
7604.28
7604.28
7604.61
7604.61
7604.94
7604.94
7605.27
7605.27
7605.60
7605.60
7605.93
7605.93
7606.26
7606.26
7606.59
7606.59
7606.92
7606.92
7607.25
7607.25
7607.58
7607.58
7607.91
7607.91
7608.24
13.599
9.601
9.601
10.400
10.400
7.199
7.199
6.400
6.400
8.801
8.801
13.599
13.599
9.601
9.601
3.201
3.201
0.800
0.800
0.800
0.800
0.800
0.800
-4.001
-4.001
-6.400
-6.400
-11.200
-11.200
-15.201
-15.201
-13.599
-13.599
-15.201
-15.201
-19.199
-19.199
-16.800
-16.800
-19.199
-19.199
-16.800
-16.800
-20.001
-20.001
-16.000
002213
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
60.0200
60.0220
60.0220
60.0220
60.0220
60.0210
60.0210
60.0230
60.0230
60.0190
60.0190
60.0180
60.0180
60.0180
60.0180
60.0190
60.0190
60.0150
60.0150
60.0140
60.0140
60.0120
60.0120
60.0100
60.0100
60.0070
60.0070
60.0090
60.0090
60.0030
60.0030
59.9950
59.9950
59.9910
59.9910
59.9920
59.9920
59.9860
59.9860
59.9840
59.9840
59.9840
59.9840
59.9810
59.9810
59.9790
3785.80
3786.88
3786.88
3785.73
3785.73
3785.82
3785.82
3786.28
3786.28
3787.63
3787.63
3789.67
3789.67
3788.48
3788.48
3789.37
3789.37
3788.66
3788.66
3790.67
3790.67
3790.41
3790.41
3791.54
3791.54
3791.03
3791.03
3791.43
3791.43
3790.46
3790.46
3789.58
3789.58
3788.10
3788.10
3788.19
3788.19
3788.54
3788.54
3788.10
3788.10
3786.45
3786.45
3788.81
3788.81
3788.26
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
164.00
164.50
164.50
165.00
165.00
165.50
165.50
166.00
166.00
166.50
166.50
167.00
167.00
167.50
167.50
168.00
168.00
168.50
168.50
169.00
169.00
169.50
169.50
170.00
170.00
170.50
170.50
171.00
171.00
171.50
171.50
172.00
172.00
172.50
172.50
173.00
173.00
173.50
173.50
174.00
174.00
174.50
174.50
175.00
175.00
175.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7608.24
7608.57
7608.57
7608.90
7608.90
7609.23
7609.23
7609.56
7609.56
7609.89
7609.89
7610.22
7610.22
7610.55
7610.55
7610.88
7610.88
7611.21
7611.21
7611.54
7611.54
7611.87
7611.87
7612.20
7612.20
7612.53
7612.53
7612.86
7612.86
7613.19
7613.19
7613.52
7613.52
7613.85
7613.85
7614.18
7614.18
7614.51
7614.51
7614.84
7614.84
7615.17
7615.17
7615.50
7615.50
7615.83
-16.000
-17.599
-17.599
-17.599
-17.599
-16.800
-16.800
-18.399
-18.399
-15.201
-15.201
-14.401
-14.401
-14.401
-14.401
-15.201
-15.201
-12.000
-12.000
-11.200
-11.200
-9.601
-9.601
-7.999
-7.999
-5.600
-5.600
-7.199
-7.199
-2.399
-2.399
4.001
4.001
7.199
7.199
6.400
6.400
11.200
11.200
12.799
12.799
12.799
12.799
15.201
15.201
16.800
002214
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
59.9790
59.9760
59.9760
59.9790
59.9790
59.9780
59.9780
59.9740
59.9740
59.9770
59.9770
59.9750
59.9750
59.9690
59.9690
59.9710
59.9710
59.9780
59.9780
59.9780
59.9780
59.9720
59.9720
59.9750
59.9750
59.9690
59.9690
59.9650
59.9650
59.9690
59.9690
59.9680
59.9680
59.9640
59.9640
59.9720
59.9720
59.9670
59.9670
59.9680
59.9680
59.9670
59.9670
59.9660
59.9660
59.9710
3788.26
3790.47
3790.47
3790.42
3790.42
3789.27
3789.27
3790.43
3790.43
3786.24
3786.24
3788.96
3788.96
3791.88
3791.88
3792.31
3792.31
3788.08
3788.08
3787.14
3787.14
3787.00
3787.00
3786.49
3786.49
3789.21
3789.21
3791.22
3791.22
3790.96
3790.96
3789.03
3789.03
3787.39
3787.39
3784.83
3784.83
3784.32
3784.32
3782.11
3782.11
3779.06
3779.06
3779.21
3779.21
3776.43
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-262.42
-262.42
-262.42
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-258.15
-258.15
-258.15
-258.15
-258.15
-258.15
-258.15
-258.15
-258.15
-258.15
-258.87
-258.87
-258.87
-258.87
-258.87
-258.87
-258.87
-258.87
-258.87
-258.87
-249.34
-249.34
-249.34
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
175.50
176.00
176.00
176.50
176.50
177.00
177.00
177.50
177.50
178.00
178.00
178.50
178.50
179.00
179.00
179.50
179.50
180.00
180.00
180.50
180.50
181.00
181.00
181.50
181.50
182.00
182.00
182.50
182.50
183.00
183.00
183.50
183.50
184.00
184.00
184.50
184.50
185.00
185.00
185.50
185.50
186.00
186.00
186.50
186.50
187.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7615.83
7616.16
7616.16
7616.49
7616.49
7616.82
7616.82
7617.15
7617.15
7617.48
7617.48
7617.81
7617.81
7618.14
7618.14
7618.47
7618.47
7618.80
7618.80
7619.13
7619.13
7619.46
7619.46
7619.79
7619.79
7620.12
7620.12
7620.45
7620.45
7620.78
7620.78
7621.11
7621.11
7621.44
7621.44
7621.77
7621.77
7622.10
7622.10
7622.43
7622.43
7622.76
7622.76
7623.09
7623.09
7623.42
16.800
19.199
19.199
16.800
16.800
17.599
17.599
20.801
20.801
18.399
18.399
20.001
20.001
24.799
24.799
23.199
23.199
17.599
17.599
17.599
17.599
22.400
22.400
20.001
20.001
24.799
24.799
28.000
28.000
24.799
24.799
25.601
25.601
28.799
28.799
22.400
22.400
26.401
26.401
25.601
25.601
26.401
26.401
27.200
27.200
23.199
002215
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
59.9710
59.9650
59.9650
59.9640
59.9640
59.9670
59.9670
59.9680
59.9680
59.9650
59.9650
59.9730
59.9730
59.9650
59.9650
59.9690
59.9690
59.9640
59.9640
59.9790
59.9790
59.9830
59.9830
59.9670
59.9670
59.9620
59.9620
59.9610
59.9610
59.9600
59.9600
59.9590
59.9590
59.9510
59.9510
59.9540
59.9540
59.9560
59.9560
59.9630
59.9630
59.9590
59.9590
59.9630
59.9630
59.9680
3776.43
3776.60
3776.60
3776.02
3776.02
3771.73
3771.73
3768.50
3768.50
3767.37
3767.37
3760.30
3760.30
3761.89
3761.89
3760.58
3760.58
3759.78
3759.78
3757.77
3757.77
3753.09
3753.09
3753.75
3753.75
3759.25
3759.25
3760.96
3760.96
3763.82
3763.82
3763.86
3763.86
3766.13
3766.13
3767.97
3767.97
3765.61
3765.61
3761.57
3761.57
3759.63
3759.63
3752.43
3752.43
3753.83
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-249.34
-249.34
-249.34
-249.34
-249.34
-249.34
-249.34
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.28
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-258.41
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-260.54
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
-257.88
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
187.00
187.50
187.50
188.00
188.00
188.50
188.50
189.00
189.00
189.50
189.50
190.00
190.00
190.50
190.50
191.00
191.00
191.50
191.50
192.00
192.00
192.50
192.50
193.00
193.00
193.50
193.50
194.00
194.00
194.50
194.50
195.00
195.00
195.50
195.50
196.00
196.00
196.50
196.50
197.00
197.00
197.50
197.50
198.00
198.00
198.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7623.42
7623.75
7623.75
7624.08
7624.08
7624.41
7624.41
7624.74
7624.74
7625.07
7625.07
7625.40
7625.40
7625.73
7625.73
7626.06
7626.06
7626.39
7626.39
7626.72
7626.72
7627.05
7627.05
7627.38
7627.38
7627.71
7627.71
7628.04
7628.04
7628.37
7628.37
7628.70
7628.70
7629.03
7629.03
7629.36
7629.36
7629.69
7629.69
7630.02
7630.02
7630.35
7630.35
7630.68
7630.68
7631.01
23.199
28.000
28.000
28.799
28.799
26.401
26.401
25.601
25.601
28.000
28.000
21.600
21.600
28.000
28.000
24.799
24.799
28.799
28.799
16.800
16.800
13.599
13.599
26.401
26.401
30.399
30.399
31.201
31.201
32.001
32.001
32.800
32.800
39.200
39.200
36.801
36.801
35.199
35.199
29.599
29.599
32.800
32.800
29.599
29.599
25.601
002216
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
59.9680
59.9680
59.9680
59.9730
59.9730
59.9650
59.9650
59.9670
59.9670
59.9760
59.9760
59.9690
59.9690
59.9740
59.9740
59.9810
59.9810
59.9810
59.9810
59.9820
59.9820
59.9820
59.9820
59.9790
59.9790
59.9780
59.9780
59.9800
59.9800
59.9800
59.9800
59.9760
59.9760
59.9710
59.9710
59.9740
59.9740
59.9760
59.9760
59.9690
59.9690
59.9740
59.9740
59.9720
59.9720
59.9770
3753.83
3753.52
3753.52
3753.18
3753.18
3753.29
3753.29
3752.36
3752.36
3747.48
3747.48
3741.29
3741.29
3745.74
3745.74
3741.62
3741.62
3738.48
3738.48
3737.40
3737.40
3736.31
3736.31
3735.45
3735.45
3737.54
3737.54
3736.75
3736.75
3736.07
3736.07
3736.57
3736.57
3738.87
3738.87
3738.65
3738.65
3737.38
3737.38
3740.02
3740.02
3742.05
3742.05
3742.52
3742.52
3741.72
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-257.88
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-258.59
-261.91
-261.91
-261.91
-261.91
-261.91
-261.91
-261.91
-261.91
-261.91
-261.91
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-256.75
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-167.43
-164.97
-164.97
-164.97
-164.97
-164.97
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
198.50
199.00
199.00
199.50
199.50
200.00
200.00
200.50
200.50
201.00
201.00
201.50
201.50
202.00
202.00
202.50
202.50
203.00
203.00
203.50
203.50
204.00
204.00
204.50
204.50
205.00
205.00
205.50
205.50
206.00
206.00
206.50
206.50
207.00
207.00
207.50
207.50
208.00
208.00
208.50
208.50
209.00
209.00
209.50
209.50
210.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7631.01
7631.34
7631.34
7631.67
7631.67
7632.00
7632.00
7632.33
7632.33
7632.66
7632.66
7632.99
7632.99
7633.32
7633.32
7633.65
7633.65
7633.98
7633.98
7634.31
7634.31
7634.64
7634.64
7634.97
7634.97
7635.30
7635.30
7635.63
7635.63
7635.96
7635.96
7636.29
7636.29
7636.62
7636.62
7636.95
7636.95
7637.28
7637.28
7637.61
7637.61
7637.94
7637.94
7638.27
7638.27
7638.60
25.601
25.601
25.601
21.600
21.600
28.000
28.000
26.401
26.401
19.199
19.199
24.799
24.799
20.801
20.801
15.201
15.201
15.201
15.201
14.401
14.401
14.401
14.401
16.800
16.800
17.599
17.599
16.000
16.000
16.000
16.000
19.199
19.199
23.199
23.199
20.801
20.801
19.199
19.199
24.799
24.799
20.801
20.801
22.400
22.400
18.399
002217
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
59.9770
59.9780
59.9780
59.9730
59.9730
59.9770
59.9770
59.9780
59.9780
59.9810
59.9810
59.9740
59.9740
59.9710
59.9710
59.9720
59.9720
59.9660
59.9660
59.9710
59.9710
59.9720
59.9720
59.9720
59.9720
59.9730
59.9730
59.9710
59.9710
59.9820
59.9820
59.9850
59.9850
59.9870
59.9870
59.9890
59.9890
59.9870
59.9870
59.9940
59.9940
60.0010
60.0010
60.0040
60.0040
60.0120
3741.72
3740.63
3740.63
3740.78
3740.78
3741.27
3741.27
3738.97
3738.97
3738.88
3738.88
3738.10
3738.10
3743.51
3743.51
3745.25
3745.25
3747.34
3747.34
3749.75
3749.75
3744.68
3744.68
3743.15
3743.15
3739.45
3739.45
3731.83
3731.83
3736.23
3736.23
3733.43
3733.43
3730.51
3730.51
3725.46
3725.46
3720.11
3720.11
3725.66
3725.66
3727.75
3727.75
3727.68
3727.68
3725.01
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-164.97
-164.97
-164.97
-164.97
-164.97
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-157.63
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-155.53
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
-160.45
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-163.96
-166.07
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
210.00
210.50
210.50
211.00
211.00
211.50
211.50
212.00
212.00
212.50
212.50
213.00
213.00
213.50
213.50
214.00
214.00
214.50
214.50
215.00
215.00
215.50
215.50
216.00
216.00
216.50
216.50
217.00
217.00
217.50
217.50
218.00
218.00
218.50
218.50
219.00
219.00
219.50
219.50
220.00
220.00
220.50
220.50
221.00
221.00
221.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7638.60
7638.93
7638.93
7639.26
7639.26
7639.59
7639.59
7639.92
7639.92
7640.25
7640.25
7640.58
7640.58
7640.91
7640.91
7641.24
7641.24
7641.57
7641.57
7641.90
7641.90
7642.23
7642.23
7642.56
7642.56
7642.89
7642.89
7643.22
7643.22
7643.55
7643.55
7643.88
7643.88
7644.21
7644.21
7644.54
7644.54
7644.87
7644.87
7645.20
7645.20
7645.53
7645.53
7645.86
7645.86
7646.19
18.399
17.599
17.599
21.600
21.600
18.399
18.399
17.599
17.599
15.201
15.201
20.801
20.801
23.199
23.199
22.400
22.400
27.200
27.200
23.199
23.199
22.400
22.400
22.400
22.400
21.600
21.600
23.199
23.199
14.401
14.401
12.000
12.000
10.400
10.400
8.801
8.801
10.400
10.400
4.800
4.800
-0.800
-0.800
-3.201
-3.201
-9.601
002218
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
60.0120
60.0190
60.0190
60.0250
60.0250
60.0270
60.0270
60.0290
60.0290
60.0360
60.0360
60.0370
60.0370
60.0410
60.0410
60.0440
60.0440
60.0460
60.0460
60.0460
60.0460
60.0430
60.0430
60.0440
60.0440
3725.01
3726.02
3726.02
3716.37
3716.37
3717.56
3717.56
3715.17
3715.17
3710.28
3710.28
3699.36
3699.36
3704.59
3704.59
3702.48
3702.48
3700.83
3700.83
3699.73
3699.73
3690.48
3690.48
3696.88
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-166.07
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-163.77
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
221.50
222.00
222.00
222.50
222.50
223.00
223.00
223.50
223.50
224.00
224.00
224.50
224.50
225.00
225.00
225.50
225.50
226.00
226.00
226.50
226.50
227.00
227.00
227.50
227.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7646.19
7646.52
7646.52
7646.85
7646.85
7647.18
7647.18
7647.51
7647.51
7647.84
7647.84
7648.17
7648.17
7648.50
7648.50
7648.83
7648.83
7649.16
7649.16
7649.49
7649.49
7649.82
7649.82
7650.15
7650.15
-9.601
-15.201
-15.201
-20.001
-20.001
-21.600
-21.600
-23.199
-23.199
-28.799
-28.799
-29.599
-29.599
-32.800
-32.800
-35.199
-35.199
-36.801
-36.801
-36.801
-36.801
-34.399
-34.399
-35.199
-35.199
002219
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
lue B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8823
-0.160
3645.30
3770.95
125.65
-52.27
-33.60
94.17
127.77
75.50
350.00
-165.48
0.00
114.25
-4.20
15.00
309.57
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-207.83
1.00
117.36
11.77
0.00
257.30
-52.27
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
121.2453
164.5052
76.38%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7575.405
7577.456
2.051
1.284
-1.63%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
24 second Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
0.983 P.U.
1.393 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002220
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3770.953
3770.953
3770.953
3770.953
3770.953
3770.953
3770.953
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-207.830
-207.830
-207.830
-207.830
-207.830
-207.830
-207.830
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
114.250
114.250
114.250
114.250
114.250
114.250
114.250
114.250
117.357
117.357
117.357
117.357
117.357
117.357
117.357
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7577.456
7577.456
7577.456
7577.456
7577.456
7577.456
7577.456
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
94.171
94.171
94.171
94.171
94.171
94.171
94.171
3720.799
3720.799
3720.799
3720.799
3720.799
3720.799
3720.799
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.883
59.883
59.883
59.883
3779.625
3779.625
3779.625
3779.625
335.000
335.000
335.000
335.000
002221
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.883
59.883
59.883
3779.625
3779.625
3779.625
335.000
335.000
335.000
002222
002223
002224
002225
002226
002227
002228
002229
002230
002231
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8831
-0.159
3645.30
3779.63
134.32
-53.49
-33.60
93.49
127.09
73.60
350.00
-165.48
0.00
114.25
-4.20
15.00
309.57
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-209.89
1.14
118.14
11.69
0.00
256.09
-53.49
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -103.000 MW/0.1 Hz
Post-Perturbation Bias Setting -103.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -43.2598 MW
EPFR for Bias Setting Post-Perturbation Average 120.3630 MW
EPFR for Bias Setting Delta 163.6228 MW
Primary Frequency Response Delivery of Bias
82.09%
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8883
-0.154
3645.30
3784.13
138.83
-53.27
-33.60
89.38
122.98
69.72
350.00
-165.48
0.00
114.25
-4.20
15.00
309.57
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-210.82
2.09
118.86
11.17
0.00
256.31
-53.27
Pre-Perturbation BA Load 7575.405 MW
Post-Perturbation BA Load 7577.974 MW
Pre to Post Perturbation BA Load Change
2.569 MW
Load Dampening Frequency Response
1.617 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
-1.91%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
1.057 P.U.
1.478 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.129
1.562
Pumped
Hydro
Load (-) Gen (+)
MW
002232
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-209.885
-209.885
-209.885
-209.885
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1.143
1.143
1.143
1.143
114.250
114.250
114.250
114.250
114.250
114.250
114.250
114.250
118.143
118.143
118.143
118.143
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7577.974
7577.974
7577.974
7577.974
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
93.486
93.486
93.486
93.486
3718.901
3718.901
3718.901
3718.901
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.888
59.888
59.888
3784.134
3784.134
3784.134
335.000
335.000
335.000
-210.820
-210.820
-210.820
2.091
2.091
2.091
002233
-209.885
-209.885
-209.885
1.143
1.143
1.143
118.143
118.143
118.143
10.000
10.000
10.000
0.000
0.000
0.000
-103.000 7577.974
-103.000 7577.974
-103.000 7577.974
93.486
93.486
93.486
3718.901 T+26 sec
3718.901 T+28 sec
3718.901 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3784.134
3784.134
3784.134
3784.134
3784.134
3784.134
3784.134
3784.134
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-210.820
-210.820
-210.820
-210.820
-210.820
-210.820
-210.820
-210.820
2.091
2.091
2.091
2.091
2.091
2.091
2.091
2.091
002234
002235
002236
002237
002238
002239
002240
002241
002242
002243
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
115.0787
158.3386
87.68%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7575.405
7578.450
3.045
1.981
-2.19%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8880
-0.154
3645.30
3787.80
142.49
-52.29
-33.60
89.60
123.20
70.91
350.00
-165.48
0.00
114.25
-4.20
15.00
309.57
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-211.75
3.33
119.50
11.20
0.00
257.28
-52.29
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.157 P.U.
1.581 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002244
114.250
114.250
114.250
114.250
114.250
114.250
114.250
114.250
118.864
118.864
118.864
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7578.450
7578.450
7578.450
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
89.382
89.382
89.382
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
3715.018 T+20 sec
3715.018 T+22 sec
3715.018 T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
114.250
114.250
114.250
114.250
114.250
114.250
114.250
114.250
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.888
59.888
59.888
59.888
3787.795
3787.795
3787.795
3787.795
335.000
335.000
335.000
335.000
-211.753
-211.753
-211.753
-211.753
3.333
3.333
3.333
3.333
119.500
119.500
119.500
119.500
10.000
10.000
10.000
10.000
002245
118.864
118.864
118.864
118.864
118.864
118.864
118.864
118.864
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7578.450
7578.450
7578.450
7578.450
7578.450
7578.450
7578.450
7578.450
89.382
89.382
89.382
89.382
89.382
89.382
89.382
89.382
3715.018
3715.018
3715.018
3715.018
3715.018
3715.018
3715.018
3715.018
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
3787.795
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
-211.753
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
3.333
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
119.500
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
002246
002247
002248
002249
002250
002251
002252
002253
002254
002255
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
115.3599
158.6197
89.83%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7575.405
7578.870
3.465
2.250
-2.43%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:08
60.0420
59.8888
-0.153
3645.30
3788.85
143.54
-52.43
-33.60
88.99
122.59
70.16
350.00
-165.48
0.00
114.25
-4.20
15.00
309.57
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-212.06
3.47
119.62
11.12
0.00
257.15
-52.43
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.171 P.U.
1.599 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002256
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7578.870
7578.870
7578.870
7578.870
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
89.600
89.600
89.600
89.600
3716.209
3716.209
3716.209
3716.209
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
3645.303
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
114.250
114.250
114.250
114.250
114.250
114.250
114.250
114.250
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.889
59.889
59.889
3788.847
3788.847
3788.847
335.000
335.000
335.000
-212.065
-212.065
-212.065
3.471
3.471
3.471
119.618
119.618
119.618
10.000
10.000
10.000
0.000
0.000
0.000
002257
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
7578.870
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
89.600
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
3716.209
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
3788.847
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
-212.065
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
3.471
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
119.618
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002258
002259
002260
002261
002262
002263
002264
002265
002266
002267
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
114.5723
157.8321
90.95%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
7575.405
7578.948
3.543
2.312
-2.47%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002268
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
7575.405
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-103.000
-103.000
-103.000
7578.948
7578.948
7578.948
88.988
88.988
88.988
3715.464
3715.464
3715.464
002269
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
7578.948
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
88.988
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
3715.464
002270
Monday, October 12, 2009
Balancing Authority
60.08
1.171
My BA
60.0420
1.599
Initial P.U. Performance
Initial P.U. Performance Adjusted
3850.0
20 to 52 second Average Period Evaluation
60.06
60.04
3788.85
60.02
3800.0
60
59.98
59.96
3750.0
3715.464
59.92
MW
Frequency - Hz
59.94
59.9
3700.0
59.88
59.8888
59.86
59.84
3650.0
59.82
3645.30
59.8
59.78
3600.0
59.76
59.74
59.72
2:26:24
2:26:34
2:26:44
2:26:54
Hz
2:27:04
2:27:14
Average Frequency
2:27:24
MW
2:27:34
Average MW
2:27:44
2:27:54
EPFR for FRO Adjusted
2:28:04
2:28:14
3550.0
2:28:24
002271
Monday, October 12, 2009
0.895 Sustained P.U. Performance
My BA
60.08
3850.0
60.06
60.04
3800.0
60.02
60
59.98
3750.0
59.96
3700.0
59.92
MW
Frequency - Hz
59.94
59.9
59.88
3650.0
59.86
59.84
3600.0
59.82
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:24
2:27:24
2:28:24
2:29:24
Hz
2:30:24
2:31:24
2:32:24
Interchange MW
2:33:24
2:34:24
2:35:24
Recovery Period Target MW
2:36:24
2:37:24
2:38:24
2:39:24
Recovery Period Ramp MW
2:40:24
2:41:24
3500.0
2:42:24
002272
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:22
FPointA
Hz
60.0410
A Value
Hz
60.0420
t(0) Time
2:27:24
C Value
Hz
59.8360
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8822861 -396.90693 59.8831427
-398.8954 59.8887648 -412.28807 59.8880001 -411.60431 59.8887648 -413.51972
002273
Value A Data
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
60.042
3645.30
350.00
-165.48
0.00
114.25
-4.20
15.00
-103 7575.405
Value B
Bias
Setting
EPFR
Frequency
MW
Hz
-43.2598 59.882286
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
Actual
Schedules
Load
Hydro
Units
Response
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+)
MW
MW
MW
MW
MW
MW
3770.95
335.00
-207.83
1.00
117.36
11.77
002274
Value B
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
1.393
Initial
Performance
Unadjusted
P.U.
0.983
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Bias
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Setting
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
P.U.
MW/0.1 Hz
MW
MW
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
0.895
-103 7577.456 121.2453 59.883143
3779.63
335.00
-209.89
1.14
118.14
11.69
0.00
Sustained
Performance
Initial
Performance
Adjusted
P.U.
1.478
002275
Value B
Initial
Performance
Unadjusted
P.U.
1.057
Sustained
Performance
P.U.
0.895
BA
BA
Bias
Load
Setting
MW
MW
-103 7577.974
Bias
Setting
EPFR
Frequency
MW
Hz
120.363 59.888273
20 to 40 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
3784.13
335.00
-210.82
2.09
118.86
11.17
0.00
Initial
Performance
Adjusted
P.U.
1.562
Initial
Performance
Unadjusted
P.U.
1.129
Sustained
Performance
P.U.
0.895
002276
Value B
BA
Bias
Setting
MW
-103
18 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW
MW
7578.45 115.0787
59.888
3787.80
335.00
-211.75
3.33
119.50
11.20
0.00
Value B
Initial
Performance
Adjusted
P.U.
1.581
Initial
Performance
Unadjusted
P.U.
1.157
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.895
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7578.87 115.3599 59.888765
002277
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Ramping
Actual
Schedules
Load
Hydro
Units
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+)
MW
MW
MW
MW
MW
3788.85
335.00
-165.48
3.47
119.62
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.12
0.00
Initial
Performance
Adjusted
P.U.
1.599
Initial
Performance
Unadjusted
P.U.
1.171
Sustained
Performance
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
P.U.
MW/0.1 Hz
MW
MW
0.895
-103 7578.948 114.5723
002278
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
C
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Ramping units
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 5 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with up to 60 minutes of data. Be sure "Data" worksheet is clear of any old data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data. The data must be numbers not text.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 190 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A190"
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency of the event on the center vertical grid line of the graph (Red Trend).
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 258.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A258"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if you're interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar.
When set appropriately, the "Target" trend on the "Sustained" graph will model what Interchange Actual should have done during the event recovery period based on your minimum FRO.
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
002279
Time (T)
10/12/09 02:12:00
10/12/09 02:12:05
10/12/09 02:12:10
10/12/09 02:12:15
10/12/09 02:12:20
10/12/09 02:12:25
10/12/09 02:12:30
10/12/09 02:12:35
10/12/09 02:12:40
10/12/09 02:12:45
10/12/09 02:12:50
10/12/09 02:12:55
10/12/09 02:13:00
10/12/09 02:13:05
10/12/09 02:13:10
10/12/09 02:13:15
10/12/09 02:13:20
10/12/09 02:13:25
10/12/09 02:13:30
10/12/09 02:13:35
10/12/09 02:13:40
10/12/09 02:13:45
10/12/09 02:13:50
10/12/09 02:13:55
10/12/09 02:14:00
10/12/09 02:14:05
10/12/09 02:14:10
10/12/09 02:14:15
10/12/09 02:14:20
Hz
59.98
59.982
59.981
59.979
59.98
59.986
59.976
59.979
59.987
59.993
59.995
59.995
59.994
59.997
60.001
60.003
60
60.003
60.001
60.001
60.004
60.005
60.003
59.999
59.998
59.995
59.996
60.001
60.007
Net
Actual
Interchange
MW
3669.878
3670.949
3671.548
3672.174
3674.263
3675.092
3669.33
3673.56
3673.834
3671.22
3671.283
3668.129
3669.291
3670.683
3670.212
3671.184
3670.267
3670.249
3669.899
3671.628
3671.968
3671.875
3672.873
3673.531
3673.186
3673.365
3672.093
3671.073
3671.441
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonTransferred
Contingent
Conforming
Pumped
Ramping
Frequency
BA
BA
Load
Hydro
Units
Response
Lost Generation
Bias
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW
MW/0.1 Hz
MW
MW/0.1 Hz
351.361511
0
0
10
15
-103
351.361511
0
0.5
10
15
-103
351.361511
0
1
10
15
-103
357.94751
0
1.5
10
15
-103
357.94751
0
2
10
15
-103
357.94751
0
2.5
10
15
-103
357.94751
0
3
10
15
-103
357.94751
0
3.5
10
15
-103
360.234741
0
4
10
15
-103
360.234741
0
4.5
10
15
-103
360.234741
0
5
10
15
-103
360.234741
0
5.5
10
15
-103
360.234741
0
6
10
15
-103
346.525879
0
6.5
10
15
-103
346.525879
0
7
10
15
-103
346.525879
0
7.5
10
15
-103
346.525879
0
8
10
15
-103
346.525879
0
8.5
10
15
-103
296.443359
0
9
10
15
-103
296.443359
0
9.5
10
15
-103
296.443359
0
10
10
15
-103
296.443359
0
10.5
10
15
-103
296.443359
0
11
10
15
-103
341.061157
0
11.5
10
15
-103
341.061157
0
12
10
15
-103
341.061157
0
12.5
10
15
-103
341.061157
0
13
10
15
-103
341.061157
0
13.5
10
15
-103
322.826294
0
14
10
15
-103
BA
Load
MW
7500
7500.33
7500.66
7500.99
7501.32
7501.65
7501.98
7502.31
7502.64
7502.97
7503.3
7503.63
7503.96
7504.29
7504.62
7504.95
7505.28
7505.61
7505.94
7506.27
7506.6
7506.93
7507.26
7507.59
7507.92
7508.25
7508.58
7508.91
7509.24
002280
10/12/09 02:14:25
10/12/09 02:14:30
10/12/09 02:14:35
10/12/09 02:14:40
10/12/09 02:14:45
10/12/09 02:14:50
10/12/09 02:14:55
10/12/09 02:15:00
10/12/09 02:15:05
10/12/09 02:15:10
10/12/09 02:15:15
10/12/09 02:15:20
10/12/09 02:15:25
10/12/09 02:15:30
10/12/09 02:15:35
10/12/09 02:15:40
10/12/09 02:15:45
10/12/09 02:15:50
10/12/09 02:15:55
10/12/09 02:16:00
10/12/09 02:16:05
10/12/09 02:16:10
10/12/09 02:16:15
10/12/09 02:16:20
10/12/09 02:16:25
10/12/09 02:16:30
10/12/09 02:16:35
10/12/09 02:16:40
10/12/09 02:16:45
10/12/09 02:16:50
10/12/09 02:16:55
10/12/09 02:17:00
10/12/09 02:17:05
10/12/09 02:17:10
60.002
59.999
60.007
60.009
59.997
59.994
60.001
59.995
59.986
59.988
59.988
59.984
59.982
59.985
59.987
59.987
59.98
59.987
59.988
59.978
59.979
59.988
59.989
59.992
59.995
59.998
59.999
59.992
59.998
60.006
60.009
60.011
60.008
60.012
3670.513
3672.713
3670.826
3671.809
3673.255
3675.426
3675.311
3675.166
3674.906
3676.714
3675.543
3676.931
3677.361
3679.228
3677.627
3676.409
3676.915
3679.233
3678.344
3677.678
3678.729
3680.287
3678.489
3678.74
3677.063
3678.49
3678.951
3679.148
3678.997
3678.493
3677.899
3679.209
3679.057
3680.604
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
322.826294
322.826294
322.826294
322.826294
321.544403
321.544403
321.544403
321.544403
321.544403
362.136261
362.136261
362.136261
362.136261
362.136261
336.311798
336.311798
336.311798
336.311798
336.311798
316.443054
316.443054
316.443054
316.443054
316.443054
325.464294
325.464294
325.464294
325.464294
325.464294
336.614166
336.614166
336.614166
336.614166
336.614166
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
14.5
15
15.5
16
16.5
17
17.5
18
18.5
19
19.5
20
20.5
21
21.5
22
22.5
23
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
28.5
29
29.5
30
30.5
31
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7509.57
7509.9
7510.23
7510.56
7510.89
7511.22
7511.55
7511.88
7512.21
7512.54
7512.87
7513.2
7513.53
7513.86
7514.19
7514.52
7514.85
7515.18
7515.51
7515.84
7516.17
7516.5
7516.83
7517.16
7517.49
7517.82
7518.15
7518.48
7518.81
7519.14
7519.47
7519.8
7520.13
7520.46
002281
10/12/09 02:17:15
10/12/09 02:17:20
10/12/09 02:17:25
10/12/09 02:17:30
10/12/09 02:17:35
10/12/09 02:17:40
10/12/09 02:17:45
10/12/09 02:17:50
10/12/09 02:17:55
10/12/09 02:18:00
10/12/09 02:18:05
10/12/09 02:18:10
10/12/09 02:18:15
10/12/09 02:18:20
10/12/09 02:18:25
10/12/09 02:18:30
10/12/09 02:18:35
10/12/09 02:18:40
10/12/09 02:18:45
10/12/09 02:18:50
10/12/09 02:18:55
10/12/09 02:19:00
10/12/09 02:19:05
10/12/09 02:19:10
10/12/09 02:19:15
10/12/09 02:19:20
10/12/09 02:19:25
10/12/09 02:19:30
10/12/09 02:19:35
10/12/09 02:19:40
10/12/09 02:19:45
10/12/09 02:19:50
10/12/09 02:19:55
10/12/09 02:20:00
60.01
60.009
60.006
60.009
60.009
60.004
59.999
59.994
59.994
59.995
59.99
59.983
59.977
59.999
59.989
59.984
59.985
59.986
59.981
59.998
60.007
59.981
59.974
59.974
59.979
59.984
59.988
59.987
59.985
59.983
59.989
59.982
59.981
59.986
3680.263
3679.561
3679.912
3679.888
3679.261
3679.025
3678.295
3678.236
3677.772
3677.093
3678.516
3680.197
3677.921
3682.07
3678.077
3678.427
3677.822
3677.397
3678.617
3681.252
3678.161
3676.222
3677.49
3675.437
3683.829
3681.108
3676.752
3671.942
3670.129
3672.048
3672.414
3671.837
3670.372
3671.401
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
316.726166
316.726166
316.726166
316.726166
316.726166
320.195526
320.195526
320.195526
320.195526
320.195526
341.86615
341.86615
341.86615
341.86615
341.86615
348.597839
348.597839
348.597839
348.597839
348.597839
329.085022
329.085022
329.085022
329.085022
329.085022
342.418243
342.418243
342.418243
342.418243
342.418243
338.794647
338.794647
338.794647
338.794647
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
31.5
32
32.5
33
33.5
34
34.5
35
35.5
36
36.5
37
37.5
38
38.5
39
39.5
40
40.5
41
41.5
42
42.5
43
43.5
44
44.5
45
45.5
46
46.5
47
47.5
48
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7520.79
7521.12
7521.45
7521.78
7522.11
7522.44
7522.77
7523.1
7523.43
7523.76
7524.09
7524.42
7524.75
7525.08
7525.41
7525.74
7526.07
7526.4
7526.73
7527.06
7527.39
7527.72
7528.05
7528.38
7528.71
7529.04
7529.37
7529.7
7530.03
7530.36
7530.69
7531.02
7531.35
7531.68
002282
10/12/09 02:20:05
10/12/09 02:20:10
10/12/09 02:20:15
10/12/09 02:20:20
10/12/09 02:20:25
10/12/09 02:20:30
10/12/09 02:20:35
10/12/09 02:20:40
10/12/09 02:20:45
10/12/09 02:20:50
10/12/09 02:20:55
10/12/09 02:21:00
10/12/09 02:21:05
10/12/09 02:21:10
10/12/09 02:21:15
10/12/09 02:21:20
10/12/09 02:21:25
10/12/09 02:21:30
10/12/09 02:21:35
10/12/09 02:21:40
10/12/09 02:21:45
10/12/09 02:21:50
10/12/09 02:21:55
10/12/09 02:22:00
10/12/09 02:22:05
10/12/09 02:22:10
10/12/09 02:22:15
10/12/09 02:22:20
10/12/09 02:22:25
10/12/09 02:22:30
10/12/09 02:22:35
10/12/09 02:22:40
10/12/09 02:22:45
10/12/09 02:22:50
59.987
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.977
59.973
59.973
59.975
59.977
59.98
59.981
59.982
59.981
59.985
59.989
59.998
60.004
60.013
60.013
60.01
60.019
60.02
60.021
60.019
60.025
60.02
60.018
60.019
60.023
60.025
3670.296
3668.59
3670.263
3670.102
3672.442
3671.947
3670.137
3672.391
3672.626
3673.183
3676.623
3676.543
3675.256
3671.277
3669.963
3669.497
3666.482
3666.911
3667.456
3665.262
3663.229
3661.695
3662.959
3664.139
3663.265
3661.929
3658.661
3657.571
3658.015
3659.224
3658.155
3659.778
3662.387
3662.39
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
338.794647
335.931
335.931
335.931
335.931
335.931
339.712402
339.712402
339.712402
339.712402
339.712402
332.024658
332.024658
332.024658
332.024658
332.024658
330.759033
330.759033
330.759033
330.759033
330.759033
323.419952
323.419952
323.419952
323.419952
323.419952
342.350922
342.350922
342.350922
342.350922
342.350922
345.081818
345.081818
345.081818
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
48.5
49
49.5
50
50.5
51
51.5
52
52.5
53
53.5
54
54.5
55
55.5
56
56.5
57
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
63
63.5
64
64.5
65
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7532.01
7532.34
7532.67
7533
7533.33
7533.66
7533.99
7534.32
7534.65
7534.98
7535.31
7535.64
7535.97
7536.3
7536.63
7536.96
7537.29
7537.62
7537.95
7538.28
7538.61
7538.94
7539.27
7539.6
7539.93
7540.26
7540.59
7540.92
7541.25
7541.58
7541.91
7542.24
7542.57
7542.9
002283
10/12/09 02:22:55
10/12/09 02:23:00
10/12/09 02:23:05
10/12/09 02:23:10
10/12/09 02:23:15
10/12/09 02:23:20
10/12/09 02:23:25
10/12/09 02:23:30
10/12/09 02:23:35
10/12/09 02:23:40
10/12/09 02:23:45
10/12/09 02:23:50
10/12/09 02:23:55
10/12/09 02:24:00
10/12/09 02:24:05
10/12/09 02:24:10
10/12/09 02:24:15
10/12/09 02:24:20
10/12/09 02:24:25
10/12/09 02:24:30
10/12/09 02:24:35
10/12/09 02:24:40
10/12/09 02:24:45
10/12/09 02:24:50
10/12/09 02:24:55
10/12/09 02:25:00
10/12/09 02:25:05
10/12/09 02:25:10
10/12/09 02:25:15
10/12/09 02:25:20
10/12/09 02:25:25
10/12/09 02:25:30
10/12/09 02:25:35
10/12/09 02:25:40
60.02
60.02
60.021
60.014
60.013
60.008
60.011
60.009
60.009
60.002
59.996
59.998
59.998
59.995
59.993
59.982
59.982
59.982
59.978
59.974
59.979
59.98
59.987
59.99
59.991
59.993
59.996
60.003
60.005
60.004
60.01
60.011
60.014
60.011
3663.539
3662.552
3663.91
3662.791
3664.315
3665.798
3667.677
3666.688
3667.696
3667.043
3665.88
3665.802
3664.948
3666.133
3667.084
3667.337
3668.691
3669.606
3670.265
3673.243
3676.418
3674.637
3674.768
3673.514
3673.056
3671.493
3670.028
3671.578
3673.819
3673.182
3672.363
3672.261
3673.553
3674.537
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
345.081818
345.081818
346.537384
346.537384
346.537384
346.537384
346.537384
342.905762
342.905762
342.905762
342.905762
342.905762
340.094391
340.094391
340.094391
340.094391
340.094391
342.771179
342.771179
342.771179
342.771179
342.771179
342.909912
342.909912
342.909912
342.909912
342.909912
343.286011
343.286011
343.286011
343.286011
343.286011
331.852966
331.852966
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
65.5
66
66.5
67
67.5
68
68.5
69
69.5
70
70.5
71
71.5
72
72.5
73
73.5
74
74.5
75
75.5
76
76.5
77
77.5
78
78.5
79
79.5
80
80.5
81
81.5
82
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7543.23
7543.56
7543.89
7544.22
7544.55
7544.88
7545.21
7545.54
7545.87
7546.2
7546.53
7546.86
7547.19
7547.52
7547.85
7548.18
7548.51
7548.84
7549.17
7549.5
7549.83
7550.16
7550.49
7550.82
7551.15
7551.48
7551.81
7552.14
7552.47
7552.8
7553.13
7553.46
7553.79
7554.12
002284
10/12/09 02:25:45
10/12/09 02:25:50
10/12/09 02:25:55
10/12/09 02:26:00
10/12/09 02:26:05
10/12/09 02:26:10
10/12/09 02:26:15
10/12/09 02:26:20
10/12/09 02:26:25
10/12/09 02:26:30
10/12/09 02:26:35
10/12/09 02:26:40
10/12/09 02:26:45
10/12/09 02:26:50
10/12/09 02:26:55
10/12/09 02:27:00
10/12/09 02:27:05
10/12/09 02:27:10
10/12/09 02:27:15
10/12/09 02:27:20
10/12/09 02:27:25
10/12/09 02:27:30
10/12/09 02:27:35
10/12/09 02:27:40
10/12/09 02:27:45
10/12/09 02:27:50
10/12/09 02:27:55
10/12/09 02:28:00
10/12/09 02:28:05
10/12/09 02:28:10
10/12/09 02:28:15
10/12/09 02:28:20
10/12/09 02:28:25
10/12/09 02:28:30
60.017
60.014
60.014
60.019
60.019
60.026
60.019
60.02
60.021
60.019
60.022
60.037
60.037
60.048
60.041
60.039
60.043
60.041
60.041
59.852
59.869
59.88
59.875
59.886
59.887
59.895
59.893
59.891
59.885
59.887
59.888
59.882
59.857
59.858
3672.563
3672.388
3671.288
3672.982
3671.193
3671.189
3664.495
3666.821
3670.267
3672.493
3672.164
3669.983
3661.599
3651.492
3648.246
3654.294
3651.059
3648.236
3645.446
3641.191
3734.904
3737.157
3766.194
3769.925
3782.5
3784.73
3788.328
3788.472
3794.374
3800.427
3802.925
3804.388
3809.237
3814.862
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
331.852966
331.852966
331.852966
329.98822
329.98822
329.98822
329.98822
329.98822
255.444168
165.101685
165.101685
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
002285
10/12/09 02:28:35
10/12/09 02:28:40
10/12/09 02:28:45
10/12/09 02:28:50
10/12/09 02:28:55
10/12/09 02:29:00
10/12/09 02:29:05
10/12/09 02:29:10
10/12/09 02:29:15
10/12/09 02:29:20
10/12/09 02:29:25
10/12/09 02:29:30
10/12/09 02:29:35
10/12/09 02:29:40
10/12/09 02:29:45
10/12/09 02:29:50
10/12/09 02:29:55
10/12/09 02:30:00
10/12/09 02:30:05
10/12/09 02:30:10
10/12/09 02:30:15
10/12/09 02:30:20
10/12/09 02:30:25
10/12/09 02:30:30
10/12/09 02:30:35
10/12/09 02:30:40
10/12/09 02:30:45
10/12/09 02:30:50
10/12/09 02:30:55
10/12/09 02:31:00
10/12/09 02:31:05
10/12/09 02:31:10
10/12/09 02:31:15
10/12/09 02:31:20
59.866
59.866
59.874
59.883
59.89
59.893
59.903
59.904
59.911
59.917
59.92
59.917
59.921
59.925
59.927
59.928
59.929
59.937
59.945
59.942
59.942
59.947
59.951
59.951
59.952
59.952
59.952
59.952
59.954
59.956
59.956
59.961
59.962
59.966
3826.053
3827.524
3826.454
3823.826
3818.055
3815.01
3809.652
3805.593
3793.975
3791.502
3784.563
3781.701
3774.604
3773.958
3769.63
3767.643
3766.788
3765.672
3765.105
3758.387
3746.889
3749.593
3749.077
3740.259
3727.838
3722.649
3718.142
3713.694
3710.81
3714.623
3716.461
3717.759
3722.658
3722.278
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
99.5
100
100.5
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7565.67
7566
7566.33
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
002286
10/12/09 02:31:25
10/12/09 02:31:30
10/12/09 02:31:35
10/12/09 02:31:40
10/12/09 02:31:45
10/12/09 02:31:50
10/12/09 02:31:55
10/12/09 02:32:00
10/12/09 02:32:05
10/12/09 02:32:10
10/12/09 02:32:15
10/12/09 02:32:20
10/12/09 02:32:25
10/12/09 02:32:30
10/12/09 02:32:35
10/12/09 02:32:40
10/12/09 02:32:45
10/12/09 02:32:50
10/12/09 02:32:55
10/12/09 02:33:00
10/12/09 02:33:05
10/12/09 02:33:10
10/12/09 02:33:15
10/12/09 02:33:20
10/12/09 02:33:25
10/12/09 02:33:30
10/12/09 02:33:35
10/12/09 02:33:40
10/12/09 02:33:45
10/12/09 02:33:50
10/12/09 02:33:55
10/12/09 02:34:00
10/12/09 02:34:05
10/12/09 02:34:10
59.97
59.969
59.97
59.973
59.978
59.978
59.978
59.982
59.98
59.979
59.983
59.989
59.987
59.992
59.989
59.983
59.993
59.999
59.999
60.002
60.007
60.014
60.019
60.017
60.023
60.021
60.024
60.02
60.024
60.022
60.022
60.023
60.022
60.018
3723.984
3723.893
3728.053
3732.53
3736.907
3738.699
3741.794
3746.608
3751.558
3755.599
3760.405
3761.407
3764.958
3766.433
3768.634
3772.445
3775.841
3774.866
3778.554
3781.256
3783.896
3785.768
3786.304
3787.516
3788.607
3787.537
3787.93
3786.875
3785.018
3785.949
3786.877
3785.726
3785.798
3786.939
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
354.89566
354.89566
340.46936
340.46936
340.46936
340.46936
340.46936
337.642914
337.642914
337.642914
337.642914
337.642914
284.36084
284.36084
284.36084
284.36084
284.36084
260.467987
260.467987
260.467987
260.467987
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
002287
10/12/09 02:34:15
10/12/09 02:34:20
10/12/09 02:34:25
10/12/09 02:34:30
10/12/09 02:34:35
10/12/09 02:34:40
10/12/09 02:34:45
10/12/09 02:34:50
10/12/09 02:34:55
10/12/09 02:35:00
10/12/09 02:35:05
10/12/09 02:35:10
10/12/09 02:35:15
10/12/09 02:35:20
10/12/09 02:35:25
10/12/09 02:35:30
10/12/09 02:35:35
10/12/09 02:35:40
10/12/09 02:35:45
10/12/09 02:35:50
10/12/09 02:35:55
10/12/09 02:36:00
10/12/09 02:36:05
10/12/09 02:36:10
10/12/09 02:36:15
10/12/09 02:36:20
10/12/09 02:36:25
10/12/09 02:36:30
10/12/09 02:36:35
10/12/09 02:36:40
10/12/09 02:36:45
10/12/09 02:36:50
10/12/09 02:36:55
10/12/09 02:37:00
60.018
60.016
60.016
60.012
60.01
60.009
60.01
59.995
59.991
59.988
59.985
59.984
59.981
59.977
59.976
59.978
59.974
59.977
59.973
59.971
59.978
59.975
59.976
59.969
59.965
59.97
59.965
59.972
59.967
59.969
59.967
59.971
59.965
59.97
3789.673
3788.479
3789.005
3788.933
3790.411
3791.54
3791.443
3790.603
3789.585
3788.105
3788.497
3788.571
3786.453
3788.813
3788.41
3790.665
3789.267
3790.43
3787.442
3790.602
3792.311
3788.08
3787.164
3787.405
3789.214
3791.221
3788.824
3789.167
3784.831
3784.32
3779.352
3778.633
3776.429
3776.597
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
260.467987
253.141541
253.141541
253.141541
253.141541
253.141541
251.929871
251.929871
251.929871
251.929871
251.929871
250.674194
250.674194
250.674194
250.674194
250.674194
253.631866
253.631866
253.631866
253.631866
253.631866
246.957306
246.957306
246.957306
246.957306
246.957306
254.541779
254.541779
254.541779
254.541779
254.541779
256.571594
256.571594
256.571594
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
002288
10/12/09 02:37:05
10/12/09 02:37:10
10/12/09 02:37:15
10/12/09 02:37:20
10/12/09 02:37:25
10/12/09 02:37:30
10/12/09 02:37:35
10/12/09 02:37:40
10/12/09 02:37:45
10/12/09 02:37:50
10/12/09 02:37:55
10/12/09 02:38:00
10/12/09 02:38:05
10/12/09 02:38:10
10/12/09 02:38:15
10/12/09 02:38:20
10/12/09 02:38:25
10/12/09 02:38:30
10/12/09 02:38:35
10/12/09 02:38:40
10/12/09 02:38:45
10/12/09 02:38:50
10/12/09 02:38:55
10/12/09 02:39:00
10/12/09 02:39:05
10/12/09 02:39:10
10/12/09 02:39:15
10/12/09 02:39:20
10/12/09 02:39:25
10/12/09 02:39:30
10/12/09 02:39:35
10/12/09 02:39:40
10/12/09 02:39:45
10/12/09 02:39:50
59.969
59.965
59.973
59.968
59.967
59.979
59.983
59.965
59.962
59.96
59.959
59.953
59.957
59.963
59.959
59.965
59.968
59.973
59.965
59.972
59.975
59.974
59.981
59.982
59.984
59.979
59.978
59.981
59.978
59.971
59.974
59.972
59.971
59.972
3773.17
3768.793
3767.366
3760.295
3761.777
3760.157
3757.773
3753.087
3758.225
3758.041
3763.822
3763.858
3768.339
3767.438
3761.57
3759.627
3750.102
3753.51
3753.178
3753.291
3749.398
3740.37
3745.738
3741.618
3738.901
3737.273
3735.448
3737.541
3736.693
3736.094
3738.875
3738.647
3737.892
3740.329
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
256.571594
256.571594
258.37262
258.37262
258.37262
258.37262
258.37262
263.047363
263.047363
263.047363
263.047363
263.047363
260.984375
260.984375
260.984375
260.984375
260.984375
261.318329
261.318329
261.318329
261.318329
261.318329
262.1026
262.1026
262.1026
262.1026
262.1026
262.71701
262.71701
262.71701
262.71701
262.71701
260.016479
260.016479
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
002289
10/12/09 02:39:55
10/12/09 02:40:00
10/12/09 02:40:05
10/12/09 02:40:10
10/12/09 02:40:15
10/12/09 02:40:20
10/12/09 02:40:25
10/12/09 02:40:30
10/12/09 02:40:35
10/12/09 02:40:40
10/12/09 02:40:45
10/12/09 02:40:50
10/12/09 02:40:55
10/12/09 02:41:00
10/12/09 02:41:05
10/12/09 02:41:10
10/12/09 02:41:15
10/12/09 02:41:20
10/12/09 02:41:25
10/12/09 02:41:30
10/12/09 02:41:35
10/12/09 02:41:40
10/12/09 02:41:45
10/12/09 02:41:50
10/12/09 02:41:55
10/12/09 02:42:00
10/12/09 02:42:05
10/12/09 02:42:10
10/12/09 02:42:15
10/12/09 02:42:20
10/12/09 02:42:25
10/12/09 02:42:30
10/12/09 02:42:35
10/12/09 02:42:40
59.977
59.976
59.974
59.978
59.981
59.971
59.971
59.966
59.971
59.969
59.974
59.971
59.982
59.985
59.989
59.987
59.994
60.003
60.006
60.019
60.025
60.029
60.037
60.037
60.041
60.043
60.048
60.043
60.044
60.045
60.041
60.036
60.033
60.037
3742.524
3741.723
3739.964
3742.833
3738.966
3738.879
3738.558
3743.419
3747.34
3749.75
3743.745
3740.299
3731.83
3736.229
3733.115
3729.18
3720.108
3725.661
3727.825
3727.231
3726.016
3716.375
3717.142
3713.632
3699.356
3704.591
3701.316
3699.529
3690.477
3696.877
3696.968
3699.631
3700.106
3701.122
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
260.016479
260.016479
260.016479
263.87323
263.87323
263.87323
263.87323
263.87323
264.5979
264.5979
264.5979
264.5979
264.5979
262.415924
262.415924
262.415924
262.415924
262.415924
259.685242
259.685242
259.685242
259.685242
259.685242
255.911011
255.911011
255.911011
255.911011
255.911011
258.148193
258.148193
258.148193
258.148193
258.148193
258.873596
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
002290
10/12/09 02:42:45
10/12/09 02:42:50
10/12/09 02:42:55
10/12/09 02:43:00
10/12/09 02:43:05
10/12/09 02:43:10
10/12/09 02:43:15
10/12/09 02:43:20
10/12/09 02:43:25
10/12/09 02:43:30
10/12/09 02:43:35
10/12/09 02:43:40
10/12/09 02:43:45
10/12/09 02:43:50
10/12/09 02:43:55
10/12/09 02:44:00
10/12/09 02:44:05
10/12/09 02:44:10
10/12/09 02:44:15
10/12/09 02:44:20
10/12/09 02:44:25
10/12/09 02:44:30
10/12/09 02:44:35
10/12/09 02:44:40
10/12/09 02:44:45
10/12/09 02:44:50
10/12/09 02:44:55
10/12/09 02:45:00
10/12/09 02:45:05
10/12/09 02:45:10
10/12/09 02:45:15
10/12/09 02:45:20
10/12/09 02:45:25
10/12/09 02:45:30
60.03
60.033
60.032
60.033
60.035
60.039
60.039
60.038
60.037
60.04
60.045
60.043
60.044
60.034
60.039
60.034
60.032
60.027
60.032
60.033
60.039
60.035
60.04
60.036
60.045
60.042
60.044
60.041
60.045
60.039
60.042
60.036
60.039
60.039
3701.998
3703.909
3704.087
3703.706
3704.36
3702.204
3703.318
3702.525
3702.865
3702.28
3700.276
3697.729
3697.346
3694.763
3696.798
3701.791
3702.148
3707.521
3707.34
3707.384
3706.823
3701.582
3702.212
3700.397
3700.827
3696.935
3693.824
3696.897
3697.502
3700.177
3697.681
3698.359
3700.262
3700.902
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
258.873596
258.873596
258.873596
258.873596
249.33757
249.33757
249.33757
249.33757
249.33757
258.278168
258.278168
258.278168
258.278168
258.278168
258.406372
258.406372
258.406372
258.406372
258.406372
260.538879
260.538879
260.538879
260.538879
260.538879
257.88208
257.88208
257.88208
257.88208
257.88208
258.588654
258.588654
258.588654
258.588654
258.588654
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
200
200.5
201
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
002291
10/12/09 02:45:35
10/12/09 02:45:40
10/12/09 02:45:45
10/12/09 02:45:50
10/12/09 02:45:55
10/12/09 02:46:00
10/12/09 02:46:05
10/12/09 02:46:10
10/12/09 02:46:15
10/12/09 02:46:20
10/12/09 02:46:25
10/12/09 02:46:30
10/12/09 02:46:35
10/12/09 02:46:40
10/12/09 02:46:45
10/12/09 02:46:50
10/12/09 02:46:55
10/12/09 02:47:00
10/12/09 02:47:05
10/12/09 02:47:10
10/12/09 02:47:15
10/12/09 02:47:20
10/12/09 02:47:25
10/12/09 02:47:30
10/12/09 02:47:35
10/12/09 02:47:40
10/12/09 02:47:45
10/12/09 02:47:50
10/12/09 02:47:55
10/12/09 02:48:00
10/12/09 02:48:05
10/12/09 02:48:10
10/12/09 02:48:15
10/12/09 02:48:20
60.038
60.037
60.037
60.036
60.033
60.032
60.037
60.036
60.032
60.034
60.038
60.042
60.04
60.043
60.04
60.044
60.036
60.042
60.043
60.039
60.034
60.035
60.03
60.031
60.032
60.032
60.033
60.039
60.036
60.04
60.036
60.041
60.036
60.038
3701.139
3700.264
3700.458
3698.794
3700.661
3702.968
3705.775
3703.744
3700.747
3705.059
3703.831
3702.795
3696.25
3693.518
3695.186
3694.753
3694.159
3692.686
3692.357
3690.836
3694.117
3695.581
3696.305
3697.336
3699.251
3699.105
3698.136
3697.412
3693.224
3691.919
3692.374
3694.71
3693.617
3694.27
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
261.906158
261.906158
261.906158
261.906158
261.906158
256.747803
256.747803
256.747803
256.747803
256.747803
167.431976
167.431976
167.431976
167.431976
167.431976
164.973404
164.973404
164.973404
164.973404
164.973404
157.628082
157.628082
157.628082
157.628082
157.628082
155.531708
155.531708
155.531708
155.531708
155.531708
160.447235
160.447235
160.447235
160.447235
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
002292
10/12/09 02:48:25
10/12/09 02:48:30
10/12/09 02:48:35
10/12/09 02:48:40
10/12/09 02:48:45
10/12/09 02:48:50
10/12/09 02:48:55
10/12/09 02:49:00
10/12/09 02:49:05
10/12/09 02:49:10
10/12/09 02:49:15
10/12/09 02:49:20
10/12/09 02:49:25
10/12/09 02:49:30
10/12/09 02:49:35
10/12/09 02:49:40
10/12/09 02:49:45
10/12/09 02:49:50
10/12/09 02:49:55
10/12/09 02:50:00
10/12/09 02:50:05
10/12/09 02:50:10
10/12/09 02:50:15
10/12/09 02:50:20
10/12/09 02:50:25
10/12/09 02:50:30
10/12/09 02:50:35
10/12/09 02:50:40
10/12/09 02:50:45
10/12/09 02:50:50
10/12/09 02:50:55
10/12/09 02:51:00
10/12/09 02:51:05
10/12/09 02:51:10
60.041
60.036
60.038
60.034
60.031
60.029
60.03
60.022
60.024
60.021
60.025
60.025
60.024
60.023
60.026
60.024
60.025
60.023
60.024
60.026
60.02
60.015
60.017
60.017
60.012
60.002
59.999
60.004
59.996
59.989
59.985
59.984
59.98
59.976
3692.532
3691.012
3693.727
3692.641
3688.208
3693.172
3695.225
3693.412
3698.012
3699.414
3700.544
3698.596
3700.802
3701.45
3701.702
3701.965
3701.09
3701.205
3700.177
3700.277
3700.26
3699.926
3703.516
3703.672
3702.921
3703.167
3703.775
3701.534
3700.625
3701.737
3700.977
3699.854
3700.77
3701.625
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
160.447235
163.958603
163.958603
163.958603
163.958603
163.958603
166.072449
166.072449
166.072449
166.072449
166.072449
163.766586
163.766586
163.766586
163.766586
163.766586
165.101685
165.101685
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
002293
10/12/09 02:51:15
10/12/09 02:51:20
10/12/09 02:51:25
10/12/09 02:51:30
10/12/09 02:51:35
10/12/09 02:51:40
10/12/09 02:51:45
10/12/09 02:51:50
10/12/09 02:51:55
10/12/09 02:52:00
10/12/09 02:52:05
10/12/09 02:52:10
10/12/09 02:52:15
10/12/09 02:52:20
10/12/09 02:52:25
10/12/09 02:52:30
10/12/09 02:52:35
10/12/09 02:52:40
10/12/09 02:52:45
10/12/09 02:52:50
10/12/09 02:52:55
10/12/09 02:53:00
10/12/09 02:53:05
10/12/09 02:53:10
10/12/09 02:53:15
10/12/09 02:53:20
10/12/09 02:53:25
10/12/09 02:53:30
10/12/09 02:53:35
10/12/09 02:53:40
10/12/09 02:53:45
10/12/09 02:53:50
10/12/09 02:53:55
10/12/09 02:54:00
59.974
59.973
59.971
59.98
59.982
59.981
59.978
59.977
59.978
59.97
59.971
59.999
59.998
60.005
60.01
60.022
60.025
60.023
60.029
60.028
60.032
60.031
60.021
60.017
60.016
60.012
60.008
60.005
59.999
60
59.995
59.993
59.985
59.988
3704.785
3706.958
3706.257
3710.118
3708.018
3706.343
3706.119
3707.721
3708.531
3707.24
3711.75
3710.695
3705.639
3703.191
3698.658
3697.882
3697.868
3693.912
3688.021
3688.237
3686.683
3685.576
3686.418
3688.997
3692.715
3692.462
3693.743
3694.681
3693.75
3692.806
3691.077
3689.797
3689.553
3689.736
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
214.830353
214.830353
227.655914
227.655914
1
1
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
250.5
251
251.5
252
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
7627
7628
7628
7629
002294
10/12/09 02:54:05
10/12/09 02:54:10
10/12/09 02:54:15
10/12/09 02:54:20
10/12/09 02:54:25
10/12/09 02:54:30
10/12/09 02:54:35
10/12/09 02:54:40
10/12/09 02:54:45
10/12/09 02:54:50
10/12/09 02:54:55
10/12/09 02:55:00
10/12/09 02:55:05
10/12/09 02:55:10
10/12/09 02:55:15
10/12/09 02:55:20
10/12/09 02:55:25
10/12/09 02:55:30
10/12/09 02:55:35
10/12/09 02:55:40
10/12/09 02:55:45
10/12/09 02:55:50
10/12/09 02:55:55
10/12/09 02:56:00
10/12/09 02:56:05
10/12/09 02:56:10
10/12/09 02:56:15
10/12/09 02:56:20
10/12/09 02:56:25
10/12/09 02:56:30
10/12/09 02:56:35
10/12/09 02:56:40
10/12/09 02:56:45
10/12/09 02:56:50
59.983
59.986
59.99
59.984
59.982
59.978
59.975
59.976
59.979
59.979
59.977
59.978
59.983
59.978
59.978
59.987
59.992
59.988
59.99
59.993
59.994
59.984
59.985
59.986
59.985
59.982
59.992
60.003
60.003
60.002
60.004
60.009
60.017
60.021
3687.494
3686.707
3684.333
3683.735
3683.473
3684.884
3685.087
3685.196
3688.599
3686.678
3685.143
3684.093
3682.318
3682.647
3684.052
3686.049
3683.415
3681.403
3671.761
3670.159
3681.799
3684.116
3684.165
3685.584
3684.976
3684.872
3685.589
3682.579
3682.224
3681.458
3680.167
3679.429
3678.267
3676.81
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
229.466965
229.466965
229.466965
229.466965
228.980164
228.980164
228.980164
228.980164
228.980164
219.975555
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
002295
10/12/09 02:56:55
10/12/09 02:57:00
10/12/09 02:57:05
10/12/09 02:57:10
10/12/09 02:57:15
10/12/09 02:57:20
10/12/09 02:57:25
10/12/09 02:57:30
10/12/09 02:57:35
10/12/09 02:57:40
10/12/09 02:57:45
10/12/09 02:57:50
10/12/09 02:57:55
10/12/09 02:58:00
10/12/09 02:58:05
10/12/09 02:58:10
10/12/09 02:58:15
10/12/09 02:58:20
10/12/09 02:58:25
10/12/09 02:58:30
10/12/09 02:58:35
10/12/09 02:58:40
10/12/09 02:58:45
10/12/09 02:58:50
10/12/09 02:58:55
10/12/09 02:59:00
10/12/09 02:59:05
10/12/09 02:59:10
10/12/09 02:59:15
10/12/09 02:59:20
10/12/09 02:59:25
10/12/09 02:59:30
10/12/09 02:59:35
10/12/09 02:59:40
60.018
60.02
60.018
60.018
60.016
60.015
60.014
60.015
60.016
60.021
60.022
60.025
60.022
60.024
60.029
60.032
60.03
60.021
60.025
60.023
60.02
60.02
60.014
60.011
60.01
60.012
60.014
60.011
60.008
60.013
60.018
60.019
60.02
60.016
3671.145
3673.648
3676.676
3676.437
3678.828
3678.915
3678.367
3678.589
3674.669
3674.402
3671.914
3670.946
3671.539
3674.01
3676.051
3672.583
3668.654
3666.312
3657.714
3669.309
3671.332
3672.683
3675.641
3677.009
3680.02
3679.597
3679.062
3679.587
3678.418
3679.681
3678.469
3678.456
3677.431
3677.315
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
219.975555
219.975555
219.975555
219.975555
229.089249
229.089249
229.089249
229.089249
229.089249
229.663269
229.663269
229.663269
229.663269
229.663269
229.233856
229.233856
229.233856
229.233856
229.233856
231.409882
231.409882
231.409882
231.409882
231.409882
218.622284
218.622284
218.622284
218.622284
218.622284
213.535858
213.535858
213.535858
213.535858
213.535858
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
269.5
270
270.5
271
271.5
272
272.5
273
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7663
7664
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
002296
10/12/09 02:59:45
10/12/09 02:59:50
10/12/09 02:59:55
10/12/09 03:00:00
10/12/09 03:00:05
10/12/09 03:00:10
10/12/09 03:00:15
10/12/09 03:00:20
10/12/09 03:00:25
10/12/09 03:00:30
10/12/09 03:00:35
10/12/09 03:00:40
10/12/09 03:00:45
10/12/09 03:00:50
10/12/09 03:00:55
10/12/09 03:01:00
10/12/09 03:01:05
10/12/09 03:01:10
10/12/09 03:01:15
10/12/09 03:01:20
10/12/09 03:01:25
10/12/09 03:01:30
10/12/09 03:01:35
10/12/09 03:01:40
10/12/09 03:01:45
10/12/09 03:01:50
10/12/09 03:01:55
10/12/09 03:02:00
10/12/09 03:02:05
10/12/09 03:02:10
10/12/09 03:02:15
10/12/09 03:02:20
10/12/09 03:02:25
10/12/09 03:02:30
60.019
60.018
60.016
60.015
59.999
59.982
59.97
59.968
59.972
59.964
59.966
59.965
59.97
59.973
59.976
59.977
59.976
59.974
59.976
59.981
59.985
59.979
59.987
59.98
59.984
59.989
59.996
59.997
59.997
59.996
60.003
60.008
60.004
60.001
3678.874
3681.058
3679.553
3682.73
3681.915
3683.813
3684.643
3689.404
3693.793
3694.974
3698.617
3699.85
3702.218
3703.365
3704.899
3704.293
3703.142
3705.376
3706.776
3706.928
3706.771
3704.127
3705.968
3704.683
3704.988
3704.893
3701.795
3701.308
3700.541
3700.858
3700.224
3698.032
3699.241
3701.11
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
225.651855
225.651855
225.651855
225.651855
225.651855
212.573639
212.573639
212.573639
212.573639
212.573639
219.897293
219.897293
219.897293
219.897293
219.897293
231.1754
231.1754
231.1754
231.1754
231.1754
226.634125
226.634125
226.634125
226.634125
226.634125
227.255066
227.255066
227.255066
227.255066
227.255066
229.290222
229.290222
229.290222
229.290222
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
002297
10/12/09 03:02:35
10/12/09 03:02:40
10/12/09 03:02:45
10/12/09 03:02:50
10/12/09 03:02:55
10/12/09 03:03:00
10/12/09 03:03:05
10/12/09 03:03:10
10/12/09 03:03:15
10/12/09 03:03:20
10/12/09 03:03:25
10/12/09 03:03:30
10/12/09 03:03:35
10/12/09 03:03:40
10/12/09 03:03:45
10/12/09 03:03:50
10/12/09 03:03:55
10/12/09 03:04:00
10/12/09 03:04:05
10/12/09 03:04:10
10/12/09 03:04:15
10/12/09 03:04:20
10/12/09 03:04:25
10/12/09 03:04:30
10/12/09 03:04:35
10/12/09 03:04:40
10/12/09 03:04:45
10/12/09 03:04:50
10/12/09 03:04:55
10/12/09 03:05:00
10/12/09 03:05:05
10/12/09 03:05:10
10/12/09 03:05:15
10/12/09 03:05:20
60.004
60.008
60.006
60.005
59.999
60.004
60.013
60.012
60.005
60.011
60.016
60.019
60.013
60.009
60.009
60.02
60.018
60.019
60.022
60.03
60.023
60.023
60.024
60.022
60.025
60.02
60.013
60.017
60.019
60.015
60.014
60.019
60.014
60.022
3700.22
3702.554
3701.923
3704.093
3704.455
3705.329
3703.675
3702.669
3703.297
3705.279
3703.438
3703.708
3704.139
3705.429
3705.634
3707.267
3705.655
3704.224
3704.795
3702.764
3701.063
3699.369
3704.25
3703.374
3704.947
3703.541
3704.376
3706.995
3707.767
3708.831
3709.817
3709.094
3709.933
3710.591
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
229.290222
221.461365
221.461365
221.461365
221.461365
221.461365
241.274368
241.274368
241.274368
241.274368
241.274368
243.071854
243.071854
243.071854
243.071854
243.071854
241.670212
241.670212
241.670212
241.670212
241.670212
228.149307
228.149307
228.149307
228.149307
228.149307
235.128983
235.128983
235.128983
235.128983
235.128983
246.433136
246.433136
246.433136
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
317.5
318
318.5
319
319.5
320
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
002298
10/12/09 03:05:25
10/12/09 03:05:30
10/12/09 03:05:35
10/12/09 03:05:40
10/12/09 03:05:45
10/12/09 03:05:50
10/12/09 03:05:55
10/12/09 03:06:00
10/12/09 03:06:05
10/12/09 03:06:10
10/12/09 03:06:15
10/12/09 03:06:20
10/12/09 03:06:25
10/12/09 03:06:30
10/12/09 03:06:35
10/12/09 03:06:40
10/12/09 03:06:45
10/12/09 03:06:50
10/12/09 03:06:55
10/12/09 03:07:00
10/12/09 03:07:05
10/12/09 03:07:10
10/12/09 03:07:15
10/12/09 03:07:20
10/12/09 03:07:25
10/12/09 03:07:30
10/12/09 03:07:35
10/12/09 03:07:40
10/12/09 03:07:45
10/12/09 03:07:50
10/12/09 03:07:55
10/12/09 03:08:00
10/12/09 03:08:05
10/12/09 03:08:10
60.024
60.024
60.02
60.025
60.03
60.026
60.029
60.03
60.016
60.028
60.015
60.011
60.013
60.016
60.013
59.994
59.99
59.993
59.993
59.985
59.982
59.981
59.978
59.977
59.983
59.981
59.981
59.98
59.978
59.976
59.975
59.975
59.975
59.977
3707.38
3706.99
3704.406
3706.567
3704.428
3703.532
3703.169
3701.52
3698.009
3703.192
3699.956
3703.802
3707.49
3706.991
3705.398
3709.144
3706.193
3707.903
3706.683
3704.934
3707.071
3707.479
3710.419
3708.708
3708.335
3707.911
3709.689
3706.541
3712.303
3711.703
3714.612
3715.323
3714.717
3713.996
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
246.433136
246.433136
236.553543
236.553543
236.553543
236.553543
236.553543
230.297562
230.297562
230.297562
230.297562
230.297562
231.175537
231.175537
231.175537
231.175537
231.175537
225.61763
225.61763
225.61763
225.61763
225.61763
230.734421
230.734421
230.734421
230.734421
230.734421
234.847107
234.847107
234.847107
234.847107
234.847107
228.960922
228.960922
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
002299
10/12/09 03:08:15
10/12/09 03:08:20
10/12/09 03:08:25
10/12/09 03:08:30
10/12/09 03:08:35
10/12/09 03:08:40
10/12/09 03:08:45
10/12/09 03:08:50
10/12/09 03:08:55
10/12/09 03:09:00
10/12/09 03:09:05
10/12/09 03:09:10
10/12/09 03:09:15
10/12/09 03:09:20
10/12/09 03:09:25
10/12/09 03:09:30
10/12/09 03:09:35
10/12/09 03:09:40
10/12/09 03:09:45
10/12/09 03:09:50
10/12/09 03:09:55
10/12/09 03:10:00
10/12/09 03:10:05
10/12/09 03:10:10
10/12/09 03:10:15
10/12/09 03:10:20
10/12/09 03:10:25
10/12/09 03:10:30
10/12/09 03:10:35
10/12/09 03:10:40
10/12/09 03:10:45
10/12/09 03:10:50
10/12/09 03:10:55
10/12/09 03:11:00
59.976
59.979
59.979
59.987
59.984
59.98
59.978
59.982
59.983
59.987
59.976
59.983
59.981
59.978
59.999
59.986
59.983
59.99
59.995
59.991
60
60.004
59.999
59.996
60.002
60.005
60.004
60.003
60.006
60.01
60.013
60.009
60.008
60.009
3715.631
3715.567
3713.142
3712.275
3710.05
3710.472
3710.2
3709.462
3710.573
3708.371
3707.49
3709.894
3711.627
3712.393
3716.626
3712.092
3714.953
3716.308
3714.714
3715.927
3715.324
3711.708
3713.362
3718.292
3717.815
3718.56
3718.821
3719.299
3719.731
3718.58
3720.034
3720.811
3719.447
3721.272
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
228.960922
228.960922
228.960922
231.177917
231.177917
231.177917
231.177917
231.177917
236.489288
236.489288
236.489288
236.489288
236.489288
245.038925
245.038925
245.038925
245.038925
245.038925
223.605682
223.605682
223.605682
223.605682
223.605682
231.119354
231.119354
231.119354
231.119354
231.119354
237.20665
237.20665
237.20665
237.20665
237.20665
240.516373
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
002300
10/12/09 03:11:05
10/12/09 03:11:10
10/12/09 03:11:15
10/12/09 03:11:20
10/12/09 03:11:25
10/12/09 03:11:30
10/12/09 03:11:35
10/12/09 03:11:40
10/12/09 03:11:45
10/12/09 03:11:50
10/12/09 03:11:55
10/12/09 03:12:00
60.013
60.012
60.011
60.001
59.998
60.002
60.003
60.001
59.989
59.988
59.992
60.04
3721.594
3721.999
3720.86
3723.816
3724.869
3723.696
3721.879
3722.906
3723.201
3723.881
3724.944
3723.693
350
350
350
350
350
350
350
350
350
350
350
350
240.516373
240.516373
240.516373
240.516373
237.566055
237.566055
237.566055
237.566055
237.566055
231.581421
231.581421
231.581421
16
16
16
16
16
16
16
16
16
16
16
16
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
002301
Balancing Authority Name: My BA
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-80
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Step 4.
Enter MW output of generator or load that caused event (+ for gen loss, - for load loss)
(Value from NERC Event List. If multiple units, enter total MW loss.)
If MW loss value is not known, enter a default 1000 MW.
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 5. worksheet.
2:27:20
2:33:00
633 MW
Event Frequency Data
60.1
60.05
60
Copy Form 2 Data for
Pasting into Form 1
59.95
59.9
59.85
59.8
Step 6. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
59.75
2:12:00 2:17:00 2:22:00 2:27:00 2:32:00 2:37:00 2:42:00 2:47:00 2:52:00 2:57:00 3:02:00 3:07:00 3:12:00
Hz
Step 7. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
002302
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8883
-0.153
3649.00
3785.20
136.20
-12.61
-33.00
89.36
122.36
Balancing Authority My BA
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
109.75 MW
Yes
Initial Response P.U. Performance
1.241 P.U.
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
60.019
60.026
60.026
Interchange
MW
3671.193
3671.189
3671.189
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
3763.51
3781.52
3727.24
3645.45
98.66
0:05:40
No
136.07
118.06
No
Yes
Yes
37.41
19.40
Up
60.000 Hz
2400.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-80 MW/0.1 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.868 P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-15.201
-20.801
-20.801
(TC)
Delayed
Delivery
Frequency
Response
-5.320
-10.738
-14.260
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
633
002303
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
60.026
60.019
60.019
60.02
60.02
60.02
60.021
60.021
60.019
60.019
60.019
60.022
60.022
60.037
60.037
60.037
60.037
60.037
60.048
60.048
60.048
60.041
60.041
60.039
60.039
60.039
60.043
60.043
60.041
60.041
60.041
60.041
60.041
59.852
59.852
59.852
59.869
59.869
59.869
59.88
59.88
59.875
59.875
59.875
59.886
59.886
3671.189
3664.495
3664.495
3666.821
3666.821
3666.821
3670.267
3670.267
3672.493
3672.493
3672.493
3672.164
3672.164
3669.983
3669.983
3669.983
3661.599
3661.599
3651.492
3651.492
3651.492
3648.246
3648.246
3654.294
3654.294
3654.294
3651.059
3651.059
3648.236
3648.236
3648.236
3645.446
3645.446
3641.191
3641.191
3641.191
3734.904
3734.904
3734.904
3737.157
3737.157
3766.194
3766.194
3766.194
3769.925
3769.925
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
59.888 3785.205
59.888 3785.205
59.888 3785.205
-20.801
-15.201
-15.201
-16.000
-16.000
-16.000
-16.800
-16.800
-15.201
-15.201
-15.201
-17.599
-17.599
-29.599
-29.599
-29.599
-29.599
-29.599
-38.400
-38.400
-38.400
-32.800
-32.800
-31.201
-31.201
-31.201
-34.399
-34.399
-32.800
-32.800
-32.800
-32.800
-32.800
118.399
118.399
118.399
104.800
104.800
104.800
95.999
95.999
100.000
100.000
100.000
91.199
91.199
-16.549
-16.077
-15.771
-15.851
-15.903
-15.937
-16.239
-16.435
-16.003
-15.722
-15.540
-16.261
-16.729
-21.234
-24.162
-26.065
-27.302
-28.106
-31.709
-34.051
-35.573
-34.603
-33.972
-33.002
-32.372
-31.962
-32.815
-33.370
-33.170
-33.041
-32.957
-32.902
-32.866
20.077
54.489
76.858
86.638
92.995
97.127
96.732
96.476
97.709
98.511
99.032
96.290
94.508
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
-0.150
3758.755
3758.755
3758.755
0.000
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
3666.821
3666.618
3666.434
3665.982
3665.635
3665.917
3666.047
3666.080
3665.208
3664.590
3659.935
3656.857
3654.803
3653.416
3652.461
3648.708
3646.216
3644.543
3645.363
3645.844
3646.663
3647.143
3647.402
3646.399
3645.694
3645.743
3645.722
3645.656
3645.561
3645.446
3698.389
3733.382
3756.331
3766.691
3773.628
3778.341
3778.526
3778.850
3780.664
3782.046
3783.148
3780.987
3779.785
3641.191
3641.191
3664.619
3678.676
3688.048
3695.063
3700.325
3707.644
3713.499
3718.289
3722.592
3726.233
3715.885
3729.367
3738.698
3745.684
3751.127
3755.041
3758.017
3760.534
3762.685
3764.545
3765.915
3766.982
3678.197
3678.778
3679.358
3679.938
3680.519
3681.099
3681.680
3682.260
3682.840
3683.421
3684.001
3684.581
3678.197
3678.488
3678.778
3679.068
3679.358
3679.648
3679.938
3680.229
3680.519
3680.809
3681.099
3681.389
633
633
633
633
633
633
633
633
633
633
633
633
633
002304
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
59.887
59.887
59.887
59.895
59.895
59.893
59.893
59.893
59.891
59.891
59.885
59.885
59.885
59.887
59.887
59.888
59.888
59.888
59.882
59.882
59.857
59.857
59.857
59.858
59.858
59.866
59.866
59.866
59.866
59.866
59.874
59.874
59.874
59.883
59.883
59.89
59.89
59.89
59.893
59.893
59.903
59.903
59.903
59.904
59.904
3782.500
3782.500
3782.500
3784.730
3784.730
3788.328
3788.328
3788.328
3788.472
3788.472
3794.374
3794.374
3794.374
3800.427
3800.427
3802.925
3802.925
3802.925
3804.388
3804.388
3809.237
3809.237
3809.237
3814.862
3814.862
3826.053
3826.053
3826.053
3827.524
3827.524
3826.454
3826.454
3826.454
3823.826
3823.826
3818.055
3818.055
3818.055
3815.010
3815.010
3809.652
3809.652
3809.652
3805.593
3805.593
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
90.399
90.399
90.399
84.000
84.000
85.599
85.599
85.599
87.201
87.201
92.001
92.001
92.001
90.399
90.399
89.600
89.600
89.600
94.400
94.400
114.401
114.401
114.401
113.599
113.599
107.199
107.199
107.199
107.199
107.199
100.800
100.800
100.800
93.600
93.600
88.000
88.000
88.000
85.599
85.599
77.600
77.600
77.600
76.801
76.801
93.070
92.135
91.528
88.893
87.180
86.627
86.267
86.033
86.442
86.708
88.560
89.765
90.548
90.496
90.462
90.160
89.964
89.836
91.434
92.472
100.147
105.136
108.379
110.206
111.393
109.925
108.971
108.351
107.948
107.686
105.276
103.709
102.691
99.509
97.441
94.137
91.989
90.593
88.845
87.709
84.171
81.871
80.376
79.125
78.311
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
3758.755
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
3778.927
3778.572
3778.545
3776.491
3775.358
3775.385
3775.606
3775.952
3776.941
3777.788
3780.221
3782.005
3783.369
3783.897
3784.444
3784.722
3785.106
3785.559
3787.737
3789.355
3797.611
3803.180
3807.004
3809.411
3811.179
3810.291
3809.917
3809.877
3810.055
3810.373
3808.543
3807.557
3807.119
3804.518
3803.030
3800.306
3798.739
3797.923
3796.755
3796.200
3793.242
3791.523
3790.608
3789.937
3789.704
3730.252
3733.735
3736.783
3739.604
3742.111
3744.543
3746.732
3748.713
3750.520
3752.170
3753.929
3755.547
3757.040
3758.647
3760.139
3761.614
3762.991
3764.280
3765.533
3766.710
3767.961
3769.141
3770.254
3771.460
3772.602
3773.973
3775.275
3776.513
3777.728
3778.886
3779.967
3781.000
3781.988
3782.878
3783.731
3784.432
3785.104
3785.750
3786.313
3786.854
3787.277
3787.683
3788.076
3788.383
3788.680
3767.835
3768.551
3769.176
3769.606
3769.926
3770.213
3770.483
3770.743
3771.025
3771.319
3771.690
3772.102
3772.536
3772.956
3773.367
3773.758
3774.137
3774.505
3774.919
3775.356
3776.011
3776.787
3777.626
3778.485
3779.346
3780.139
3780.884
3781.591
3782.268
3782.922
3783.504
3784.039
3784.541
3784.966
3785.342
3785.647
3785.909
3786.145
3786.349
3786.535
3786.659
3786.747
3786.816
3786.871
3786.920
3685.162
3685.742
3686.322
3686.903
3687.483
3688.063
3688.644
3689.224
3689.805
3690.385
3690.965
3691.546
3692.126
3692.706
3693.287
3693.867
3694.447
3695.028
3695.608
3696.188
3696.769
3697.349
3697.930
3698.510
3699.090
3699.671
3700.251
3700.831
3701.412
3701.992
3702.572
3703.153
3703.733
3704.313
3704.894
3705.474
3706.055
3706.635
3707.215
3707.796
3708.376
3708.956
3709.537
3710.117
3710.697
3681.680
3681.970
3682.260
3682.550
3682.840
3683.130
3683.421
3683.711
3684.001
3684.291
3684.581
3684.872
3685.162
3685.452
3685.742
3686.032
3686.322
3686.613
3686.903
3687.193
3687.483
3687.773
3688.063
3688.354
3688.644
3688.934
3689.224
3689.514
3689.805
3690.095
3690.385
3690.675
3690.965
3691.255
3691.546
3691.836
3692.126
3692.416
3692.706
3692.997
3693.287
3693.577
3693.867
3694.157
3694.447
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002305
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
59.911
59.911
59.911
59.917
59.917
59.92
59.92
59.92
59.917
59.917
59.921
59.921
59.921
59.925
59.925
59.927
59.927
59.927
59.928
59.928
59.929
59.929
59.929
59.937
59.937
59.945
59.945
59.945
59.942
59.942
59.942
59.942
59.942
59.947
59.947
59.951
59.951
59.951
59.951
59.951
59.952
59.952
59.952
59.952
59.952
59.952
3793.975
3793.975
3793.975
3791.502
3791.502
3784.563
3784.563
3784.563
3781.701
3781.701
3774.604
3774.604
3774.604
3773.958
3773.958
3769.630
3769.630
3769.630
3767.643
3767.643
3766.788
3766.788
3766.788
3765.672
3765.672
3765.105
3765.105
3765.105
3758.387
3758.387
3746.889
3746.889
3746.889
3749.593
3749.593
3749.077
3749.077
3749.077
3740.259
3740.259
3727.838
3727.838
3727.838
3722.649
3722.649
3718.142
71.201
71.201
71.201
66.400
66.400
64.001
64.001
64.001
66.400
66.400
63.199
63.199
63.199
60.001
60.001
58.401
58.401
58.401
57.599
57.599
56.799
56.799
56.799
50.400
50.400
44.000
44.000
44.000
46.399
46.399
46.399
46.399
46.399
42.401
42.401
39.200
39.200
39.200
39.200
39.200
38.400
38.400
38.400
38.400
38.400
38.400
75.823
74.205
73.153
70.790
69.253
67.415
66.220
65.444
65.779
65.996
65.017
64.381
63.967
62.579
61.676
60.530
59.785
59.301
58.705
58.318
57.786
57.441
57.216
54.831
53.280
50.032
47.921
46.549
46.496
46.462
46.440
46.426
46.416
45.011
44.098
42.383
41.269
40.545
40.074
39.768
39.289
38.978
38.776
38.644
38.559
38.503
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
3787.795
3786.758
3786.287
3784.504
3783.548
3782.290
3781.675
3781.479
3782.394
3783.192
3782.794
3782.738
3782.904
3782.096
3781.774
3781.208
3781.044
3781.140
3781.125
3781.318
3781.367
3781.601
3781.957
3780.152
3779.181
3776.514
3774.983
3774.191
3774.719
3775.265
3775.824
3776.390
3776.961
3776.136
3775.803
3774.669
3774.135
3773.991
3774.101
3774.375
3774.477
3774.746
3775.124
3775.573
3776.068
3776.592
3788.770
3788.856
3788.940
3788.982
3789.022
3788.952
3788.884
3788.819
3788.713
3788.610
3788.407
3788.209
3788.018
3787.823
3787.633
3787.389
3787.153
3786.922
3786.672
3786.428
3786.179
3785.937
3785.700
3785.456
3785.218
3784.978
3784.744
3784.516
3784.216
3783.922
3783.506
3783.099
3782.701
3782.341
3781.989
3781.639
3781.296
3780.961
3780.541
3780.130
3779.602
3779.084
3778.577
3778.029
3777.491
3776.920
3786.935
3786.932
3786.921
3786.882
3786.829
3786.758
3786.680
3786.601
3786.539
3786.489
3786.436
3786.383
3786.334
3786.275
3786.213
3786.146
3786.078
3786.013
3785.949
3785.890
3785.833
3785.780
3785.733
3785.665
3785.586
3785.478
3785.355
3785.225
3785.104
3784.993
3784.890
3784.795
3784.709
3784.616
3784.521
3784.416
3784.308
3784.201
3784.096
3783.997
3783.901
3783.809
3783.723
3783.644
3783.570
3783.503
3711.278
3711.858
3712.439
3713.019
3713.599
3714.180
3714.760
3715.340
3715.921
3716.501
3717.081
3717.662
3718.242
3718.822
3719.403
3719.983
3720.564
3721.144
3721.724
3722.305
3722.885
3723.465
3724.046
3724.626
3725.206
3725.787
3726.367
3726.947
3727.528
3728.108
3728.689
3729.269
3729.849
3730.430
3731.010
3731.590
3732.171
3732.751
3733.331
3733.912
3734.492
3735.072
3735.653
3736.233
3736.814
3737.394
3694.738
3695.028
3695.318
3695.608
3695.898
3696.188
3696.479
3696.769
3697.059
3697.349
3697.639
3697.930
3698.220
3698.510
3698.800
3699.090
3699.380
3699.671
3699.961
3700.251
3700.541
3700.831
3701.122
3701.412
3701.702
3701.992
3702.282
3702.572
3702.863
3703.153
3703.443
3703.733
3704.023
3704.313
3704.604
3704.894
3705.184
3705.474
3705.764
3706.055
3706.345
3706.635
3706.925
3707.215
3707.505
3707.796
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002306
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
59.952
59.952
59.952
59.952
59.954
59.954
59.954
59.956
59.956
59.956
59.956
59.956
59.961
59.961
59.962
59.962
59.962
59.966
59.966
59.97
59.97
59.97
59.969
59.969
59.97
59.97
59.97
59.973
59.973
59.978
59.978
59.978
59.978
59.978
59.978
59.978
59.978
59.982
59.982
59.98
59.98
59.98
59.979
59.979
59.983
59.983
3718.142
3718.142
3713.694
3713.694
3710.810
3710.810
3710.810
3714.623
3714.623
3716.461
3716.461
3716.461
3717.759
3717.759
3722.658
3722.658
3722.658
3722.278
3722.278
3723.984
3723.984
3723.984
3723.893
3723.893
3728.053
3728.053
3728.053
3732.530
3732.530
3736.907
3736.907
3736.907
3738.699
3738.699
3741.794
3741.794
3741.794
3746.608
3746.608
3751.558
3751.558
3751.558
3755.599
3755.599
3760.405
3760.405
38.400
38.400
38.400
38.400
36.801
36.801
36.801
35.199
35.199
35.199
35.199
35.199
31.201
31.201
30.399
30.399
30.399
27.200
27.200
23.999
23.999
23.999
24.799
24.799
23.999
23.999
23.999
21.600
21.600
17.599
17.599
17.599
17.599
17.599
17.599
17.599
17.599
14.401
14.401
16.000
16.000
16.000
16.800
16.800
13.599
13.599
38.467
38.444
38.429
38.419
37.853
37.485
37.245
36.529
36.064
35.761
35.564
35.436
33.954
32.991
32.083
31.494
31.110
29.742
28.852
27.154
26.050
25.332
25.145
25.024
24.665
24.432
24.280
23.342
22.733
20.936
19.768
19.009
18.516
18.195
17.987
17.851
17.763
16.586
15.822
15.884
15.925
15.951
16.248
16.441
15.446
14.800
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
3777.137
3777.694
3778.259
3778.829
3778.843
3779.056
3779.397
3779.261
3779.376
3779.654
3780.037
3780.490
3779.588
3779.205
3778.878
3778.868
3779.065
3778.277
3777.968
3776.850
3776.326
3776.189
3776.582
3777.041
3777.263
3777.610
3778.039
3777.681
3777.652
3776.436
3775.848
3775.670
3775.757
3776.016
3776.388
3776.833
3777.325
3776.729
3776.545
3777.187
3777.809
3778.415
3779.293
3780.066
3779.652
3779.585
3776.360
3775.811
3775.231
3774.661
3774.075
3773.500
3772.935
3772.415
3771.903
3771.417
3770.939
3770.469
3770.019
3769.576
3769.182
3768.794
3768.413
3768.034
3767.662
3767.310
3766.964
3766.623
3766.286
3765.955
3765.661
3765.372
3765.087
3764.840
3764.597
3764.391
3764.187
3763.986
3763.802
3763.620
3763.463
3763.308
3763.156
3763.039
3762.924
3762.845
3762.767
3762.691
3762.642
3762.595
3762.580
3762.566
3783.442
3783.388
3783.340
3783.298
3783.257
3783.219
3783.185
3783.150
3783.116
3783.086
3783.060
3783.037
3783.008
3782.976
3782.941
3782.907
3782.876
3782.838
3782.798
3782.750
3782.699
3782.647
3782.599
3782.556
3782.515
3782.477
3782.443
3782.407
3782.372
3782.327
3782.279
3782.231
3782.183
3782.139
3782.097
3782.060
3782.026
3781.989
3781.951
3781.918
3781.889
3781.866
3781.848
3781.836
3781.821
3781.806
3737.974
3738.555
3739.135
3739.715
3740.296
3740.876
3741.456
3742.037
3742.617
3743.197
3743.778
3744.358
3744.939
3745.519
3746.099
3746.680
3747.260
3747.840
3748.421
3749.001
3749.581
3750.162
3750.742
3751.322
3751.903
3752.483
3753.064
3753.644
3754.224
3754.805
3755.385
3755.965
3756.546
3757.126
3757.706
3758.287
3758.867
3759.447
3760.028
3760.608
3761.189
3761.769
3762.349
3762.930
3763.510
3764.090
3708.086
3708.376
3708.666
3708.956
3709.247
3709.537
3709.827
3710.117
3710.407
3710.697
3710.988
3711.278
3711.568
3711.858
3712.148
3712.439
3712.729
3713.019
3713.309
3713.599
3713.889
3714.180
3714.470
3714.760
3715.050
3715.340
3715.630
3715.921
3716.211
3716.501
3716.791
3717.081
3717.372
3717.662
3717.952
3718.242
3718.532
3718.822
3719.113
3719.403
3719.693
3719.983
3720.273
3720.564
3720.854
3721.144
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002307
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
59.983
59.989
59.989
59.987
59.987
59.987
59.992
59.992
59.989
59.989
59.989
59.983
59.983
59.993
59.993
59.993
59.999
59.999
59.999
59.999
59.999
60.002
60.002
60.007
60.007
60.007
60.014
60.014
60.019
60.019
60.019
60.017
60.017
60.023
60.023
60.023
60.021
60.021
60.024
60.024
60.024
60.02
60.02
60.024
60.024
60.024
3760.405
3761.407
3761.407
3764.958
3764.958
3764.958
3766.433
3766.433
3768.634
3768.634
3768.634
3772.445
3772.445
3775.841
3775.841
3775.841
3774.866
3774.866
3778.554
3778.554
3778.554
3781.256
3781.256
3783.896
3783.896
3783.896
3785.768
3785.768
3786.304
3786.304
3786.304
3787.516
3787.516
3788.607
3788.607
3788.607
3787.537
3787.537
3787.930
3787.930
3787.930
3786.875
3786.875
3785.018
3785.018
3785.018
13.599
8.801
8.801
10.400
10.400
10.400
6.400
6.400
8.801
8.801
8.801
13.599
13.599
5.600
5.600
5.600
0.800
0.800
0.800
0.800
0.800
-1.599
-1.599
-5.600
-5.600
-5.600
-11.200
-11.200
-15.201
-15.201
-15.201
-13.599
-13.599
-18.399
-18.399
-18.399
-16.800
-16.800
-19.199
-19.199
-19.199
-16.000
-16.000
-19.199
-19.199
-19.199
14.379
12.427
11.158
10.893
10.720
10.608
9.135
8.178
8.396
8.538
8.630
10.369
11.499
9.435
8.092
7.220
4.973
3.512
2.563
1.946
1.545
0.444
-0.271
-2.136
-3.348
-4.136
-6.609
-8.216
-10.660
-12.250
-13.283
-13.393
-13.465
-15.192
-16.314
-17.044
-16.959
-16.903
-17.707
-18.229
-18.568
-17.669
-17.085
-17.825
-18.306
-18.618
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.580
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3779.745
3778.373
3777.685
3778.000
3778.408
3778.876
3777.983
3777.606
3778.405
3779.127
3779.799
3782.119
3783.830
3782.345
3781.583
3781.291
3779.624
3778.744
3778.375
3778.338
3778.518
3777.417
3776.702
3774.837
3773.625
3772.836
3770.364
3768.757
3766.313
3764.723
3763.690
3763.580
3763.508
3761.781
3760.659
3759.929
3760.014
3760.070
3759.266
3758.744
3758.405
3759.304
3759.888
3759.148
3758.667
3758.355
3762.551
3762.544
3762.536
3762.552
3762.568
3762.583
3762.607
3762.632
3762.669
3762.707
3762.743
3762.803
3762.862
3762.942
3763.020
3763.097
3763.168
3763.237
3763.328
3763.417
3763.506
3763.609
3763.711
3763.827
3763.942
3764.055
3764.178
3764.299
3764.422
3764.544
3764.664
3764.789
3764.914
3765.042
3765.170
3765.296
3765.415
3765.532
3765.651
3765.768
3765.884
3765.993
3766.102
3766.199
3766.296
3766.391
3781.793
3781.770
3781.744
3781.719
3781.698
3781.680
3781.656
3781.631
3781.610
3781.595
3781.584
3781.587
3781.601
3781.605
3781.605
3781.603
3781.591
3781.575
3781.556
3781.537
3781.519
3781.495
3781.467
3781.429
3781.385
3781.336
3781.274
3781.204
3781.121
3781.030
3780.934
3780.838
3780.744
3780.641
3780.533
3780.422
3780.313
3780.205
3780.094
3779.982
3779.869
3779.762
3779.659
3779.553
3779.446
3779.338
3764.671
3765.251
3765.831
3766.412
3766.992
3767.572
3768.153
3768.733
3769.314
3769.894
3770.474
3771.055
3771.635
3772.215
3772.796
3773.376
3773.956
3774.537
3775.117
3775.698
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3721.434
3721.724
3722.014
3722.305
3722.595
3722.885
3723.175
3723.465
3723.755
3724.046
3724.336
3724.626
3724.916
3725.206
3725.497
3725.787
3726.077
3726.367
3726.657
3726.947
3727.238
3727.524
3727.808
3728.088
3728.365
3728.639
3728.909
3729.177
3729.442
3729.703
3729.962
3730.218
3730.471
3730.721
3730.969
3731.214
3731.456
3731.696
3731.933
3732.168
3732.400
3732.629
3732.857
3733.082
3733.304
3733.525
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002308
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
60.022
60.022
60.022
60.022
60.022
60.023
60.023
60.022
60.022
60.022
60.018
60.018
60.018
60.018
60.018
60.016
60.016
60.016
60.016
60.016
60.012
60.012
60.01
60.01
60.01
60.009
60.009
60.01
60.01
60.01
59.995
59.995
59.991
59.991
59.991
59.988
59.988
59.985
59.985
59.985
59.984
59.984
59.981
59.981
59.981
59.977
3785.949
3785.949
3786.877
3786.877
3786.877
3785.726
3785.726
3785.798
3785.798
3785.798
3786.939
3786.939
3789.673
3789.673
3789.673
3788.479
3788.479
3789.005
3789.005
3789.005
3788.933
3788.933
3790.411
3790.411
3790.411
3791.540
3791.540
3791.443
3791.443
3791.443
3790.603
3790.603
3789.585
3789.585
3789.585
3788.105
3788.105
3788.497
3788.497
3788.497
3788.571
3788.571
3786.453
3786.453
3786.453
3788.813
-17.599
-17.599
-17.599
-17.599
-17.599
-18.399
-18.399
-17.599
-17.599
-17.599
-14.401
-14.401
-14.401
-14.401
-14.401
-12.799
-12.799
-12.799
-12.799
-12.799
-9.601
-9.601
-7.999
-7.999
-7.999
-7.199
-7.199
-7.999
-7.999
-7.999
4.001
4.001
7.199
7.199
7.199
9.601
9.601
12.000
12.000
12.000
12.799
12.799
15.201
15.201
15.201
18.399
-18.262
-18.030
-17.879
-17.781
-17.718
-17.956
-18.111
-17.932
-17.816
-17.740
-16.571
-15.812
-15.318
-14.997
-14.789
-14.092
-13.640
-13.345
-13.154
-13.030
-11.830
-11.050
-9.982
-9.288
-8.837
-8.263
-7.891
-7.929
-7.953
-7.969
-3.780
-1.056
1.833
3.711
4.932
6.566
7.628
9.158
10.153
10.799
11.499
11.954
13.090
13.829
14.309
15.741
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3758.711
3758.943
3759.094
3759.192
3759.255
3759.017
3758.862
3759.041
3759.157
3759.233
3760.402
3761.161
3761.655
3761.976
3762.184
3762.881
3763.333
3763.628
3763.819
3763.943
3765.143
3765.923
3766.991
3767.685
3768.136
3768.710
3769.082
3769.044
3769.020
3769.004
3773.193
3775.917
3778.806
3780.684
3781.905
3783.539
3784.601
3786.131
3787.126
3787.772
3788.472
3788.927
3790.063
3790.802
3791.282
3792.714
3766.490
3766.589
3766.691
3766.792
3766.892
3766.985
3767.077
3767.169
3767.260
3767.350
3767.444
3767.538
3767.644
3767.749
3767.853
3767.950
3768.046
3768.144
3768.241
3768.338
3768.432
3768.527
3768.626
3768.725
3768.824
3768.926
3769.027
3769.127
3769.227
3769.325
3769.419
3769.512
3769.599
3769.686
3769.772
3769.851
3769.930
3770.009
3770.088
3770.166
3770.243
3770.320
3770.388
3770.455
3770.521
3770.597
3779.234
3779.131
3779.031
3778.931
3778.833
3778.735
3778.637
3778.541
3778.447
3778.354
3778.267
3778.185
3778.106
3778.029
3777.954
3777.883
3777.814
3777.748
3777.683
3777.620
3777.562
3777.509
3777.461
3777.416
3777.374
3777.335
3777.298
3777.261
3777.225
3777.188
3777.171
3777.165
3777.172
3777.188
3777.208
3777.235
3777.267
3777.305
3777.347
3777.391
3777.438
3777.486
3777.538
3777.594
3777.651
3777.713
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3733.743
3733.959
3734.173
3734.384
3734.594
3734.801
3735.006
3735.210
3735.411
3735.610
3735.808
3736.003
3736.197
3736.389
3736.579
3736.767
3736.953
3737.138
3737.321
3737.502
3737.681
3737.859
3738.035
3738.210
3738.383
3738.555
3738.725
3738.893
3739.060
3739.225
3739.389
3739.552
3739.713
3739.872
3740.031
3740.188
3740.343
3740.497
3740.650
3740.802
3740.952
3741.101
3741.249
3741.396
3741.541
3741.685
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002309
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
59.977
59.976
59.976
59.976
59.978
59.978
59.974
59.974
59.974
59.977
59.977
59.973
59.973
59.973
59.971
59.971
59.978
59.978
59.978
59.975
59.975
59.976
59.976
59.976
59.969
59.969
59.965
59.965
59.965
59.97
59.97
59.965
59.965
59.965
59.972
59.972
59.967
59.967
59.967
59.969
59.969
59.967
59.967
59.967
59.971
59.971
3788.813
3788.410
3788.410
3788.410
3790.665
3790.665
3789.267
3789.267
3789.267
3790.430
3790.430
3787.442
3787.442
3787.442
3790.602
3790.602
3792.311
3792.311
3792.311
3788.080
3788.080
3787.164
3787.164
3787.164
3787.405
3787.405
3789.214
3789.214
3789.214
3791.221
3791.221
3788.824
3788.824
3788.824
3789.167
3789.167
3784.831
3784.831
3784.831
3784.320
3784.320
3779.352
3779.352
3779.352
3778.633
3778.633
18.399
19.199
19.199
19.199
17.599
17.599
20.801
20.801
20.801
18.399
18.399
21.600
21.600
21.600
23.199
23.199
17.599
17.599
17.599
20.001
20.001
19.199
19.199
19.199
24.799
24.799
28.000
28.000
28.000
23.999
23.999
28.000
28.000
28.000
22.400
22.400
26.401
26.401
26.401
24.799
24.799
26.401
26.401
26.401
23.199
23.199
16.671
17.556
18.131
18.504
18.188
17.982
18.968
19.610
20.027
19.457
19.087
19.966
20.538
20.910
21.711
22.232
20.611
19.557
18.872
19.267
19.524
19.410
19.336
19.288
21.217
22.470
24.406
25.664
26.481
25.613
25.048
26.081
26.753
27.189
25.513
24.423
25.115
25.565
25.858
25.487
25.246
25.650
25.913
26.084
25.074
24.418
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3793.644
3794.529
3795.104
3795.477
3795.161
3794.955
3795.941
3796.583
3797.000
3796.430
3796.060
3796.939
3797.511
3797.883
3798.684
3799.205
3797.584
3796.530
3795.845
3796.240
3796.497
3796.383
3796.309
3796.261
3798.190
3799.443
3801.379
3802.637
3803.454
3802.586
3802.021
3803.054
3803.726
3804.162
3802.486
3801.396
3802.088
3802.538
3802.831
3802.460
3802.219
3802.623
3802.886
3803.057
3802.047
3801.391
3770.672
3770.744
3770.816
3770.888
3770.968
3771.047
3771.121
3771.193
3771.265
3771.341
3771.417
3771.480
3771.542
3771.605
3771.678
3771.752
3771.831
3771.910
3771.988
3772.050
3772.110
3772.168
3772.224
3772.280
3772.337
3772.393
3772.456
3772.518
3772.579
3772.648
3772.716
3772.775
3772.833
3772.891
3772.950
3773.008
3773.050
3773.093
3773.134
3773.174
3773.213
3773.235
3773.256
3773.278
3773.296
3773.315
3777.778
3777.847
3777.917
3777.989
3778.058
3778.126
3778.198
3778.272
3778.346
3778.418
3778.488
3778.560
3778.635
3778.710
3778.788
3778.867
3778.939
3779.007
3779.071
3779.137
3779.203
3779.268
3779.332
3779.396
3779.466
3779.541
3779.622
3779.707
3779.795
3779.878
3779.960
3780.044
3780.130
3780.217
3780.297
3780.373
3780.451
3780.530
3780.609
3780.687
3780.763
3780.840
3780.917
3780.995
3781.068
3781.139
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3741.828
3741.970
3742.110
3742.250
3742.388
3742.525
3742.662
3742.797
3742.930
3743.063
3743.195
3743.326
3743.456
3743.584
3743.712
3743.839
3743.965
3744.089
3744.213
3744.336
3744.458
3744.579
3744.699
3744.818
3744.936
3745.054
3745.170
3745.286
3745.401
3745.515
3745.628
3745.740
3745.851
3745.962
3746.072
3746.181
3746.289
3746.397
3746.503
3746.609
3746.715
3746.819
3746.923
3747.026
3747.128
3747.230
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002310
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
59.965
59.965
59.965
59.97
59.97
59.969
59.969
59.969
59.965
59.965
59.973
59.973
59.973
59.968
59.968
59.967
59.967
59.967
59.979
59.979
59.983
59.983
59.983
59.965
59.965
59.962
59.962
59.962
59.96
59.96
59.959
59.959
59.959
59.953
59.953
59.957
59.957
59.957
59.963
59.963
59.959
59.959
59.959
59.965
59.965
59.968
3776.429
3776.429
3776.429
3776.597
3776.597
3773.170
3773.170
3773.170
3768.793
3768.793
3767.366
3767.366
3767.366
3760.295
3760.295
3761.777
3761.777
3761.777
3760.157
3760.157
3757.773
3757.773
3757.773
3753.087
3753.087
3758.225
3758.225
3758.225
3758.041
3758.041
3763.822
3763.822
3763.822
3763.858
3763.858
3768.339
3768.339
3768.339
3767.438
3767.438
3761.570
3761.570
3761.570
3759.627
3759.627
3750.102
28.000
28.000
28.000
23.999
23.999
24.799
24.799
24.799
28.000
28.000
21.600
21.600
21.600
25.601
25.601
26.401
26.401
26.401
16.800
16.800
13.599
13.599
13.599
28.000
28.000
30.399
30.399
30.399
32.001
32.001
32.800
32.800
32.800
37.601
37.601
34.399
34.399
34.399
29.599
29.599
32.800
32.800
32.800
28.000
28.000
25.601
25.672
26.487
27.016
25.960
25.274
25.107
24.999
24.929
26.004
26.702
24.917
23.756
23.002
23.911
24.503
25.167
25.599
25.880
22.702
20.636
18.173
16.572
15.531
19.895
22.732
25.415
27.159
28.293
29.591
30.434
31.262
31.801
32.151
34.058
35.298
34.983
34.779
34.646
32.880
31.731
32.106
32.349
32.507
30.929
29.904
28.398
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3802.645
3803.460
3803.989
3802.933
3802.247
3802.080
3801.972
3801.902
3802.977
3803.675
3801.890
3800.729
3799.974
3800.884
3801.476
3802.140
3802.572
3802.853
3799.675
3797.609
3795.146
3793.545
3792.504
3796.868
3799.705
3802.388
3804.132
3805.266
3806.564
3807.407
3808.235
3808.774
3809.123
3811.031
3812.271
3811.956
3811.752
3811.619
3809.853
3808.704
3809.079
3809.322
3809.480
3807.902
3806.877
3805.371
3773.326
3773.336
3773.347
3773.358
3773.369
3773.369
3773.368
3773.367
3773.352
3773.337
3773.317
3773.297
3773.277
3773.234
3773.191
3773.154
3773.116
3773.079
3773.037
3772.996
3772.946
3772.897
3772.849
3772.785
3772.722
3772.676
3772.630
3772.585
3772.539
3772.493
3772.466
3772.439
3772.412
3772.386
3772.359
3772.347
3772.335
3772.322
3772.307
3772.293
3772.260
3772.228
3772.195
3772.157
3772.120
3772.054
3781.213
3781.290
3781.368
3781.442
3781.513
3781.583
3781.652
3781.720
3781.792
3781.865
3781.932
3781.995
3782.054
3782.117
3782.181
3782.246
3782.313
3782.380
3782.436
3782.486
3782.527
3782.562
3782.594
3782.640
3782.694
3782.757
3782.825
3782.896
3782.971
3783.048
3783.127
3783.207
3783.287
3783.374
3783.463
3783.551
3783.638
3783.724
3783.803
3783.879
3783.956
3784.033
3784.110
3784.181
3784.250
3784.313
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3747.330
3747.431
3747.530
3747.629
3747.727
3747.824
3747.921
3748.017
3748.113
3748.208
3748.302
3748.395
3748.488
3748.581
3748.672
3748.764
3748.854
3748.944
3749.033
3749.122
3749.210
3749.298
3749.385
3749.471
3749.557
3749.643
3749.727
3749.812
3749.895
3749.979
3750.061
3750.144
3750.225
3750.306
3750.387
3750.467
3750.547
3750.626
3750.705
3750.783
3750.861
3750.938
3751.015
3751.091
3751.167
3751.242
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002311
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
59.968
59.968
59.973
59.973
59.965
59.965
59.965
59.972
59.972
59.975
59.975
59.975
59.974
59.974
59.981
59.981
59.981
59.982
59.982
59.984
59.984
59.984
59.979
59.979
59.978
59.978
59.978
59.981
59.981
59.978
59.978
59.978
59.971
59.971
59.974
59.974
59.974
59.972
59.972
59.971
59.971
59.971
59.972
59.972
59.977
59.977
3750.102
3750.102
3753.510
3753.510
3753.178
3753.178
3753.178
3753.291
3753.291
3749.398
3749.398
3749.398
3740.370
3740.370
3745.738
3745.738
3745.738
3741.618
3741.618
3738.901
3738.901
3738.901
3737.273
3737.273
3735.448
3735.448
3735.448
3737.541
3737.541
3736.693
3736.693
3736.693
3736.094
3736.094
3738.875
3738.875
3738.875
3738.647
3738.647
3737.892
3737.892
3737.892
3740.329
3740.329
3742.524
3742.524
25.601
25.601
21.600
21.600
28.000
28.000
28.000
22.400
22.400
20.001
20.001
20.001
20.801
20.801
15.201
15.201
15.201
14.401
14.401
12.799
12.799
12.799
16.800
16.800
17.599
17.599
17.599
15.201
15.201
17.599
17.599
17.599
23.199
23.199
20.801
20.801
20.801
22.400
22.400
23.199
23.199
23.199
22.400
22.400
18.399
18.399
27.419
26.783
24.969
23.790
25.263
26.221
26.844
25.288
24.277
22.781
21.808
21.176
21.044
20.959
18.944
17.634
16.782
15.949
15.407
14.494
13.901
13.515
14.665
15.412
16.178
16.675
16.999
16.370
15.960
16.534
16.907
17.149
19.267
20.643
20.698
20.734
20.758
21.332
21.706
22.229
22.568
22.789
22.653
22.564
21.107
20.159
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3804.392
3803.756
3801.942
3800.763
3802.236
3803.194
3803.817
3802.261
3801.250
3799.754
3798.781
3798.149
3798.017
3797.932
3795.917
3794.607
3793.755
3792.922
3792.380
3791.467
3790.874
3790.488
3791.638
3792.385
3793.151
3793.648
3793.972
3793.342
3792.933
3793.507
3793.880
3794.122
3796.240
3797.616
3797.671
3797.707
3797.731
3798.305
3798.679
3799.202
3799.541
3799.762
3799.626
3799.537
3798.080
3797.132
3771.988
3771.923
3771.869
3771.814
3771.759
3771.705
3771.650
3771.597
3771.543
3771.479
3771.415
3771.351
3771.262
3771.173
3771.100
3771.028
3770.956
3770.872
3770.790
3770.700
3770.610
3770.521
3770.428
3770.335
3770.238
3770.141
3770.045
3769.955
3769.866
3769.775
3769.684
3769.594
3769.503
3769.412
3769.329
3769.247
3769.165
3769.083
3769.002
3768.918
3768.836
3768.753
3768.678
3768.603
3768.534
3768.466
3784.373
3784.430
3784.482
3784.531
3784.583
3784.638
3784.694
3784.745
3784.793
3784.837
3784.877
3784.916
3784.953
3784.991
3785.022
3785.049
3785.074
3785.096
3785.117
3785.135
3785.151
3785.166
3785.184
3785.204
3785.226
3785.250
3785.274
3785.296
3785.317
3785.340
3785.363
3785.387
3785.417
3785.450
3785.483
3785.516
3785.549
3785.583
3785.618
3785.655
3785.692
3785.729
3785.766
3785.802
3785.835
3785.865
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3751.317
3751.392
3751.466
3751.539
3751.613
3751.685
3751.758
3751.830
3751.901
3751.972
3752.043
3752.113
3752.183
3752.252
3752.321
3752.390
3752.458
3752.526
3752.594
3752.661
3752.727
3752.794
3752.860
3752.925
3752.991
3753.055
3753.120
3753.184
3753.248
3753.311
3753.374
3753.437
3753.500
3753.562
3753.623
3753.685
3753.746
3753.807
3753.867
3753.927
3753.987
3754.046
3754.105
3754.164
3754.223
3754.281
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002312
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
59.977
59.976
59.976
59.974
59.974
59.974
59.978
59.978
59.981
59.981
59.981
59.971
59.971
59.971
59.971
59.971
59.966
59.966
59.971
59.971
59.971
59.969
59.969
59.974
59.974
59.974
59.971
59.971
59.982
59.982
59.982
59.985
59.985
59.989
59.989
59.989
59.987
59.987
59.994
59.994
59.994
60.003
60.003
60.006
60.006
60.006
3742.524
3741.723
3741.723
3739.964
3739.964
3739.964
3742.833
3742.833
3738.966
3738.966
3738.966
3738.879
3738.879
3738.558
3738.558
3738.558
3743.419
3743.419
3747.340
3747.340
3747.340
3749.750
3749.750
3743.745
3743.745
3743.745
3740.299
3740.299
3731.830
3731.830
3731.830
3736.229
3736.229
3733.115
3733.115
3733.115
3729.180
3729.180
3720.108
3720.108
3720.108
3725.661
3725.661
3727.825
3727.825
3727.825
18.399
19.199
19.199
20.801
20.801
20.801
17.599
17.599
15.201
15.201
15.201
23.199
23.199
23.199
23.199
23.199
27.200
27.200
23.199
23.199
23.199
24.799
24.799
20.801
20.801
20.801
23.199
23.199
14.401
14.401
14.401
12.000
12.000
8.801
8.801
8.801
10.400
10.400
4.800
4.800
4.800
-2.399
-2.399
-4.800
-4.800
-4.800
19.543
19.422
19.344
19.854
20.185
20.401
19.420
18.783
17.529
16.714
16.185
18.640
20.236
21.273
21.947
22.386
24.071
25.166
24.478
24.030
23.740
24.110
24.351
23.109
22.301
21.776
22.274
22.598
19.729
17.864
16.652
15.024
13.965
12.158
10.983
10.219
10.283
10.324
8.391
7.134
6.317
3.267
1.284
-0.846
-2.230
-3.130
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3796.516
3796.395
3796.317
3796.827
3797.158
3797.374
3796.393
3795.756
3794.502
3793.687
3793.158
3795.613
3797.209
3798.246
3798.920
3799.359
3801.044
3802.139
3801.451
3801.003
3800.713
3801.083
3801.324
3800.081
3799.274
3798.749
3799.247
3799.571
3796.702
3794.837
3793.625
3791.997
3790.938
3789.131
3787.956
3787.192
3787.256
3787.297
3785.364
3784.107
3783.290
3780.240
3778.257
3776.127
3774.743
3773.843
3768.398
3768.328
3768.258
3768.185
3768.111
3768.038
3767.973
3767.909
3767.834
3767.760
3767.686
3767.613
3767.540
3767.466
3767.393
3767.320
3767.260
3767.200
3767.150
3767.101
3767.052
3767.009
3766.966
3766.908
3766.851
3766.794
3766.729
3766.664
3766.579
3766.494
3766.410
3766.337
3766.264
3766.184
3766.104
3766.025
3765.936
3765.849
3765.739
3765.631
3765.523
3765.428
3765.334
3765.246
3765.158
3765.070
3785.893
3785.920
3785.947
3785.976
3786.005
3786.034
3786.061
3786.086
3786.107
3786.127
3786.145
3786.169
3786.197
3786.228
3786.260
3786.293
3786.330
3786.370
3786.408
3786.444
3786.480
3786.516
3786.553
3786.586
3786.617
3786.647
3786.678
3786.710
3786.734
3786.754
3786.771
3786.784
3786.794
3786.799
3786.802
3786.803
3786.804
3786.805
3786.802
3786.795
3786.787
3786.772
3786.751
3786.726
3786.698
3786.668
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3754.339
3754.396
3754.454
3754.511
3754.567
3754.624
3754.680
3754.736
3754.791
3754.846
3754.901
3754.956
3755.010
3755.065
3755.118
3755.172
3755.225
3755.278
3755.331
3755.384
3755.436
3755.488
3755.539
3755.591
3755.642
3755.693
3755.744
3755.794
3755.844
3755.894
3755.944
3755.994
3756.043
3756.092
3756.141
3756.189
3756.237
3756.285
3756.333
3756.381
3756.428
3756.475
3756.522
3756.569
3756.616
3756.662
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002313
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
60.019
60.019
60.025
60.025
60.025
60.029
60.029
60.037
60.037
60.037
60.037
60.037
60.041
60.041
60.041
60.043
60.043
60.048
60.048
60.048
60.043
60.043
60.044
60.044
60.044
3727.231
3727.231
3726.016
3726.016
3726.016
3716.375
3716.375
3717.142
3717.142
3717.142
3713.632
3713.632
3699.356
3699.356
3699.356
3704.591
3704.591
3701.316
3701.316
3701.316
3699.529
3699.529
3690.477
3690.477
3690.477
-15.201
-15.201
-20.001
-20.001
-20.001
-23.199
-23.199
-29.599
-29.599
-29.599
-29.599
-29.599
-32.800
-32.800
-32.800
-34.399
-34.399
-38.400
-38.400
-38.400
-34.399
-34.399
-35.199
-35.199
-35.199
-7.354
-10.101
-13.566
-15.818
-17.282
-19.353
-20.699
-23.814
-25.839
-27.155
-28.010
-28.566
-30.048
-31.011
-31.638
-32.604
-33.233
-35.041
-36.217
-36.981
-36.077
-35.490
-35.388
-35.322
-35.279
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3769.619
3766.872
3763.407
3761.155
3759.691
3757.620
3756.274
3753.159
3751.134
3749.818
3748.963
3748.407
3746.925
3745.962
3745.335
3744.369
3743.740
3741.932
3740.756
3739.992
3740.895
3741.483
3741.585
3741.651
3741.694
3764.981
3764.893
3764.803
3764.712
3764.623
3764.511
3764.400
3764.291
3764.182
3764.075
3763.959
3763.844
3763.697
3763.551
3763.405
3763.272
3763.140
3763.001
3762.862
3762.724
3762.583
3762.442
3762.282
3762.122
3761.963
3786.628
3786.582
3786.528
3786.469
3786.407
3786.340
3786.271
3786.194
3786.114
3786.031
3785.946
3785.860
3785.771
3785.681
3785.589
3785.496
3785.402
3785.304
3785.204
3785.102
3785.004
3784.906
3784.810
3784.714
3784.619
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3776.278
3756.708
3756.754
3756.799
3756.845
3756.890
3756.935
3756.980
3757.024
3757.069
3757.113
3757.157
3757.200
3757.244
3757.287
3757.330
3757.373
3757.416
3757.459
3757.501
3757.543
3757.585
3757.627
3757.669
3757.710
3757.752
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002314
A Point
2:27:18
FPointA
60.0410
2:27:18 AM
A Value
60.0413
C Value
59.8520
2:27:24 AM
Delta FCA -0.189249039
FR C
-334.5 MW/0.1 Hz
Slope A-C dF/dT
-0.031500 Hz/second
C Value Maximum Resource Loss
633
Secondary C Value
No
n/a Time
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:18
60.04100037
60.04125023
59.85200119
2:27:18
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
59.8796
59.8833
59.8883
59.8876
59.8883
-0.1617
-391.834
-0.1580
-401.156
-0.1530
-415.813
-0.1537
-412.389
-0.1530
-0.0080839
-0.00789818
-0.0076478
-0.0076847
-0.0076478
85.4314
83.4686
80.8225
81.2128
80.8225
-0.0147
-0.0184
-0.0234
-0.0227
-0.0234
Tzero
2:27:18
FT+4 59.85200119
FT+10 59.86899948
FT+20
59.875
FT+60 59.88800049
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss
B Value Average LaaR Loss
B Value Average Net Loss
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
633
0
633
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection FR B
Generation Primary
20 to 52 sec
Trip
Frequency
Average
MW
Response
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002315
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-334.48
T+0 sec
-334.48
T+02 sec
-334.48
T+04 sec
-367.488
T+06 sec
-367.488
T+08 sec
-367.488
T+10 sec
-392.56
T+12 sec
-392.56
T+14 sec
-380.751
T+16 sec
-380.751
T+18 sec
-380.751 -414.2499042 T+20 sec
-407.733 -414.2499042 T+22 sec
-407.733 -414.2499042 T+24 sec
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
59.8796
59.8796
59.8796
59.8796
59.8796
59.8796
59.8796
-391.834
-391.834
-391.834
-391.834
-391.834
-391.834
-391.834
59.8833
59.8833
59.8833
59.8833
-401.156
-401.156
-401.156
-401.156
59.8883
59.8883
59.8883
-415.813
-415.813
-415.813
59.8876
59.8876
59.8876
59.8876
-412.389
-412.389
-412.389
-412.389
59.8883
59.8883
59.8883
002316
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-410.375
-410.375
-410.375
-432.821
-432.821
-426.985
-426.985
-426.985
-421.294
-421.294
-405.115
-405.115
-405.115
-410.375
-410.375
-413.051
-413.051
-413.051
-397.488
-397.488
-343.552
-343.552
-343.552
-345.433
-345.433
-361.2
-361.2
-361.2
-361.2
-361.2
-378.476
-378.476
-378.476
-399.998
-399.998
-418.51
-418.51
-418.51
-426.985
-426.985
-457.865
-457.865
-457.865
-461.199
-461.199
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
-414.2499042
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8833
59.8833
59.8833
-401.156
-401.156
-401.156
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
-415.813
-415.813
-415.813
-415.813
-415.813
-415.813
-415.813
-415.813
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
-412.389
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
59.8883
002317
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-485.985
-485.985
-485.985
-509.455
-509.455
-522.053
-522.053
-522.053
-509.455
-509.455
-526.409
-526.409
-526.409
-544.511
-544.511
-554.038
-554.038
-554.038
-558.946
-558.946
-563.923
-563.923
-563.923
-607.195
-607.195
-657.659
-657.659
-657.659
-637.791
-637.791
-637.791
-637.791
-637.791
-671.606
-671.606
-701.385
-701.385
-701.385
-701.385
-701.385
-709.239
-709.239
-709.239
-709.239
-709.239
-709.239
002318
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-709.239
-709.239
-709.239
-709.239
-725.488
-725.488
-725.488
-742.531
-742.531
-742.531
-742.531
-742.531
-788.768
-788.768
-798.754
-798.754
-798.754
-841.189
-841.189
-888.433
-888.433
-888.433
-876.143
-876.143
-888.433
-888.433
-888.433
-927.464
-927.464
-1000.8
-1000.8
-1000.8
-1000.8
-1000.8
-1000.8
-1000.8
-1000.8
-1068.32
-1068.32
-1033.46
-1033.46
-1033.46
-1016.87
-1016.87
-1086.72
-1086.72
002319
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1086.72
-1211.44
-1211.44
-1166.8
-1166.8
-1166.8
-1285.29
-1285.29
-1211.44
-1211.44
-1211.44
-1086.72
-1086.72
-1311.91
-1311.91
-1311.91
-1498.24
-1498.24
-1498.24
-1498.24
-1498.24
-1612.68
-1612.68
-1848.16
-1848.16
-1848.16
-2322.91
-2322.91
-2845.04
-2845.04
-2845.04
-2610.1
-2610.1
-3468.22
-3468.22
-3468.22
-3125.88
-3125.88
-3669.15
-3669.15
-3669.15
-2978.86
-2978.86
-3669.15
-3669.15
-3669.15
002320
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-3288.16
-3288.16
-3288.16
-3288.16
-3288.16
-3468.22
-3468.22
-3288.16
-3288.16
-3288.16
-2722.74
-2722.74
-2722.74
-2722.74
-2722.74
-2506.79
-2506.79
-2506.79
-2506.79
-2506.79
-2164.16
-2164.16
-2025.48
-2025.48
-2025.48
-1962.71
-1962.71
-2025.48
-2025.48
-2025.48
-1368.61
-1368.61
-1259.72
-1259.72
-1259.72
-1188.7
-1188.7
-1125.34
-1125.34
-1125.34
-1105.69
-1105.69
-1050.6
-1050.6
-1050.6
-985.229
002321
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-985.229
-970.137
-970.137
-970.137
-1000.8
-1000.8
-941.247
-941.247
-941.247
-985.229
-985.229
-927.464
-927.464
-927.464
-901.073
-901.073
-1000.8
-1000.8
-1000.8
-955.446
-955.446
-970.137
-970.137
-970.137
-876.143
-876.143
-830.163
-830.163
-830.163
-888.433
-888.433
-830.163
-830.163
-830.163
-914.078
-914.078
-852.512
-852.512
-852.512
-876.143
-876.143
-852.512
-852.512
-852.512
-901.073
-901.073
002322
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-830.163
-830.163
-830.163
-888.433
-888.433
-876.143
-876.143
-876.143
-830.163
-830.163
-927.464
-927.464
-927.464
-864.143
-864.143
-852.512
-852.512
-852.512
-1016.87
-1016.87
-1086.72
-1086.72
-1086.72
-830.163
-830.163
-798.754
-798.754
-798.754
-779.066
-779.066
-769.599
-769.599
-769.599
-717.271
-717.271
-751.34
-751.34
-751.34
-808.956
-808.956
-769.599
-769.599
-769.599
-830.163
-830.163
-864.143
002323
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-864.143
-864.143
-927.464
-927.464
-830.163
-830.163
-830.163
-914.078
-914.078
-955.446
-955.446
-955.446
-941.247
-941.247
-1050.6
-1050.6
-1050.6
-1068.32
-1068.32
-1105.69
-1105.69
-1105.69
-1016.87
-1016.87
-1000.8
-1000.8
-1000.8
-1050.6
-1050.6
-1000.8
-1000.8
-1000.8
-901.073
-901.073
-941.247
-941.247
-941.247
-914.078
-914.078
-901.073
-901.073
-901.073
-914.078
-914.078
-985.229
-985.229
002324
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-985.229
-970.137
-970.137
-941.247
-941.247
-941.247
-1000.8
-1000.8
-1050.6
-1050.6
-1050.6
-901.073
-901.073
-901.073
-901.073
-901.073
-841.189
-841.189
-901.073
-901.073
-901.073
-876.143
-876.143
-941.247
-941.247
-941.247
-901.073
-901.073
-1068.32
-1068.32
-1068.32
-1125.34
-1125.34
-1211.44
-1211.44
-1211.44
-1166.8
-1166.8
-1339.66
-1339.66
-1339.66
-1654.82
-1654.82
-1795.76
-1795.76
-1795.76
002325
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2845.04
-2845.04
-3895.7
-3895.7
-3895.7
-5166.97
-5166.97
-14888.9
-14888.9
-14888.9
-14888.9
-14888.9
-253339
-253339
-253339
36191.31
36191.31
9377.629
9377.629
9377.629
36191.31
36191.31
23030.83
23030.83
23030.83
002326
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
Time of Frequency Recovery to 60 Hz or P
Value A Pre-Perturbation Average Frequen
Value B Post-Perturbation Average Frequen
Pre to Post Perturbation Delt
Value A Pre-Perturbation Average Interchange M
Value B Post-Perturbation Average Interchange MW
Pre to Post Perturbation Interchang
FR B
20 to 52 sec
-414.250
eriods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
FR B
20 to 52 sec
Average
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
Net
Actual
Interchange
MW
60.0190
60.0260
60.0260
3671.19
3671.19
3671.19
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
-329.99
-329.99
-329.99
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
84.50
85.00
85.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
12 to 24 second Average Period Ev
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
BA
Load
MW
7555.77
7556.10
7556.10
Expected
Primary
Freq Response
MW
-15.201 T-72 sec
-20.801 T-70 sec
-20.801 T-68 sec
T
2:26:08
2:26:10
2:26:12
Frequency
Hz
002327
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-414.250 T+20 sec
-414.250 T+22 sec
-414.250 T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
60.0260
60.0190
60.0190
60.0200
60.0200
60.0200
60.0210
60.0210
60.0190
60.0190
60.0190
60.0220
60.0220
60.0370
60.0370
60.0370
60.0370
60.0370
60.0480
60.0480
60.0480
60.0410
60.0410
60.0390
60.0390
60.0390
60.0430
60.0430
60.0410
60.0410
60.0410
60.0410
60.0410
59.8520
59.8520
59.8520
59.8690
59.8690
59.8690
59.8800
59.8800
59.8750
59.8750
59.8750
59.8860
59.8860
3671.19
3664.50
3664.50
3666.82
3666.82
3666.82
3670.27
3670.27
3672.49
3672.49
3672.49
3672.16
3672.16
3669.98
3669.98
3669.98
3661.60
3661.60
3651.49
3651.49
3651.49
3648.25
3648.25
3654.29
3654.29
3654.29
3651.06
3651.06
3648.24
3648.24
3648.24
3645.45
3645.45
3641.19
3641.19
3641.19
3734.90
3734.90
3734.90
3737.16
3737.16
3766.19
3766.19
3766.19
3769.93
3769.93
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-329.99
-329.99
-329.99
-329.99
-329.99
-329.99
-255.44
-255.44
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.10
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
85.00
85.50
85.50
86.00
86.00
86.00
86.50
86.50
87.00
87.00
87.00
87.50
87.50
88.00
88.00
88.00
88.50
88.50
89.00
89.00
89.00
89.50
89.50
90.00
90.00
90.00
90.50
90.50
91.00
91.00
91.00
91.50
91.50
92.00
92.00
92.00
92.50
92.50
92.50
93.00
93.00
93.50
93.50
93.50
94.00
94.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7556.10
7556.43
7556.43
7556.76
7556.76
7556.76
7557.09
7557.09
7557.42
7557.42
7557.42
7557.75
7557.75
7558.08
7558.08
7558.08
7558.41
7558.41
7558.74
7558.74
7558.74
7559.07
7559.07
7559.40
7559.40
7559.40
7559.73
7559.73
7560.06
7560.06
7560.06
7560.39
7560.39
7560.72
7560.72
7560.72
7561.05
7561.05
7561.05
7561.38
7561.38
7561.71
7561.71
7561.71
7562.04
7562.04
-20.801
-15.201
-15.201
-16.000
-16.000
-16.000
-16.800
-16.800
-15.201
-15.201
-15.201
-17.599
-17.599
-29.599
-29.599
-29.599
-29.599
-29.599
-38.400
-38.400
-38.400
-32.800
-32.800
-31.201
-31.201
-31.201
-34.399
-34.399
-32.800
-32.800
-32.800
-32.800
-32.800
118.399
118.399
118.399
104.800
104.800
104.800
95.999
95.999
100.000
100.000
100.000
91.199
91.199
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
59.880
59.880
59.880
59.880
59.880
59.880
59.880
002328
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
-414.250
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
59.8870
59.8870
59.8870
59.8950
59.8950
59.8930
59.8930
59.8930
59.8910
59.8910
59.8850
59.8850
59.8850
59.8870
59.8870
59.8880
59.8880
59.8880
59.8820
59.8820
59.8570
59.8570
59.8570
59.8580
59.8580
59.8660
59.8660
59.8660
59.8660
59.8660
59.8740
59.8740
59.8740
59.8830
59.8830
59.8900
59.8900
59.8900
59.8930
59.8930
59.9030
59.9030
59.9030
59.9040
59.9040
3782.50
3782.50
3782.50
3784.73
3784.73
3788.33
3788.33
3788.33
3788.47
3788.47
3794.37
3794.37
3794.37
3800.43
3800.43
3802.93
3802.93
3802.93
3804.39
3804.39
3809.24
3809.24
3809.24
3814.86
3814.86
3826.05
3826.05
3826.05
3827.52
3827.52
3826.45
3826.45
3826.45
3823.83
3823.83
3818.06
3818.06
3818.06
3815.01
3815.01
3809.65
3809.65
3809.65
3805.59
3805.59
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
-215.60
1.00
1.00
1.00
1.00
1.00
2.00
2.00
2.00
3.00
3.00
4.00
4.00
4.00
5.00
5.00
6.00
6.00
6.00
7.00
7.00
8.00
8.00
8.00
9.00
9.00
10.00
10.00
10.00
11.00
11.00
12.00
12.00
12.00
13.00
13.00
14.00
14.00
14.00
15.00
15.00
16.00
16.00
16.00
16.00
16.00
94.50
94.50
94.50
95.00
95.00
95.50
95.50
95.50
96.00
96.00
96.50
96.50
96.50
97.00
97.00
97.50
97.50
97.50
98.00
98.00
98.50
98.50
98.50
99.00
99.00
99.50
99.50
99.50
100.00
100.00
100.50
100.50
100.50
101.00
101.00
101.50
101.50
101.50
102.00
102.00
102.50
102.50
102.50
103.00
103.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7562.37
7562.37
7562.37
7562.70
7562.70
7563.03
7563.03
7563.03
7563.36
7563.36
7563.69
7563.69
7563.69
7564.02
7564.02
7564.35
7564.35
7564.35
7564.68
7564.68
7565.01
7565.01
7565.01
7565.34
7565.34
7565.67
7565.67
7565.67
7566.00
7566.00
7566.33
7566.33
7566.33
7566.66
7566.66
7566.99
7566.99
7566.99
7567.32
7567.32
7567.65
7567.65
7567.65
7567.98
7567.98
90.399
90.399
90.399
84.000
84.000
85.599
85.599
85.599
87.201
87.201
92.001
92.001
92.001
90.399
90.399
89.600
89.600
89.600
94.400
94.400
114.401
114.401
114.401
113.599
113.599
107.199
107.199
107.199
107.199
107.199
100.800
100.800
100.800
93.600
93.600
88.000
88.000
88.000
85.599
85.599
77.600
77.600
77.600
76.801
76.801
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
002329
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
59.9110
59.9110
59.9110
59.9170
59.9170
59.9200
59.9200
59.9200
59.9170
59.9170
59.9210
59.9210
59.9210
59.9250
59.9250
59.9270
59.9270
59.9270
59.9280
59.9280
59.9290
59.9290
59.9290
59.9370
59.9370
59.9450
59.9450
59.9450
59.9420
59.9420
59.9420
59.9420
59.9420
59.9470
59.9470
59.9510
59.9510
59.9510
59.9510
59.9510
59.9520
59.9520
59.9520
59.9520
59.9520
59.9520
3793.98
3793.98
3793.98
3791.50
3791.50
3784.56
3784.56
3784.56
3781.70
3781.70
3774.60
3774.60
3774.60
3773.96
3773.96
3769.63
3769.63
3769.63
3767.64
3767.64
3766.79
3766.79
3766.79
3765.67
3765.67
3765.10
3765.10
3765.10
3758.39
3758.39
3746.89
3746.89
3746.89
3749.59
3749.59
3749.08
3749.08
3749.08
3740.26
3740.26
3727.84
3727.84
3727.84
3722.65
3722.65
3718.14
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-215.60
-215.60
-215.60
-215.60
-215.60
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-218.33
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-217.38
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-214.83
-227.66
-227.66
-227.66
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
103.50
103.50
103.50
104.00
104.00
104.50
104.50
104.50
105.00
105.00
105.50
105.50
105.50
106.00
106.00
106.50
106.50
106.50
107.00
107.00
107.50
107.50
107.50
108.00
108.00
108.50
108.50
108.50
109.00
109.00
109.50
109.50
109.50
110.00
110.00
110.50
110.50
110.50
111.00
111.00
111.50
111.50
111.50
112.00
112.00
112.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7568.31
7568.31
7568.31
7568.64
7568.64
7568.97
7568.97
7568.97
7569.30
7569.30
7569.63
7569.63
7569.63
7569.96
7569.96
7570.29
7570.29
7570.29
7570.62
7570.62
7570.95
7570.95
7570.95
7571.28
7571.28
7571.61
7571.61
7571.61
7571.94
7571.94
7572.27
7572.27
7572.27
7572.60
7572.60
7572.93
7572.93
7572.93
7573.26
7573.26
7573.59
7573.59
7573.59
7573.92
7573.92
7574.25
71.201
71.201
71.201
66.400
66.400
64.001
64.001
64.001
66.400
66.400
63.199
63.199
63.199
60.001
60.001
58.401
58.401
58.401
57.599
57.599
56.799
56.799
56.799
50.400
50.400
44.000
44.000
44.000
46.399
46.399
46.399
46.399
46.399
42.401
42.401
39.200
39.200
39.200
39.200
39.200
38.400
38.400
38.400
38.400
38.400
38.400
002330
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
59.9520
59.9520
59.9520
59.9520
59.9540
59.9540
59.9540
59.9560
59.9560
59.9560
59.9560
59.9560
59.9610
59.9610
59.9620
59.9620
59.9620
59.9660
59.9660
59.9700
59.9700
59.9700
59.9690
59.9690
59.9700
59.9700
59.9700
59.9730
59.9730
59.9780
59.9780
59.9780
59.9780
59.9780
59.9780
59.9780
59.9780
59.9820
59.9820
59.9800
59.9800
59.9800
59.9790
59.9790
59.9830
59.9830
3718.14
3718.14
3713.69
3713.69
3710.81
3710.81
3710.81
3714.62
3714.62
3716.46
3716.46
3716.46
3717.76
3717.76
3722.66
3722.66
3722.66
3722.28
3722.28
3723.98
3723.98
3723.98
3723.89
3723.89
3728.05
3728.05
3728.05
3732.53
3732.53
3736.91
3736.91
3736.91
3738.70
3738.70
3741.79
3741.79
3741.79
3746.61
3746.61
3751.56
3751.56
3751.56
3755.60
3755.60
3760.41
3760.41
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-227.66
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-225.02
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-228.37
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
-234.08
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
112.50
112.50
113.00
113.00
113.50
113.50
113.50
114.00
114.00
114.50
114.50
114.50
115.00
115.00
115.50
115.50
115.50
116.00
116.00
116.50
116.50
116.50
117.00
117.00
117.50
117.50
117.50
118.00
118.00
118.50
118.50
118.50
119.00
119.00
119.50
119.50
119.50
120.00
120.00
120.50
120.50
120.50
121.00
121.00
121.50
121.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7574.25
7574.25
7574.58
7574.58
7574.91
7574.91
7574.91
7575.24
7575.24
7575.57
7575.57
7575.57
7575.90
7575.90
7576.23
7576.23
7576.23
7576.56
7576.56
7576.89
7576.89
7576.89
7577.22
7577.22
7577.55
7577.55
7577.55
7577.88
7577.88
7578.21
7578.21
7578.21
7578.54
7578.54
7578.87
7578.87
7578.87
7579.20
7579.20
7579.53
7579.53
7579.53
7579.86
7579.86
7580.19
7580.19
38.400
38.400
38.400
38.400
36.801
36.801
36.801
35.199
35.199
35.199
35.199
35.199
31.201
31.201
30.399
30.399
30.399
27.200
27.200
23.999
23.999
23.999
24.799
24.799
23.999
23.999
23.999
21.600
21.600
17.599
17.599
17.599
17.599
17.599
17.599
17.599
17.599
14.401
14.401
16.000
16.000
16.000
16.800
16.800
13.599
13.599
002331
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
59.9830
59.9890
59.9890
59.9870
59.9870
59.9870
59.9920
59.9920
59.9890
59.9890
59.9890
59.9830
59.9830
59.9930
59.9930
59.9930
59.9990
59.9990
59.9990
59.9990
59.9990
60.0020
60.0020
60.0070
60.0070
60.0070
60.0140
60.0140
60.0190
60.0190
60.0190
60.0170
60.0170
60.0230
60.0230
60.0230
60.0210
60.0210
60.0240
60.0240
60.0240
60.0200
60.0200
60.0240
60.0240
60.0240
3760.41
3761.41
3761.41
3764.96
3764.96
3764.96
3766.43
3766.43
3768.63
3768.63
3768.63
3772.44
3772.44
3775.84
3775.84
3775.84
3774.87
3774.87
3778.55
3778.55
3778.55
3781.26
3781.26
3783.90
3783.90
3783.90
3785.77
3785.77
3786.30
3786.30
3786.30
3787.52
3787.52
3788.61
3788.61
3788.61
3787.54
3787.54
3787.93
3787.93
3787.93
3786.87
3786.87
3785.02
3785.02
3785.02
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
-234.08
-228.80
-228.80
-228.80
-228.80
-228.80
-354.90
-354.90
-354.90
-354.90
-354.90
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
121.50
122.00
122.00
122.50
122.50
122.50
123.00
123.00
123.50
123.50
123.50
124.00
124.00
124.50
124.50
124.50
125.00
125.00
125.50
125.50
125.50
126.00
126.00
126.50
126.50
126.50
127.00
127.00
127.50
127.50
127.50
128.00
128.00
128.50
128.50
128.50
129.00
129.00
129.50
129.50
129.50
130.00
130.00
130.50
130.50
130.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7580.19
7580.52
7580.52
7580.85
7580.85
7580.85
7581.18
7581.18
7581.51
7581.51
7581.51
7581.84
7581.84
7582.17
7582.17
7582.17
7582.50
7582.50
7582.83
7582.83
7582.83
7583.16
7583.16
7583.49
7583.49
7583.49
7583.82
7583.82
7584.15
7584.15
7584.15
7584.48
7584.48
7584.81
7584.81
7584.81
7585.14
7585.14
7585.47
7585.47
7585.47
7585.80
7585.80
7586.13
7586.13
7586.13
13.599
8.801
8.801
10.400
10.400
10.400
6.400
6.400
8.801
8.801
8.801
13.599
13.599
5.600
5.600
5.600
0.800
0.800
0.800
0.800
0.800
-1.599
-1.599
-5.600
-5.600
-5.600
-11.200
-11.200
-15.201
-15.201
-15.201
-13.599
-13.599
-18.399
-18.399
-18.399
-16.800
-16.800
-19.199
-19.199
-19.199
-16.000
-16.000
-19.199
-19.199
-19.199
002332
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
60.0220
60.0220
60.0220
60.0220
60.0220
60.0230
60.0230
60.0220
60.0220
60.0220
60.0180
60.0180
60.0180
60.0180
60.0180
60.0160
60.0160
60.0160
60.0160
60.0160
60.0120
60.0120
60.0100
60.0100
60.0100
60.0090
60.0090
60.0100
60.0100
60.0100
59.9950
59.9950
59.9910
59.9910
59.9910
59.9880
59.9880
59.9850
59.9850
59.9850
59.9840
59.9840
59.9810
59.9810
59.9810
59.9770
3785.95
3785.95
3786.88
3786.88
3786.88
3785.73
3785.73
3785.80
3785.80
3785.80
3786.94
3786.94
3789.67
3789.67
3789.67
3788.48
3788.48
3789.00
3789.00
3789.00
3788.93
3788.93
3790.41
3790.41
3790.41
3791.54
3791.54
3791.44
3791.44
3791.44
3790.60
3790.60
3789.58
3789.58
3789.58
3788.10
3788.10
3788.50
3788.50
3788.50
3788.57
3788.57
3786.45
3786.45
3786.45
3788.81
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-284.36
-284.36
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
131.00
131.00
131.50
131.50
131.50
132.00
132.00
132.50
132.50
132.50
133.00
133.00
133.50
133.50
133.50
134.00
134.00
134.50
134.50
134.50
135.00
135.00
135.50
135.50
135.50
136.00
136.00
136.50
136.50
136.50
137.00
137.00
137.50
137.50
137.50
138.00
138.00
138.50
138.50
138.50
139.00
139.00
139.50
139.50
139.50
140.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7586.46
7586.46
7586.79
7586.79
7586.79
7587.12
7587.12
7587.45
7587.45
7587.45
7587.78
7587.78
7588.11
7588.11
7588.11
7588.44
7588.44
7588.77
7588.77
7588.77
7589.10
7589.10
7589.43
7589.43
7589.43
7589.76
7589.76
7590.09
7590.09
7590.09
7590.42
7590.42
7590.75
7590.75
7590.75
7591.08
7591.08
7591.41
7591.41
7591.41
7591.74
7591.74
7592.07
7592.07
7592.07
7592.40
-17.599
-17.599
-17.599
-17.599
-17.599
-18.399
-18.399
-17.599
-17.599
-17.599
-14.401
-14.401
-14.401
-14.401
-14.401
-12.799
-12.799
-12.799
-12.799
-12.799
-9.601
-9.601
-7.999
-7.999
-7.999
-7.199
-7.199
-7.999
-7.999
-7.999
4.001
4.001
7.199
7.199
7.199
9.601
9.601
12.000
12.000
12.000
12.799
12.799
15.201
15.201
15.201
18.399
002333
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
59.9770
59.9760
59.9760
59.9760
59.9780
59.9780
59.9740
59.9740
59.9740
59.9770
59.9770
59.9730
59.9730
59.9730
59.9710
59.9710
59.9780
59.9780
59.9780
59.9750
59.9750
59.9760
59.9760
59.9760
59.9690
59.9690
59.9650
59.9650
59.9650
59.9700
59.9700
59.9650
59.9650
59.9650
59.9720
59.9720
59.9670
59.9670
59.9670
59.9690
59.9690
59.9670
59.9670
59.9670
59.9710
59.9710
3788.81
3788.41
3788.41
3788.41
3790.66
3790.66
3789.27
3789.27
3789.27
3790.43
3790.43
3787.44
3787.44
3787.44
3790.60
3790.60
3792.31
3792.31
3792.31
3788.08
3788.08
3787.16
3787.16
3787.16
3787.40
3787.40
3789.21
3789.21
3789.21
3791.22
3791.22
3788.82
3788.82
3788.82
3789.17
3789.17
3784.83
3784.83
3784.83
3784.32
3784.32
3779.35
3779.35
3779.35
3778.63
3778.63
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-256.57
-256.57
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
140.00
140.50
140.50
140.50
141.00
141.00
141.50
141.50
141.50
142.00
142.00
142.50
142.50
142.50
143.00
143.00
143.50
143.50
143.50
144.00
144.00
144.50
144.50
144.50
145.00
145.00
145.50
145.50
145.50
146.00
146.00
146.50
146.50
146.50
147.00
147.00
147.50
147.50
147.50
148.00
148.00
148.50
148.50
148.50
149.00
149.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7592.40
7592.73
7592.73
7592.73
7593.06
7593.06
7593.39
7593.39
7593.39
7593.72
7593.72
7594.05
7594.05
7594.05
7594.38
7594.38
7594.71
7594.71
7594.71
7595.04
7595.04
7595.37
7595.37
7595.37
7595.70
7595.70
7596.03
7596.03
7596.03
7596.36
7596.36
7596.69
7596.69
7596.69
7597.02
7597.02
7597.35
7597.35
7597.35
7597.68
7597.68
7598.01
7598.01
7598.01
7598.34
7598.34
18.399
19.199
19.199
19.199
17.599
17.599
20.801
20.801
20.801
18.399
18.399
21.600
21.600
21.600
23.199
23.199
17.599
17.599
17.599
20.001
20.001
19.199
19.199
19.199
24.799
24.799
28.000
28.000
28.000
23.999
23.999
28.000
28.000
28.000
22.400
22.400
26.401
26.401
26.401
24.799
24.799
26.401
26.401
26.401
23.199
23.199
002334
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
59.9650
59.9650
59.9650
59.9700
59.9700
59.9690
59.9690
59.9690
59.9650
59.9650
59.9730
59.9730
59.9730
59.9680
59.9680
59.9670
59.9670
59.9670
59.9790
59.9790
59.9830
59.9830
59.9830
59.9650
59.9650
59.9620
59.9620
59.9620
59.9600
59.9600
59.9590
59.9590
59.9590
59.9530
59.9530
59.9570
59.9570
59.9570
59.9630
59.9630
59.9590
59.9590
59.9590
59.9650
59.9650
59.9680
3776.43
3776.43
3776.43
3776.60
3776.60
3773.17
3773.17
3773.17
3768.79
3768.79
3767.37
3767.37
3767.37
3760.30
3760.30
3761.78
3761.78
3761.78
3760.16
3760.16
3757.77
3757.77
3757.77
3753.09
3753.09
3758.22
3758.22
3758.22
3758.04
3758.04
3763.82
3763.82
3763.82
3763.86
3763.86
3768.34
3768.34
3768.34
3767.44
3767.44
3761.57
3761.57
3761.57
3759.63
3759.63
3750.10
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-258.37
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-263.05
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
-260.98
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
149.50
149.50
149.50
150.00
150.00
150.50
150.50
150.50
151.00
151.00
151.50
151.50
151.50
152.00
152.00
152.50
152.50
152.50
153.00
153.00
153.50
153.50
153.50
154.00
154.00
154.50
154.50
154.50
155.00
155.00
155.50
155.50
155.50
156.00
156.00
156.50
156.50
156.50
157.00
157.00
157.50
157.50
157.50
158.00
158.00
158.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7598.67
7598.67
7598.67
7599.00
7599.00
7599.33
7599.33
7599.33
7599.66
7599.66
7599.99
7599.99
7599.99
7600.32
7600.32
7600.65
7600.65
7600.65
7600.98
7600.98
7601.31
7601.31
7601.31
7601.64
7601.64
7601.97
7601.97
7601.97
7602.30
7602.30
7602.63
7602.63
7602.63
7602.96
7602.96
7603.29
7603.29
7603.29
7603.62
7603.62
7603.95
7603.95
7603.95
7604.28
7604.28
7604.61
28.000
28.000
28.000
23.999
23.999
24.799
24.799
24.799
28.000
28.000
21.600
21.600
21.600
25.601
25.601
26.401
26.401
26.401
16.800
16.800
13.599
13.599
13.599
28.000
28.000
30.399
30.399
30.399
32.001
32.001
32.800
32.800
32.800
37.601
37.601
34.399
34.399
34.399
29.599
29.599
32.800
32.800
32.800
28.000
28.000
25.601
002335
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
59.9680
59.9680
59.9730
59.9730
59.9650
59.9650
59.9650
59.9720
59.9720
59.9750
59.9750
59.9750
59.9740
59.9740
59.9810
59.9810
59.9810
59.9820
59.9820
59.9840
59.9840
59.9840
59.9790
59.9790
59.9780
59.9780
59.9780
59.9810
59.9810
59.9780
59.9780
59.9780
59.9710
59.9710
59.9740
59.9740
59.9740
59.9720
59.9720
59.9710
59.9710
59.9710
59.9720
59.9720
59.9770
59.9770
3750.10
3750.10
3753.51
3753.51
3753.18
3753.18
3753.18
3753.29
3753.29
3749.40
3749.40
3749.40
3740.37
3740.37
3745.74
3745.74
3745.74
3741.62
3741.62
3738.90
3738.90
3738.90
3737.27
3737.27
3735.45
3735.45
3735.45
3737.54
3737.54
3736.69
3736.69
3736.69
3736.09
3736.09
3738.87
3738.87
3738.87
3738.65
3738.65
3737.89
3737.89
3737.89
3740.33
3740.33
3742.52
3742.52
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-260.98
-260.98
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-261.32
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.10
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-262.72
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
158.50
158.50
159.00
159.00
159.50
159.50
159.50
160.00
160.00
160.50
160.50
160.50
161.00
161.00
161.50
161.50
161.50
162.00
162.00
162.50
162.50
162.50
163.00
163.00
163.50
163.50
163.50
164.00
164.00
164.50
164.50
164.50
165.00
165.00
165.50
165.50
165.50
166.00
166.00
166.50
166.50
166.50
167.00
167.00
167.50
167.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7604.61
7604.61
7604.94
7604.94
7605.27
7605.27
7605.27
7605.60
7605.60
7605.93
7605.93
7605.93
7606.26
7606.26
7606.59
7606.59
7606.59
7606.92
7606.92
7607.25
7607.25
7607.25
7607.58
7607.58
7607.91
7607.91
7607.91
7608.24
7608.24
7608.57
7608.57
7608.57
7608.90
7608.90
7609.23
7609.23
7609.23
7609.56
7609.56
7609.89
7609.89
7609.89
7610.22
7610.22
7610.55
7610.55
25.601
25.601
21.600
21.600
28.000
28.000
28.000
22.400
22.400
20.001
20.001
20.001
20.801
20.801
15.201
15.201
15.201
14.401
14.401
12.799
12.799
12.799
16.800
16.800
17.599
17.599
17.599
15.201
15.201
17.599
17.599
17.599
23.199
23.199
20.801
20.801
20.801
22.400
22.400
23.199
23.199
23.199
22.400
22.400
18.399
18.399
002336
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
59.9770
59.9760
59.9760
59.9740
59.9740
59.9740
59.9780
59.9780
59.9810
59.9810
59.9810
59.9710
59.9710
59.9710
59.9710
59.9710
59.9660
59.9660
59.9710
59.9710
59.9710
59.9690
59.9690
59.9740
59.9740
59.9740
59.9710
59.9710
59.9820
59.9820
59.9820
59.9850
59.9850
59.9890
59.9890
59.9890
59.9870
59.9870
59.9940
59.9940
59.9940
60.0030
60.0030
60.0060
60.0060
60.0060
3742.52
3741.72
3741.72
3739.96
3739.96
3739.96
3742.83
3742.83
3738.97
3738.97
3738.97
3738.88
3738.88
3738.56
3738.56
3738.56
3743.42
3743.42
3747.34
3747.34
3747.34
3749.75
3749.75
3743.75
3743.75
3743.75
3740.30
3740.30
3731.83
3731.83
3731.83
3736.23
3736.23
3733.12
3733.12
3733.12
3729.18
3729.18
3720.11
3720.11
3720.11
3725.66
3725.66
3727.82
3727.82
3727.82
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-260.02
-260.02
-260.02
-260.02
-260.02
-260.02
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-263.87
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-264.60
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-262.42
-259.69
-259.69
-259.69
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
167.50
168.00
168.00
168.50
168.50
168.50
169.00
169.00
169.50
169.50
169.50
170.00
170.00
170.50
170.50
170.50
171.00
171.00
171.50
171.50
171.50
172.00
172.00
172.50
172.50
172.50
173.00
173.00
173.50
173.50
173.50
174.00
174.00
174.50
174.50
174.50
175.00
175.00
175.50
175.50
175.50
176.00
176.00
176.50
176.50
176.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7610.55
7610.88
7610.88
7611.21
7611.21
7611.21
7611.54
7611.54
7611.87
7611.87
7611.87
7612.20
7612.20
7612.53
7612.53
7612.53
7612.86
7612.86
7613.19
7613.19
7613.19
7613.52
7613.52
7613.85
7613.85
7613.85
7614.18
7614.18
7614.51
7614.51
7614.51
7614.84
7614.84
7615.17
7615.17
7615.17
7615.50
7615.50
7615.83
7615.83
7615.83
7616.16
7616.16
7616.49
7616.49
7616.49
18.399
19.199
19.199
20.801
20.801
20.801
17.599
17.599
15.201
15.201
15.201
23.199
23.199
23.199
23.199
23.199
27.200
27.200
23.199
23.199
23.199
24.799
24.799
20.801
20.801
20.801
23.199
23.199
14.401
14.401
14.401
12.000
12.000
8.801
8.801
8.801
10.400
10.400
4.800
4.800
4.800
-2.399
-2.399
-4.800
-4.800
-4.800
002337
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
60.0190
60.0190
60.0250
60.0250
60.0250
60.0290
60.0290
60.0370
60.0370
60.0370
60.0370
60.0370
60.0410
60.0410
60.0410
60.0430
60.0430
60.0480
60.0480
60.0480
60.0430
60.0430
60.0440
60.0440
60.0440
3727.23
3727.23
3726.02
3726.02
3726.02
3716.37
3716.37
3717.14
3717.14
3717.14
3713.63
3713.63
3699.36
3699.36
3699.36
3704.59
3704.59
3701.32
3701.32
3701.32
3699.53
3699.53
3690.48
3690.48
3690.48
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-259.69
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-255.91
-258.15
-258.15
-258.15
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
177.00
177.00
177.50
177.50
177.50
178.00
178.00
178.50
178.50
178.50
179.00
179.00
179.50
179.50
179.50
180.00
180.00
180.50
180.50
180.50
181.00
181.00
181.50
181.50
181.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7616.82
7616.82
7617.15
7617.15
7617.15
7617.48
7617.48
7617.81
7617.81
7617.81
7618.14
7618.14
7618.47
7618.47
7618.47
7618.80
7618.80
7619.13
7619.13
7619.13
7619.46
7619.46
7619.79
7619.79
7619.79
-15.201
-15.201
-20.001
-20.001
-20.001
-23.199
-23.199
-29.599
-29.599
-29.599
-29.599
-29.599
-32.800
-32.800
-32.800
-34.399
-34.399
-38.400
-38.400
-38.400
-34.399
-34.399
-35.199
-35.199
-35.199
002338
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
lue B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8796
-0.162
3649.00
3758.96
109.96
-51.19
-33.00
96.34
129.34
78.15
350.00
-165.48
0.00
90.88
-4.13
15.00
286.27
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-206.46
1.00
93.50
12.04
0.00
235.08
-51.19
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-42.4877
124.0406
166.5284
66.03%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7559.978
7561.710
1.733
1.072
-1.58%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
24 second Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
0.850 P.U.
1.246 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002339
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3758.964
3758.964
3758.964
3758.964
3758.964
3758.964
3758.964
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-206.459
-206.459
-206.459
-206.459
-206.459
-206.459
-206.459
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
90.875
90.875
90.875
90.875
90.875
90.875
90.875
90.875
93.500
93.500
93.500
93.500
93.500
93.500
93.500
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7561.710
7561.710
7561.710
7561.710
7561.710
7561.710
7561.710
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
96.342
96.342
96.342
96.342
96.342
96.342
96.342
3727.154
3727.154
3727.154
3727.154
3727.154
3727.154
3727.154
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
59.883
59.883
59.883
59.883
3774.248
3774.248
3774.248
3774.248
335.000
335.000
335.000
335.000
002340
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
59.883
59.883
59.883
3774.248
3774.248
3774.248
335.000
335.000
335.000
002341
002342
002343
002344
002345
002346
002347
002348
002349
002350
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8833
-0.158
3649.00
3774.25
125.25
-53.05
-33.00
93.37
126.37
73.33
350.00
-165.48
0.00
90.88
-4.13
15.00
286.27
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-208.51
1.00
94.07
11.67
0.00
233.23
-53.05
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -103.000 MW/0.1 Hz
Post-Perturbation Bias Setting -103.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -42.4877 MW
EPFR for Bias Setting Post-Perturbation Average 120.2148 MW
EPFR for Bias Setting Delta 162.7025 MW
Primary Frequency Response Delivery of Bias
76.98%
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8888
-0.152
3649.00
3780.73
131.72
-54.15
-33.00
88.94
121.94
67.80
350.00
-165.48
0.00
90.88
-4.13
15.00
286.27
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-209.95
1.27
94.68
11.12
0.00
232.12
-54.15
Pre-Perturbation BA Load 7559.978 MW
Post-Perturbation BA Load 7562.087 MW
Pre to Post Perturbation BA Load Change
2.110 MW
Load Dampening Frequency Response
1.336 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
-1.68%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
0.991 P.U.
1.411 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.080
1.524
Pumped
Hydro
Load (-) Gen (+)
MW
002351
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-208.515
-208.515
-208.515
-208.515
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1.000
1.000
1.000
1.000
90.875
90.875
90.875
90.875
90.875
90.875
90.875
90.875
94.071
94.071
94.071
94.071
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7562.087
7562.087
7562.087
7562.087
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
93.371
93.371
93.371
93.371
3722.327
3722.327
3722.327
3722.327
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
59.889
59.889
59.889
3780.726
3780.726
3780.726
335.000
335.000
335.000
-209.948
-209.948
-209.948
1.273
1.273
1.273
002352
-208.515
-208.515
-208.515
1.000
1.000
1.000
94.071
94.071
94.071
10.000
10.000
10.000
0.000
0.000
0.000
-103.000 7562.087
-103.000 7562.087
-103.000 7562.087
93.371
93.371
93.371
3722.327 T+26 sec
3722.327 T+28 sec
3722.327 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3780.726
3780.726
3780.726
3780.726
3780.726
3780.726
3780.726
3780.726
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-209.948
-209.948
-209.948
-209.948
-209.948
-209.948
-209.948
-209.948
1.273
1.273
1.273
1.273
1.273
1.273
1.273
1.273
002353
002354
002355
002356
002357
002358
002359
002360
002361
002362
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-42.4877
114.5162
157.0039
83.90%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7559.978
7562.490
2.512
1.648
-1.91%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8876
-0.154
3649.00
3784.15
135.15
-53.09
-33.00
89.96
122.96
69.87
350.00
-165.48
0.00
90.88
-4.13
15.00
286.27
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-210.36
2.11
95.19
11.24
0.00
233.19
-53.09
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.099 P.U.
1.531 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002363
90.875
90.875
90.875
90.875
90.875
90.875
90.875
90.875
94.682
94.682
94.682
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7562.490
7562.490
7562.490
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
88.945
88.945
88.945
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
3716.798 T+20 sec
3716.798 T+22 sec
3716.798 T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
90.875
90.875
90.875
90.875
90.875
90.875
90.875
90.875
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
59.888
59.888
59.888
59.888
3784.148
3784.148
3784.148
3784.148
335.000
335.000
335.000
335.000
-210.362
-210.362
-210.362
-210.362
2.111
2.111
2.111
2.111
95.194
95.194
95.194
95.194
10.000
10.000
10.000
10.000
002364
94.682
94.682
94.682
94.682
94.682
94.682
94.682
94.682
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7562.490
7562.490
7562.490
7562.490
7562.490
7562.490
7562.490
7562.490
88.945
88.945
88.945
88.945
88.945
88.945
88.945
88.945
3716.798
3716.798
3716.798
3716.798
3716.798
3716.798
3716.798
3716.798
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
3784.148
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
-210.362
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
2.111
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
95.194
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
002365
002366
002367
002368
002369
002370
002371
002372
002373
002374
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-42.4877
115.8175
158.3052
85.37%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7559.978
7562.828
2.851
1.855
-2.11%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:20
2:33:00
60.0413
59.8883
-0.153
3649.00
3785.20
136.20
-53.22
-33.00
89.36
122.36
69.14
350.00
-165.48
0.00
90.88
-4.13
15.00
286.27
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-210.59
2.18
95.29
11.17
0.00
233.05
-53.22
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:08
2:26:10
2:26:12
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.113 P.U.
1.548 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002375
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7562.828
7562.828
7562.828
7562.828
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
89.955
89.955
89.955
89.955
3718.872
3718.872
3718.872
3718.872
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
60.041
60.041
60.041
60.041
60.041
60.041
60.041
60.041
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
3649.002
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
90.875
90.875
90.875
90.875
90.875
90.875
90.875
90.875
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
59.888
59.888
59.888
3785.205
3785.205
3785.205
335.000
335.000
335.000
-210.591
-210.591
-210.591
2.176
2.176
2.176
95.294
95.294
95.294
10.000
10.000
10.000
0.000
0.000
0.000
002376
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
7562.828
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
89.955
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
3718.872
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
3785.205
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
-210.591
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
2.176
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
95.294
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002377
002378
002379
002380
002381
002382
002383
002384
002385
002386
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-103.000
-103.000
-42.4877
115.0567
157.5445
86.45%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
7559.978
7562.894
2.917
1.907
-2.14%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002387
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
7559.978
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-33.000
-103.000
-103.000
-103.000
7562.894
7562.894
7562.894
89.364
89.364
89.364
3718.143
3718.143
3718.143
002388
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
7562.894
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
89.364
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
3718.143
002389
Monday, October 12, 2009
Balancing Authority
60.08
1.113
My BA
60.0413
1.548
Initial P.U. Performance
Initial P.U. Performance Adjusted
3850.0
20 to 52 second Average Period
60.06
60.04
3800.0
3785.20
60.02
60
59.98
3750.0
59.96
3718.143
MW
Frequency - Hz
59.94
59.92
3700.0
59.9
59.8883
59.88
59.86
3650.0
59.84
3649.00
59.82
59.8
3600.0
59.78
59.76
59.74
2:26:20
2:26:30
2:26:40
2:26:50
Hz
2:27:00
2:27:10
Average Frequency
2:27:20
MW
2:27:30
Average MW
2:27:40
2:27:50
2:28:00
EPFR for FRO Adjusted
2:28:10
3550.0
2:28:20
002390
Monday, October 12, 2009
0.868 Sustained P.U. Performance
My BA
60.08
3850.0
60.06
60.04
3800.0
60.02
60
3750.0
59.98
59.96
3700.0
MW
Frequency - Hz
59.94
59.92
59.9
3650.0
59.88
59.86
59.84
3600.0
59.82
59.8
3550.0
59.78
59.76
59.74
2:26:20
2:27:20
2:28:20
2:29:20
Hz
2:30:20
2:31:20
2:32:20
Interchange MW
2:33:20
2:34:20
2:35:20
Recovery Period Target MW
2:36:20
2:37:20
2:38:20
2:39:20
Recovery Period Ramp MW
2:40:20
2:41:20
3500.0
2:42:20
002391
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:18
FPointA
Hz
60.0410
A Value
Hz
60.0413
t(0) Time
2:27:20
C Value
Hz
59.8520
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8795722 -391.83436 59.8832866 -401.15622 59.8882944 -415.81276 59.8875559 -412.38887 59.8882944
-414.2499
002392
Value A Data
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
60.04125
3649.00
350.00
-165.48
0.00
90.88
-4.13
15.00
-103 7559.978
Value B
Bias
Setting
EPFR
Frequency
MW
Hz
-42.4877 59.879572
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
Actual
Schedules
Load
Hydro
Units
Response
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+)
MW
MW
MW
MW
MW
MW
3758.96
335.00
-206.46
1.00
93.50
12.04
002393
Value B
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
1.246
Initial
Performance
Unadjusted
P.U.
0.850
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.868
-103
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
7561.71 124.0406 59.883287
3774.25
335.00
-208.51
1.00
94.07
11.67
0.00
BA
Load
Initial
Performance
Adjusted
P.U.
1.411
002394
Value B
Initial
Performance
Unadjusted
P.U.
0.991
Sustained
Performance
P.U.
0.868
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
Frequency
MW
MW
MW
Hz
-103 7562.087 120.2148 59.888819
20 to 40 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
3780.73
335.00
-209.95
1.27
94.68
11.12
0.00
Initial
Performance
Adjusted
P.U.
1.524
Initial
Performance
Unadjusted
P.U.
1.080
Sustained
Performance
P.U.
0.868
002395
Value B
BA
Bias
Setting
MW
-103
18 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Hz
MW
MW
MW
MW
MW
MW
MW
7562.49 114.5162 59.887556
3784.15
335.00
-210.36
2.11
95.19
11.24
0.00
Value B
Initial
Performance
Adjusted
P.U.
1.531
Initial
Performance
Unadjusted
P.U.
1.099
Sustained
Performance
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
Frequency
P.U.
MW/0.1 Hz
MW
MW
Hz
0.868
-103 7562.828 115.8175 59.888294
002396
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Ramping
Actual
Schedules
Load
Hydro
Units
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+)
MW
MW
MW
MW
MW
3785.20
335.00
-165.48
2.18
95.29
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.17
0.00
Initial
Performance
Adjusted
P.U.
1.548
Initial
Performance
Unadjusted
P.U.
1.113
Sustained
Performance
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
P.U.
MW/0.1 Hz
MW
MW
0.868
-103 7562.894 115.0567
002397
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
C
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Ramping units
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 6 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with up to 60 minutes of data. Be sure "Data" worksheet is clear of any old data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data. The data must be numbers not text.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 160 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A160"
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency of the event on the center vertical grid line of the graph (Red Trend).
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 217.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A217"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if your interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar.
When set appropriately, the "Target" trend on the "Sustained" graph will model what Interchange Actual should have done during the event recovery period.
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidded worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
002398
Time (T)
10/12/09 02:12:00
10/12/09 02:12:06
10/12/09 02:12:12
10/12/09 02:12:18
10/12/09 02:12:24
10/12/09 02:12:30
10/12/09 02:12:36
10/12/09 02:12:42
10/12/09 02:12:48
10/12/09 02:12:54
10/12/09 02:13:00
10/12/09 02:13:06
10/12/09 02:13:12
10/12/09 02:13:18
10/12/09 02:13:24
10/12/09 02:13:30
10/12/09 02:13:36
10/12/09 02:13:42
10/12/09 02:13:48
10/12/09 02:13:54
10/12/09 02:14:00
10/12/09 02:14:06
10/12/09 02:14:12
10/12/09 02:14:18
10/12/09 02:14:24
10/12/09 02:14:30
10/12/09 02:14:36
10/12/09 02:14:42
10/12/09 02:14:48
10/12/09 02:14:54
10/12/09 02:15:00
10/12/09 02:15:06
10/12/09 02:15:12
10/12/09 02:15:18
10/12/09 02:15:24
10/12/09 02:15:30
10/12/09 02:15:36
10/12/09 02:15:42
10/12/09 02:15:48
10/12/09 02:15:54
10/12/09 02:16:00
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
MW/0.1 Hz
59.981 3669.878
350 351.361511
0
0
10
15
-103
59.98 3670.949
350 351.361511
0
0.5
10
15
-103
59.981
3672.31
350 351.361511
0
1
10
15
-103
59.982 3672.276
350
357.94751
0
1.5
10
15
-103
59.98 3673.844
350
357.94751
0
2
10
15
-103
59.986
3669.33
350
357.94751
0
2.5
10
15
-103
59.976
3673.56
350
357.94751
0
3
10
15
-103
59.981 3671.887
350
357.94751
0
3.5
10
15
-103
59.99
3671.56
350 360.234741
0
4
10
15
-103
59.995 3668.362
350 360.234741
0
4.5
10
15
-103
59.995 3669.291
350 360.234741
0
5
10
15
-103
59.994 3670.683
350 360.234741
0
5.5
10
15
-103
60.001 3670.712
350 360.234741
0
6
10
15
-103
60.003 3671.227
350 346.525879
0
6.5
10
15
-103
60.003 3671.092
350 346.525879
0
7
10
15
-103
60.003 3669.899
350 346.525879
0
7.5
10
15
-103
60.001 3671.628
350 346.525879
0
8
10
15
-103
60.004 3671.444
350 346.525879
0
8.5
10
15
-103
60.004 3671.066
350 296.443359
0
9
10
15
-103
60.002 3673.498
350 296.443359
0
9.5
10
15
-103
59.999 3673.186
350 296.443359
0
10
10
15
-103
59.998 3673.365
350 296.443359
0
10.5
10
15
-103
59.993 3671.998
350 296.443359
0
11
10
15
-103
59.999 3670.957
350 341.061157
0
11.5
10
15
-103
60.007 3670.162
350 341.061157
0
12
10
15
-103
60.002 3672.713
350 341.061157
0
12.5
10
15
-103
59.999 3670.826
350 341.061157
0
13
10
15
-103
60.01 3673.363
350 341.061157
0
13.5
10
15
-103
60.003 3674.415
350 322.826294
0
14
10
15
-103
59.994
3674.29
350 322.826294
0
14.5
10
15
-103
60.001 3675.166
350 322.826294
0
15
10
15
-103
59.995 3674.906
350 322.826294
0
15.5
10
15
-103
59.986 3677.791
350 322.826294
0
16
10
15
-103
59.989 3676.593
350 321.544403
0
16.5
10
15
-103
59.985 3677.067
350 321.544403
0
17
10
15
-103
59.982 3679.228
350 321.544403
0
17.5
10
15
-103
59.985 3677.627
350 321.544403
0
18
10
15
-103
59.99 3677.528
350 321.544403
0
18.5
10
15
-103
59.983 3678.086
350 362.136261
0
19
10
15
-103
59.983 3679.213
350 362.136261
0
19.5
10
15
-103
59.988 3677.678
350 362.136261
0
20
10
15
-103
BA
Load
MW
7500
7500.99
7501.98
7502.97
7503.96
7504.95
7505.94
7506.93
7507.92
7508.91
7509.9
7510.89
7511.88
7512.87
7513.86
7514.85
7515.84
7516.83
7517.82
7518.81
7519.8
7520.79
7521.78
7522.77
7523.76
7524.75
7525.74
7526.73
7527.72
7528.71
7529.7
7530.69
7531.68
7532.67
7533.66
7534.65
7535.64
7536.63
7537.62
7538.61
7539.6
002399
10/12/09 02:16:06
10/12/09 02:16:12
10/12/09 02:16:18
10/12/09 02:16:24
10/12/09 02:16:30
10/12/09 02:16:36
10/12/09 02:16:42
10/12/09 02:16:48
10/12/09 02:16:54
10/12/09 02:17:00
10/12/09 02:17:06
10/12/09 02:17:12
10/12/09 02:17:18
10/12/09 02:17:24
10/12/09 02:17:30
10/12/09 02:17:36
10/12/09 02:17:42
10/12/09 02:17:48
10/12/09 02:17:54
10/12/09 02:18:00
10/12/09 02:18:06
10/12/09 02:18:12
10/12/09 02:18:18
10/12/09 02:18:24
10/12/09 02:18:30
10/12/09 02:18:36
10/12/09 02:18:42
10/12/09 02:18:48
10/12/09 02:18:54
10/12/09 02:19:00
10/12/09 02:19:06
10/12/09 02:19:12
10/12/09 02:19:18
10/12/09 02:19:24
10/12/09 02:19:30
10/12/09 02:19:36
10/12/09 02:19:42
10/12/09 02:19:48
10/12/09 02:19:54
10/12/09 02:20:00
10/12/09 02:20:06
10/12/09 02:20:12
10/12/09 02:20:18
10/12/09 02:20:24
10/12/09 02:20:30
10/12/09 02:20:36
59.978
59.989
59.983
59.989
59.995
59.998
59.995
59.995
60.003
60.009
60.011
60.007
60.013
60.007
60.006
60.009
60.009
60.001
59.991
59.994
59.995
59.99
59.977
59.995
59.989
59.984
59.986
59.98
59.989
60.007
59.981
59.976
59.977
59.982
59.988
59.987
59.984
59.989
59.984
59.981
59.986
59.985
59.983
59.979
59.98
59.98
3678.729
3679.026
3678.72
3679.39
3678.49
3678.951
3679.903
3677.86
3677.686
3679.209
3679.057
3679.806
3679.851
3679.44
3679.888
3679.261
3679.152
3678.249
3677.955
3677.093
3678.516
3678.743
3680.254
3678.656
3678.427
3677.822
3677.917
3678.963
3680.045
3676.222
3677.49
3680.451
3682.843
3678.229
3671.942
3670.129
3671.576
3671.882
3670.726
3671.401
3670.296
3669.908
3669.382
3671.403
3671.947
3670.137
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
362.136261
362.136261
336.311798
336.311798
336.311798
336.311798
336.311798
316.443054
316.443054
316.443054
316.443054
316.443054
325.464294
325.464294
325.464294
325.464294
325.464294
336.614166
336.614166
336.614166
336.614166
336.614166
316.726166
316.726166
316.726166
316.726166
316.726166
320.195526
320.195526
320.195526
320.195526
320.195526
341.86615
341.86615
341.86615
341.86615
341.86615
348.597839
348.597839
348.597839
348.597839
348.597839
329.085022
329.085022
329.085022
329.085022
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20.5
21
21.5
22
22.5
23
23.5
24
24.5
25
25.5
26
26.5
27
27.5
28
28.5
29
29.5
30
30.5
31
31.5
32
32.5
33
33.5
34
34.5
35
35.5
36
36.5
37
37.5
38
38.5
39
39.5
40
40.5
41
41.5
42
42.5
43
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7540.59
7541.58
7542.57
7543.56
7544.55
7545.54
7546.53
7547.52
7548.51
7549.5
7550.49
7551.48
7552.47
7553.46
7554.45
7555.44
7556.43
7557.42
7558.41
7559.4
7560.39
7561.38
7562.37
7563.36
7564.35
7565.34
7566.33
7567.32
7568.31
7569.3
7570.29
7571.28
7572.27
7573.26
7574.25
7575.24
7576.23
7577.22
7578.21
7579.2
7580.19
7581.18
7582.17
7583.16
7584.15
7585.14
002400
10/12/09 02:20:42
10/12/09 02:20:48
10/12/09 02:20:54
10/12/09 02:21:00
10/12/09 02:21:06
10/12/09 02:21:12
10/12/09 02:21:18
10/12/09 02:21:24
10/12/09 02:21:30
10/12/09 02:21:36
10/12/09 02:21:42
10/12/09 02:21:48
10/12/09 02:21:54
10/12/09 02:22:00
10/12/09 02:22:06
10/12/09 02:22:12
10/12/09 02:22:18
10/12/09 02:22:24
10/12/09 02:22:30
10/12/09 02:22:36
10/12/09 02:22:42
10/12/09 02:22:48
10/12/09 02:22:54
10/12/09 02:23:00
10/12/09 02:23:06
10/12/09 02:23:12
10/12/09 02:23:18
10/12/09 02:23:24
10/12/09 02:23:30
10/12/09 02:23:36
10/12/09 02:23:42
10/12/09 02:23:48
10/12/09 02:23:54
10/12/09 02:24:00
10/12/09 02:24:06
10/12/09 02:24:12
10/12/09 02:24:18
10/12/09 02:24:24
10/12/09 02:24:30
10/12/09 02:24:36
10/12/09 02:24:42
10/12/09 02:24:48
10/12/09 02:24:54
10/12/09 02:25:00
10/12/09 02:25:06
10/12/09 02:25:12
59.979
59.976
59.971
59.973
59.975
59.975
59.979
59.982
59.981
59.985
59.993
59.998
60.01
60.013
60.01
60.023
60.021
60.019
60.025
60.02
60.018
60.019
60.022
60.02
60.02
60.018
60.014
60.01
60.011
60.009
60.009
59.999
59.997
59.998
59.995
59.988
59.982
59.984
59.978
59.974
59.98
59.984
59.988
59.991
59.993
60.002
3672.558
3671.8
3676.263
3676.543
3675.256
3671.593
3669.54
3667.677
3666.911
3667.456
3664.031
3662.055
3662.224
3664.139
3663.265
3661.512
3656.785
3657.71
3659.224
3658.155
3660.82
3662.079
3663.577
3662.552
3663.91
3663.396
3665.313
3666.726
3666.688
3667.696
3666.624
3665.403
3665.352
3666.133
3667.084
3667.853
3669.399
3670.25
3673.243
3676.418
3675.329
3674.399
3672.442
3671.493
3670.028
3672.625
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
329.085022
342.418243
342.418243
342.418243
342.418243
342.418243
338.794647
338.794647
338.794647
338.794647
338.794647
335.931
335.931
335.931
335.931
335.931
339.712402
339.712402
339.712402
339.712402
339.712402
332.024658
332.024658
332.024658
332.024658
332.024658
330.759033
330.759033
330.759033
330.759033
330.759033
323.419952
323.419952
323.419952
323.419952
323.419952
342.350922
342.350922
342.350922
342.350922
342.350922
345.081818
345.081818
345.081818
345.081818
345.081818
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
43.5
44
44.5
45
45.5
46
46.5
47
47.5
48
48.5
49
49.5
50
50.5
51
51.5
52
52.5
53
53.5
54
54.5
55
55.5
56
56.5
57
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
63
63.5
64
64.5
65
65.5
66
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7586.13
7587.12
7588.11
7589.1
7590.09
7591.08
7592.07
7593.06
7594.05
7595.04
7596.03
7597.02
7598.01
7599
7599.99
7600.98
7601.97
7602.96
7603.95
7604.94
7605.93
7606.92
7607.91
7608.9
7609.89
7610.88
7611.87
7612.86
7613.85
7614.84
7615.83
7616.82
7617.81
7618.8
7619.79
7620.78
7621.77
7622.76
7623.75
7624.74
7625.73
7626.72
7627.71
7628.7
7629.69
7630.68
002401
10/12/09 02:25:18
10/12/09 02:25:24
10/12/09 02:25:30
10/12/09 02:25:36
10/12/09 02:25:42
10/12/09 02:25:48
10/12/09 02:25:54
10/12/09 02:26:00
10/12/09 02:26:06
10/12/09 02:26:12
10/12/09 02:26:18
10/12/09 02:26:24
10/12/09 02:26:30
10/12/09 02:26:36
10/12/09 02:26:42
10/12/09 02:26:48
10/12/09 02:26:54
10/12/09 02:27:00
10/12/09 02:27:06
10/12/09 02:27:12
10/12/09 02:27:18
10/12/09 02:27:24
10/12/09 02:27:30
10/12/09 02:27:36
10/12/09 02:27:42
10/12/09 02:27:48
10/12/09 02:27:54
10/12/09 02:28:00
10/12/09 02:28:06
10/12/09 02:28:12
10/12/09 02:28:18
10/12/09 02:28:24
10/12/09 02:28:30
10/12/09 02:28:36
10/12/09 02:28:42
10/12/09 02:28:48
10/12/09 02:28:54
10/12/09 02:29:00
10/12/09 02:29:06
10/12/09 02:29:12
10/12/09 02:29:18
10/12/09 02:29:24
10/12/09 02:29:30
10/12/09 02:29:36
10/12/09 02:29:42
10/12/09 02:29:48
60.004
60.002
60.01
60.011
60.013
60.011
60.017
60.014
60.019
60.027
60.022
60.019
60.021
60.019
60.031
60.036
60.048
60.041
60.039
60.045
60.041
59.978
59.869
59.88
59.883
59.885
59.89
59.893
59.891
59.885
59.888
59.889
59.857
59.858
59.865
59.871
59.88
59.89
59.893
59.902
59.907
59.916
59.92
59.917
59.923
59.928
3673.25
3672.418
3672.261
3673.553
3673.813
3673.068
3671.25
3672.982
3671.193
3668.611
3666.062
3670.454
3672.493
3672.164
3666.467
3660.672
3650.025
3654.294
3651.059
3645.387
3640.682
3696.362
3737.157
3766.194
3780.621
3784.962
3788.072
3788.472
3794.374
3799.959
3802.951
3805.617
3814.862
3826.053
3826.753
3825.713
3819.081
3815.01
3809.652
3804.188
3792.169
3788.132
3781.701
3774.604
3772.722
3768.707
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
346.537384
346.537384
346.537384
346.537384
346.537384
342.905762
342.905762
342.905762
342.905762
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
329.98822
255.444168
255.444168
255.444168
255.444168
255.444168
254.838303
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
66.5
67
67.5
68
68.5
69
69.5
70
70.5
71
71.5
72
72.5
73
73.5
74
74.5
75
75.5
76
76.5
77
77.5
78
78.5
79
79.5
80
80.5
81
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7631.67
7632.66
7633.65
7634.64
7635.63
7636.62
7637.61
7638.6
7639.59
7640.58
7641.57
7642.56
7643.55
7644.54
7645.53
7646.52
7647.51
7648.5
7649.49
7650.48
7651.47
7645
7639
7631
7630
7631
7630
7632
7633
7634
7635
7636
7637
7638
7641
7642
7629
7630
7630
7631
7633
7636
7640
7644
7648
7652
002402
10/12/09 02:29:54
10/12/09 02:30:00
10/12/09 02:30:06
10/12/09 02:30:12
10/12/09 02:30:18
10/12/09 02:30:24
10/12/09 02:30:30
10/12/09 02:30:36
10/12/09 02:30:42
10/12/09 02:30:48
10/12/09 02:30:54
10/12/09 02:31:00
10/12/09 02:31:06
10/12/09 02:31:12
10/12/09 02:31:18
10/12/09 02:31:24
10/12/09 02:31:30
10/12/09 02:31:36
10/12/09 02:31:42
10/12/09 02:31:48
10/12/09 02:31:54
10/12/09 02:32:00
10/12/09 02:32:06
10/12/09 02:32:12
10/12/09 02:32:18
10/12/09 02:32:24
10/12/09 02:32:30
10/12/09 02:32:36
10/12/09 02:32:42
10/12/09 02:32:48
10/12/09 02:32:54
10/12/09 02:33:00
10/12/09 02:33:06
10/12/09 02:33:12
10/12/09 02:33:18
10/12/09 02:33:24
10/12/09 02:33:30
10/12/09 02:33:36
10/12/09 02:33:42
10/12/09 02:33:48
10/12/09 02:33:54
10/12/09 02:34:00
10/12/09 02:34:06
10/12/09 02:34:12
10/12/09 02:34:18
10/12/09 02:34:24
59.927
59.929
59.937
59.949
59.941
59.948
59.951
59.951
59.952
59.954
59.953
59.954
59.956
59.955
59.962
59.966
59.97
59.969
59.971
59.976
59.976
59.978
59.982
59.979
59.983
59.988
59.987
59.992
59.986
59.988
59.998
59.999
60.002
60.008
60.017
60.017
60.023
60.021
60.024
60.025
60.02
60.022
60.023
60.019
60.018
60.019
3767.408
3765.672
3765.105
3753.922
3747.875
3746.706
3740.259
3727.838
3720.578
3715.753
3710.848
3714.623
3716.461
3722.361
3722.267
3723.091
3723.893
3728.053
3733.327
3736.822
3740.877
3746.608
3751.558
3756.407
3760.982
3763.212
3766.433
3768.634
3773.695
3775.363
3776.42
3781.256
3783.896
3785.463
3787.259
3788.03
3787.537
3787.93
3786.55
3785.614
3786.864
3785.726
3785.798
3787.627
3789.404
3789.369
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
254.838303
254.838303
254.838303
254.838303
257.146973
257.146973
257.146973
257.146973
257.146973
262.289368
262.289368
262.289368
262.289368
262.289368
256.647949
256.647949
256.647949
256.647949
256.647949
256.307251
256.307251
256.307251
256.307251
256.307251
249.086395
249.086395
249.086395
249.086395
249.086395
253.742477
253.742477
253.742477
253.742477
253.742477
257.421204
257.421204
257.421204
257.421204
257.421204
261.73822
261.73822
261.73822
261.73822
261.73822
271.875977
271.875977
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7656
7662
7665
7670
7674
7679
7682
7684
7686
7688
7689
7689
7690
7690.08
7690
7692.06
7693.05
7694.04
7695.03
7696.02
7697.01
7698
7699
7699.98
7700.97
7701.96
7702.95
7703.94
7704.93
7705.92
7706.91
7707.9
7708.89
7709.88
7710.87
7711.86
7712.85
7713.84
7714.83
7715.82
7716.81
7717.8
7718.79
7719.78
7720.77
7721.76
002403
10/12/09 02:34:30
10/12/09 02:34:36
10/12/09 02:34:42
10/12/09 02:34:48
10/12/09 02:34:54
10/12/09 02:35:00
10/12/09 02:35:06
10/12/09 02:35:12
10/12/09 02:35:18
10/12/09 02:35:24
10/12/09 02:35:30
10/12/09 02:35:36
10/12/09 02:35:42
10/12/09 02:35:48
10/12/09 02:35:54
10/12/09 02:36:00
10/12/09 02:36:06
10/12/09 02:36:12
10/12/09 02:36:18
10/12/09 02:36:24
10/12/09 02:36:30
10/12/09 02:36:36
10/12/09 02:36:42
10/12/09 02:36:48
10/12/09 02:36:54
10/12/09 02:37:00
10/12/09 02:37:06
10/12/09 02:37:12
10/12/09 02:37:18
10/12/09 02:37:24
10/12/09 02:37:30
10/12/09 02:37:36
10/12/09 02:37:42
10/12/09 02:37:48
10/12/09 02:37:54
10/12/09 02:38:00
10/12/09 02:38:06
10/12/09 02:38:12
10/12/09 02:38:18
10/12/09 02:38:24
10/12/09 02:38:30
10/12/09 02:38:36
10/12/09 02:38:42
10/12/09 02:38:48
10/12/09 02:38:54
10/12/09 02:39:00
60.016
60.012
60.007
60.009
59.999
59.991
59.988
59.984
59.982
59.979
59.976
59.978
59.976
59.975
59.97
59.978
59.975
59.975
59.966
59.969
59.965
59.972
59.969
59.967
59.965
59.965
59.97
59.968
59.97
59.965
59.967
59.979
59.974
59.962
59.961
59.959
59.953
59.956
59.961
59.963
59.968
59.973
59.967
59.976
59.973
59.981
3788.933
3790.411
3792.945
3791.426
3790.216
3788.105
3788.497
3788.101
3787.732
3788.256
3790.665
3789.267
3789.914
3788.963
3792.911
3788.08
3787.164
3786.487
3790.512
3790.959
3789.167
3784.831
3782.809
3779.056
3779.335
3776.597
3773.17
3768.503
3764.786
3761.894
3760.157
3757.773
3751.637
3759.25
3762.022
3763.858
3768.339
3765.606
3761.92
3752.429
3753.51
3753.178
3752.872
3747.476
3746.651
3741.618
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
271.875977
271.875977
271.875977
262.073486
262.073486
262.073486
262.073486
262.073486
260.36441
260.36441
260.36441
260.36441
260.36441
352.644379
352.644379
352.644379
352.644379
352.644379
354.89566
354.89566
354.89566
354.89566
354.89566
340.46936
340.46936
340.46936
340.46936
340.46936
337.642914
337.642914
337.642914
337.642914
337.642914
284.36084
284.36084
284.36084
284.36084
284.36084
260.467987
260.467987
260.467987
260.467987
260.467987
253.141541
253.141541
253.141541
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7722.75
7723.74
7724.73
7725.72
7726.71
7727.7
7728.69
7729.68
7730.67
7731.66
7732.65
7733.64
7734.63
7735.62
7736.61
7737.6
7738.59
7739.58
7740.57
7741.56
7742.55
7743.54
7744.53
7745.52
7746.51
7747.5
7748.49
7749.48
7750.47
7751.46
7752.45
7753.44
7754.43
7755.42
7756.41
7757.4
7758.39
7759.38
7760.37
7761.36
7762.35
7763.34
7764.33
7765.32
7766.31
7767.3
002404
10/12/09 02:39:06
10/12/09 02:39:12
10/12/09 02:39:18
10/12/09 02:39:24
10/12/09 02:39:30
10/12/09 02:39:36
10/12/09 02:39:42
10/12/09 02:39:48
10/12/09 02:39:54
10/12/09 02:40:00
10/12/09 02:40:06
10/12/09 02:40:12
10/12/09 02:40:18
10/12/09 02:40:24
10/12/09 02:40:30
10/12/09 02:40:36
10/12/09 02:40:42
10/12/09 02:40:48
10/12/09 02:40:54
10/12/09 02:41:00
10/12/09 02:41:06
10/12/09 02:41:12
10/12/09 02:41:18
10/12/09 02:41:24
10/12/09 02:41:30
10/12/09 02:41:36
10/12/09 02:41:42
10/12/09 02:41:48
10/12/09 02:41:54
10/12/09 02:42:00
10/12/09 02:42:06
10/12/09 02:42:12
10/12/09 02:42:18
10/12/09 02:42:24
10/12/09 02:42:30
10/12/09 02:42:36
10/12/09 02:42:42
10/12/09 02:42:48
10/12/09 02:42:54
10/12/09 02:43:00
10/12/09 02:43:06
10/12/09 02:43:12
10/12/09 02:43:18
10/12/09 02:43:24
10/12/09 02:43:30
10/12/09 02:43:36
59.982
59.982
59.98
59.98
59.978
59.971
59.975
59.969
59.972
59.977
59.976
59.977
59.979
59.974
59.971
59.966
59.973
59.972
59.97
59.982
59.985
59.989
59.99
60.001
60.006
60.019
60.026
60.029
60.037
60.041
60.043
60.046
60.043
60.043
60.041
60.036
60.034
60.035
60.036
60.032
60.033
60.035
60.037
60.034
60.037
60.04
3738.901
3736.308
3735.65
3736.748
3736.094
3738.875
3737.684
3740.017
3742.424
3741.723
3739.964
3741.268
3738.706
3738.102
3743.419
3747.34
3746.217
3743.149
3733.376
3736.229
3733.115
3725.459
3720.938
3727.754
3727.231
3726.016
3717.333
3715.166
3710.158
3704.591
3701.316
3699.726
3696.865
3696.541
3699.631
3700.106
3701.865
3702.913
3704.967
3703.706
3704.36
3701.942
3702.457
3703.844
3702.28
3700.276
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
253.141541
253.141541
251.929871
251.929871
251.929871
251.929871
251.929871
250.674194
250.674194
250.674194
250.674194
250.674194
253.631866
253.631866
253.631866
253.631866
253.631866
246.957306
246.957306
246.957306
246.957306
246.957306
254.541779
254.541779
254.541779
254.541779
254.541779
256.571594
256.571594
256.571594
256.571594
256.571594
258.37262
258.37262
258.37262
258.37262
258.37262
263.047363
263.047363
263.047363
263.047363
263.047363
260.984375
260.984375
260.984375
260.984375
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7768.29
7769.28
7770.27
7771.26
7772.25
7773.24
7774.23
7775.22
7776.21
7777.2
7778.19
7779.18
7780.17
7781.16
7782.15
7783.14
7784.13
7785.12
7786.11
7787.1
7788.09
7789.08
7790.07
7791.06
7792.05
7793.04
7794.03
7795.02
7796.01
7797
7797.99
7798.98
7799.97
7800.96
7801.95
7802.94
7803.93
7804.92
7805.91
7806.9
7807.89
7808.88
7809.87
7810.86
7811.85
7812.84
002405
10/12/09 02:43:42
10/12/09 02:43:48
10/12/09 02:43:54
10/12/09 02:44:00
10/12/09 02:44:06
10/12/09 02:44:12
10/12/09 02:44:18
10/12/09 02:44:24
10/12/09 02:44:30
10/12/09 02:44:36
10/12/09 02:44:42
10/12/09 02:44:48
10/12/09 02:44:54
10/12/09 02:45:00
10/12/09 02:45:06
10/12/09 02:45:12
10/12/09 02:45:18
10/12/09 02:45:24
10/12/09 02:45:30
10/12/09 02:45:36
10/12/09 02:45:42
10/12/09 02:45:48
10/12/09 02:45:54
10/12/09 02:46:00
10/12/09 02:46:06
10/12/09 02:46:12
10/12/09 02:46:18
10/12/09 02:46:24
10/12/09 02:46:30
10/12/09 02:46:36
10/12/09 02:46:42
10/12/09 02:46:48
10/12/09 02:46:54
10/12/09 02:47:00
10/12/09 02:47:06
10/12/09 02:47:12
10/12/09 02:47:18
10/12/09 02:47:24
10/12/09 02:47:30
10/12/09 02:47:36
10/12/09 02:47:42
10/12/09 02:47:48
10/12/09 02:47:54
10/12/09 02:48:00
10/12/09 02:48:06
10/12/09 02:48:12
60.045
60.04
60.042
60.039
60.034
60.031
60.031
60.031
60.039
60.035
60.042
60.04
60.048
60.044
60.04
60.044
60.042
60.038
60.039
60.039
60.039
60.037
60.038
60.033
60.032
60.042
60.031
60.034
60.038
60.042
60.04
60.041
60.043
60.036
60.042
60.036
60.037
60.035
60.03
60.031
60.031
60.032
60.04
60.036
60.04
60.038
3696.916
3698.429
3693.241
3701.791
3702.148
3707.287
3707.917
3707.615
3701.582
3702.212
3699.69
3700.662
3695.819
3696.897
3698.424
3699.806
3698.507
3699.077
3700.902
3701.139
3699.458
3699.505
3699.4
3702.968
3705.775
3701.981
3702.213
3704.449
3702.795
3696.25
3693.577
3693.786
3694.938
3692.686
3692.357
3692.042
3695.258
3695.491
3697.336
3699.251
3699.126
3698.277
3693.736
3691.919
3692.374
3694.331
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
260.984375
261.318329
261.318329
261.318329
261.318329
261.318329
262.1026
262.1026
262.1026
262.1026
262.1026
262.71701
262.71701
262.71701
262.71701
262.71701
260.016479
260.016479
260.016479
260.016479
260.016479
263.87323
263.87323
263.87323
263.87323
263.87323
264.5979
264.5979
264.5979
264.5979
264.5979
262.415924
262.415924
262.415924
262.415924
262.415924
259.685242
259.685242
259.685242
259.685242
259.685242
255.911011
255.911011
255.911011
255.911011
255.911011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7813.83
7814.82
7815.81
7816.8
7817.79
7818.78
7819.77
7820.76
7821.75
7822.74
7823.73
7824.72
7825.71
7826.7
7827.69
7828.68
7829.67
7830.66
7831.65
7832.64
7833.63
7834.62
7835.61
7836.6
7837.59
7838.58
7839.57
7840.56
7841.55
7842.54
7843.53
7844.52
7845.51
7846.5
7847.49
7848.48
7849.47
7850.46
7851.45
7852.44
7853.43
7854.42
7855.41
7856.4
7857.39
7858.38
002406
10/12/09 02:48:18
10/12/09 02:48:24
10/12/09 02:48:30
10/12/09 02:48:36
10/12/09 02:48:42
10/12/09 02:48:48
10/12/09 02:48:54
10/12/09 02:49:00
10/12/09 02:49:06
10/12/09 02:49:12
10/12/09 02:49:18
10/12/09 02:49:24
10/12/09 02:49:30
10/12/09 02:49:36
10/12/09 02:49:42
10/12/09 02:49:48
10/12/09 02:49:54
10/12/09 02:50:00
10/12/09 02:50:06
10/12/09 02:50:12
10/12/09 02:50:18
10/12/09 02:50:24
10/12/09 02:50:30
10/12/09 02:50:36
10/12/09 02:50:42
10/12/09 02:50:48
10/12/09 02:50:54
10/12/09 02:51:00
10/12/09 02:51:06
10/12/09 02:51:12
10/12/09 02:51:18
10/12/09 02:51:24
10/12/09 02:51:30
10/12/09 02:51:36
10/12/09 02:51:42
10/12/09 02:51:48
10/12/09 02:51:54
10/12/09 02:52:00
10/12/09 02:52:06
10/12/09 02:52:12
10/12/09 02:52:18
10/12/09 02:52:24
10/12/09 02:52:30
10/12/09 02:52:36
10/12/09 02:52:42
10/12/09 02:52:48
60.04
60.034
60.041
60.036
60.039
60.033
60.029
60.03
60.022
60.023
60.023
60.026
60.024
60.023
60.029
60.021
60.025
60.024
60.026
60.02
60.016
60.015
60.012
60.002
60.002
60.001
59.992
59.985
59.984
59.977
59.972
59.975
59.971
59.98
59.982
59.979
59.978
59.978
59.97
59.99
59.999
60.003
60.01
60.022
60.025
60.029
3694.324
3693.748
3691.012
3693.727
3688.159
3690.092
3694.593
3693.412
3698.012
3698.935
3700.486
3699.914
3701.45
3701.702
3700.269
3701.268
3700.532
3700.277
3700.26
3700.965
3703.824
3703.003
3703.167
3703.775
3700.617
3701.389
3700.826
3699.854
3700.77
3703.166
3705.811
3706.543
3710.118
3708.018
3706.125
3706.19
3708.971
3707.24
3711.75
3707.867
3703.787
3699.51
3697.882
3697.868
3693.418
3689.143
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
258.148193
258.148193
258.148193
258.148193
258.148193
258.873596
258.873596
258.873596
258.873596
258.873596
249.33757
249.33757
249.33757
249.33757
249.33757
258.278168
258.278168
258.278168
258.278168
258.278168
258.406372
258.406372
258.406372
258.406372
258.406372
260.538879
260.538879
260.538879
260.538879
260.538879
257.88208
257.88208
257.88208
257.88208
257.88208
258.588654
258.588654
258.588654
258.588654
258.588654
261.906158
261.906158
261.906158
261.906158
261.906158
256.747803
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7859.37
7860.36
7861.35
7862.34
7863.33
7864.32
7865.31
7866.3
7867.29
7868.28
7869.27
7870.26
7871.25
7872.24
7873.23
7874.22
7875.21
7876.2
7877.19
7878.18
7879.17
7880.16
7881.15
7882.14
7883.13
7884.12
7885.11
7886.1
7887.09
7888.08
7889.07
7890.06
7891.05
7892.04
7893.03
7894.02
7895.01
7896
7896.99
7897.98
7898.97
7899.96
7900.95
7901.94
7902.93
7903.92
002407
10/12/09 02:52:54
10/12/09 02:53:00
10/12/09 02:53:06
10/12/09 02:53:12
10/12/09 02:53:18
10/12/09 02:53:24
10/12/09 02:53:30
10/12/09 02:53:36
10/12/09 02:53:42
10/12/09 02:53:48
10/12/09 02:53:54
10/12/09 02:54:00
10/12/09 02:54:06
10/12/09 02:54:12
10/12/09 02:54:18
10/12/09 02:54:24
10/12/09 02:54:30
10/12/09 02:54:36
10/12/09 02:54:42
10/12/09 02:54:48
10/12/09 02:54:54
10/12/09 02:55:00
10/12/09 02:55:06
10/12/09 02:55:12
10/12/09 02:55:18
10/12/09 02:55:24
10/12/09 02:55:30
10/12/09 02:55:36
10/12/09 02:55:42
10/12/09 02:55:48
10/12/09 02:55:54
10/12/09 02:56:00
10/12/09 02:56:06
10/12/09 02:56:12
10/12/09 02:56:18
10/12/09 02:56:24
10/12/09 02:56:30
10/12/09 02:56:36
10/12/09 02:56:42
10/12/09 02:56:48
10/12/09 02:56:54
10/12/09 02:57:00
10/12/09 02:57:06
10/12/09 02:57:12
10/12/09 02:57:18
10/12/09 02:57:24
60.028
60.032
60.03
60.019
60.017
60.015
60.008
60.005
59.997
59.998
59.992
59.985
59.988
59.983
59.987
59.985
59.982
59.978
59.973
59.976
59.979
59.977
59.978
59.981
59.979
59.983
59.992
59.988
59.993
59.994
59.989
59.985
59.986
59.982
59.987
60
60.003
60.002
60.005
60.012
60.022
60.018
60.02
60.019
60.017
60.016
3687.026
3685.576
3687.159
3690.426
3692.578
3693.249
3694.681
3693.75
3691.15
3690.588
3689.445
3689.736
3687.494
3685.66
3683.911
3683.811
3684.884
3685.087
3687.412
3687.848
3684.89
3684.093
3682.318
3682.855
3684.318
3685.286
3681.403
3671.761
3679
3682.7
3684.878
3685.584
3684.976
3684.245
3683.736
3682.138
3681.458
3680.167
3679.669
3676.796
3673.906
3673.648
3676.676
3677.185
3679.289
3678.599
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
256.747803
256.747803
256.747803
256.747803
167.431976
167.431976
167.431976
167.431976
167.431976
164.973404
164.973404
164.973404
164.973404
164.973404
157.628082
157.628082
157.628082
157.628082
157.628082
155.531708
155.531708
155.531708
155.531708
155.531708
160.447235
160.447235
160.447235
160.447235
160.447235
163.958603
163.958603
163.958603
163.958603
163.958603
166.072449
166.072449
166.072449
166.072449
166.072449
163.766586
163.766586
163.766586
163.766586
163.766586
165.101685
165.101685
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7904.91
7905.9
7906.89
7907.88
7908.87
7909.86
7910.85
7911.84
7912.83
7913.82
7914.81
7915.8
7916.79
7917.78
7918.77
7919.76
7920.75
7921.74
7922.73
7923.72
7924.71
7925.7
7926.69
7927.68
7928.67
7929.66
7930.65
7931.64
7932.63
7933.62
7934.61
7935.6
7936.59
7937.58
7938.57
7939.56
7940.55
7941.54
7942.53
7943.52
7944.51
7945.5
7946.49
7947.48
7948.47
7949.46
002408
10/12/09 02:57:30
10/12/09 02:57:36
10/12/09 02:57:42
10/12/09 02:57:48
10/12/09 02:57:54
10/12/09 02:58:00
10/12/09 02:58:06
10/12/09 02:58:12
10/12/09 02:58:18
10/12/09 02:58:24
10/12/09 02:58:30
10/12/09 02:58:36
10/12/09 02:58:42
10/12/09 02:58:48
10/12/09 02:58:54
10/12/09 02:59:00
10/12/09 02:59:06
10/12/09 02:59:12
10/12/09 02:59:18
10/12/09 02:59:24
10/12/09 02:59:30
10/12/09 02:59:36
10/12/09 02:59:42
10/12/09 02:59:48
10/12/09 02:59:54
10/12/09 03:00:00
10/12/09 03:00:06
10/12/09 03:00:12
10/12/09 03:00:18
10/12/09 03:00:24
10/12/09 03:00:30
10/12/09 03:00:36
10/12/09 03:00:42
10/12/09 03:00:48
10/12/09 03:00:54
10/12/09 03:01:00
10/12/09 03:01:06
10/12/09 03:01:12
10/12/09 03:01:18
10/12/09 03:01:24
10/12/09 03:01:30
10/12/09 03:01:36
10/12/09 03:01:42
10/12/09 03:01:48
10/12/09 03:01:54
10/12/09 03:02:00
60.014
60.015
60.019
60.02
60.026
60.022
60.024
60.028
60.035
60.021
60.025
60.023
60.02
60.017
60.01
60.01
60.012
60.013
60.01
60.011
60.018
60.019
60.018
60.016
60.022
60.016
60.01
59.995
59.974
59.968
59.972
59.964
59.963
59.968
59.97
59.976
59.977
59.974
59.974
59.979
59.985
59.979
59.986
59.982
59.987
59.996
3678.589
3674.669
3674.546
3671.982
3671.06
3674.01
3676.051
3671.343
3668.767
3657.164
3669.309
3671.332
3673.833
3675.971
3679.393
3679.597
3679.062
3679.637
3679.383
3679.138
3678.456
3677.431
3678.151
3680.771
3679.167
3682.73
3682.01
3685.306
3687.527
3692.966
3694.974
3698.617
3702.645
3704.023
3703.814
3704.293
3703.142
3705.662
3707.514
3706.335
3704.127
3705.968
3703.913
3705.05
3701.831
3701.308
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
165.101685
165.101685
165.101685
165.476395
165.476395
165.476395
165.476395
165.476395
206.459106
206.459106
206.459106
206.459106
206.459106
211.256042
211.256042
211.256042
211.256042
211.256042
214.346695
214.346695
214.346695
214.346695
214.346695
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.327255
218.327255
218.327255
218.327255
218.327255
217.379425
217.379425
217.379425
217.379425
217.379425
214.830353
214.830353
214.830353
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
16
16
16
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7950.45
7951.44
7952.43
7953.42
7954.41
7955.4
7956.39
7957.38
7958.37
7959.36
7960.35
7961.34
7962.33
7963.32
7964.31
7965.3
7966.29
7967.28
7968.27
7969.26
7970.25
7971.24
7972.23
7973.22
7974.21
7975.2
7976.19
7977.18
7978.17
7979.16
7980.15
7981.14
7982.13
7983.12
7984.11
7985.1
7986.09
7987.08
7988.07
7989.06
7990.05
7991.04
7992.03
7993.02
7994.01
7995
002409
10/12/09 03:02:06
10/12/09 03:02:12
10/12/09 03:02:18
10/12/09 03:02:24
10/12/09 03:02:30
10/12/09 03:02:36
10/12/09 03:02:42
10/12/09 03:02:48
10/12/09 03:02:54
10/12/09 03:03:00
10/12/09 03:03:06
10/12/09 03:03:12
10/12/09 03:03:18
10/12/09 03:03:24
10/12/09 03:03:30
10/12/09 03:03:36
10/12/09 03:03:42
10/12/09 03:03:48
10/12/09 03:03:54
10/12/09 03:04:00
10/12/09 03:04:06
10/12/09 03:04:12
10/12/09 03:04:18
10/12/09 03:04:24
10/12/09 03:04:30
10/12/09 03:04:36
10/12/09 03:04:42
10/12/09 03:04:48
10/12/09 03:04:54
10/12/09 03:05:00
10/12/09 03:05:06
10/12/09 03:05:12
10/12/09 03:05:18
10/12/09 03:05:24
10/12/09 03:05:30
10/12/09 03:05:36
10/12/09 03:05:42
10/12/09 03:05:48
10/12/09 03:05:54
10/12/09 03:06:00
10/12/09 03:06:06
10/12/09 03:06:12
10/12/09 03:06:18
10/12/09 03:06:24
10/12/09 03:06:30
10/12/09 03:06:36
59.997
59.996
59.998
60.01
60.004
60.001
60.007
60.008
60.006
59.999
60.004
60.015
60.009
60.011
60.016
60.019
60.011
60.008
60.015
60.018
60.019
60.025
60.027
60.023
60.024
60.022
60.023
60.018
60.012
60.019
60.015
60.016
60.016
60.018
60.024
60.024
60.019
60.028
60.029
60.029
60.03
60.019
60.021
60.012
60.013
60.016
3700.541
3700.549
3699.5
3699.409
3701.11
3700.22
3702.276
3702.943
3703.819
3705.329
3703.675
3703.017
3705.189
3704.051
3703.708
3704.139
3705.942
3705.749
3706.63
3704.224
3704.795
3702.008
3700.34
3702.959
3703.374
3704.947
3703.16
3705.441
3707.971
3708.831
3709.817
3709.642
3710.677
3707.696
3706.99
3704.406
3705.516
3704.773
3702.093
3701.52
3698.009
3703.815
3700.816
3708.527
3706.991
3705.398
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
214.830353
214.830353
227.655914
227.655914
227.655914
227.655914
227.655914
225.018082
225.018082
225.018082
225.018082
225.018082
228.365158
228.365158
228.365158
228.365158
228.365158
234.075333
234.075333
234.075333
234.075333
234.075333
228.798157
228.798157
228.798157
228.798157
228.798157
229.466965
229.466965
229.466965
229.466965
229.466965
228.980164
228.980164
228.980164
228.980164
228.980164
219.975555
219.975555
219.975555
219.975555
219.975555
229.089249
229.089249
229.089249
229.089249
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7995.99
7996.98
7997.97
7998.96
7999.95
8000.94
8001.93
8002.92
8003.91
8004.9
8005.89
8006.88
8007.87
8008.86
8009.85
8010.84
8011.83
8012.82
8013.81
8014.8
8015.79
8016.78
8017.77
8018.76
8019.75
8020.74
8021.73
8022.72
8023.71
8024.7
8025.69
8026.68
8027.67
8028.66
8029.65
8030.64
8031.63
8032.62
8033.61
8034.6
8035.59
8036.58
8037.57
8038.56
8039.55
8040.54
002410
10/12/09 03:06:42
10/12/09 03:06:48
10/12/09 03:06:54
10/12/09 03:07:00
10/12/09 03:07:06
10/12/09 03:07:12
10/12/09 03:07:18
10/12/09 03:07:24
10/12/09 03:07:30
10/12/09 03:07:36
10/12/09 03:07:42
10/12/09 03:07:48
10/12/09 03:07:54
10/12/09 03:08:00
10/12/09 03:08:06
10/12/09 03:08:12
10/12/09 03:08:18
10/12/09 03:08:24
10/12/09 03:08:30
10/12/09 03:08:36
10/12/09 03:08:42
10/12/09 03:08:48
10/12/09 03:08:54
10/12/09 03:09:00
10/12/09 03:09:06
10/12/09 03:09:12
10/12/09 03:09:18
10/12/09 03:09:24
10/12/09 03:09:30
10/12/09 03:09:36
10/12/09 03:09:42
10/12/09 03:09:48
10/12/09 03:09:54
10/12/09 03:10:00
10/12/09 03:10:06
10/12/09 03:10:12
10/12/09 03:10:18
10/12/09 03:10:24
10/12/09 03:10:30
10/12/09 03:10:36
10/12/09 03:10:42
10/12/09 03:10:48
10/12/09 03:10:54
10/12/09 03:11:00
10/12/09 03:11:06
10/12/09 03:11:12
60.007
59.993
59.994
59.993
59.985
59.98
59.982
59.98
59.983
59.981
59.981
59.978
59.978
59.975
59.979
59.976
59.975
59.98
59.979
59.987
59.98
59.979
59.979
59.983
59.987
59.979
59.979
59.975
59.999
59.986
59.982
59.995
59.989
60
60.004
59.998
60.001
60.003
60.004
60.003
60.009
60.009
60.014
60.008
60.009
60.014
3708.99
3707.304
3706.921
3704.934
3707.071
3708.246
3710.134
3709.192
3707.911
3709.689
3711.256
3712.012
3713.992
3715.323
3715.161
3714.063
3715.688
3714.848
3712.275
3710.05
3710.624
3710.475
3709.286
3708.371
3707.49
3712.303
3712.076
3713.51
3712.092
3714.953
3715.438
3715.068
3716.285
3711.708
3713.362
3719.079
3717.889
3719.021
3719.299
3719.731
3718.976
3720.609
3720.38
3721.272
3721.594
3721.646
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
229.089249
229.663269
229.663269
229.663269
229.663269
229.663269
229.233856
229.233856
229.233856
229.233856
229.233856
231.409882
231.409882
231.409882
231.409882
231.409882
218.622284
218.622284
218.622284
218.622284
218.622284
213.535858
213.535858
213.535858
213.535858
213.535858
225.651855
225.651855
225.651855
225.651855
225.651855
212.573639
212.573639
212.573639
212.573639
212.573639
219.897293
219.897293
219.897293
219.897293
219.897293
231.1754
231.1754
231.1754
231.1754
231.1754
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8041.53
8042.52
8043.51
8044.5
8045.49
8046.48
8047.47
8048.46
8049.45
8050.44
8051.43
8052.42
8053.41
8054.4
8055.39
8056.38
8057.37
8058.36
8059.35
8060.34
8061.33
8062.32
8063.31
8064.3
8065.29
8066.28
8067.27
8068.26
8069.25
8070.24
8071.23
8072.22
8073.21
8074.2
8075.19
8076.18
8077.17
8078.16
8079.15
8080.14
8081.13
8082.12
8083.11
8084.1
8085.09
8086.08
002411
10/12/09 03:11:18
10/12/09 03:11:24
10/12/09 03:11:30
10/12/09 03:11:36
10/12/09 03:11:42
10/12/09 03:11:48
10/12/09 03:11:54
10/12/09 03:12:00
60.01
60.003
59.998
60.002
59.999
59.995
59.988
59.992
3721.645
3724.656
3723.696
3721.879
3724.142
3723.639
3725.361
3723.693
350
350
350
350
350
350
350
350
226.634125
226.634125
226.634125
226.634125
226.634125
227.255066
227.255066
227.255066
16
16
16
16
16
16
16
16
296.5
297
297.5
298
298.5
299
299.5
300
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
8087.07
8088.06
8089.05
8090.04
8091.03
8092.02
8093.01
8094
002412
Balancing Authority Name: My BA
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-80
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Step 4.
Enter MW output of generator or load that caused event (+ for gen loss, - for load loss)
(Value from NERC Event List. If multiple units, enter total MW loss.)
If MW loss value is not known, enter a default 1000 MW.
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 5. worksheet.
2:27:24
2:33:06
633 MW
Event Frequency Data
60.1
60.05
60
Copy Form 2 Data for
Pasting into Form 1
59.95
59.9
59.85
59.8
Step 6. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
59.75
2:12:00
2:18:00
2:24:00
2:30:00
2:36:00
2:42:00
Hz
Step 7. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
2:48:00
2:54:00
3:00:00
3:06:00
3:12:00
002413
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8880
-0.154
3645.04
3788.79
143.75
-17.57
-33.60
89.60
123.20
Balancing Authority My BA
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
105.64 MW
Yes
Initial Response P.U. Performance
1.361 P.U.
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
60.027
60.027
60.027
Interchange
MW
3668.611
3668.611
3668.611
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
3764.66
3778.52
3726.23
3640.68
105.27
0:05:42
No
137.84
123.98
No
Yes
Yes
32.57
18.71
Up
60.000 Hz
2400.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-80 MW/0.1 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.899 P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-21.600
-21.600
-21.600
(TC)
Delayed
Delivery
Frequency
Response
-7.560
-12.474
-15.668
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
633
002414
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
60.022
60.022
60.022
60.019
60.019
60.019
60.021
60.021
60.021
60.019
60.019
60.019
60.031
60.031
60.031
60.036
60.036
60.036
60.048
60.048
60.048
60.041
60.041
60.041
60.039
60.039
60.039
60.045
60.045
60.045
60.041
60.041
60.041
59.978
59.978
59.978
59.978
59.869
59.869
59.869
59.88
59.88
59.88
59.883
59.883
59.883
3666.062
3666.062
3666.062
3670.454
3670.454
3670.454
3672.493
3672.493
3672.493
3672.164
3672.164
3672.164
3666.467
3666.467
3666.467
3660.672
3660.672
3660.672
3650.025
3650.025
3650.025
3654.294
3654.294
3654.294
3651.059
3651.059
3651.059
3645.387
3645.387
3645.387
3640.682
3640.682
3640.682
3696.362
3696.362
3696.362
3696.362
3737.157
3737.157
3737.157
3766.194
3766.194
3766.194
3780.621
3780.621
3780.621
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
59.888 3788.789
59.888 3788.789
59.888 3788.789
-17.599
-17.599
-17.599
-15.201
-15.201
-15.201
-16.800
-16.800
-16.800
-15.201
-15.201
-15.201
-24.799
-24.799
-24.799
-28.799
-28.799
-28.799
-38.400
-38.400
-38.400
-32.800
-32.800
-32.800
-31.201
-31.201
-31.201
-35.999
-35.999
-35.999
-32.800
-32.800
-32.800
17.599
17.599
17.599
17.599
104.800
104.800
104.800
95.999
95.999
95.999
93.600
93.600
93.600
-16.344
-16.784
-17.069
-16.415
-15.990
-15.714
-16.094
-16.341
-16.502
-16.046
-15.750
-15.558
-18.792
-20.894
-22.261
-24.549
-26.037
-27.004
-30.993
-33.585
-35.271
-34.406
-33.844
-33.479
-32.682
-32.163
-31.827
-33.287
-34.236
-34.853
-34.134
-33.667
-33.364
-15.527
-3.933
3.604
8.502
42.207
64.114
78.355
84.530
88.544
91.153
92.010
92.567
92.928
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
-0.442
3750.676
3750.676
3750.676
0.000
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
3670.454
3670.436
3670.271
3669.448
3668.759
3668.156
3668.169
3668.023
3667.773
3664.097
3661.553
3659.744
3657.013
3655.084
3653.675
3649.244
3646.209
3644.082
3644.504
3644.624
3644.547
3644.902
3644.978
3644.872
3642.970
3641.579
3640.520
3640.796
3640.821
3640.682
3658.519
3670.729
3678.881
3684.395
3718.715
3741.239
3756.094
3762.886
3767.515
3770.740
3772.212
3773.385
3774.362
3696.362
3696.362
3696.362
3704.521
3709.960
3713.846
3720.389
3725.479
3729.550
3734.193
3738.062
3741.336
3664.624
3669.376
3673.131
3682.248
3692.080
3701.225
3708.932
3715.442
3720.971
3725.630
3729.609
3733.052
3673.907
3674.523
3675.139
3675.754
3676.370
3676.986
3677.601
3678.217
3678.832
3679.448
3680.064
3680.679
3673.907
3674.215
3674.523
3674.831
3675.139
3675.446
3675.754
3676.062
3676.370
3676.678
3676.986
3677.293
633
633
633
633
633
633
633
633
633
633
633
633
633
002415
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
59.885
59.885
59.885
59.89
59.89
59.89
59.893
59.893
59.893
59.891
59.891
59.891
59.885
59.885
59.885
59.888
59.888
59.888
59.889
59.889
59.889
59.857
59.857
59.857
59.858
59.858
59.858
59.865
59.865
59.865
59.871
59.871
59.871
59.88
59.88
59.88
59.89
59.89
59.89
59.893
59.893
59.893
59.902
59.902
59.902
3784.962
3784.962
3784.962
3788.072
3788.072
3788.072
3788.472
3788.472
3788.472
3794.374
3794.374
3794.374
3799.959
3799.959
3799.959
3802.951
3802.951
3802.951
3805.617
3805.617
3805.617
3814.862
3814.862
3814.862
3826.053
3826.053
3826.053
3826.753
3826.753
3826.753
3825.713
3825.713
3825.713
3819.081
3819.081
3819.081
3815.010
3815.010
3815.010
3809.652
3809.652
3809.652
3804.188
3804.188
3804.188
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
92.001
92.001
92.001
88.000
88.000
88.000
85.599
85.599
85.599
87.201
87.201
87.201
92.001
92.001
92.001
89.600
89.600
89.600
88.800
88.800
88.800
114.401
114.401
114.401
113.599
113.599
113.599
107.999
107.999
107.999
103.201
103.201
103.201
95.999
95.999
95.999
88.000
88.000
88.000
85.599
85.599
85.599
78.400
78.400
78.400
92.604
92.393
92.256
90.767
89.798
89.169
87.920
87.107
86.579
86.797
86.938
87.030
88.770
89.901
90.636
90.273
90.038
89.884
89.505
89.258
89.098
97.954
103.711
107.452
109.604
111.002
111.911
110.541
109.651
109.073
107.018
105.682
104.814
101.729
99.723
98.420
94.773
92.403
90.862
89.020
87.822
87.044
84.019
82.052
80.774
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
3750.676
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
3774.653
3775.058
3775.536
3774.663
3774.310
3774.296
3773.662
3773.466
3773.553
3774.387
3775.144
3775.851
3778.207
3779.953
3781.304
3781.557
3781.937
3782.399
3782.635
3783.004
3783.459
3792.931
3799.303
3803.661
3806.427
3808.441
3809.966
3809.212
3808.938
3808.975
3807.536
3806.815
3806.563
3804.093
3802.703
3802.016
3798.984
3797.230
3796.305
3795.078
3794.496
3794.334
3791.924
3790.573
3789.910
3744.452
3747.152
3749.516
3751.784
3753.800
3755.603
3757.247
3758.734
3760.086
3761.576
3762.943
3764.200
3765.576
3766.849
3768.031
3769.236
3770.359
3771.411
3772.480
3773.484
3774.429
3775.584
3776.675
3777.707
3778.980
3780.187
3781.333
3782.441
3783.496
3784.502
3785.439
3786.334
3787.190
3787.868
3788.519
3789.142
3789.660
3790.157
3790.635
3790.993
3791.339
3791.672
3791.895
3792.111
3792.319
3736.023
3738.626
3740.932
3742.917
3744.661
3746.220
3747.593
3748.825
3749.949
3751.011
3752.017
3752.970
3753.941
3754.904
3755.847
3756.734
3757.574
3758.374
3759.133
3759.856
3760.550
3761.475
3762.526
3763.638
3764.764
3765.884
3766.986
3768.016
3768.990
3769.920
3770.775
3771.576
3772.336
3773.012
3773.631
3774.210
3774.705
3775.147
3775.554
3775.922
3776.266
3776.595
3776.869
3777.109
3777.330
3681.295
3681.910
3682.526
3683.142
3683.757
3684.373
3684.989
3685.604
3686.220
3686.835
3687.451
3688.067
3688.682
3689.298
3689.914
3690.529
3691.145
3691.760
3692.376
3692.992
3693.607
3694.223
3694.838
3695.454
3696.070
3696.685
3697.301
3697.917
3698.532
3699.148
3699.763
3700.379
3700.995
3701.610
3702.226
3702.841
3703.457
3704.073
3704.688
3705.304
3705.920
3706.535
3707.151
3707.766
3708.382
3677.601
3677.909
3678.217
3678.525
3678.832
3679.140
3679.448
3679.756
3680.064
3680.371
3680.679
3680.987
3681.295
3681.603
3681.910
3682.218
3682.526
3682.834
3683.142
3683.450
3683.757
3684.065
3684.373
3684.681
3684.989
3685.296
3685.604
3685.912
3686.220
3686.528
3686.835
3687.143
3687.451
3687.759
3688.067
3688.374
3688.682
3688.990
3689.298
3689.606
3689.914
3690.221
3690.529
3690.837
3691.145
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002416
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
59.907
59.907
59.907
59.916
59.916
59.916
59.92
59.92
59.92
59.917
59.917
59.917
59.923
59.923
59.923
59.928
59.928
59.928
59.927
59.927
59.927
59.929
59.929
59.929
59.937
59.937
59.937
59.949
59.949
59.949
59.941
59.941
59.941
59.948
59.948
59.948
59.951
59.951
59.951
59.951
59.951
59.951
59.952
59.952
59.952
59.954
3792.169
3792.169
3792.169
3788.132
3788.132
3788.132
3781.701
3781.701
3781.701
3774.604
3774.604
3774.604
3772.722
3772.722
3772.722
3768.707
3768.707
3768.707
3767.408
3767.408
3767.408
3765.672
3765.672
3765.672
3765.105
3765.105
3765.105
3753.922
3753.922
3753.922
3747.875
3747.875
3747.875
3746.706
3746.706
3746.706
3740.259
3740.259
3740.259
3727.838
3727.838
3727.838
3720.578
3720.578
3720.578
3715.753
74.399
74.399
74.399
67.200
67.200
67.200
64.001
64.001
64.001
66.400
66.400
66.400
61.600
61.600
61.600
57.599
57.599
57.599
58.401
58.401
58.401
56.799
56.799
56.799
50.400
50.400
50.400
40.799
40.799
40.799
47.198
47.198
47.198
41.599
41.599
41.599
39.200
39.200
39.200
39.200
39.200
39.200
38.400
38.400
38.400
36.801
78.542
77.092
76.149
73.017
70.981
69.658
67.678
66.391
65.555
65.851
66.043
66.168
64.569
63.530
62.854
61.015
59.819
59.042
58.818
58.672
58.577
57.955
57.551
57.288
54.877
53.310
52.291
48.269
45.654
43.955
45.090
45.828
46.308
44.660
43.588
42.892
41.600
40.760
40.214
39.859
39.628
39.478
39.101
38.856
38.696
38.033
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
3788.294
3787.460
3787.133
3784.616
3783.195
3782.488
3781.124
3780.452
3780.232
3781.143
3781.951
3782.692
3781.708
3781.285
3781.225
3780.001
3779.421
3779.260
3779.651
3780.121
3780.642
3780.635
3780.846
3781.199
3779.404
3778.452
3778.049
3774.643
3772.644
3771.560
3773.311
3774.664
3775.759
3774.727
3774.271
3774.190
3773.514
3773.289
3773.359
3773.620
3774.005
3774.471
3774.709
3775.079
3775.535
3775.488
3792.317
3792.314
3792.312
3792.245
3792.179
3792.116
3791.956
3791.800
3791.650
3791.399
3791.156
3790.919
3790.663
3790.414
3790.171
3789.881
3789.599
3789.324
3789.039
3788.762
3788.492
3788.207
3787.928
3787.657
3787.385
3787.120
3786.861
3786.478
3786.104
3785.738
3785.313
3784.897
3784.490
3784.079
3783.677
3783.284
3782.831
3782.388
3781.953
3781.401
3780.860
3780.330
3779.738
3779.158
3778.590
3777.985
3777.515
3777.681
3777.836
3777.946
3778.029
3778.099
3778.145
3778.180
3778.211
3778.254
3778.307
3778.370
3778.417
3778.457
3778.495
3778.515
3778.527
3778.537
3778.551
3778.571
3778.598
3778.623
3778.651
3778.682
3778.690
3778.687
3778.680
3778.633
3778.564
3778.485
3778.426
3778.385
3778.356
3778.316
3778.273
3778.229
3778.180
3778.129
3778.080
3778.034
3777.993
3777.958
3777.926
3777.898
3777.875
3777.852
3708.998
3709.613
3710.229
3710.845
3711.460
3712.076
3712.691
3713.307
3713.923
3714.538
3715.154
3715.769
3716.385
3717.001
3717.616
3718.232
3718.848
3719.463
3720.079
3720.694
3721.310
3721.926
3722.541
3723.157
3723.773
3724.388
3725.004
3725.619
3726.235
3726.851
3727.466
3728.082
3728.697
3729.313
3729.929
3730.544
3731.160
3731.776
3732.391
3733.007
3733.622
3734.238
3734.854
3735.469
3736.085
3736.700
3691.453
3691.760
3692.068
3692.376
3692.684
3692.992
3693.299
3693.607
3693.915
3694.223
3694.531
3694.838
3695.146
3695.454
3695.762
3696.070
3696.378
3696.685
3696.993
3697.301
3697.609
3697.917
3698.224
3698.532
3698.840
3699.148
3699.456
3699.763
3700.071
3700.379
3700.687
3700.995
3701.302
3701.610
3701.918
3702.226
3702.534
3702.841
3703.149
3703.457
3703.765
3704.073
3704.381
3704.688
3704.996
3705.304
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002417
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
59.954
59.954
59.953
59.953
59.953
59.954
59.954
59.954
59.956
59.956
59.956
59.955
59.955
59.955
59.962
59.962
59.962
59.966
59.966
59.966
59.97
59.97
59.97
59.969
59.969
59.969
59.971
59.971
59.971
59.976
59.976
59.976
59.976
59.976
59.976
59.978
59.978
59.978
59.982
59.982
59.982
59.979
59.979
59.979
59.983
59.983
3715.753
3715.753
3710.848
3710.848
3710.848
3714.623
3714.623
3714.623
3716.461
3716.461
3716.461
3722.361
3722.361
3722.361
3722.267
3722.267
3722.267
3723.091
3723.091
3723.091
3723.893
3723.893
3723.893
3728.053
3728.053
3728.053
3733.327
3733.327
3733.327
3736.822
3736.822
3736.822
3740.877
3740.877
3740.877
3746.608
3746.608
3746.608
3751.558
3751.558
3751.558
3756.407
3756.407
3756.407
3760.982
3760.982
36.801
36.801
37.601
37.601
37.601
36.801
36.801
36.801
35.199
35.199
35.199
35.999
35.999
35.999
30.399
30.399
30.399
27.200
27.200
27.200
23.999
23.999
23.999
24.799
24.799
24.799
23.199
23.199
23.199
19.199
19.199
19.199
19.199
19.199
19.199
17.599
17.599
17.599
14.401
14.401
14.401
16.800
16.800
16.800
13.599
13.599
37.602
37.322
37.419
37.483
37.524
37.271
37.107
37.000
36.369
35.960
35.693
35.800
35.870
35.915
33.984
32.729
31.913
30.264
29.192
28.495
26.921
25.898
25.234
25.081
24.982
24.918
24.317
23.926
23.671
22.106
21.088
20.427
19.997
19.718
19.536
18.858
18.418
18.131
16.826
15.977
15.426
15.907
16.219
16.423
15.434
14.792
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
3775.672
3776.008
3776.721
3777.400
3778.057
3778.419
3778.871
3779.379
3779.365
3779.571
3779.920
3780.642
3781.327
3781.988
3780.673
3780.034
3779.834
3778.800
3778.343
3778.262
3777.304
3776.897
3776.848
3777.311
3777.828
3778.379
3778.393
3778.618
3778.979
3778.029
3777.627
3777.581
3777.767
3778.103
3778.537
3778.475
3778.650
3778.980
3778.290
3778.057
3778.121
3779.217
3780.146
3780.964
3780.592
3780.565
3777.393
3776.811
3776.195
3775.590
3774.996
3774.447
3773.908
3773.379
3772.875
3772.380
3771.894
3771.467
3771.047
3770.634
3770.228
3769.828
3769.435
3769.055
3768.682
3768.314
3767.959
3767.609
3767.265
3766.958
3766.657
3766.360
3766.108
3765.859
3765.615
3765.400
3765.188
3764.980
3764.804
3764.630
3764.459
3764.332
3764.206
3764.082
3763.995
3763.908
3763.823
3763.772
3763.722
3763.673
3763.655
3763.637
3777.832
3777.814
3777.804
3777.800
3777.803
3777.808
3777.818
3777.832
3777.845
3777.861
3777.878
3777.902
3777.932
3777.966
3777.989
3778.006
3778.021
3778.027
3778.030
3778.032
3778.026
3778.017
3778.008
3778.002
3778.001
3778.004
3778.007
3778.011
3778.019
3778.019
3778.016
3778.013
3778.011
3778.011
3778.015
3778.019
3778.023
3778.030
3778.032
3778.032
3778.032
3778.040
3778.055
3778.074
3778.091
3778.108
3737.316
3737.932
3738.547
3739.163
3739.779
3740.394
3741.010
3741.625
3742.241
3742.857
3743.472
3744.088
3744.704
3745.319
3745.935
3746.550
3747.166
3747.782
3748.397
3749.013
3749.628
3750.244
3750.860
3751.475
3752.091
3752.707
3753.322
3753.938
3754.553
3755.169
3755.785
3756.400
3757.016
3757.631
3758.247
3758.863
3759.478
3760.094
3760.710
3761.325
3761.941
3762.556
3763.172
3763.788
3764.403
3765.019
3705.612
3705.920
3706.227
3706.535
3706.843
3707.151
3707.459
3707.766
3708.074
3708.382
3708.690
3708.998
3709.305
3709.613
3709.921
3710.229
3710.537
3710.845
3711.152
3711.460
3711.768
3712.076
3712.384
3712.691
3712.999
3713.307
3713.615
3713.923
3714.230
3714.538
3714.846
3715.154
3715.462
3715.769
3716.077
3716.385
3716.693
3717.001
3717.309
3717.616
3717.924
3718.232
3718.540
3718.848
3719.155
3719.463
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002418
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
59.983
59.988
59.988
59.988
59.987
59.987
59.987
59.992
59.992
59.992
59.986
59.986
59.986
59.988
59.988
59.988
59.998
59.998
59.998
59.999
59.999
59.999
60.002
60.002
60.002
60.008
60.008
60.008
60.017
60.017
60.017
60.017
60.017
60.017
60.023
60.023
60.023
60.021
60.021
60.021
60.024
60.024
60.024
60.025
60.025
60.025
3760.982
3763.212
3763.212
3763.212
3766.433
3766.433
3766.433
3768.634
3768.634
3768.634
3773.695
3773.695
3773.695
3775.363
3775.363
3775.363
3776.420
3776.420
3776.420
3781.256
3781.256
3781.256
3783.896
3783.896
3783.896
3785.463
3785.463
3785.463
3787.259
3787.259
3787.259
3788.030
3788.030
3788.030
3787.537
3787.537
3787.537
3787.930
3787.930
3787.930
3786.550
3786.550
3786.550
3785.614
3785.614
3785.614
13.599
9.601
9.601
9.601
10.400
10.400
10.400
6.400
6.400
6.400
11.200
11.200
11.200
9.601
9.601
9.601
1.599
1.599
1.599
0.800
0.800
0.800
-1.599
-1.599
-1.599
-6.400
-6.400
-6.400
-13.599
-13.599
-13.599
-13.599
-13.599
-13.599
-18.399
-18.399
-18.399
-16.800
-16.800
-16.800
-19.199
-19.199
-19.199
-20.001
-20.001
-20.001
14.374
12.703
11.618
10.912
10.733
10.616
10.541
9.091
8.149
7.537
8.819
9.652
10.194
9.986
9.851
9.764
6.906
5.049
3.841
2.777
2.085
1.635
0.503
-0.233
-0.711
-2.702
-3.996
-4.837
-7.904
-9.897
-11.193
-12.035
-12.582
-12.938
-14.849
-16.092
-16.899
-16.865
-16.842
-16.827
-17.657
-18.197
-18.547
-19.056
-19.387
-19.602
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.616
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3780.763
3779.708
3779.238
3779.147
3779.584
3780.083
3780.623
3779.789
3779.463
3779.466
3781.364
3782.813
3783.970
3784.378
3784.859
3785.387
3783.145
3781.903
3781.311
3780.862
3780.786
3780.952
3779.820
3779.084
3778.606
3776.615
3775.321
3774.479
3771.413
3769.420
3768.124
3767.282
3766.735
3766.379
3764.467
3763.225
3762.417
3762.452
3762.475
3762.490
3761.660
3761.120
3760.769
3760.261
3759.930
3759.715
3763.619
3763.617
3763.614
3763.611
3763.630
3763.648
3763.665
3763.697
3763.728
3763.758
3763.820
3763.881
3763.941
3764.011
3764.080
3764.148
3764.221
3764.294
3764.366
3764.465
3764.563
3764.660
3764.771
3764.881
3764.990
3765.106
3765.221
3765.335
3765.457
3765.579
3765.698
3765.821
3765.942
3766.062
3766.179
3766.293
3766.407
3766.521
3766.635
3766.747
3766.851
3766.953
3767.055
3767.150
3767.245
3767.339
3778.125
3778.136
3778.143
3778.150
3778.159
3778.171
3778.187
3778.197
3778.205
3778.213
3778.232
3778.261
3778.296
3778.333
3778.372
3778.415
3778.443
3778.463
3778.480
3778.494
3778.508
3778.522
3778.529
3778.533
3778.533
3778.522
3778.504
3778.481
3778.442
3778.392
3778.335
3778.274
3778.211
3778.147
3778.073
3777.993
3777.910
3777.828
3777.746
3777.666
3777.582
3777.497
3777.410
3777.322
3777.232
3777.143
3765.635
3766.250
3766.866
3767.481
3768.097
3768.713
3769.328
3769.944
3770.559
3771.175
3771.791
3772.406
3773.022
3773.638
3774.253
3774.869
3775.484
3776.100
3776.716
3777.331
3777.947
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3719.771
3720.079
3720.387
3720.694
3721.002
3721.310
3721.618
3721.926
3722.233
3722.541
3722.849
3723.157
3723.465
3723.773
3724.080
3724.388
3724.696
3725.004
3725.312
3725.619
3725.927
3726.235
3726.539
3726.840
3727.137
3727.431
3727.722
3728.009
3728.293
3728.574
3728.851
3729.126
3729.398
3729.666
3729.932
3730.195
3730.455
3730.712
3730.967
3731.219
3731.468
3731.714
3731.958
3732.200
3732.439
3732.675
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002419
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
60.02
60.02
60.02
60.022
60.022
60.022
60.023
60.023
60.023
60.019
60.019
60.019
60.018
60.018
60.018
60.019
60.019
60.019
60.016
60.016
60.016
60.012
60.012
60.012
60.007
60.007
60.007
60.009
60.009
60.009
59.999
59.999
59.999
59.991
59.991
59.991
59.988
59.988
59.988
59.984
59.984
59.984
59.982
59.982
59.982
59.979
3786.864
3786.864
3786.864
3785.726
3785.726
3785.726
3785.798
3785.798
3785.798
3787.627
3787.627
3787.627
3789.404
3789.404
3789.404
3789.369
3789.369
3789.369
3788.933
3788.933
3788.933
3790.411
3790.411
3790.411
3792.945
3792.945
3792.945
3791.426
3791.426
3791.426
3790.216
3790.216
3790.216
3788.105
3788.105
3788.105
3788.497
3788.497
3788.497
3788.101
3788.101
3788.101
3787.732
3787.732
3787.732
3788.256
-16.000
-16.000
-16.000
-17.599
-17.599
-17.599
-18.399
-18.399
-18.399
-15.201
-15.201
-15.201
-14.401
-14.401
-14.401
-15.201
-15.201
-15.201
-12.799
-12.799
-12.799
-9.601
-9.601
-9.601
-5.600
-5.600
-5.600
-7.199
-7.199
-7.199
0.800
0.800
0.800
7.199
7.199
7.199
9.601
9.601
9.601
12.799
12.799
12.799
14.401
14.401
14.401
16.800
-18.341
-17.522
-16.989
-17.203
-17.342
-17.432
-17.770
-17.990
-18.133
-17.107
-16.440
-16.006
-15.444
-15.079
-14.842
-14.968
-15.049
-15.102
-14.296
-13.772
-13.432
-12.091
-11.219
-10.653
-8.884
-7.735
-6.988
-7.062
-7.110
-7.141
-4.362
-2.555
-1.381
1.622
3.574
4.843
6.508
7.591
8.294
9.871
10.896
11.562
12.556
13.202
13.621
14.734
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3760.975
3761.795
3762.327
3762.114
3761.975
3761.885
3761.546
3761.326
3761.183
3762.210
3762.877
3763.311
3763.872
3764.237
3764.475
3764.349
3764.268
3764.214
3765.021
3765.545
3765.885
3767.226
3768.097
3768.664
3770.432
3771.582
3772.329
3772.255
3772.207
3772.176
3774.955
3776.761
3777.936
3780.939
3782.891
3784.160
3785.825
3786.907
3787.611
3789.188
3790.213
3790.879
3791.872
3792.518
3792.938
3794.051
3767.438
3767.536
3767.633
3767.724
3767.813
3767.902
3767.990
3768.077
3768.164
3768.258
3768.352
3768.444
3768.545
3768.644
3768.742
3768.840
3768.936
3769.032
3769.124
3769.216
3769.307
3769.404
3769.499
3769.595
3769.700
3769.805
3769.909
3770.005
3770.100
3770.194
3770.282
3770.370
3770.457
3770.533
3770.609
3770.685
3770.761
3770.837
3770.912
3770.985
3771.057
3771.129
3771.198
3771.267
3771.336
3771.405
3777.061
3776.984
3776.910
3776.836
3776.762
3776.689
3776.614
3776.539
3776.464
3776.395
3776.330
3776.267
3776.208
3776.151
3776.095
3776.040
3775.985
3775.930
3775.879
3775.831
3775.785
3775.746
3775.711
3775.679
3775.655
3775.637
3775.622
3775.607
3775.592
3775.577
3775.574
3775.579
3775.590
3775.613
3775.644
3775.681
3775.725
3775.772
3775.823
3775.879
3775.940
3776.003
3776.069
3776.138
3776.207
3776.281
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3732.909
3733.141
3733.371
3733.598
3733.822
3734.045
3734.265
3734.484
3734.700
3734.914
3735.126
3735.335
3735.543
3735.749
3735.953
3736.155
3736.355
3736.553
3736.749
3736.944
3737.137
3737.327
3737.517
3737.704
3737.890
3738.074
3738.256
3738.437
3738.616
3738.794
3738.970
3739.144
3739.317
3739.488
3739.658
3739.827
3739.994
3740.159
3740.323
3740.486
3740.647
3740.807
3740.966
3741.123
3741.279
3741.434
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002420
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
59.979
59.979
59.976
59.976
59.976
59.978
59.978
59.978
59.976
59.976
59.976
59.975
59.975
59.975
59.97
59.97
59.97
59.978
59.978
59.978
59.975
59.975
59.975
59.975
59.975
59.975
59.966
59.966
59.966
59.969
59.969
59.969
59.965
59.965
59.965
59.972
59.972
59.972
59.969
59.969
59.969
59.967
59.967
59.967
59.965
59.965
3788.256
3788.256
3790.665
3790.665
3790.665
3789.267
3789.267
3789.267
3789.914
3789.914
3789.914
3788.963
3788.963
3788.963
3792.911
3792.911
3792.911
3788.080
3788.080
3788.080
3787.164
3787.164
3787.164
3786.487
3786.487
3786.487
3790.512
3790.512
3790.512
3790.959
3790.959
3790.959
3789.167
3789.167
3789.167
3784.831
3784.831
3784.831
3782.809
3782.809
3782.809
3779.056
3779.056
3779.056
3779.335
3779.335
16.800
16.800
19.199
19.199
19.199
17.599
17.599
17.599
19.199
19.199
19.199
20.001
20.001
20.001
23.999
23.999
23.999
17.599
17.599
17.599
20.001
20.001
20.001
20.001
20.001
20.001
27.200
27.200
27.200
24.799
24.799
24.799
28.000
28.000
28.000
22.400
22.400
22.400
24.799
24.799
24.799
26.401
26.401
26.401
28.000
28.000
15.457
15.927
17.072
17.816
18.300
18.055
17.896
17.792
18.284
18.604
18.812
19.228
19.499
19.675
21.188
22.172
22.811
20.987
19.802
19.031
19.370
19.591
19.735
19.828
19.889
19.928
22.473
24.128
25.203
25.062
24.970
24.910
25.991
26.694
27.151
25.488
24.407
23.705
24.088
24.336
24.498
25.164
25.597
25.878
26.621
27.103
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3794.774
3795.244
3796.389
3797.133
3797.617
3797.372
3797.212
3797.109
3797.601
3797.921
3798.129
3798.545
3798.816
3798.991
3800.505
3801.489
3802.128
3800.304
3799.118
3798.348
3798.687
3798.908
3799.051
3799.145
3799.205
3799.245
3801.790
3803.445
3804.520
3804.378
3804.286
3804.226
3805.308
3806.011
3806.468
3804.805
3803.724
3803.021
3803.404
3803.653
3803.815
3804.481
3804.914
3805.195
3805.938
3806.420
3771.475
3771.544
3771.622
3771.699
3771.776
3771.846
3771.916
3771.986
3772.057
3772.128
3772.198
3772.264
3772.330
3772.395
3772.475
3772.554
3772.632
3772.692
3772.751
3772.809
3772.864
3772.918
3772.972
3773.023
3773.073
3773.123
3773.188
3773.252
3773.316
3773.380
3773.445
3773.509
3773.566
3773.622
3773.678
3773.718
3773.758
3773.798
3773.830
3773.862
3773.893
3773.912
3773.930
3773.947
3773.966
3773.985
3776.357
3776.435
3776.516
3776.600
3776.685
3776.768
3776.850
3776.932
3777.014
3777.097
3777.180
3777.264
3777.349
3777.433
3777.523
3777.616
3777.710
3777.797
3777.879
3777.957
3778.036
3778.115
3778.194
3778.273
3778.351
3778.429
3778.516
3778.608
3778.704
3778.798
3778.892
3778.984
3779.080
3779.177
3779.276
3779.368
3779.455
3779.539
3779.624
3779.709
3779.795
3779.882
3779.969
3780.058
3780.148
3780.239
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3741.587
3741.739
3741.890
3742.040
3742.188
3742.336
3742.482
3742.627
3742.770
3742.913
3743.055
3743.195
3743.334
3743.472
3743.609
3743.745
3743.880
3744.014
3744.147
3744.279
3744.410
3744.540
3744.669
3744.796
3744.923
3745.049
3745.174
3745.299
3745.422
3745.544
3745.665
3745.786
3745.906
3746.024
3746.142
3746.259
3746.375
3746.491
3746.605
3746.719
3746.832
3746.944
3747.055
3747.166
3747.276
3747.385
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002421
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
59.965
59.965
59.965
59.965
59.97
59.97
59.97
59.968
59.968
59.968
59.97
59.97
59.97
59.965
59.965
59.965
59.967
59.967
59.967
59.979
59.979
59.979
59.974
59.974
59.974
59.962
59.962
59.962
59.961
59.961
59.961
59.959
59.959
59.959
59.953
59.953
59.953
59.956
59.956
59.956
59.961
59.961
59.961
59.963
59.963
59.963
3779.335
3776.597
3776.597
3776.597
3773.170
3773.170
3773.170
3768.503
3768.503
3768.503
3764.786
3764.786
3764.786
3761.894
3761.894
3761.894
3760.157
3760.157
3760.157
3757.773
3757.773
3757.773
3751.637
3751.637
3751.637
3759.250
3759.250
3759.250
3762.022
3762.022
3762.022
3763.858
3763.858
3763.858
3768.339
3768.339
3768.339
3765.606
3765.606
3765.606
3761.920
3761.920
3761.920
3752.429
3752.429
3752.429
28.000
28.000
28.000
28.000
23.999
23.999
23.999
25.601
25.601
25.601
23.999
23.999
23.999
28.000
28.000
28.000
26.401
26.401
26.401
16.800
16.800
16.800
20.801
20.801
20.801
30.399
30.399
30.399
31.201
31.201
31.201
32.800
32.800
32.800
37.601
37.601
37.601
35.199
35.199
35.199
31.201
31.201
31.201
29.599
29.599
29.599
27.417
27.621
27.754
27.840
26.496
25.622
25.054
25.245
25.370
25.451
24.943
24.612
24.398
25.658
26.478
27.011
26.797
26.658
26.568
23.149
20.927
19.483
19.944
20.244
20.439
23.925
26.191
27.663
28.902
29.706
30.230
31.129
31.714
32.094
34.022
35.274
36.089
35.777
35.575
35.443
33.959
32.993
32.366
31.398
30.768
30.359
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3806.734
3806.938
3807.070
3807.157
3805.812
3804.939
3804.371
3804.562
3804.687
3804.768
3804.259
3803.929
3803.714
3804.975
3805.795
3806.327
3806.114
3805.975
3805.885
3802.466
3800.244
3798.799
3799.261
3799.561
3799.756
3803.241
3805.507
3806.980
3808.218
3809.023
3809.546
3810.446
3811.031
3811.411
3813.338
3814.591
3815.405
3815.094
3814.892
3814.760
3813.275
3812.310
3811.683
3810.714
3810.085
3809.676
3774.003
3774.012
3774.021
3774.030
3774.027
3774.024
3774.021
3774.003
3773.984
3773.966
3773.935
3773.905
3773.874
3773.835
3773.795
3773.756
3773.711
3773.667
3773.623
3773.572
3773.521
3773.470
3773.400
3773.330
3773.261
3773.216
3773.172
3773.127
3773.092
3773.058
3773.023
3772.994
3772.966
3772.938
3772.923
3772.909
3772.895
3772.873
3772.851
3772.829
3772.795
3772.762
3772.730
3772.669
3772.608
3772.547
3780.331
3780.422
3780.514
3780.605
3780.691
3780.774
3780.854
3780.934
3781.014
3781.093
3781.171
3781.247
3781.321
3781.400
3781.480
3781.562
3781.643
3781.722
3781.801
3781.868
3781.927
3781.982
3782.037
3782.093
3782.150
3782.217
3782.291
3782.369
3782.451
3782.534
3782.619
3782.706
3782.794
3782.883
3782.977
3783.075
3783.174
3783.272
3783.369
3783.465
3783.555
3783.642
3783.727
3783.808
3783.887
3783.965
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3747.493
3747.601
3747.707
3747.813
3747.919
3748.023
3748.127
3748.230
3748.333
3748.435
3748.536
3748.636
3748.736
3748.835
3748.933
3749.031
3749.128
3749.225
3749.321
3749.416
3749.511
3749.605
3749.698
3749.791
3749.883
3749.975
3750.066
3750.156
3750.246
3750.335
3750.424
3750.512
3750.600
3750.687
3750.774
3750.860
3750.945
3751.030
3751.115
3751.199
3751.282
3751.365
3751.447
3751.529
3751.611
3751.692
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002422
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
59.968
59.968
59.968
59.973
59.973
59.973
59.967
59.967
59.967
59.976
59.976
59.976
59.973
59.973
59.973
59.981
59.981
59.981
59.982
59.982
59.982
59.982
59.982
59.982
59.98
59.98
59.98
59.98
59.98
59.98
59.978
59.978
59.978
59.971
59.971
59.971
59.975
59.975
59.975
59.969
59.969
59.969
59.972
59.972
59.972
59.977
3753.510
3753.510
3753.510
3753.178
3753.178
3753.178
3752.872
3752.872
3752.872
3747.476
3747.476
3747.476
3746.651
3746.651
3746.651
3741.618
3741.618
3741.618
3738.901
3738.901
3738.901
3736.308
3736.308
3736.308
3735.650
3735.650
3735.650
3736.748
3736.748
3736.748
3736.094
3736.094
3736.094
3738.875
3738.875
3738.875
3737.684
3737.684
3737.684
3740.017
3740.017
3740.017
3742.424
3742.424
3742.424
3741.723
25.601
25.601
25.601
21.600
21.600
21.600
26.401
26.401
26.401
19.199
19.199
19.199
21.600
21.600
21.600
15.201
15.201
15.201
14.401
14.401
14.401
14.401
14.401
14.401
16.000
16.000
16.000
16.000
16.000
16.000
17.599
17.599
17.599
23.199
23.199
23.199
20.001
20.001
20.001
24.799
24.799
24.799
22.400
22.400
22.400
18.399
28.694
27.611
26.908
25.050
23.843
23.058
24.228
24.988
25.483
23.283
21.854
20.924
21.161
21.315
21.415
19.240
17.826
16.907
16.030
15.460
15.089
14.849
14.692
14.590
15.084
15.405
15.613
15.749
15.837
15.894
16.491
16.879
17.131
19.255
20.636
21.533
20.997
20.648
20.422
21.954
22.949
23.597
23.178
22.906
22.729
21.213
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3808.010
3806.928
3806.225
3804.367
3803.160
3802.375
3803.545
3804.305
3804.799
3802.600
3801.170
3800.241
3800.478
3800.632
3800.731
3798.557
3797.143
3796.224
3795.347
3794.777
3794.406
3794.165
3794.009
3793.907
3794.401
3794.721
3794.930
3795.065
3795.154
3795.211
3795.808
3796.196
3796.448
3798.572
3799.952
3800.850
3800.314
3799.965
3799.739
3801.270
3802.266
3802.913
3802.495
3802.222
3802.045
3800.530
3772.491
3772.434
3772.378
3772.321
3772.265
3772.208
3772.152
3772.095
3772.039
3771.968
3771.897
3771.826
3771.754
3771.682
3771.610
3771.524
3771.439
3771.354
3771.262
3771.171
3771.080
3770.982
3770.885
3770.789
3770.691
3770.593
3770.497
3770.403
3770.311
3770.219
3770.125
3770.032
3769.940
3769.855
3769.771
3769.688
3769.601
3769.516
3769.430
3769.352
3769.273
3769.196
3769.125
3769.054
3768.984
3768.912
3784.036
3784.104
3784.170
3784.230
3784.286
3784.339
3784.395
3784.453
3784.513
3784.565
3784.613
3784.659
3784.704
3784.750
3784.796
3784.835
3784.870
3784.902
3784.932
3784.960
3784.986
3785.012
3785.037
3785.062
3785.088
3785.115
3785.142
3785.170
3785.197
3785.225
3785.254
3785.283
3785.314
3785.350
3785.389
3785.431
3785.471
3785.510
3785.548
3785.590
3785.635
3785.681
3785.726
3785.769
3785.812
3785.851
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3751.772
3751.852
3751.932
3752.011
3752.089
3752.167
3752.245
3752.322
3752.399
3752.475
3752.551
3752.626
3752.701
3752.776
3752.850
3752.924
3752.997
3753.070
3753.142
3753.214
3753.286
3753.357
3753.428
3753.498
3753.568
3753.638
3753.707
3753.776
3753.844
3753.912
3753.980
3754.047
3754.114
3754.181
3754.247
3754.313
3754.379
3754.444
3754.509
3754.573
3754.637
3754.701
3754.765
3754.828
3754.891
3754.953
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002423
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
59.977
59.977
59.976
59.976
59.976
59.977
59.977
59.977
59.979
59.979
59.979
59.974
59.974
59.974
59.971
59.971
59.971
59.966
59.966
59.966
59.973
59.973
59.973
59.972
59.972
59.972
59.97
59.97
59.97
59.982
59.982
59.982
59.985
59.985
59.985
59.989
59.989
59.989
59.99
59.99
59.99
60.001
60.001
60.001
60.006
60.006
3741.723
3741.723
3739.964
3739.964
3739.964
3741.268
3741.268
3741.268
3738.706
3738.706
3738.706
3738.102
3738.102
3738.102
3743.419
3743.419
3743.419
3747.340
3747.340
3747.340
3746.217
3746.217
3746.217
3743.149
3743.149
3743.149
3733.376
3733.376
3733.376
3736.229
3736.229
3736.229
3733.115
3733.115
3733.115
3725.459
3725.459
3725.459
3720.938
3720.938
3720.938
3727.754
3727.754
3727.754
3727.231
3727.231
18.399
18.399
19.199
19.199
19.199
18.399
18.399
18.399
16.800
16.800
16.800
20.801
20.801
20.801
23.199
23.199
23.199
27.200
27.200
27.200
21.600
21.600
21.600
22.400
22.400
22.400
23.999
23.999
23.999
14.401
14.401
14.401
12.000
12.000
12.000
8.801
8.801
8.801
7.999
7.999
7.999
-0.800
-0.800
-0.800
-4.800
-4.800
20.228
19.588
19.452
19.363
19.306
18.988
18.782
18.648
18.001
17.581
17.307
18.530
19.325
19.841
21.017
21.781
22.277
24.000
25.120
25.848
24.362
23.395
22.767
22.638
22.555
22.501
23.025
23.366
23.588
20.372
18.282
16.924
15.200
14.080
13.352
11.759
10.724
10.051
9.333
8.866
8.562
5.286
3.156
1.771
-0.529
-2.024
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3799.545
3798.905
3798.769
3798.680
3798.622
3798.305
3798.099
3797.965
3797.318
3796.897
3796.624
3797.847
3798.642
3799.158
3800.334
3801.097
3801.594
3803.317
3804.437
3805.165
3803.678
3802.712
3802.084
3801.955
3801.872
3801.817
3802.342
3802.683
3802.904
3799.689
3797.599
3796.241
3794.517
3793.397
3792.669
3791.076
3790.041
3789.368
3788.649
3788.183
3787.879
3784.602
3782.473
3781.088
3778.788
3777.293
3768.841
3768.770
3768.694
3768.620
3768.545
3768.474
3768.404
3768.334
3768.258
3768.182
3768.107
3768.030
3767.954
3767.878
3767.817
3767.755
3767.694
3767.642
3767.592
3767.541
3767.488
3767.435
3767.382
3767.322
3767.263
3767.203
3767.120
3767.037
3766.955
3766.880
3766.806
3766.731
3766.650
3766.569
3766.488
3766.390
3766.292
3766.194
3766.086
3765.978
3765.871
3765.781
3765.691
3765.602
3765.511
3765.422
3785.887
3785.921
3785.954
3785.988
3786.020
3786.052
3786.083
3786.114
3786.143
3786.170
3786.197
3786.227
3786.258
3786.291
3786.327
3786.364
3786.402
3786.445
3786.490
3786.537
3786.579
3786.619
3786.658
3786.696
3786.733
3786.770
3786.809
3786.847
3786.887
3786.918
3786.944
3786.967
3786.985
3787.000
3787.014
3787.024
3787.031
3787.037
3787.040
3787.043
3787.045
3787.039
3787.029
3787.015
3786.995
3786.972
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3755.015
3755.077
3755.138
3755.200
3755.260
3755.321
3755.381
3755.441
3755.501
3755.560
3755.619
3755.678
3755.736
3755.794
3755.852
3755.909
3755.967
3756.023
3756.080
3756.136
3756.192
3756.248
3756.304
3756.359
3756.414
3756.469
3756.523
3756.577
3756.631
3756.685
3756.738
3756.791
3756.844
3756.897
3756.949
3757.001
3757.053
3757.104
3757.156
3757.207
3757.258
3757.308
3757.359
3757.409
3757.459
3757.508
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002424
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
60.006
60.019
60.019
60.019
60.026
60.026
60.026
60.029
60.029
60.029
60.037
60.037
60.037
60.041
60.041
60.041
60.043
60.043
60.043
60.046
60.046
60.046
60.043
60.043
60.043
3727.231
3726.016
3726.016
3726.016
3717.333
3717.333
3717.333
3715.166
3715.166
3715.166
3710.158
3710.158
3710.158
3704.591
3704.591
3704.591
3701.316
3701.316
3701.316
3699.726
3699.726
3699.726
3696.865
3696.865
3696.865
-4.800
-15.201
-15.201
-15.201
-20.801
-20.801
-20.801
-23.199
-23.199
-23.199
-29.599
-29.599
-29.599
-32.800
-32.800
-32.800
-34.399
-34.399
-34.399
-36.801
-36.801
-36.801
-34.399
-34.399
-34.399
-2.996
-7.267
-10.044
-11.849
-14.982
-17.019
-18.342
-20.042
-21.147
-21.866
-24.572
-26.332
-27.475
-29.339
-30.550
-31.338
-32.409
-33.106
-33.559
-34.694
-35.431
-35.911
-35.382
-35.038
-34.814
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3776.321
3772.049
3769.273
3767.468
3764.335
3762.298
3760.974
3759.274
3758.169
3757.451
3754.744
3752.985
3751.842
3749.978
3748.766
3747.979
3746.907
3746.211
3745.758
3744.623
3743.886
3743.406
3743.935
3744.279
3744.502
3765.332
3765.240
3765.149
3765.058
3764.947
3764.837
3764.727
3764.613
3764.499
3764.386
3764.262
3764.138
3764.016
3763.880
3763.746
3763.612
3763.472
3763.332
3763.192
3763.050
3762.908
3762.767
3762.620
3762.474
3762.329
3786.947
3786.913
3786.872
3786.826
3786.774
3786.718
3786.658
3786.595
3786.530
3786.463
3786.390
3786.314
3786.236
3786.153
3786.068
3785.982
3785.894
3785.805
3785.715
3785.623
3785.529
3785.435
3785.343
3785.251
3785.161
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3778.562
3757.558
3757.607
3757.656
3757.705
3757.753
3757.801
3757.850
3757.897
3757.945
3757.992
3758.040
3758.087
3758.133
3758.180
3758.226
3758.272
3758.318
3758.364
3758.409
3758.455
3758.500
3758.545
3758.589
3758.634
3758.678
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002425
A Point
2:27:22
FPointA
60.0410
2:27:22 AM
A Value
60.0420
C Value
59.8690
2:27:36 AM
Delta FCA -0.173000336
FR C
-365.9 MW/0.1 Hz
Slope A-C dF/dT
-0.012286 Hz/second
C Value Maximum Resource Loss
633
Secondary C Value 59.8569984
2:28:36 AM Time
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:22
60.04100037
60.04199982
59.86899948
2:27:22
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
59.8797
59.8834
59.8880
59.8876
59.8880
-0.1623
-390.352
-0.1586
-399.232
-0.1540
-409.354
-0.1544
-410.136
-0.1540
-0.00811427
-0.0079286
-0.0077
-0.0077222
-0.0077
93.8064
91.6600
89.0174
89.2743
89.0174
-0.0120
-0.0157
-0.0203
-0.0199
-0.0203
Tzero
2:27:22
FT+4 59.97800064
FT+10 59.86899948
FT+20 59.88299942
FT+60 59.88800049
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss
B Value Average LaaR Loss
B Value Average Net Loss
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
633
0
633
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection FR B
Generation Primary
20 to 52 sec
Trip
Frequency
Average
MW
Response
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002426
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-989.075
T+0 sec
-989.075
T+02 sec
-989.075
T+04 sec
-989.075
T+06 sec
-365.895
T+08 sec
-365.895
T+10 sec
-365.895
T+12 sec
-390.744
T+14 sec
-390.744
T+16 sec
-390.744
T+18 sec
-398.112 -411.2764051 T+20 sec
-398.112 -411.2764051 T+22 sec
-398.112 -411.2764051 T+24 sec
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.8797
59.8797
59.8797
59.8797
59.8797
59.8797
59.8797
-390.352
-390.352
-390.352
-390.352
-390.352
-390.352
-390.352
59.8834
59.8834
59.8834
59.8834
-399.232
-399.232
-399.232
-399.232
59.8880
59.8880
59.8880
-409.354
-409.354
-409.354
59.8876
59.8876
59.8876
59.8876
-410.136
-410.136
-410.136
-410.136
59.8880
59.8880
59.8880
002427
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-403.181
-403.181
-403.181
-416.446
-416.446
-416.446
-424.837
-424.837
-424.837
-419.203
-419.203
-419.203
-403.181
-403.181
-403.181
-411.041
-411.041
-411.041
-413.726
-413.726
-413.726
-342.16
-342.16
-342.16
-344.025
-344.025
-344.025
-357.631
-357.631
-357.631
-370.172
-370.172
-370.172
-390.744
-390.744
-390.744
-416.446
-416.446
-416.446
-424.837
-424.837
-424.837
-452.145
-452.145
-452.145
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
-411.2764051
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8834
59.8834
59.8834
-399.232
-399.232
-399.232
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
-409.354
-409.354
-409.354
-409.354
-409.354
-409.354
-409.354
-409.354
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
59.8876
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
-410.136
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
59.8880
002428
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-468.895
-468.895
-468.895
-502.383
-502.383
-502.383
-518.845
-518.845
-518.845
-506.4
-506.4
-506.4
-531.935
-531.935
-531.935
-555.271
-555.271
-555.271
-550.427
-550.427
-550.427
-560.182
-560.182
-560.182
-602.86
-602.86
-602.86
-680.656
-680.656
-680.656
-626.746
-626.746
-626.746
-673.419
-673.419
-673.419
-695.607
-695.607
-695.607
-695.607
-695.607
-695.607
-703.332
-703.332
-703.332
-719.308
002429
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-719.308
-719.308
-711.23
-711.23
-711.23
-719.308
-719.308
-719.308
-736.059
-736.059
-736.059
-727.603
-727.603
-727.603
-791.27
-791.27
-791.27
-832.892
-832.892
-832.892
-879.184
-879.184
-879.184
-867.146
-867.146
-867.146
-891.56
-891.56
-891.56
-959.119
-959.119
-959.119
-959.119
-959.119
-959.119
-989.075
-989.075
-989.075
-1054.98
-1054.98
-1054.98
-1004.77
-1004.77
-1004.77
-1072.92
-1072.92
002430
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1072.92
-1172.2
-1172.2
-1172.2
-1150.9
-1150.9
-1150.9
-1266.02
-1266.02
-1266.02
-1130.36
-1130.36
-1130.36
-1172.2
-1172.2
-1172.2
-1438.68
-1438.68
-1438.68
-1472.12
-1472.12
-1472.12
-1582.46
-1582.46
-1582.46
-1861.74
-1861.74
-1861.74
-2531.85
-2531.85
-2531.85
-2531.85
-2531.85
-2531.85
-3331.4
-3331.4
-3331.4
-3014.3
-3014.3
-3014.3
-3516.36
-3516.36
-3516.36
-3723.9
-3723.9
-3723.9
002431
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2877.36
-2877.36
-2877.36
-3164.93
-3164.93
-3164.93
-3331.4
-3331.4
-3331.4
-2752.32
-2752.32
-2752.32
-2637.69
-2637.69
-2637.69
-2752.32
-2752.32
-2752.32
-2434.52
-2434.52
-2434.52
-2110.09
-2110.09
-2110.09
-1808.58
-1808.58
-1808.58
-1918.13
-1918.13
-1918.13
-1472.12
-1472.12
-1472.12
-1241.21
-1241.21
-1241.21
-1172.2
-1172.2
-1172.2
-1091.4
-1091.4
-1091.4
-1054.98
-1054.98
-1054.98
-1004.77
002432
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1004.77
-1004.77
-959.119
-959.119
-959.119
-989.075
-989.075
-989.075
-959.119
-959.119
-959.119
-944.757
-944.757
-944.757
-879.184
-879.184
-879.184
-989.075
-989.075
-989.075
-944.757
-944.757
-944.757
-944.757
-944.757
-944.757
-832.892
-832.892
-832.892
-867.146
-867.146
-867.146
-822.082
-822.082
-822.082
-904.29
-904.29
-904.29
-867.146
-867.146
-867.146
-843.991
-843.991
-843.991
-822.082
-822.082
002433
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-822.082
-822.082
-822.082
-822.082
-879.184
-879.184
-879.184
-855.39
-855.39
-855.39
-879.184
-879.184
-879.184
-822.082
-822.082
-822.082
-843.991
-843.991
-843.991
-1004.77
-1004.77
-1004.77
-930.871
-930.871
-930.871
-791.27
-791.27
-791.27
-781.469
-781.469
-781.469
-762.649
-762.649
-762.649
-711.23
-711.23
-711.23
-736.059
-736.059
-736.059
-781.469
-781.469
-781.469
-801.28
-801.28
-801.28
002434
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-855.39
-855.39
-855.39
-917.388
-917.388
-917.388
-843.991
-843.991
-843.991
-959.119
-959.119
-959.119
-917.388
-917.388
-917.388
-1037.69
-1037.69
-1037.69
-1054.98
-1054.98
-1054.98
-1054.98
-1054.98
-1054.98
-1020.96
-1020.96
-1020.96
-1020.96
-1020.96
-1020.96
-989.075
-989.075
-989.075
-891.56
-891.56
-891.56
-944.757
-944.757
-944.757
-867.146
-867.146
-867.146
-904.29
-904.29
-904.29
-973.867
002435
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-973.867
-973.867
-959.119
-959.119
-959.119
-973.867
-973.867
-973.867
-1004.77
-1004.77
-1004.77
-930.871
-930.871
-930.871
-891.56
-891.56
-891.56
-832.892
-832.892
-832.892
-917.388
-917.388
-917.388
-904.29
-904.29
-904.29
-879.184
-879.184
-879.184
-1054.98
-1054.98
-1054.98
-1110.54
-1110.54
-1110.54
-1194.31
-1194.31
-1194.31
-1217.35
-1217.35
-1217.35
-1543.89
-1543.89
-1543.89
-1758.37
-1758.37
002436
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1758.37
-2752.32
-2752.32
-2752.32
-3956.54
-3956.54
-3956.54
-4869.05
-4869.05
-4869.05
-12657.3
-12657.3
-12657.3
-63334.8
-63334.8
-63334.8
63334.79
63334.79
63334.79
15818.6
15818.6
15818.6
63334.79
63334.79
63334.79
002437
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
Time of Frequency Recovery to 60 Hz or P
Value A Pre-Perturbation Average Frequen
Value B Post-Perturbation Average Frequen
Pre to Post Perturbation Delt
Value A Pre-Perturbation Average Interchange M
Value B Post-Perturbation Average Interchange MW
Pre to Post Perturbation Interchang
FR B
20 to 52 sec
-411.276
eriods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
FR B
20 to 52 sec
Average
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Net
Actual
Interchange
MW
60.0270
60.0270
60.0270
3668.61
3668.61
3668.61
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
-165.48
-165.48
-165.48
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
71.00
71.00
71.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
12 to 24 second Average Period Ev
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
BA
Load
MW
7640.58
7640.58
7640.58
Expected
Primary
Freq Response
MW
-21.600 T-72 sec
-21.600 T-70 sec
-21.600 T-68 sec
T
2:26:12
2:26:14
2:26:16
Frequency
Hz
002438
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-411.276 T+20 sec
-411.276 T+22 sec
-411.276 T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
60.0220
60.0220
60.0220
60.0190
60.0190
60.0190
60.0210
60.0210
60.0210
60.0190
60.0190
60.0190
60.0310
60.0310
60.0310
60.0360
60.0360
60.0360
60.0480
60.0480
60.0480
60.0410
60.0410
60.0410
60.0390
60.0390
60.0390
60.0450
60.0450
60.0450
60.0410
60.0410
60.0410
59.9780
59.9780
59.9780
59.9780
59.8690
59.8690
59.8690
59.8800
59.8800
59.8800
59.8830
59.8830
59.8830
3666.06
3666.06
3666.06
3670.45
3670.45
3670.45
3672.49
3672.49
3672.49
3672.16
3672.16
3672.16
3666.47
3666.47
3666.47
3660.67
3660.67
3660.67
3650.03
3650.03
3650.03
3654.29
3654.29
3654.29
3651.06
3651.06
3651.06
3645.39
3645.39
3645.39
3640.68
3640.68
3640.68
3696.36
3696.36
3696.36
3696.36
3737.16
3737.16
3737.16
3766.19
3766.19
3766.19
3780.62
3780.62
3780.62
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-165.48
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
-206.46
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
71.50
71.50
71.50
72.00
72.00
72.00
72.50
72.50
72.50
73.00
73.00
73.00
73.50
73.50
73.50
74.00
74.00
74.00
74.50
74.50
74.50
75.00
75.00
75.00
75.50
75.50
75.50
76.00
76.00
76.00
76.50
76.50
76.50
77.00
77.00
77.00
77.00
77.50
77.50
77.50
78.00
78.00
78.00
78.50
78.50
78.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7641.57
7641.57
7641.57
7642.56
7642.56
7642.56
7643.55
7643.55
7643.55
7644.54
7644.54
7644.54
7645.53
7645.53
7645.53
7646.52
7646.52
7646.52
7647.51
7647.51
7647.51
7648.50
7648.50
7648.50
7649.49
7649.49
7649.49
7650.48
7650.48
7650.48
7651.47
7651.47
7651.47
7645.00
7645.00
7645.00
7645.00
7639.00
7639.00
7639.00
7631.00
7631.00
7631.00
7630.00
7630.00
7630.00
-17.599
-17.599
-17.599
-15.201
-15.201
-15.201
-16.800
-16.800
-16.800
-15.201
-15.201
-15.201
-24.799
-24.799
-24.799
-28.799
-28.799
-28.799
-38.400
-38.400
-38.400
-32.800
-32.800
-32.800
-31.201
-31.201
-31.201
-35.999
-35.999
-35.999
-32.800
-32.800
-32.800
17.599
17.599
17.599
17.599
104.800
104.800
104.800
95.999
95.999
95.999
93.600
93.600
93.600
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.880
59.880
59.880
59.880
59.880
59.880
59.880
002439
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
-411.276
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
59.8850
59.8850
59.8850
59.8900
59.8900
59.8900
59.8930
59.8930
59.8930
59.8910
59.8910
59.8910
59.8850
59.8850
59.8850
59.8880
59.8880
59.8880
59.8890
59.8890
59.8890
59.8570
59.8570
59.8570
59.8580
59.8580
59.8580
59.8650
59.8650
59.8650
59.8710
59.8710
59.8710
59.8800
59.8800
59.8800
59.8900
59.8900
59.8900
59.8930
59.8930
59.8930
59.9020
59.9020
59.9020
3784.96
3784.96
3784.96
3788.07
3788.07
3788.07
3788.47
3788.47
3788.47
3794.37
3794.37
3794.37
3799.96
3799.96
3799.96
3802.95
3802.95
3802.95
3805.62
3805.62
3805.62
3814.86
3814.86
3814.86
3826.05
3826.05
3826.05
3826.75
3826.75
3826.75
3825.71
3825.71
3825.71
3819.08
3819.08
3819.08
3815.01
3815.01
3815.01
3809.65
3809.65
3809.65
3804.19
3804.19
3804.19
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
-206.46
-206.46
-206.46
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-211.26
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-214.35
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-212.17
-329.99
-329.99
-329.99
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
79.00
79.00
79.00
79.50
79.50
79.50
80.00
80.00
80.00
80.50
80.50
80.50
81.00
81.00
81.00
81.50
81.50
81.50
82.00
82.00
82.00
82.50
82.50
82.50
83.00
83.00
83.00
83.50
83.50
83.50
84.00
84.00
84.00
84.50
84.50
84.50
85.00
85.00
85.00
85.50
85.50
85.50
86.00
86.00
86.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7631.00
7631.00
7631.00
7630.00
7630.00
7630.00
7632.00
7632.00
7632.00
7633.00
7633.00
7633.00
7634.00
7634.00
7634.00
7635.00
7635.00
7635.00
7636.00
7636.00
7636.00
7637.00
7637.00
7637.00
7638.00
7638.00
7638.00
7641.00
7641.00
7641.00
7642.00
7642.00
7642.00
7629.00
7629.00
7629.00
7630.00
7630.00
7630.00
7630.00
7630.00
7630.00
7631.00
7631.00
7631.00
92.001
92.001
92.001
88.000
88.000
88.000
85.599
85.599
85.599
87.201
87.201
87.201
92.001
92.001
92.001
89.600
89.600
89.600
88.800
88.800
88.800
114.401
114.401
114.401
113.599
113.599
113.599
107.999
107.999
107.999
103.201
103.201
103.201
95.999
95.999
95.999
88.000
88.000
88.000
85.599
85.599
85.599
78.400
78.400
78.400
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
002440
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
59.9070
59.9070
59.9070
59.9160
59.9160
59.9160
59.9200
59.9200
59.9200
59.9170
59.9170
59.9170
59.9230
59.9230
59.9230
59.9280
59.9280
59.9280
59.9270
59.9270
59.9270
59.9290
59.9290
59.9290
59.9370
59.9370
59.9370
59.9490
59.9490
59.9490
59.9410
59.9410
59.9410
59.9480
59.9480
59.9480
59.9510
59.9510
59.9510
59.9510
59.9510
59.9510
59.9520
59.9520
59.9520
59.9540
3792.17
3792.17
3792.17
3788.13
3788.13
3788.13
3781.70
3781.70
3781.70
3774.60
3774.60
3774.60
3772.72
3772.72
3772.72
3768.71
3768.71
3768.71
3767.41
3767.41
3767.41
3765.67
3765.67
3765.67
3765.10
3765.10
3765.10
3753.92
3753.92
3753.92
3747.88
3747.88
3747.88
3746.71
3746.71
3746.71
3740.26
3740.26
3740.26
3727.84
3727.84
3727.84
3720.58
3720.58
3720.58
3715.75
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-255.44
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-254.84
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-257.15
-262.29
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
86.50
86.50
86.50
87.00
87.00
87.00
87.50
87.50
87.50
88.00
88.00
88.00
88.50
88.50
88.50
89.00
89.00
89.00
89.50
89.50
89.50
90.00
90.00
90.00
90.50
90.50
90.50
91.00
91.00
91.00
91.50
91.50
91.50
92.00
92.00
92.00
92.50
92.50
92.50
93.00
93.00
93.00
93.50
93.50
93.50
94.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7633.00
7633.00
7633.00
7636.00
7636.00
7636.00
7640.00
7640.00
7640.00
7644.00
7644.00
7644.00
7648.00
7648.00
7648.00
7652.00
7652.00
7652.00
7656.00
7656.00
7656.00
7662.00
7662.00
7662.00
7665.00
7665.00
7665.00
7670.00
7670.00
7670.00
7674.00
7674.00
7674.00
7679.00
7679.00
7679.00
7682.00
7682.00
7682.00
7684.00
7684.00
7684.00
7686.00
7686.00
7686.00
7688.00
74.399
74.399
74.399
67.200
67.200
67.200
64.001
64.001
64.001
66.400
66.400
66.400
61.600
61.600
61.600
57.599
57.599
57.599
58.401
58.401
58.401
56.799
56.799
56.799
50.400
50.400
50.400
40.799
40.799
40.799
47.198
47.198
47.198
41.599
41.599
41.599
39.200
39.200
39.200
39.200
39.200
39.200
38.400
38.400
38.400
36.801
002441
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
59.9540
59.9540
59.9530
59.9530
59.9530
59.9540
59.9540
59.9540
59.9560
59.9560
59.9560
59.9550
59.9550
59.9550
59.9620
59.9620
59.9620
59.9660
59.9660
59.9660
59.9700
59.9700
59.9700
59.9690
59.9690
59.9690
59.9710
59.9710
59.9710
59.9760
59.9760
59.9760
59.9760
59.9760
59.9760
59.9780
59.9780
59.9780
59.9820
59.9820
59.9820
59.9790
59.9790
59.9790
59.9830
59.9830
3715.75
3715.75
3710.85
3710.85
3710.85
3714.62
3714.62
3714.62
3716.46
3716.46
3716.46
3722.36
3722.36
3722.36
3722.27
3722.27
3722.27
3723.09
3723.09
3723.09
3723.89
3723.89
3723.89
3728.05
3728.05
3728.05
3733.33
3733.33
3733.33
3736.82
3736.82
3736.82
3740.88
3740.88
3740.88
3746.61
3746.61
3746.61
3751.56
3751.56
3751.56
3756.41
3756.41
3756.41
3760.98
3760.98
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-262.29
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.65
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-256.31
-249.09
-249.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
94.00
94.00
94.50
94.50
94.50
95.00
95.00
95.00
95.50
95.50
95.50
96.00
96.00
96.00
96.50
96.50
96.50
97.00
97.00
97.00
97.50
97.50
97.50
98.00
98.00
98.00
98.50
98.50
98.50
99.00
99.00
99.00
99.50
99.50
99.50
100.00
100.00
100.00
100.50
100.50
100.50
101.00
101.00
101.00
101.50
101.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7688.00
7688.00
7689.00
7689.00
7689.00
7689.00
7689.00
7689.00
7690.00
7690.00
7690.00
7690.08
7690.08
7690.08
7690.00
7690.00
7690.00
7692.06
7692.06
7692.06
7693.05
7693.05
7693.05
7694.04
7694.04
7694.04
7695.03
7695.03
7695.03
7696.02
7696.02
7696.02
7697.01
7697.01
7697.01
7698.00
7698.00
7698.00
7699.00
7699.00
7699.00
7699.98
7699.98
7699.98
7700.97
7700.97
36.801
36.801
37.601
37.601
37.601
36.801
36.801
36.801
35.199
35.199
35.199
35.999
35.999
35.999
30.399
30.399
30.399
27.200
27.200
27.200
23.999
23.999
23.999
24.799
24.799
24.799
23.199
23.199
23.199
19.199
19.199
19.199
19.199
19.199
19.199
17.599
17.599
17.599
14.401
14.401
14.401
16.800
16.800
16.800
13.599
13.599
002442
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
59.9830
59.9880
59.9880
59.9880
59.9870
59.9870
59.9870
59.9920
59.9920
59.9920
59.9860
59.9860
59.9860
59.9880
59.9880
59.9880
59.9980
59.9980
59.9980
59.9990
59.9990
59.9990
60.0020
60.0020
60.0020
60.0080
60.0080
60.0080
60.0170
60.0170
60.0170
60.0170
60.0170
60.0170
60.0230
60.0230
60.0230
60.0210
60.0210
60.0210
60.0240
60.0240
60.0240
60.0250
60.0250
60.0250
3760.98
3763.21
3763.21
3763.21
3766.43
3766.43
3766.43
3768.63
3768.63
3768.63
3773.69
3773.69
3773.69
3775.36
3775.36
3775.36
3776.42
3776.42
3776.42
3781.26
3781.26
3781.26
3783.90
3783.90
3783.90
3785.46
3785.46
3785.46
3787.26
3787.26
3787.26
3788.03
3788.03
3788.03
3787.54
3787.54
3787.54
3787.93
3787.93
3787.93
3786.55
3786.55
3786.55
3785.61
3785.61
3785.61
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-249.09
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-253.74
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-257.42
-261.74
-261.74
-261.74
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
101.50
102.00
102.00
102.00
102.50
102.50
102.50
103.00
103.00
103.00
103.50
103.50
103.50
104.00
104.00
104.00
104.50
104.50
104.50
105.00
105.00
105.00
105.50
105.50
105.50
106.00
106.00
106.00
106.50
106.50
106.50
107.00
107.00
107.00
107.50
107.50
107.50
108.00
108.00
108.00
108.50
108.50
108.50
109.00
109.00
109.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7700.97
7701.96
7701.96
7701.96
7702.95
7702.95
7702.95
7703.94
7703.94
7703.94
7704.93
7704.93
7704.93
7705.92
7705.92
7705.92
7706.91
7706.91
7706.91
7707.90
7707.90
7707.90
7708.89
7708.89
7708.89
7709.88
7709.88
7709.88
7710.87
7710.87
7710.87
7711.86
7711.86
7711.86
7712.85
7712.85
7712.85
7713.84
7713.84
7713.84
7714.83
7714.83
7714.83
7715.82
7715.82
7715.82
13.599
9.601
9.601
9.601
10.400
10.400
10.400
6.400
6.400
6.400
11.200
11.200
11.200
9.601
9.601
9.601
1.599
1.599
1.599
0.800
0.800
0.800
-1.599
-1.599
-1.599
-6.400
-6.400
-6.400
-13.599
-13.599
-13.599
-13.599
-13.599
-13.599
-18.399
-18.399
-18.399
-16.800
-16.800
-16.800
-19.199
-19.199
-19.199
-20.001
-20.001
-20.001
002443
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
60.0200
60.0200
60.0200
60.0220
60.0220
60.0220
60.0230
60.0230
60.0230
60.0190
60.0190
60.0190
60.0180
60.0180
60.0180
60.0190
60.0190
60.0190
60.0160
60.0160
60.0160
60.0120
60.0120
60.0120
60.0070
60.0070
60.0070
60.0090
60.0090
60.0090
59.9990
59.9990
59.9990
59.9910
59.9910
59.9910
59.9880
59.9880
59.9880
59.9840
59.9840
59.9840
59.9820
59.9820
59.9820
59.9790
3786.86
3786.86
3786.86
3785.73
3785.73
3785.73
3785.80
3785.80
3785.80
3787.63
3787.63
3787.63
3789.40
3789.40
3789.40
3789.37
3789.37
3789.37
3788.93
3788.93
3788.93
3790.41
3790.41
3790.41
3792.95
3792.95
3792.95
3791.43
3791.43
3791.43
3790.22
3790.22
3790.22
3788.10
3788.10
3788.10
3788.50
3788.50
3788.50
3788.10
3788.10
3788.10
3787.73
3787.73
3787.73
3788.26
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-261.74
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-271.88
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-262.07
-260.36
-260.36
-260.36
-260.36
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
109.50
109.50
109.50
110.00
110.00
110.00
110.50
110.50
110.50
111.00
111.00
111.00
111.50
111.50
111.50
112.00
112.00
112.00
112.50
112.50
112.50
113.00
113.00
113.00
113.50
113.50
113.50
114.00
114.00
114.00
114.50
114.50
114.50
115.00
115.00
115.00
115.50
115.50
115.50
116.00
116.00
116.00
116.50
116.50
116.50
117.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7716.81
7716.81
7716.81
7717.80
7717.80
7717.80
7718.79
7718.79
7718.79
7719.78
7719.78
7719.78
7720.77
7720.77
7720.77
7721.76
7721.76
7721.76
7722.75
7722.75
7722.75
7723.74
7723.74
7723.74
7724.73
7724.73
7724.73
7725.72
7725.72
7725.72
7726.71
7726.71
7726.71
7727.70
7727.70
7727.70
7728.69
7728.69
7728.69
7729.68
7729.68
7729.68
7730.67
7730.67
7730.67
7731.66
-16.000
-16.000
-16.000
-17.599
-17.599
-17.599
-18.399
-18.399
-18.399
-15.201
-15.201
-15.201
-14.401
-14.401
-14.401
-15.201
-15.201
-15.201
-12.799
-12.799
-12.799
-9.601
-9.601
-9.601
-5.600
-5.600
-5.600
-7.199
-7.199
-7.199
0.800
0.800
0.800
7.199
7.199
7.199
9.601
9.601
9.601
12.799
12.799
12.799
14.401
14.401
14.401
16.800
002444
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
59.9790
59.9790
59.9760
59.9760
59.9760
59.9780
59.9780
59.9780
59.9760
59.9760
59.9760
59.9750
59.9750
59.9750
59.9700
59.9700
59.9700
59.9780
59.9780
59.9780
59.9750
59.9750
59.9750
59.9750
59.9750
59.9750
59.9660
59.9660
59.9660
59.9690
59.9690
59.9690
59.9650
59.9650
59.9650
59.9720
59.9720
59.9720
59.9690
59.9690
59.9690
59.9670
59.9670
59.9670
59.9650
59.9650
3788.26
3788.26
3790.66
3790.66
3790.66
3789.27
3789.27
3789.27
3789.91
3789.91
3789.91
3788.96
3788.96
3788.96
3792.91
3792.91
3792.91
3788.08
3788.08
3788.08
3787.16
3787.16
3787.16
3786.49
3786.49
3786.49
3790.51
3790.51
3790.51
3790.96
3790.96
3790.96
3789.17
3789.17
3789.17
3784.83
3784.83
3784.83
3782.81
3782.81
3782.81
3779.06
3779.06
3779.06
3779.33
3779.33
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-260.36
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-352.64
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-354.90
-340.47
-340.47
-340.47
-340.47
-340.47
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
117.00
117.00
117.50
117.50
117.50
118.00
118.00
118.00
118.50
118.50
118.50
119.00
119.00
119.00
119.50
119.50
119.50
120.00
120.00
120.00
120.50
120.50
120.50
121.00
121.00
121.00
121.50
121.50
121.50
122.00
122.00
122.00
122.50
122.50
122.50
123.00
123.00
123.00
123.50
123.50
123.50
124.00
124.00
124.00
124.50
124.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7731.66
7731.66
7732.65
7732.65
7732.65
7733.64
7733.64
7733.64
7734.63
7734.63
7734.63
7735.62
7735.62
7735.62
7736.61
7736.61
7736.61
7737.60
7737.60
7737.60
7738.59
7738.59
7738.59
7739.58
7739.58
7739.58
7740.57
7740.57
7740.57
7741.56
7741.56
7741.56
7742.55
7742.55
7742.55
7743.54
7743.54
7743.54
7744.53
7744.53
7744.53
7745.52
7745.52
7745.52
7746.51
7746.51
16.800
16.800
19.199
19.199
19.199
17.599
17.599
17.599
19.199
19.199
19.199
20.001
20.001
20.001
23.999
23.999
23.999
17.599
17.599
17.599
20.001
20.001
20.001
20.001
20.001
20.001
27.200
27.200
27.200
24.799
24.799
24.799
28.000
28.000
28.000
22.400
22.400
22.400
24.799
24.799
24.799
26.401
26.401
26.401
28.000
28.000
002445
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
59.9650
59.9650
59.9650
59.9650
59.9700
59.9700
59.9700
59.9680
59.9680
59.9680
59.9700
59.9700
59.9700
59.9650
59.9650
59.9650
59.9670
59.9670
59.9670
59.9790
59.9790
59.9790
59.9740
59.9740
59.9740
59.9620
59.9620
59.9620
59.9610
59.9610
59.9610
59.9590
59.9590
59.9590
59.9530
59.9530
59.9530
59.9560
59.9560
59.9560
59.9610
59.9610
59.9610
59.9630
59.9630
59.9630
3779.33
3776.60
3776.60
3776.60
3773.17
3773.17
3773.17
3768.50
3768.50
3768.50
3764.79
3764.79
3764.79
3761.89
3761.89
3761.89
3760.16
3760.16
3760.16
3757.77
3757.77
3757.77
3751.64
3751.64
3751.64
3759.25
3759.25
3759.25
3762.02
3762.02
3762.02
3763.86
3763.86
3763.86
3768.34
3768.34
3768.34
3765.61
3765.61
3765.61
3761.92
3761.92
3761.92
3752.43
3752.43
3752.43
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-340.47
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-337.64
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-284.36
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
124.50
125.00
125.00
125.00
125.50
125.50
125.50
126.00
126.00
126.00
126.50
126.50
126.50
127.00
127.00
127.00
127.50
127.50
127.50
128.00
128.00
128.00
128.50
128.50
128.50
129.00
129.00
129.00
129.50
129.50
129.50
130.00
130.00
130.00
130.50
130.50
130.50
131.00
131.00
131.00
131.50
131.50
131.50
132.00
132.00
132.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7746.51
7747.50
7747.50
7747.50
7748.49
7748.49
7748.49
7749.48
7749.48
7749.48
7750.47
7750.47
7750.47
7751.46
7751.46
7751.46
7752.45
7752.45
7752.45
7753.44
7753.44
7753.44
7754.43
7754.43
7754.43
7755.42
7755.42
7755.42
7756.41
7756.41
7756.41
7757.40
7757.40
7757.40
7758.39
7758.39
7758.39
7759.38
7759.38
7759.38
7760.37
7760.37
7760.37
7761.36
7761.36
7761.36
28.000
28.000
28.000
28.000
23.999
23.999
23.999
25.601
25.601
25.601
23.999
23.999
23.999
28.000
28.000
28.000
26.401
26.401
26.401
16.800
16.800
16.800
20.801
20.801
20.801
30.399
30.399
30.399
31.201
31.201
31.201
32.800
32.800
32.800
37.601
37.601
37.601
35.199
35.199
35.199
31.201
31.201
31.201
29.599
29.599
29.599
002446
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
59.9680
59.9680
59.9680
59.9730
59.9730
59.9730
59.9670
59.9670
59.9670
59.9760
59.9760
59.9760
59.9730
59.9730
59.9730
59.9810
59.9810
59.9810
59.9820
59.9820
59.9820
59.9820
59.9820
59.9820
59.9800
59.9800
59.9800
59.9800
59.9800
59.9800
59.9780
59.9780
59.9780
59.9710
59.9710
59.9710
59.9750
59.9750
59.9750
59.9690
59.9690
59.9690
59.9720
59.9720
59.9720
59.9770
3753.51
3753.51
3753.51
3753.18
3753.18
3753.18
3752.87
3752.87
3752.87
3747.48
3747.48
3747.48
3746.65
3746.65
3746.65
3741.62
3741.62
3741.62
3738.90
3738.90
3738.90
3736.31
3736.31
3736.31
3735.65
3735.65
3735.65
3736.75
3736.75
3736.75
3736.09
3736.09
3736.09
3738.87
3738.87
3738.87
3737.68
3737.68
3737.68
3740.02
3740.02
3740.02
3742.42
3742.42
3742.42
3741.72
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-260.47
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-253.14
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-251.93
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
132.50
132.50
132.50
133.00
133.00
133.00
133.50
133.50
133.50
134.00
134.00
134.00
134.50
134.50
134.50
135.00
135.00
135.00
135.50
135.50
135.50
136.00
136.00
136.00
136.50
136.50
136.50
137.00
137.00
137.00
137.50
137.50
137.50
138.00
138.00
138.00
138.50
138.50
138.50
139.00
139.00
139.00
139.50
139.50
139.50
140.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7762.35
7762.35
7762.35
7763.34
7763.34
7763.34
7764.33
7764.33
7764.33
7765.32
7765.32
7765.32
7766.31
7766.31
7766.31
7767.30
7767.30
7767.30
7768.29
7768.29
7768.29
7769.28
7769.28
7769.28
7770.27
7770.27
7770.27
7771.26
7771.26
7771.26
7772.25
7772.25
7772.25
7773.24
7773.24
7773.24
7774.23
7774.23
7774.23
7775.22
7775.22
7775.22
7776.21
7776.21
7776.21
7777.20
25.601
25.601
25.601
21.600
21.600
21.600
26.401
26.401
26.401
19.199
19.199
19.199
21.600
21.600
21.600
15.201
15.201
15.201
14.401
14.401
14.401
14.401
14.401
14.401
16.000
16.000
16.000
16.000
16.000
16.000
17.599
17.599
17.599
23.199
23.199
23.199
20.001
20.001
20.001
24.799
24.799
24.799
22.400
22.400
22.400
18.399
002447
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
59.9770
59.9770
59.9760
59.9760
59.9760
59.9770
59.9770
59.9770
59.9790
59.9790
59.9790
59.9740
59.9740
59.9740
59.9710
59.9710
59.9710
59.9660
59.9660
59.9660
59.9730
59.9730
59.9730
59.9720
59.9720
59.9720
59.9700
59.9700
59.9700
59.9820
59.9820
59.9820
59.9850
59.9850
59.9850
59.9890
59.9890
59.9890
59.9900
59.9900
59.9900
60.0010
60.0010
60.0010
60.0060
60.0060
3741.72
3741.72
3739.96
3739.96
3739.96
3741.27
3741.27
3741.27
3738.71
3738.71
3738.71
3738.10
3738.10
3738.10
3743.42
3743.42
3743.42
3747.34
3747.34
3747.34
3746.22
3746.22
3746.22
3743.15
3743.15
3743.15
3733.38
3733.38
3733.38
3736.23
3736.23
3736.23
3733.12
3733.12
3733.12
3725.46
3725.46
3725.46
3720.94
3720.94
3720.94
3727.75
3727.75
3727.75
3727.23
3727.23
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
-250.67
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-253.63
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-246.96
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
140.00
140.00
140.50
140.50
140.50
141.00
141.00
141.00
141.50
141.50
141.50
142.00
142.00
142.00
142.50
142.50
142.50
143.00
143.00
143.00
143.50
143.50
143.50
144.00
144.00
144.00
144.50
144.50
144.50
145.00
145.00
145.00
145.50
145.50
145.50
146.00
146.00
146.00
146.50
146.50
146.50
147.00
147.00
147.00
147.50
147.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7777.20
7777.20
7778.19
7778.19
7778.19
7779.18
7779.18
7779.18
7780.17
7780.17
7780.17
7781.16
7781.16
7781.16
7782.15
7782.15
7782.15
7783.14
7783.14
7783.14
7784.13
7784.13
7784.13
7785.12
7785.12
7785.12
7786.11
7786.11
7786.11
7787.10
7787.10
7787.10
7788.09
7788.09
7788.09
7789.08
7789.08
7789.08
7790.07
7790.07
7790.07
7791.06
7791.06
7791.06
7792.05
7792.05
18.399
18.399
19.199
19.199
19.199
18.399
18.399
18.399
16.800
16.800
16.800
20.801
20.801
20.801
23.199
23.199
23.199
27.200
27.200
27.200
21.600
21.600
21.600
22.400
22.400
22.400
23.999
23.999
23.999
14.401
14.401
14.401
12.000
12.000
12.000
8.801
8.801
8.801
7.999
7.999
7.999
-0.800
-0.800
-0.800
-4.800
-4.800
002448
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
60.0060
60.0190
60.0190
60.0190
60.0260
60.0260
60.0260
60.0290
60.0290
60.0290
60.0370
60.0370
60.0370
60.0410
60.0410
60.0410
60.0430
60.0430
60.0430
60.0460
60.0460
60.0460
60.0430
60.0430
60.0430
3727.23
3726.02
3726.02
3726.02
3717.33
3717.33
3717.33
3715.17
3715.17
3715.17
3710.16
3710.16
3710.16
3704.59
3704.59
3704.59
3701.32
3701.32
3701.32
3699.73
3699.73
3699.73
3696.86
3696.86
3696.86
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-254.54
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-256.57
-258.37
-258.37
-258.37
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
147.50
148.00
148.00
148.00
148.50
148.50
148.50
149.00
149.00
149.00
149.50
149.50
149.50
150.00
150.00
150.00
150.50
150.50
150.50
151.00
151.00
151.00
151.50
151.50
151.50
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7792.05
7793.04
7793.04
7793.04
7794.03
7794.03
7794.03
7795.02
7795.02
7795.02
7796.01
7796.01
7796.01
7797.00
7797.00
7797.00
7797.99
7797.99
7797.99
7798.98
7798.98
7798.98
7799.97
7799.97
7799.97
-4.800
-15.201
-15.201
-15.201
-20.801
-20.801
-20.801
-23.199
-23.199
-23.199
-29.599
-29.599
-29.599
-32.800
-32.800
-32.800
-34.399
-34.399
-34.399
-36.801
-36.801
-36.801
-34.399
-34.399
-34.399
002449
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
lue B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8797
-0.162
3645.04
3768.23
123.19
-52.67
-33.60
96.23
129.83
77.15
350.00
-165.48
0.00
76.06
-4.20
15.00
271.39
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-206.46
0.00
78.14
12.03
0.00
218.71
-52.67
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
123.8941
167.1540
73.70%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7650.604
7631.714
-18.889
-11.640
15.33%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
24 second Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
0.949 P.U.
1.355 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002450
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3768.229
3768.229
3768.229
3768.229
3768.229
3768.229
3768.229
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-206.459
-206.459
-206.459
-206.459
-206.459
-206.459
-206.459
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
76.063
76.063
76.063
76.063
76.063
76.063
76.063
76.063
78.143
78.143
78.143
78.143
78.143
78.143
78.143
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7631.714
7631.714
7631.714
7631.714
7631.714
7631.714
7631.714
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
96.228
96.228
96.228
96.228
96.228
96.228
96.228
3722.195
3722.195
3722.195
3722.195
3722.195
3722.195
3722.195
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.883
59.883
59.883
59.883
3780.420
3780.420
3780.420
3780.420
335.000
335.000
335.000
335.000
002451
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.883
59.883
59.883
3780.420
3780.420
3780.420
335.000
335.000
335.000
002452
002453
002454
002455
002456
002457
002458
002459
002460
002461
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8834
-0.159
3645.04
3780.42
135.38
-52.55
-33.60
93.26
126.86
74.31
350.00
-165.48
0.00
76.06
-4.20
15.00
271.39
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-206.46
0.00
78.64
11.66
0.00
218.84
-52.55
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -103.000 MW/0.1 Hz
Post-Perturbation Bias Setting -103.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -43.2598 MW
EPFR for Bias Setting Post-Perturbation Average 120.0694 MW
EPFR for Bias Setting Delta 163.3292 MW
Primary Frequency Response Delivery of Bias
82.89%
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8873
-0.155
3645.04
3785.26
140.22
-54.57
-33.60
90.18
123.78
69.21
350.00
-165.48
0.00
76.06
-4.20
15.00
271.39
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-208.64
0.00
79.18
11.27
0.00
216.82
-54.57
Pre-Perturbation BA Load 7650.604 MW
Post-Perturbation BA Load 7630.571 MW
Pre to Post Perturbation BA Load Change
-20.032 MW
Load Dampening Frequency Response
-12.633 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
14.80%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
1.067 P.U.
1.481 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.133
1.574
Pumped
Hydro
Load (-) Gen (+)
MW
002462
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-206.459
-206.459
-206.459
-206.459
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
76.063
76.063
76.063
76.063
76.063
76.063
76.063
76.063
78.643
78.643
78.643
78.643
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7630.571
7630.571
7630.571
7630.571
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
93.258
93.258
93.258
93.258
3719.353
3719.353
3719.353
3719.353
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.887
59.887
59.887
3785.264
3785.264
3785.264
335.000
335.000
335.000
-208.640
-208.640
-208.640
0.000
0.000
0.000
002463
-206.459
-206.459
-206.459
0.000
0.000
0.000
78.643
78.643
78.643
10.000
10.000
10.000
0.000
0.000
0.000
-103.000 7630.571
-103.000 7630.571
-103.000 7630.571
93.258
93.258
93.258
3719.353 T+26 sec
3719.353 T+28 sec
3719.353 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.887
59.887
59.887
59.887
59.887
59.887
59.887
59.887
3785.264
3785.264
3785.264
3785.264
3785.264
3785.264
3785.264
3785.264
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-208.640
-208.640
-208.640
-208.640
-208.640
-208.640
-208.640
-208.640
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002464
002465
002466
002467
002468
002469
002470
002471
002472
002473
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
116.1096
159.3694
87.99%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7650.604
7630.636
-19.967
-12.905
14.24%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8876
-0.154
3645.04
3787.53
142.49
-54.95
-33.60
89.96
123.56
68.61
350.00
-165.48
0.00
76.06
-4.20
15.00
271.39
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-209.39
0.00
79.58
11.24
0.00
216.44
-54.95
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.153 P.U.
1.598 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002474
76.063
76.063
76.063
76.063
76.063
76.063
76.063
76.063
79.182
79.182
79.182
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7630.636
7630.636
7630.636
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
90.182
90.182
90.182
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
3714.252 T+20 sec
3714.252 T+22 sec
3714.252 T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
76.063
76.063
76.063
76.063
76.063
76.063
76.063
76.063
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.888
59.888
59.888
59.888
3787.534
3787.534
3787.534
3787.534
335.000
335.000
335.000
335.000
-209.391
-209.391
-209.391
-209.391
0.000
0.000
0.000
0.000
79.583
79.583
79.583
79.583
10.000
10.000
10.000
10.000
002475
79.182
79.182
79.182
79.182
79.182
79.182
79.182
79.182
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7630.636
7630.636
7630.636
7630.636
7630.636
7630.636
7630.636
7630.636
90.182
90.182
90.182
90.182
90.182
90.182
90.182
90.182
3714.252
3714.252
3714.252
3714.252
3714.252
3714.252
3714.252
3714.252
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
3787.534
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
-209.391
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
79.583
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
002476
002477
002478
002479
002480
002481
002482
002483
002484
002485
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
115.8183
159.0781
89.57%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7650.604
7631.500
-19.104
-12.369
13.41%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:24
2:33:06
60.0420
59.8880
-0.154
3645.04
3788.79
143.75
-55.07
-33.60
89.60
123.20
68.13
350.00
-165.48
0.00
76.06
-4.20
15.00
271.39
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
335.00
-209.56
0.00
79.68
11.20
0.00
216.31
-55.07
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:12
2:26:14
2:26:16
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.167 P.U.
1.614 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002486
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7631.500
7631.500
7631.500
7631.500
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
89.956
89.956
89.956
89.956
3713.648
3713.648
3713.648
3713.648
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
3645.041
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
-165.476
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
76.063
76.063
76.063
76.063
76.063
76.063
76.063
76.063
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
59.888
59.888
59.888
3788.789
3788.789
3788.789
335.000
335.000
335.000
-209.563
-209.563
-209.563
0.000
0.000
0.000
79.676
79.676
79.676
10.000
10.000
10.000
0.000
0.000
0.000
002487
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
7631.500
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
89.956
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
3713.648
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
3788.789
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
-209.563
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
79.676
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002488
002489
002490
002491
002492
002493
002494
002495
002496
002497
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-103.000
-103.000
-43.2598
115.3607
158.6205
90.62%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
7650.604
7631.529
-19.074
-12.386
13.27%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
002498
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
7650.604
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-33.600
-103.000
-103.000
-103.000
7631.529
7631.529
7631.529
89.601
89.601
89.601
3713.169
3713.169
3713.169
002499
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
-103.000
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
7631.529
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
89.601
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
3713.169
002500
Monday, October 12, 2009
Balancing Authority
60.08
1.167
My BA
60.0420
1.614
Initial P.U. Performance
Initial P.U. Performance Adjusted
3850.0
20 to 52 second Average Period
60.06
60.04
3788.79
3800.0
60.02
60
59.98
3750.0
59.96
MW
Frequency - Hz
3713.169
59.94
59.92
3700.0
59.9
59.88
59.8880
3650.0
59.86
3645.04
59.84
59.82
3600.0
59.8
59.78
59.76
2:26:24
2:26:34
2:26:44
2:26:54
Hz
2:27:04
2:27:14
Average Frequency
2:27:24
MW
2:27:34
Average MW
2:27:44
2:27:54
2:28:04
EPFR for FRO Adjusted
2:28:14
3550.0
2:28:24
002501
Monday, October 12, 2009
0.899 Sustained P.U. Performance
My BA
60.08
3850.0
60.06
60.04
3800.0
60.02
60
3750.0
59.98
3700.0
59.94
MW
Frequency - Hz
59.96
59.92
59.9
3650.0
59.88
59.86
3600.0
59.84
59.82
3550.0
59.8
59.78
59.76
2:26:24
2:27:24
2:28:24
2:29:24
Hz
2:30:24
2:31:24
2:32:24
Interchange MW
2:33:24
2:34:24
2:35:24
Recovery Period Target MW
2:36:24
2:37:24
2:38:24
2:39:24
Recovery Period Ramp MW
2:40:24
2:41:24
3500.0
2:42:24
002502
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:22
FPointA
Hz
60.0410
A Value
Hz
60.0420
t(0) Time
2:27:24
C Value
Hz
59.8690
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8797144 -390.35188 59.8834278 -399.23186 59.8879994 -409.35384 59.887555
-410.1357 59.8879994 -411.27641
002503
Value A Data
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
60.042
3645.04
350.00
-165.48
0.00
76.06
-4.20
15.00
-103 7650.604
Value B
Bias
Setting
EPFR
Frequency
MW
Hz
-43.2598 59.879714
12 to 24 second Average Period Evaluation
JOU
NonTransferred
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
Actual
Schedules
Load
Hydro
Units
Response
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+)
MW
MW
MW
MW
MW
MW
3768.23
335.00
-206.46
0.00
78.14
12.03
002504
Value B
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
1.355
Initial
Performance
Unadjusted
P.U.
0.949
18 to 30 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Bias
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Setting
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
P.U.
MW/0.1 Hz
MW
MW
Hz
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
0.899
-103 7631.714 123.8941 59.883428
3780.42
335.00
-206.46
0.00
78.64
11.66
0.00
Sustained
Performance
Initial
Performance
Adjusted
P.U.
1.481
002505
Value B
Initial
Performance
Unadjusted
P.U.
1.067
Sustained
Performance
P.U.
0.899
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
Frequency
MW
MW
MW
Hz
-103 7630.571 120.0694 59.887272
20 to 40 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Interchange
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
MW
MW
MW/0.1 Hz
MW
3785.26
335.00
-208.64
0.00
79.18
11.27
0.00
Initial
Performance
Adjusted
P.U.
1.574
Initial
Performance
Unadjusted
P.U.
1.133
Sustained
Performance
P.U.
0.899
002506
Value B
18 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
BA
BA
Bias
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Bias
Load
Setting
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Setting
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
MW
MW
MW
Hz
MW
MW
MW
MW
MW
MW
MW
-103 7630.636 116.1096 59.887555
3787.53
335.00
-209.39
0.00
79.58
11.24
0.00
Value B
Initial
Performance
Adjusted
P.U.
1.598
Initial
Performance
Unadjusted
P.U.
1.153
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.899
-103
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7631.5 115.8183 59.887999
002507
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Ramping
Actual
Schedules
Load
Hydro
Units
Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+)
MW
MW
MW
MW
MW
3788.79
335.00
-209.56
0.00
79.68
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.20
0.00
Initial
Performance
Adjusted
P.U.
1.614
Initial
Performance
Unadjusted
P.U.
1.167
Sustained
Performance
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
P.U.
MW/0.1 Hz
MW
MW
0.899
-103 7631.529 115.3607
002508
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Total Lost Generation: enter the MW data of the units that tripped as a single generator where the value typically goes to zero at t(0).
Column D: not applicable
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: not applicable
Column H: not applicable
Column I: not applicable
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 2 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with larger sample size data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 469 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A469"
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 633.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A633"
In cell "R41" of the "Evaluation" spreadsheet, enter the MW value of the unit(s) that tripped (from the Master Event List). This is only necessary for the "Interconnection" evaluation if you're interested.
It is not necessary to do this for the BA evaluation but it will provide a comparison of the BA frequency response as compared to the Interconnection frequency response.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
wish to unhide.
002509
002510
mm/dd/yy hh:mm:ss
Frequency
Time (T)
Hz
07/18/11 20:35:00
07/18/11 20:35:02
07/18/11 20:35:04
07/18/11 20:35:06
07/18/11 20:35:08
07/18/11 20:35:10
07/18/11 20:35:12
07/18/11 20:35:14
07/18/11 20:35:16
07/18/11 20:35:18
07/18/11 20:35:20
07/18/11 20:35:22
07/18/11 20:35:24
07/18/11 20:35:26
07/18/11 20:35:28
07/18/11 20:35:30
07/18/11 20:35:32
07/18/11 20:35:34
07/18/11 20:35:36
07/18/11 20:35:38
07/18/11 20:35:40
07/18/11 20:35:42
07/18/11 20:35:44
07/18/11 20:35:46
07/18/11 20:35:48
07/18/11 20:35:50
07/18/11 20:35:52
07/18/11 20:35:54
07/18/11 20:35:56
07/18/11 20:35:58
07/18/11 20:36:00
07/18/11 20:36:02
07/18/11 20:36:04
07/18/11 20:36:06
07/18/11 20:36:08
07/18/11 20:36:10
07/18/11 20:36:12
07/18/11 20:36:14
07/18/11 20:36:16
07/18/11 20:36:18
07/18/11 20:36:20
07/18/11 20:36:22
07/18/11 20:36:24
07/18/11 20:36:26
60.0019989
60.0019989
60.0009995
60.0009995
59.9990005
59.9970016
59.9959984
59.9949989
59.9939995
59.993
59.9910011
59.9900017
59.987999
59.9850006
59.9840012
59.9840012
59.9860001
59.9860001
59.9840012
59.9830017
59.9830017
59.9840012
59.9840012
59.9840012
59.9830017
59.9840012
59.9840012
59.9840012
59.9819984
59.9799995
59.9819984
59.9830017
59.9830017
59.980999
59.980999
59.9799995
59.9830017
59.9840012
59.9850006
59.9869995
59.9860001
59.9850006
59.9850006
59.9860001
Total
Lost
Generation
MW
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Transferred
Frequency
Response
n/a
Contingent
BA
Lost Generation
n/a
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
56914.73
56928.6
56928.6
56928.6
56928.6
56928.6
56923.08
56923.08
56923.08
56923.08
56923.08
56937.99
56937.99
56937.99
56937.99
56937.99
56932.41
56932.41
56932.41
56932.41
56932.41
56933.85
56933.85
56933.85
56933.85
56933.85
56933.48
56933.48
56933.48
56933.48
56933.48
56928.48
56928.48
56928.48
56928.48
56928.48
56933.7
56933.7
56933.7
56933.7
56933.7
56930.09
56930.09
56930.09
LaaR Tripped
0
002511
07/18/11 20:36:28
07/18/11 20:36:30
07/18/11 20:36:32
07/18/11 20:36:34
07/18/11 20:36:36
07/18/11 20:36:38
07/18/11 20:36:40
07/18/11 20:36:42
07/18/11 20:36:44
07/18/11 20:36:46
07/18/11 20:36:48
07/18/11 20:36:50
07/18/11 20:36:52
07/18/11 20:36:54
07/18/11 20:36:56
07/18/11 20:36:58
07/18/11 20:37:00
07/18/11 20:37:02
07/18/11 20:37:04
07/18/11 20:37:06
07/18/11 20:37:08
07/18/11 20:37:10
07/18/11 20:37:12
07/18/11 20:37:14
07/18/11 20:37:16
07/18/11 20:37:18
07/18/11 20:37:20
07/18/11 20:37:22
07/18/11 20:37:24
07/18/11 20:37:26
07/18/11 20:37:28
07/18/11 20:37:30
07/18/11 20:37:32
07/18/11 20:37:34
07/18/11 20:37:36
07/18/11 20:37:38
07/18/11 20:37:40
07/18/11 20:37:42
07/18/11 20:37:44
07/18/11 20:37:46
07/18/11 20:37:48
07/18/11 20:37:50
07/18/11 20:37:52
07/18/11 20:37:54
07/18/11 20:37:56
07/18/11 20:37:58
07/18/11 20:38:00
07/18/11 20:38:02
07/18/11 20:38:04
59.9860001
59.9850006
59.9860001
59.9860001
59.9869995
59.9860001
59.9869995
59.9889984
59.9889984
59.9889984
59.9889984
59.9900017
59.9900017
59.9920006
59.9920006
59.993
59.9949989
59.9959984
59.9959984
59.9959984
59.9970016
59.9990005
59.9990005
60.0009995
60
59.9980011
59.9970016
59.9959984
59.9990005
60.0040016
60.0110016
60.0169983
60.0180016
60.0200005
60.0200005
60.0219994
60.0250015
60.0250015
60.0250015
60.0219994
60.0219994
60.0250015
60.026001
60.0289993
60.0299988
60.0279999
60.026001
60.026001
60.0180016
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56930.09
56930.09
56944
56944
56944
56944
56944
56934.53
56934.53
56934.53
56934.53
56934.53
56942.72
56942.72
56942.72
56942.72
56942.72
56939.76
56939.76
56939.76
56939.76
56939.76
56933.93
56933.93
56933.93
56933.93
56933.93
56945.98
56945.98
56945.98
56945.98
56945.98
56940.86
56940.86
56940.86
56940.86
56940.86
56916.58
56916.58
56916.58
56916.58
56916.58
56901.21
56901.21
56901.21
56901.21
56901.21
56896.12
56896.12
002512
07/18/11 20:38:06
07/18/11 20:38:08
07/18/11 20:38:10
07/18/11 20:38:12
07/18/11 20:38:14
07/18/11 20:38:16
07/18/11 20:38:18
07/18/11 20:38:20
07/18/11 20:38:22
07/18/11 20:38:24
07/18/11 20:38:26
07/18/11 20:38:28
07/18/11 20:38:30
07/18/11 20:38:32
07/18/11 20:38:34
07/18/11 20:38:36
07/18/11 20:38:38
07/18/11 20:38:40
07/18/11 20:38:42
07/18/11 20:38:44
07/18/11 20:38:46
07/18/11 20:38:48
07/18/11 20:38:50
07/18/11 20:38:52
07/18/11 20:38:54
07/18/11 20:38:56
07/18/11 20:38:58
07/18/11 20:39:00
07/18/11 20:39:02
07/18/11 20:39:04
07/18/11 20:39:06
07/18/11 20:39:08
07/18/11 20:39:10
07/18/11 20:39:12
07/18/11 20:39:14
07/18/11 20:39:16
07/18/11 20:39:18
07/18/11 20:39:20
07/18/11 20:39:22
07/18/11 20:39:24
07/18/11 20:39:26
07/18/11 20:39:28
07/18/11 20:39:30
07/18/11 20:39:32
07/18/11 20:39:34
07/18/11 20:39:36
07/18/11 20:39:38
07/18/11 20:39:40
07/18/11 20:39:42
60.0139999
60.0099983
60.0079994
60.0079994
60.0050011
60.0029984
60.0009995
59.9980011
59.9959984
59.9939995
59.993
59.9939995
59.9939995
59.9910011
59.9920006
59.993
59.9939995
59.9939995
59.993
59.993
59.9920006
59.9889984
59.987999
59.9869995
59.987999
59.9889984
59.9889984
59.9900017
59.9900017
59.9900017
59.9900017
59.9900017
59.9920006
59.9920006
59.993
59.9910011
59.9860001
59.980999
59.9770012
59.9729996
59.9700012
59.9679985
59.9690018
59.9710007
59.9720001
59.9710007
59.9720001
59.9720001
59.9720001
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56896.12
56896.12
56896.12
56911.67
56911.67
56911.67
56911.67
56911.67
56925.88
56925.88
56925.88
56925.88
56925.88
56950.88
56950.88
56950.88
56950.88
56950.88
56951.3
56951.3
56951.3
56951.3
56951.3
56958.96
56958.96
56958.96
56958.96
56958.96
56949.07
56949.07
56949.07
56949.07
56949.07
56944.2
56944.2
56944.2
56944.2
56944.2
56951.1
56951.1
56951.1
56951.1
56951.1
56961.13
56961.13
56961.13
56961.13
56961.13
56978.73
002513
07/18/11 20:39:44
07/18/11 20:39:46
07/18/11 20:39:48
07/18/11 20:39:50
07/18/11 20:39:52
07/18/11 20:39:54
07/18/11 20:39:56
07/18/11 20:39:58
07/18/11 20:40:00
07/18/11 20:40:02
07/18/11 20:40:04
07/18/11 20:40:06
07/18/11 20:40:08
07/18/11 20:40:10
07/18/11 20:40:12
07/18/11 20:40:14
07/18/11 20:40:16
07/18/11 20:40:18
07/18/11 20:40:20
07/18/11 20:40:22
07/18/11 20:40:24
07/18/11 20:40:26
07/18/11 20:40:28
07/18/11 20:40:30
07/18/11 20:40:32
07/18/11 20:40:34
07/18/11 20:40:36
07/18/11 20:40:38
07/18/11 20:40:40
07/18/11 20:40:42
07/18/11 20:40:44
07/18/11 20:40:46
07/18/11 20:40:48
07/18/11 20:40:50
07/18/11 20:40:52
07/18/11 20:40:54
07/18/11 20:40:56
07/18/11 20:40:58
07/18/11 20:41:00
07/18/11 20:41:02
07/18/11 20:41:04
07/18/11 20:41:06
07/18/11 20:41:08
07/18/11 20:41:10
07/18/11 20:41:12
07/18/11 20:41:14
07/18/11 20:41:16
07/18/11 20:41:18
07/18/11 20:41:20
59.9710007
59.9700012
59.9710007
59.9729996
59.9760017
59.973999
59.9729996
59.9720001
59.973999
59.9760017
59.9760017
59.9749985
59.9760017
59.9770012
59.9760017
59.9770012
59.9790001
59.9819984
59.9830017
59.9850006
59.9819984
59.980999
59.9790001
59.9780006
59.9799995
59.9790001
59.9799995
59.9799995
59.9819984
59.9840012
59.9869995
59.9910011
59.9910011
59.9900017
59.9900017
59.9910011
59.9939995
59.9949989
59.9959984
59.9970016
59.9970016
59.9990005
59.9980011
59.9990005
59.9980011
59.9970016
59.9949989
59.993
59.9920006
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56978.73
56978.73
56978.73
56978.73
56988.21
56988.21
56988.21
56988.21
56988.21
56975.85
56975.85
56975.85
56975.85
56975.85
57000.34
57000.34
57000.34
57000.34
57000.34
57017.81
57017.81
57017.81
57017.81
57017.81
57007.31
57007.31
57007.31
57007.31
57007.31
56999.67
56999.67
56999.67
56999.67
56999.67
57028.63
57028.63
57028.63
57028.63
57028.63
57023.53
57023.53
57023.53
57023.53
57023.53
57028.72
57028.72
57028.72
57028.72
57028.72
002514
07/18/11 20:41:22
07/18/11 20:41:24
07/18/11 20:41:26
07/18/11 20:41:28
07/18/11 20:41:30
07/18/11 20:41:32
07/18/11 20:41:34
07/18/11 20:41:36
07/18/11 20:41:38
07/18/11 20:41:40
07/18/11 20:41:42
07/18/11 20:41:44
07/18/11 20:41:46
07/18/11 20:41:48
07/18/11 20:41:50
07/18/11 20:41:52
07/18/11 20:41:54
07/18/11 20:41:56
07/18/11 20:41:58
07/18/11 20:42:00
07/18/11 20:42:02
07/18/11 20:42:04
07/18/11 20:42:06
07/18/11 20:42:08
07/18/11 20:42:10
07/18/11 20:42:12
07/18/11 20:42:14
07/18/11 20:42:16
07/18/11 20:42:18
07/18/11 20:42:20
07/18/11 20:42:22
07/18/11 20:42:24
07/18/11 20:42:26
07/18/11 20:42:28
07/18/11 20:42:30
07/18/11 20:42:32
07/18/11 20:42:34
07/18/11 20:42:36
07/18/11 20:42:38
07/18/11 20:42:40
07/18/11 20:42:42
07/18/11 20:42:44
07/18/11 20:42:46
07/18/11 20:42:48
07/18/11 20:42:50
07/18/11 20:42:52
07/18/11 20:42:54
07/18/11 20:42:56
07/18/11 20:42:58
59.9920006
59.9939995
59.9980011
59.9990005
59.9990005
60.0040016
60.007
60.0079994
60.0060005
60.0050011
60.0029984
60.0040016
60.0040016
60.0050011
60.0040016
60.0050011
60.0050011
60.0060005
60.0089989
60.0110016
60.0149994
60.0169983
60.0169983
60.0159988
60.019001
60.0219994
60.0239983
60.0229988
60.0219994
60.0219994
60.0209999
60.0209999
60.0200005
60.0229988
60.0200005
60.0200005
60.0219994
60.0239983
60.0209999
60.019001
60.0149994
60.0139999
60.012001
60.0130005
60.0110016
60.0110016
60.012001
60.012001
60.0130005
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57056.74
57056.74
57056.74
57056.74
57056.74
57053.91
57053.91
57053.91
57053.91
57053.91
57044.42
57044.42
57044.42
57044.42
57044.42
57048.84
57048.84
57048.84
57048.84
57048.84
57062
57062
57062
57062
57062
57048.32
57048.32
57048.32
57048.32
57048.32
57042.8
57042.8
57042.8
57042.8
57042.8
57059.87
57059.87
57059.87
57059.87
57059.87
57044.11
57044.11
57044.11
57044.11
57044.11
57044.17
57044.17
57044.17
57044.17
002515
07/18/11 20:43:00
07/18/11 20:43:02
07/18/11 20:43:04
07/18/11 20:43:06
07/18/11 20:43:08
07/18/11 20:43:10
07/18/11 20:43:12
07/18/11 20:43:14
07/18/11 20:43:16
07/18/11 20:43:18
07/18/11 20:43:20
07/18/11 20:43:22
07/18/11 20:43:24
07/18/11 20:43:26
07/18/11 20:43:28
07/18/11 20:43:30
07/18/11 20:43:32
07/18/11 20:43:34
07/18/11 20:43:36
07/18/11 20:43:38
07/18/11 20:43:40
07/18/11 20:43:42
07/18/11 20:43:44
07/18/11 20:43:46
07/18/11 20:43:48
07/18/11 20:43:50
07/18/11 20:43:52
07/18/11 20:43:54
07/18/11 20:43:56
07/18/11 20:43:58
07/18/11 20:44:00
07/18/11 20:44:02
07/18/11 20:44:04
07/18/11 20:44:06
07/18/11 20:44:08
07/18/11 20:44:10
07/18/11 20:44:12
07/18/11 20:44:14
07/18/11 20:44:16
07/18/11 20:44:18
07/18/11 20:44:20
07/18/11 20:44:22
07/18/11 20:44:24
07/18/11 20:44:26
07/18/11 20:44:28
07/18/11 20:44:30
07/18/11 20:44:32
07/18/11 20:44:34
07/18/11 20:44:36
60.0130005
60.012001
60.012001
60.0110016
60.0099983
60.0110016
60.0099983
60.012001
60.0130005
60.0149994
60.0159988
60.0159988
60.0159988
60.0180016
60.0180016
60.0169983
60.0180016
60.0180016
60.0159988
60.0169983
60.0169983
60.019001
60.0180016
60.0139999
60.0139999
60.0110016
60.0089989
60.0079994
60.0079994
60.0079994
60.0079994
60.0089989
60.012001
60.012001
60.0099983
60.0079994
60.0089989
60.0110016
60.0139999
60.0139999
60.0139999
60.0130005
60.012001
60.012001
60.0130005
60.0139999
60.0149994
60.0139999
60.0159988
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57044.17
57047.32
57047.32
57047.32
57047.32
57047.32
57027.43
57027.43
57027.43
57027.43
57027.43
57048.26
57048.26
57048.26
57048.26
57048.26
57063.55
57063.55
57063.55
57063.55
57063.55
57060.49
57060.49
57060.49
57060.49
57060.49
57064.85
57064.85
57064.85
57064.85
57064.85
57063.68
57063.68
57063.68
57063.68
57063.68
57056.04
57056.04
57056.04
57056.04
57056.04
57060.19
57060.19
57060.19
57060.19
57060.19
57047.78
57047.78
57047.78
002516
07/18/11 20:44:38
07/18/11 20:44:40
07/18/11 20:44:42
07/18/11 20:44:44
07/18/11 20:44:46
07/18/11 20:44:48
07/18/11 20:44:50
07/18/11 20:44:52
07/18/11 20:44:54
07/18/11 20:44:56
07/18/11 20:44:58
07/18/11 20:45:00
07/18/11 20:45:02
07/18/11 20:45:04
07/18/11 20:45:06
07/18/11 20:45:08
07/18/11 20:45:10
07/18/11 20:45:12
07/18/11 20:45:14
07/18/11 20:45:16
07/18/11 20:45:18
07/18/11 20:45:20
07/18/11 20:45:22
07/18/11 20:45:24
07/18/11 20:45:26
07/18/11 20:45:28
07/18/11 20:45:30
07/18/11 20:45:32
07/18/11 20:45:34
07/18/11 20:45:36
07/18/11 20:45:38
07/18/11 20:45:40
07/18/11 20:45:42
07/18/11 20:45:44
07/18/11 20:45:46
07/18/11 20:45:48
07/18/11 20:45:50
07/18/11 20:45:52
07/18/11 20:45:54
07/18/11 20:45:56
07/18/11 20:45:58
07/18/11 20:46:00
07/18/11 20:46:02
07/18/11 20:46:04
07/18/11 20:46:06
07/18/11 20:46:08
07/18/11 20:46:10
07/18/11 20:46:12
07/18/11 20:46:14
60.0180016
60.0169983
60.0180016
60.019001
60.019001
60.0180016
60.0139999
60.012001
60.0060005
60.0050011
60.0040016
60.0040016
60.0040016
60.0050011
60.0050011
60.007
60.0089989
60.0079994
60.0079994
60.007
60.007
60.0060005
60.0040016
60.0029984
60.0009995
60.0009995
60.0029984
60.0060005
60.0089989
60.0089989
60.0099983
60.0110016
60.0079994
60.0060005
60.0029984
60.0009995
59.9990005
60
60.0019989
60.0040016
60.0060005
60.0060005
60.0079994
60.0079994
60.0079994
60.0050011
60
59.9970016
59.9980011
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57047.78
57047.78
57053.33
57053.33
57053.33
57053.33
57053.33
57045.49
57045.49
57045.49
57045.49
57045.49
57051.96
57051.96
57051.96
57051.96
57051.96
57058.94
57058.94
57058.94
57058.94
57058.94
57042.65
57042.65
57042.65
57042.65
57042.65
57068.24
57068.24
57068.24
57068.24
57068.24
57050.98
57050.98
57050.98
57050.98
57050.98
57062.43
57062.43
57062.43
57062.43
57062.43
57071.05
57071.05
57071.05
57071.05
57071.05
57054.96
57054.96
002517
07/18/11 20:46:16
07/18/11 20:46:18
07/18/11 20:46:20
07/18/11 20:46:22
07/18/11 20:46:24
07/18/11 20:46:26
07/18/11 20:46:28
07/18/11 20:46:30
07/18/11 20:46:32
07/18/11 20:46:34
07/18/11 20:46:36
07/18/11 20:46:38
07/18/11 20:46:40
07/18/11 20:46:42
07/18/11 20:46:44
07/18/11 20:46:46
07/18/11 20:46:48
07/18/11 20:46:50
07/18/11 20:46:52
07/18/11 20:46:54
07/18/11 20:46:56
07/18/11 20:46:58
07/18/11 20:47:00
07/18/11 20:47:02
07/18/11 20:47:04
07/18/11 20:47:06
07/18/11 20:47:08
07/18/11 20:47:10
07/18/11 20:47:12
07/18/11 20:47:14
07/18/11 20:47:16
07/18/11 20:47:18
07/18/11 20:47:20
07/18/11 20:47:22
07/18/11 20:47:24
07/18/11 20:47:26
07/18/11 20:47:28
07/18/11 20:47:30
07/18/11 20:47:32
07/18/11 20:47:34
07/18/11 20:47:36
07/18/11 20:47:38
07/18/11 20:47:40
07/18/11 20:47:42
07/18/11 20:47:44
07/18/11 20:47:46
07/18/11 20:47:48
07/18/11 20:47:50
07/18/11 20:47:52
59.9980011
59.9990005
60.0019989
60.0040016
60.0040016
60.0060005
60.007
60.0060005
60.0060005
60.0060005
60.0079994
60.007
60.007
60.0079994
60.0099983
60.0130005
60.012001
60.0130005
60.0130005
60.012001
60.012001
60.0089989
60.0079994
60.007
60.007
60.0079994
60.0099983
60.0110016
60.0110016
60.0110016
60.0099983
60.0099983
60.0110016
60.0110016
60.0110016
60.012001
60.0139999
60.0159988
60.0169983
60.0200005
60.0200005
60.0200005
60.0219994
60.0219994
60.0209999
60.0200005
60.0209999
60.0219994
60.0219994
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57054.96
57054.96
57054.96
57041.59
57041.59
57041.59
57041.59
57041.59
57062.77
57062.77
57062.77
57062.77
57062.77
57072
57072
57072
57072
57072
57053.75
57053.75
57053.75
57053.75
57053.75
57041.91
57041.91
57041.91
57041.91
57041.91
57054.95
57054.95
57054.95
57054.95
57054.95
57061.43
57061.43
57061.43
57061.43
57061.43
57058.57
57058.57
57058.57
57058.57
57058.57
57063.98
57063.98
57063.98
57063.98
57063.98
57057.75
002518
07/18/11 20:47:54
07/18/11 20:47:56
07/18/11 20:47:58
07/18/11 20:48:00
07/18/11 20:48:02
07/18/11 20:48:04
07/18/11 20:48:06
07/18/11 20:48:08
07/18/11 20:48:10
07/18/11 20:48:12
07/18/11 20:48:14
07/18/11 20:48:16
07/18/11 20:48:18
07/18/11 20:48:20
07/18/11 20:48:22
07/18/11 20:48:24
07/18/11 20:48:26
07/18/11 20:48:28
07/18/11 20:48:30
07/18/11 20:48:32
07/18/11 20:48:34
07/18/11 20:48:36
07/18/11 20:48:38
07/18/11 20:48:40
07/18/11 20:48:42
07/18/11 20:48:44
07/18/11 20:48:46
07/18/11 20:48:48
07/18/11 20:48:50
07/18/11 20:48:52
07/18/11 20:48:54
07/18/11 20:48:56
07/18/11 20:48:58
07/18/11 20:49:00
07/18/11 20:49:02
07/18/11 20:49:04
07/18/11 20:49:06
07/18/11 20:49:08
07/18/11 20:49:10
07/18/11 20:49:12
07/18/11 20:49:14
07/18/11 20:49:16
07/18/11 20:49:18
07/18/11 20:49:20
07/18/11 20:49:22
07/18/11 20:49:24
07/18/11 20:49:26
07/18/11 20:49:28
07/18/11 20:49:30
60.0180016
60.0159988
60.0149994
60.0149994
60.0159988
60.0149994
60.0159988
60.0169983
60.019001
60.019001
60.0180016
60.0180016
60.0180016
60.0169983
60.0159988
60.0139999
60.0139999
60.0130005
60.0099983
60.0079994
60.007
60.0079994
60.0089989
60.0110016
60.012001
60.0159988
60.0180016
60.0180016
60.0159988
60.0139999
60.0130005
60.012001
60.012001
60.0130005
60.0130005
60.0139999
60.0159988
60.0180016
60.0200005
60.0200005
60.0209999
60.0209999
60.0200005
60.0180016
60.0180016
60.0159988
60.0139999
60.012001
60.0099983
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57057.75
57057.75
57057.75
57057.75
57075.8
57075.8
57075.8
57075.8
57075.8
57052.68
57052.68
57052.68
57052.68
57052.68
57049.95
57049.95
57049.95
57049.95
57049.95
57072.5
57072.5
57072.5
57072.5
57072.5
57075.62
57075.62
57075.62
57075.62
57075.62
57081.02
57081.02
57081.02
57081.02
57081.02
57074.86
57074.86
57074.86
57074.86
57074.86
57065.55
57065.55
57065.55
57065.55
57065.55
57058.09
57058.09
57058.09
57058.09
57058.09
002519
07/18/11 20:49:32
07/18/11 20:49:34
07/18/11 20:49:36
07/18/11 20:49:38
07/18/11 20:49:40
07/18/11 20:49:42
07/18/11 20:49:44
07/18/11 20:49:46
07/18/11 20:49:48
07/18/11 20:49:50
07/18/11 20:49:52
07/18/11 20:49:54
07/18/11 20:49:56
07/18/11 20:49:58
07/18/11 20:50:00
07/18/11 20:50:02
07/18/11 20:50:04
07/18/11 20:50:06
07/18/11 20:50:08
07/18/11 20:50:10
07/18/11 20:50:12
07/18/11 20:50:14
07/18/11 20:50:16
07/18/11 20:50:18
07/18/11 20:50:20
07/18/11 20:50:22
07/18/11 20:50:24
07/18/11 20:50:26
07/18/11 20:50:28
07/18/11 20:50:30
07/18/11 20:50:32
07/18/11 20:50:34
07/18/11 20:50:36
07/18/11 20:50:38
07/18/11 20:50:40
07/18/11 20:50:42
07/18/11 20:50:44
07/18/11 20:50:46
07/18/11 20:50:48
07/18/11 20:50:50
07/18/11 20:50:52
07/18/11 20:50:54
07/18/11 20:50:56
07/18/11 20:50:58
07/18/11 20:51:00
07/18/11 20:51:02
07/18/11 20:51:04
07/18/11 20:51:06
07/18/11 20:51:08
60.0099983
60.0110016
60.0110016
60.0099983
60.0110016
60.0110016
60.012001
60.012001
60.0110016
60.012001
60.0130005
60.0149994
60.0159988
60.0149994
60.0139999
60.0130005
60.012001
60.012001
60.012001
60.0130005
60.0149994
60.0169983
60.0169983
60.0139999
60.0149994
60.0130005
60.012001
60.0110016
60.0079994
60.0079994
60.007
60.007
60.007
60.007
59.9889984
59.9179993
59.8800011
59.8720016
59.8660011
59.8670006
59.868
59.8740005
59.8759995
59.8779984
59.8800011
59.8829994
59.8810005
59.8800011
59.8810005
593.3
593.3
593.3
593.3
593.3
593.3
593.3
593.3
585.6283569
585.6283569
586.1430054
586.1430054
586.7954102
586.7954102
585.9466553
585.9466553
585.6723022
585.6723022
585.116272
585.116272
584.6550293
584.6550293
585.307312
585.307312
585.2108765
585.2108765
585.918396
585.918396
593.2776489
593.2776489
602.7012329
602.7012329
602.7012329
602.7012329
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
57042.5
57042.5
57042.5
57042.5
57042.5
57050.12
57050.12
57050.12
57057.21
57057.21
57051.74
57051.74
57051.74
57051.74
57037.88
57037.88
57050.43
57050.43
57029.92
57029.92
57033.71
57033.71
57035.56
57035.56
57020.6
57020.6
57030.37
57030.37
57039.15
57039.15
57042.2
57042.2
57089.3
57089.3
56704.13
56704.13
56763.97
56763.97
56811.2
56811.2
56864.96
56864.96
56863.43
56863.43
56867.51
56867.51
56878.36
56878.36
56886.32
002520
07/18/11 20:51:10
07/18/11 20:51:12
07/18/11 20:51:14
07/18/11 20:51:16
07/18/11 20:51:18
07/18/11 20:51:20
07/18/11 20:51:22
07/18/11 20:51:24
07/18/11 20:51:26
07/18/11 20:51:28
07/18/11 20:51:30
07/18/11 20:51:32
07/18/11 20:51:34
07/18/11 20:51:36
07/18/11 20:51:38
07/18/11 20:51:40
07/18/11 20:51:42
07/18/11 20:51:44
07/18/11 20:51:46
07/18/11 20:51:48
07/18/11 20:51:50
07/18/11 20:51:52
07/18/11 20:51:54
07/18/11 20:51:56
07/18/11 20:51:58
07/18/11 20:52:00
07/18/11 20:52:02
07/18/11 20:52:04
07/18/11 20:52:06
07/18/11 20:52:08
07/18/11 20:52:10
07/18/11 20:52:12
07/18/11 20:52:14
07/18/11 20:52:16
07/18/11 20:52:18
07/18/11 20:52:20
07/18/11 20:52:22
07/18/11 20:52:24
07/18/11 20:52:26
07/18/11 20:52:28
07/18/11 20:52:30
07/18/11 20:52:32
07/18/11 20:52:34
07/18/11 20:52:36
07/18/11 20:52:38
07/18/11 20:52:40
07/18/11 20:52:42
07/18/11 20:52:44
07/18/11 20:52:46
59.8810005
59.8800011
59.8779984
59.8800011
59.8800011
59.8800011
59.882
59.8829994
59.882
59.8829994
59.8800011
59.8810005
59.8839989
59.8919983
59.894001
59.8959999
59.9000015
59.9020004
59.9039993
59.9029999
59.9020004
59.9029999
59.9020004
59.901001
59.9000015
59.901001
59.9039993
59.9070015
59.9099998
59.9129982
59.9160004
59.9160004
59.9189987
59.9220009
59.9239998
59.9239998
59.9239998
59.9249992
59.9280014
59.9290009
59.9319992
59.9339981
59.9350014
59.9350014
59.9350014
59.9350014
59.9339981
59.9350014
59.9379997
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56886.32
56893.13
56893.13
56875.62
56875.62
56890.82
56890.82
56891.07
56891.07
56899.47
56899.47
56874.9
56874.9
56854.81
56854.81
56837.21
56837.21
56827.59
56827.59
56841.84
56841.84
56835.3
56835.3
56837.3
56837.3
56854.15
56854.15
56861.54
56861.54
56861.64
56861.64
56866.16
56866.16
56869.21
56869.21
56876.27
56876.27
56881.39
56881.39
56889.59
56889.59
56893.89
56900.44
56900.44
56900.44
56887.58
56887.58
56901.59
56901.59
002521
07/18/11 20:52:48
07/18/11 20:52:50
07/18/11 20:52:52
07/18/11 20:52:54
07/18/11 20:52:56
07/18/11 20:52:58
07/18/11 20:53:00
07/18/11 20:53:02
07/18/11 20:53:04
07/18/11 20:53:06
07/18/11 20:53:08
07/18/11 20:53:10
07/18/11 20:53:12
07/18/11 20:53:14
07/18/11 20:53:16
07/18/11 20:53:18
07/18/11 20:53:20
07/18/11 20:53:22
07/18/11 20:53:24
07/18/11 20:53:26
07/18/11 20:53:28
07/18/11 20:53:30
07/18/11 20:53:32
07/18/11 20:53:34
07/18/11 20:53:36
07/18/11 20:53:38
07/18/11 20:53:40
07/18/11 20:53:42
07/18/11 20:53:44
07/18/11 20:53:46
07/18/11 20:53:48
07/18/11 20:53:50
07/18/11 20:53:52
07/18/11 20:53:54
07/18/11 20:53:56
07/18/11 20:53:58
07/18/11 20:54:00
07/18/11 20:54:02
07/18/11 20:54:04
07/18/11 20:54:06
07/18/11 20:54:08
07/18/11 20:54:10
07/18/11 20:54:12
07/18/11 20:54:14
07/18/11 20:54:16
07/18/11 20:54:18
07/18/11 20:54:20
07/18/11 20:54:22
07/18/11 20:54:24
59.9410019
59.9430008
59.9480019
59.9510002
59.9510002
59.9529991
59.9560013
59.9580002
59.9580002
59.9589996
59.9580002
59.9580002
59.9580002
59.9599991
59.9620018
59.9650002
59.9669991
59.9700012
59.9710007
59.9729996
59.9710007
59.9710007
59.9720001
59.973999
59.9749985
59.9770012
59.9790001
59.980999
59.9819984
59.9840012
59.9860001
59.9889984
59.9910011
59.993
59.9959984
59.9990005
60.0019989
60.0050011
60.0050011
60.0089989
60.0099983
60.0110016
60.012001
60.0110016
60.0130005
60.0139999
60.0169983
60.0209999
60.0229988
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56915.66
56915.66
56912.21
56912.21
56914.31
56914.31
56907.54
56907.54
56897.04
56897.04
56902.03
56902.03
56903.03
56903.03
56917.74
56917.74
56900.81
56900.81
56914.8
56914.8
56922.52
56922.52
56932.45
56932.45
56920.23
56920.23
56912.88
56912.88
56905.22
56905.22
56915.62
56915.62
56923.03
56923.03
56932.03
56932.03
56926.22
56926.22
56930.33
56930.33
56935.11
56935.11
56938.24
56938.24
56947.14
56947.14
56946.19
56946.19
56937.3
002522
07/18/11 20:54:26
07/18/11 20:54:28
07/18/11 20:54:30
07/18/11 20:54:32
07/18/11 20:54:34
07/18/11 20:54:36
07/18/11 20:54:38
07/18/11 20:54:40
07/18/11 20:54:42
07/18/11 20:54:44
07/18/11 20:54:46
07/18/11 20:54:48
07/18/11 20:54:50
07/18/11 20:54:52
07/18/11 20:54:54
07/18/11 20:54:56
07/18/11 20:54:58
07/18/11 20:55:00
07/18/11 20:55:02
07/18/11 20:55:04
07/18/11 20:55:06
07/18/11 20:55:08
07/18/11 20:55:10
07/18/11 20:55:12
07/18/11 20:55:14
07/18/11 20:55:16
07/18/11 20:55:18
07/18/11 20:55:20
07/18/11 20:55:22
07/18/11 20:55:24
07/18/11 20:55:26
07/18/11 20:55:28
07/18/11 20:55:30
07/18/11 20:55:32
07/18/11 20:55:34
07/18/11 20:55:36
07/18/11 20:55:38
07/18/11 20:55:40
07/18/11 20:55:42
07/18/11 20:55:44
07/18/11 20:55:46
07/18/11 20:55:48
07/18/11 20:55:50
07/18/11 20:55:52
07/18/11 20:55:54
07/18/11 20:55:56
07/18/11 20:55:58
07/18/11 20:56:00
07/18/11 20:56:02
60.0239983
60.0250015
60.026001
60.026001
60.0279999
60.0289993
60.0289993
60.0299988
60.0320015
60.0330009
60.0330009
60.0309982
60.0289993
60.0299988
60.0309982
60.0309982
60.0320015
60.0330009
60.0330009
60.0330009
60.0320015
60.0299988
60.0330009
60.0340004
60.0349998
60.0369987
60.0390015
60.0379982
60.0460014
60.0519981
60.0509987
60.0499992
60.0509987
60.0489998
60.0499992
60.0509987
60.0489998
60.0480003
60.0460014
60.0460014
60.0419998
60.0439987
60.0449982
60.0449982
60.0449982
60.0449982
60.0449982
60.0460014
60.0460014
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56937.3
56931.41
56931.41
56924.84
56924.84
56933.16
56933.16
56935.62
56935.62
56957.32
56957.32
56954.23
56954.23
56956.64
56956.64
56956.6
56956.6
56938.9
56938.9
56943.18
56943.18
56939.07
56939.07
56942.44
56942.44
56924.37
56924.37
56907.9
56907.9
56897.8
56897.8
56864.89
56864.89
56842.66
56842.66
56845.28
56845.28
56850.62
56850.62
56870.91
56870.91
56854.55
56854.55
56848.62
56848.62
56838.2
56838.2
56838.88
56838.88
002523
07/18/11 20:56:04
07/18/11 20:56:06
07/18/11 20:56:08
07/18/11 20:56:10
07/18/11 20:56:12
07/18/11 20:56:14
07/18/11 20:56:16
07/18/11 20:56:18
07/18/11 20:56:20
07/18/11 20:56:22
07/18/11 20:56:24
07/18/11 20:56:26
07/18/11 20:56:28
07/18/11 20:56:30
07/18/11 20:56:32
07/18/11 20:56:34
07/18/11 20:56:36
07/18/11 20:56:38
07/18/11 20:56:40
07/18/11 20:56:42
07/18/11 20:56:44
07/18/11 20:56:46
07/18/11 20:56:48
07/18/11 20:56:50
07/18/11 20:56:52
07/18/11 20:56:54
07/18/11 20:56:56
07/18/11 20:56:58
07/18/11 20:57:00
07/18/11 20:57:02
07/18/11 20:57:04
07/18/11 20:57:06
07/18/11 20:57:08
07/18/11 20:57:10
07/18/11 20:57:12
07/18/11 20:57:14
07/18/11 20:57:16
07/18/11 20:57:18
07/18/11 20:57:20
07/18/11 20:57:22
07/18/11 20:57:24
07/18/11 20:57:26
07/18/11 20:57:28
07/18/11 20:57:30
07/18/11 20:57:32
07/18/11 20:57:34
07/18/11 20:57:36
07/18/11 20:57:38
07/18/11 20:57:40
60.0449982
60.0460014
60.0439987
60.0460014
60.0460014
60.0460014
60.0470009
60.0470009
60.0480003
60.0499992
60.0519981
60.0519981
60.0489998
60.0480003
60.0489998
60.0509987
60.0499992
60.0489998
60.0480003
60.0460014
60.0439987
60.0429993
60.0449982
60.0439987
60.0400009
60.0379982
60.0359993
60.0349998
60.0309982
60.0299988
60.0299988
60.0320015
60.0330009
60.0330009
60.0320015
60.0349998
60.0379982
60.0390015
60.0379982
60.0390015
60.0400009
60.0400009
60.0390015
60.0390015
60.0379982
60.0369987
60.0349998
60.0340004
60.0340004
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56851.8
56851.8
56861.98
56861.98
56851.02
56851.02
56845.13
56845.13
56847.95
56847.95
56843.66
56843.66
56833.39
56833.39
56814.38
56814.38
56817.16
56817.16
56805.52
56805.52
56807.83
56807.83
56827.41
56827.41
56821.69
56821.69
56833.95
56833.95
56860.51
56860.51
56877.59
56877.59
56918.66
56918.66
56891.71
56891.71
56894.35
56894.35
56895.17
56895.17
56889.73
56889.73
56892.39
56892.39
56875.33
56874.01
56874.01
56874.01
56881
002524
07/18/11 20:57:42
07/18/11 20:57:44
07/18/11 20:57:46
07/18/11 20:57:48
07/18/11 20:57:50
07/18/11 20:57:52
07/18/11 20:57:54
07/18/11 20:57:56
07/18/11 20:57:58
07/18/11 20:58:00
07/18/11 20:58:02
07/18/11 20:58:04
07/18/11 20:58:06
07/18/11 20:58:08
07/18/11 20:58:10
07/18/11 20:58:12
07/18/11 20:58:14
07/18/11 20:58:16
07/18/11 20:58:18
07/18/11 20:58:20
07/18/11 20:58:22
07/18/11 20:58:24
07/18/11 20:58:26
07/18/11 20:58:28
07/18/11 20:58:30
07/18/11 20:58:32
07/18/11 20:58:34
07/18/11 20:58:36
07/18/11 20:58:38
07/18/11 20:58:40
07/18/11 20:58:42
07/18/11 20:58:44
07/18/11 20:58:46
07/18/11 20:58:48
07/18/11 20:58:50
07/18/11 20:58:52
07/18/11 20:58:54
07/18/11 20:58:56
07/18/11 20:58:58
07/18/11 20:59:00
07/18/11 20:59:02
07/18/11 20:59:04
07/18/11 20:59:06
07/18/11 20:59:08
07/18/11 20:59:10
07/18/11 20:59:12
07/18/11 20:59:14
07/18/11 20:59:16
07/18/11 20:59:18
60.0340004
60.0359993
60.0340004
60.0320015
60.0330009
60.0340004
60.0359993
60.0379982
60.0400009
60.0390015
60.0349998
60.0349998
60.0340004
60.0330009
60.0289993
60.0299988
60.0289993
60.0279999
60.026001
60.0279999
60.0299988
60.0320015
60.0330009
60.0349998
60.0359993
60.0369987
60.0340004
60.0320015
60.0299988
60.0279999
60.0279999
60.0279999
60.0279999
60.0299988
60.0289993
60.0299988
60.0320015
60.0349998
60.0349998
60.0349998
60.0340004
60.0330009
60.0340004
60.0340004
60.0340004
60.0330009
60.0289993
60.0270004
60.0250015
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56881
56887.45
56887.45
56882.08
56882.08
56879.11
56879.11
56884.36
56884.36
56872.63
56872.63
56865.52
56865.52
56874.48
56874.48
56866.35
56866.35
56868.5
56868.5
56865.58
56865.58
56862.76
56862.76
56871.13
56871.13
56863.48
56863.48
56856.71
56856.71
56859.67
56859.67
56860.41
56860.41
56867.31
56867.31
56852.14
56852.14
56838.81
56838.81
56839.64
56839.64
56839.96
56839.96
56841.01
56841.01
56854.9
56854.9
56846
56846
002525
07/18/11 20:59:20
07/18/11 20:59:22
07/18/11 20:59:24
07/18/11 20:59:26
07/18/11 20:59:28
07/18/11 20:59:30
07/18/11 20:59:32
07/18/11 20:59:34
07/18/11 20:59:36
07/18/11 20:59:38
07/18/11 20:59:40
07/18/11 20:59:42
07/18/11 20:59:44
07/18/11 20:59:46
07/18/11 20:59:48
07/18/11 20:59:50
07/18/11 20:59:52
07/18/11 20:59:54
07/18/11 20:59:56
07/18/11 20:59:58
07/18/11 21:00:00
07/18/11 21:00:02
07/18/11 21:00:04
07/18/11 21:00:06
07/18/11 21:00:08
07/18/11 21:00:10
07/18/11 21:00:12
07/18/11 21:00:14
07/18/11 21:00:16
07/18/11 21:00:18
07/18/11 21:00:20
07/18/11 21:00:22
07/18/11 21:00:24
07/18/11 21:00:26
07/18/11 21:00:28
07/18/11 21:00:30
07/18/11 21:00:32
07/18/11 21:00:34
07/18/11 21:00:36
07/18/11 21:00:38
07/18/11 21:00:40
07/18/11 21:00:42
07/18/11 21:00:44
07/18/11 21:00:46
07/18/11 21:00:48
07/18/11 21:00:50
07/18/11 21:00:52
07/18/11 21:00:54
07/18/11 21:00:56
60.0250015
60.026001
60.026001
60.0250015
60.026001
60.0270004
60.0270004
60.0279999
60.0299988
60.0289993
60.0299988
60.0279999
60.026001
60.0270004
60.0289993
60.0299988
60.0320015
60.0289993
60.0289993
60.0320015
60.0330009
60.0330009
60.0320015
60.0299988
60.0289993
60.0330009
60.0349998
60.0349998
60.0309982
60.0320015
60.0289993
60.0270004
60.026001
60.0270004
60.0270004
60.026001
60.026001
60.0279999
60.0279999
60.0270004
60.026001
60.0270004
60.0279999
60.0270004
60.0270004
60.0270004
60.0270004
60.0250015
60.0239983
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56833.07
56833.07
56827.28
56827.28
56829.42
56829.42
56846.66
56846.66
56840.57
56840.57
56831.91
56831.91
56833.35
56833.35
56833.63
56833.63
56828
56828
56828
56828
56833.8
56833.8
56806.86
56806.86
56813.18
56813.18
56804.27
56804.27
56787.34
56787.34
56786.84
56786.84
56773.49
56773.49
56759.37
56759.37
56742.34
56742.34
56734.98
56734.98
56750.62
56750.62
56746.89
56746.89
56753.28
56753.28
56749.96
56749.96
56728.95
002526
07/18/11 21:00:58
07/18/11 21:01:00
07/18/11 21:01:02
07/18/11 21:01:04
07/18/11 21:01:06
07/18/11 21:01:08
07/18/11 21:01:10
07/18/11 21:01:12
07/18/11 21:01:14
07/18/11 21:01:16
07/18/11 21:01:18
07/18/11 21:01:20
07/18/11 21:01:22
07/18/11 21:01:24
07/18/11 21:01:26
07/18/11 21:01:28
07/18/11 21:01:30
07/18/11 21:01:32
07/18/11 21:01:34
07/18/11 21:01:36
07/18/11 21:01:38
07/18/11 21:01:40
07/18/11 21:01:42
07/18/11 21:01:44
07/18/11 21:01:46
07/18/11 21:01:48
07/18/11 21:01:50
07/18/11 21:01:52
07/18/11 21:01:54
07/18/11 21:01:56
07/18/11 21:01:58
07/18/11 21:02:00
07/18/11 21:02:02
07/18/11 21:02:04
07/18/11 21:02:06
07/18/11 21:02:08
07/18/11 21:02:10
07/18/11 21:02:12
07/18/11 21:02:14
07/18/11 21:02:16
07/18/11 21:02:18
07/18/11 21:02:20
07/18/11 21:02:22
07/18/11 21:02:24
07/18/11 21:02:26
07/18/11 21:02:28
07/18/11 21:02:30
07/18/11 21:02:32
07/18/11 21:02:34
60.0239983
60.0239983
60.0250015
60.0250015
60.026001
60.0250015
60.0229988
60.0219994
60.0209999
60.0200005
60.0180016
60.0149994
60.0130005
60.0130005
60.0130005
60.0139999
60.0139999
60.0149994
60.0169983
60.0159988
60.0159988
60.0159988
60.0149994
60.0139999
60.0130005
60.0139999
60.0180016
60.0180016
60.0180016
60.0159988
60.0169983
60.0250015
60.0299988
60.0320015
60.0340004
60.0330009
60.0330009
60.0330009
60.0330009
60.0340004
60.0369987
60.0359993
60.0340004
60.0299988
60.0320015
60.0309982
60.0320015
60.0309982
60.0289993
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56728.95
56723.32
56723.32
56715.22
56715.22
56724.1
56724.1
56718.91
56718.91
56704.99
56704.99
56708.48
56708.48
56730.45
56730.45
56720.16
56720.16
56711.63
56711.63
56708.66
56708.66
56706.61
56706.61
56716.55
56716.55
56705.83
56705.83
56696.39
56696.39
56670.62
56670.62
56642.69
56642.69
56644.32
56644.32
56636.41
56636.41
56630.75
56630.75
56620.91
56620.91
56619
56619
56610.45
56610.45
56598.06
56598.06
56587.05
56589.89
002527
07/18/11 21:02:36
07/18/11 21:02:38
07/18/11 21:02:40
07/18/11 21:02:42
07/18/11 21:02:44
07/18/11 21:02:46
07/18/11 21:02:48
07/18/11 21:02:50
07/18/11 21:02:52
07/18/11 21:02:54
07/18/11 21:02:56
07/18/11 21:02:58
07/18/11 21:03:00
07/18/11 21:03:02
07/18/11 21:03:04
07/18/11 21:03:06
07/18/11 21:03:08
07/18/11 21:03:10
07/18/11 21:03:12
07/18/11 21:03:14
07/18/11 21:03:16
07/18/11 21:03:18
07/18/11 21:03:20
07/18/11 21:03:22
07/18/11 21:03:24
07/18/11 21:03:26
07/18/11 21:03:28
07/18/11 21:03:30
07/18/11 21:03:32
07/18/11 21:03:34
07/18/11 21:03:36
07/18/11 21:03:38
07/18/11 21:03:40
07/18/11 21:03:42
07/18/11 21:03:44
07/18/11 21:03:46
07/18/11 21:03:48
07/18/11 21:03:50
07/18/11 21:03:52
07/18/11 21:03:54
07/18/11 21:03:56
07/18/11 21:03:58
07/18/11 21:04:00
07/18/11 21:04:02
07/18/11 21:04:04
07/18/11 21:04:06
07/18/11 21:04:08
07/18/11 21:04:10
07/18/11 21:04:12
60.0270004
60.0270004
60.0229988
60.0219994
60.0200005
60.0180016
60.019001
60.0180016
60.019001
60.019001
60.0169983
60.0159988
60.0169983
60.0149994
60.0139999
60.012001
60.0110016
60.0110016
60.0110016
60.0130005
60.0130005
60.012001
60.012001
60.012001
60.0110016
60.007
60.0040016
60.0009995
59.9980011
59.9980011
59.9990005
60.0009995
60.0019989
60.0040016
60.0060005
60.0060005
60.0060005
60.0050011
60.0050011
60.0050011
60.0050011
60.0050011
60.0040016
60.0040016
60.0050011
60.0050011
60.0050011
60.0019989
59.9990005
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56589.89
56589.89
56581.13
56581.13
56587.69
56587.69
56605.2
56605.2
56592.78
56592.78
56586.05
56586.05
56581.38
56581.38
56576.92
56576.92
56570.9
56570.9
56585.3
56585.3
56579.29
56579.29
56575.29
56575.29
56567.7
56567.7
56566.86
56566.86
56567.8
56567.8
56565.92
56565.92
56570
56570
56565.58
56565.58
56557.96
56557.96
56538.89
56538.89
56537.92
56537.92
56544.36
56544.36
56542.68
56542.68
56554.31
56554.31
56543.29
002528
07/18/11 21:04:14
07/18/11 21:04:16
07/18/11 21:04:18
07/18/11 21:04:20
07/18/11 21:04:22
07/18/11 21:04:24
07/18/11 21:04:26
07/18/11 21:04:28
07/18/11 21:04:30
07/18/11 21:04:32
07/18/11 21:04:34
07/18/11 21:04:36
07/18/11 21:04:38
07/18/11 21:04:40
07/18/11 21:04:42
07/18/11 21:04:44
07/18/11 21:04:46
07/18/11 21:04:48
07/18/11 21:04:50
07/18/11 21:04:52
07/18/11 21:04:54
07/18/11 21:04:56
07/18/11 21:04:58
07/18/11 21:05:00
07/18/11 21:05:02
07/18/11 21:05:04
07/18/11 21:05:06
07/18/11 21:05:08
07/18/11 21:05:10
07/18/11 21:05:12
07/18/11 21:05:14
07/18/11 21:05:16
07/18/11 21:05:18
07/18/11 21:05:20
07/18/11 21:05:22
07/18/11 21:05:24
07/18/11 21:05:26
07/18/11 21:05:28
07/18/11 21:05:30
07/18/11 21:05:32
07/18/11 21:05:34
07/18/11 21:05:36
07/18/11 21:05:38
07/18/11 21:05:40
07/18/11 21:05:42
07/18/11 21:05:44
07/18/11 21:05:46
07/18/11 21:05:48
07/18/11 21:05:50
59.9959984
59.9980011
59.9990005
60.0009995
59.9990005
59.9980011
59.9980011
59.9980011
59.9970016
59.9959984
59.9949989
59.993
59.993
59.993
59.9949989
59.9949989
59.9959984
59.9949989
59.993
59.9900017
59.987999
59.9869995
59.9869995
59.9889984
59.9910011
59.993
59.9959984
59.9970016
59.9949989
59.993
59.993
59.9920006
59.9900017
59.9889984
59.987999
59.9860001
59.9850006
59.9850006
59.9850006
59.9850006
59.9830017
59.9830017
59.980999
59.9799995
59.9790001
59.9780006
59.9790001
59.9799995
59.9780006
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56543.29
56531.34
56531.34
56542.45
56542.45
56546.61
56546.61
56538.92
56538.92
56548.07
56548.07
56542.02
56542.02
56531.91
56531.91
56528.67
56528.67
56528.46
56528.46
56519.61
56519.61
56512.2
56512.2
56514.52
56514.52
56508.47
56508.47
56512.15
56512.15
56508.86
56508.86
56503.34
56503.34
56510.09
56510.09
56514.67
56514.67
56501.9
56501.9
56510.46
56510.46
56504.74
56504.74
56502.2
56502.2
56501.25
56501.25
56500.1
56500.1
002529
07/18/11 21:05:52
07/18/11 21:05:54
07/18/11 21:05:56
07/18/11 21:05:58
07/18/11 21:06:00
07/18/11 21:06:02
07/18/11 21:06:04
07/18/11 21:06:06
07/18/11 21:06:08
07/18/11 21:06:10
07/18/11 21:06:12
07/18/11 21:06:14
07/18/11 21:06:16
07/18/11 21:06:18
07/18/11 21:06:20
07/18/11 21:06:22
07/18/11 21:06:24
07/18/11 21:06:26
07/18/11 21:06:28
07/18/11 21:06:30
07/18/11 21:06:32
07/18/11 21:06:34
07/18/11 21:06:36
07/18/11 21:06:38
07/18/11 21:06:40
07/18/11 21:06:42
07/18/11 21:06:44
07/18/11 21:06:46
07/18/11 21:06:48
07/18/11 21:06:50
07/18/11 21:06:52
07/18/11 21:06:54
07/18/11 21:06:56
07/18/11 21:06:58
07/18/11 21:07:00
07/18/11 21:07:02
07/18/11 21:07:04
07/18/11 21:07:06
07/18/11 21:07:08
07/18/11 21:07:10
07/18/11 21:07:12
07/18/11 21:07:14
07/18/11 21:07:16
07/18/11 21:07:18
07/18/11 21:07:20
07/18/11 21:07:22
07/18/11 21:07:24
07/18/11 21:07:26
07/18/11 21:07:28
59.9749985
59.9770012
59.9790001
59.9790001
59.980999
59.9819984
59.9830017
59.9830017
59.9860001
59.9889984
59.9889984
59.9900017
59.9910011
59.9900017
59.9900017
59.987999
59.9869995
59.9830017
59.9819984
59.9819984
59.9819984
59.9830017
59.9840012
59.9850006
59.9850006
59.9830017
59.987999
59.9939995
59.9980011
59.9990005
60
60
60.0009995
60.0009995
60.0019989
60.0029984
60.0040016
60.0060005
60.007
60.007
60.0079994
60.0099983
60.0079994
60.0089989
60.0099983
60.0110016
60.0130005
60.0159988
60.0159988
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56492.3
56492.3
56483.54
56483.54
56486.4
56486.4
56496.68
56496.68
56489.48
56489.48
56476.55
56476.55
56484.84
56484.84
56494.26
56494.26
56478.49
56478.49
56501.87
56501.87
56491.51
56491.51
56480.03
56480.03
56464.71
56464.71
56462.37
56462.37
56457.73
56457.73
56446.26
56446.26
56446.1
56446.1
56440.1
56440.1
56440.59
56440.59
56443.3
56443.3
56446.27
56446.27
56442.77
56442.77
56442.02
56442.02
56445.78
56445.78
56438.68
002530
07/18/11 21:07:30
07/18/11 21:07:32
07/18/11 21:07:34
07/18/11 21:07:36
07/18/11 21:07:38
07/18/11 21:07:40
07/18/11 21:07:42
07/18/11 21:07:44
07/18/11 21:07:46
07/18/11 21:07:48
07/18/11 21:07:50
07/18/11 21:07:52
07/18/11 21:07:54
07/18/11 21:07:56
07/18/11 21:07:58
07/18/11 21:08:00
07/18/11 21:08:02
07/18/11 21:08:04
07/18/11 21:08:06
07/18/11 21:08:08
07/18/11 21:08:10
07/18/11 21:08:12
07/18/11 21:08:14
07/18/11 21:08:16
07/18/11 21:08:18
07/18/11 21:08:20
07/18/11 21:08:22
07/18/11 21:08:24
07/18/11 21:08:26
07/18/11 21:08:28
07/18/11 21:08:30
07/18/11 21:08:32
07/18/11 21:08:34
07/18/11 21:08:36
07/18/11 21:08:38
07/18/11 21:08:40
07/18/11 21:08:42
07/18/11 21:08:44
07/18/11 21:08:46
07/18/11 21:08:48
07/18/11 21:08:50
07/18/11 21:08:52
07/18/11 21:08:54
07/18/11 21:08:56
07/18/11 21:08:58
07/18/11 21:09:00
07/18/11 21:09:02
07/18/11 21:09:04
07/18/11 21:09:06
60.0159988
60.0110016
60.007
60.007
60.0029984
60.0029984
60.0060005
60.0079994
60.0110016
60.0110016
60.0139999
60.0139999
60.012001
60.0099983
60.0079994
60.007
60.0019989
60.0019989
59.9959984
59.9959984
59.9939995
59.9939995
59.9939995
59.9949989
59.987999
59.987999
59.9819984
59.9729996
59.9729996
59.9720001
59.9710007
59.9720001
59.9700012
59.9710007
59.9720001
59.9720001
59.9710007
59.973999
59.973999
59.973999
59.9729996
59.9729996
59.9720001
59.9720001
59.9729996
59.9729996
59.9720001
59.9720001
59.9710007
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56438.68
56446.48
56438.85
56438.85
56438.85
56433.16
56433.16
56423.06
56423.06
56413.65
56413.65
56422.53
56422.53
56406.34
56406.34
56407.22
56407.22
56415.69
56415.69
56420.6
56420.6
56412.14
56412.14
56439.41
56439.41
56449.05
56449.05
56441.32
56441.32
56451.41
56451.41
56449.05
56449.05
56444.22
56444.22
56448.8
56448.8
56431.23
56431.23
56428.9
56428.9
56428.16
56428.16
56438.3
56438.3
56429.57
56429.57
56421.97
56421.97
002531
07/18/11 21:09:08
07/18/11 21:09:10
07/18/11 21:09:12
07/18/11 21:09:14
07/18/11 21:09:16
07/18/11 21:09:18
07/18/11 21:09:20
07/18/11 21:09:22
07/18/11 21:09:24
07/18/11 21:09:26
07/18/11 21:09:28
07/18/11 21:09:30
07/18/11 21:09:32
07/18/11 21:09:34
07/18/11 21:09:36
07/18/11 21:09:38
07/18/11 21:09:40
07/18/11 21:09:42
07/18/11 21:09:44
07/18/11 21:09:46
07/18/11 21:09:48
07/18/11 21:09:50
07/18/11 21:09:52
07/18/11 21:09:54
07/18/11 21:09:56
07/18/11 21:09:58
07/18/11 21:10:00
07/18/11 21:10:02
07/18/11 21:10:04
07/18/11 21:10:06
07/18/11 21:10:08
07/18/11 21:10:10
07/18/11 21:10:12
07/18/11 21:10:14
07/18/11 21:10:16
07/18/11 21:10:18
07/18/11 21:10:20
07/18/11 21:10:22
07/18/11 21:10:24
07/18/11 21:10:26
07/18/11 21:10:28
07/18/11 21:10:30
07/18/11 21:10:32
07/18/11 21:10:34
07/18/11 21:10:36
07/18/11 21:10:38
07/18/11 21:10:40
07/18/11 21:10:42
07/18/11 21:10:44
59.9720001
59.9720001
59.9720001
59.9729996
59.973999
59.973999
59.973999
59.973999
59.973999
59.9749985
59.9760017
59.9770012
59.9780006
59.9780006
59.9770012
59.9770012
59.9760017
59.973999
59.973999
59.973999
59.973999
59.973999
59.9729996
59.9729996
59.9729996
59.9729996
59.9710007
59.9700012
59.9700012
59.9700012
59.9710007
59.9710007
59.9710007
59.9700012
59.9720001
59.9749985
59.9749985
59.9770012
59.9770012
59.9770012
59.9780006
59.9799995
59.9830017
59.9840012
59.9850006
59.9869995
59.987999
59.987999
59.987999
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56422.48
56422.48
56424.6
56424.6
56430.37
56430.37
56421.03
56421.03
56419.23
56419.23
56412.87
56412.87
56428.91
56428.91
56424.23
56424.23
56408.42
56408.42
56418.11
56418.11
56407.98
56407.98
56398.21
56398.21
56398.21
56398.21
56400.08
56400.08
56416.78
56416.78
56410.82
56410.82
56407.11
56407.11
56412.56
56412.56
56412.43
56412.43
56424.64
56424.64
56411.08
56411.08
56410.07
56410.07
56415.18
56415.18
56434.01
56434.01
56433.76
002532
07/18/11 21:10:46
07/18/11 21:10:48
07/18/11 21:10:50
07/18/11 21:10:52
07/18/11 21:10:54
07/18/11 21:10:56
07/18/11 21:10:58
07/18/11 21:11:00
07/18/11 21:11:02
07/18/11 21:11:04
07/18/11 21:11:06
07/18/11 21:11:08
07/18/11 21:11:10
07/18/11 21:11:12
07/18/11 21:11:14
07/18/11 21:11:16
07/18/11 21:11:18
07/18/11 21:11:20
07/18/11 21:11:22
07/18/11 21:11:24
07/18/11 21:11:26
07/18/11 21:11:28
07/18/11 21:11:30
07/18/11 21:11:32
07/18/11 21:11:34
07/18/11 21:11:36
07/18/11 21:11:38
07/18/11 21:11:40
07/18/11 21:11:42
07/18/11 21:11:44
07/18/11 21:11:46
07/18/11 21:11:48
07/18/11 21:11:50
07/18/11 21:11:52
07/18/11 21:11:54
07/18/11 21:11:56
07/18/11 21:11:58
07/18/11 21:12:00
07/18/11 21:12:02
07/18/11 21:12:04
07/18/11 21:12:06
07/18/11 21:12:08
07/18/11 21:12:10
07/18/11 21:12:12
07/18/11 21:12:14
07/18/11 21:12:16
07/18/11 21:12:18
07/18/11 21:12:20
07/18/11 21:12:22
59.987999
59.9889984
59.9869995
59.9850006
59.9850006
59.9850006
59.9850006
59.9850006
59.9860001
59.9869995
59.9889984
59.9920006
59.9920006
59.9920006
59.9910011
59.993
59.9939995
59.9959984
59.9970016
59.9959984
59.9949989
59.9970016
59.9970016
59.9970016
59.9990005
60.0040016
60.0159988
60.0229988
60.0279999
60.0289993
60.0270004
60.026001
60.0279999
60.0289993
60.0299988
60.0299988
60.0299988
60.0320015
60.0330009
60.0330009
60.0320015
60.0299988
60.0279999
60.026001
60.0250015
60.0239983
60.0239983
60.026001
60.0250015
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56433.76
56427.4
56427.4
56430.27
56430.27
56417.96
56417.96
56422.76
56422.76
56420.98
56420.98
56411.35
56411.35
56412.68
56412.68
56421.7
56421.7
56425.16
56425.16
56438.14
56438.14
56433.16
56433.16
56425.07
56425.07
56410.61
56410.61
56384.75
56384.75
56377.32
56377.32
56362.61
56362.61
56354.32
56354.32
56355.96
56355.96
56348.51
56348.51
56349.23
56349.23
56357.15
56357.15
56349.07
56349.07
56361.33
56361.33
56355.59
56355.59
002533
07/18/11 21:12:24
07/18/11 21:12:26
07/18/11 21:12:28
07/18/11 21:12:30
07/18/11 21:12:32
07/18/11 21:12:34
07/18/11 21:12:36
07/18/11 21:12:38
07/18/11 21:12:40
07/18/11 21:12:42
07/18/11 21:12:44
07/18/11 21:12:46
07/18/11 21:12:48
07/18/11 21:12:50
07/18/11 21:12:52
07/18/11 21:12:54
07/18/11 21:12:56
07/18/11 21:12:58
07/18/11 21:13:00
07/18/11 21:13:02
07/18/11 21:13:04
07/18/11 21:13:06
07/18/11 21:13:08
07/18/11 21:13:10
07/18/11 21:13:12
07/18/11 21:13:14
07/18/11 21:13:16
07/18/11 21:13:18
07/18/11 21:13:20
07/18/11 21:13:22
07/18/11 21:13:24
07/18/11 21:13:26
07/18/11 21:13:28
07/18/11 21:13:30
07/18/11 21:13:32
07/18/11 21:13:34
07/18/11 21:13:36
07/18/11 21:13:38
07/18/11 21:13:40
07/18/11 21:13:42
07/18/11 21:13:44
07/18/11 21:13:46
07/18/11 21:13:48
07/18/11 21:13:50
07/18/11 21:13:52
07/18/11 21:13:54
07/18/11 21:13:56
07/18/11 21:13:58
07/18/11 21:14:00
60.0250015
60.0219994
60.0200005
60.019001
60.0180016
60.0180016
60.0180016
60.0169983
60.0180016
60.019001
60.019001
60.0200005
60.0200005
60.0209999
60.0219994
60.0229988
60.0229988
60.0219994
60.0219994
60.0219994
60.0219994
60.0209999
60.0209999
60.0219994
60.0209999
60.0200005
60.019001
60.0200005
60.019001
60.0180016
60.0180016
60.019001
60.019001
60.0159988
60.0130005
60.0130005
60.0159988
60.0180016
60.0180016
60.0159988
60.0149994
60.0149994
60.0110016
60.0050011
59.9990005
59.9949989
59.9949989
59.9959984
59.9980011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56349.07
56349.07
56354.7
56354.7
56353.69
56345.6
56345.6
56345.6
56338.04
56338.04
56325.32
56325.32
56325.12
56325.12
56331.52
56331.52
56329.43
56329.43
56318.63
56318.63
56316.55
56316.55
56309.1
56309.1
56298.35
56298.35
56312.53
56312.53
56307.93
56307.93
56288.67
56288.67
56283.19
56283.19
56283.82
56283.82
56307.8
56307.8
56294.97
56294.97
56300.18
56300.18
56295.84
56295.84
56295.2
56295.2
56328.64
56328.64
56337.04
002534
07/18/11 21:14:02
07/18/11 21:14:04
07/18/11 21:14:06
07/18/11 21:14:08
07/18/11 21:14:10
07/18/11 21:14:12
07/18/11 21:14:14
07/18/11 21:14:16
07/18/11 21:14:18
07/18/11 21:14:20
07/18/11 21:14:22
07/18/11 21:14:24
07/18/11 21:14:26
07/18/11 21:14:28
07/18/11 21:14:30
07/18/11 21:14:32
07/18/11 21:14:34
07/18/11 21:14:36
07/18/11 21:14:38
07/18/11 21:14:40
07/18/11 21:14:42
07/18/11 21:14:44
07/18/11 21:14:46
07/18/11 21:14:48
07/18/11 21:14:50
07/18/11 21:14:52
07/18/11 21:14:54
07/18/11 21:14:56
07/18/11 21:14:58
07/18/11 21:15:00
07/18/11 21:15:02
07/18/11 21:15:04
07/18/11 21:15:06
07/18/11 21:15:08
07/18/11 21:15:10
07/18/11 21:15:12
07/18/11 21:15:14
07/18/11 21:15:16
07/18/11 21:15:18
07/18/11 21:15:20
07/18/11 21:15:22
07/18/11 21:15:24
07/18/11 21:15:26
07/18/11 21:15:28
07/18/11 21:15:30
07/18/11 21:15:32
07/18/11 21:15:34
07/18/11 21:15:36
07/18/11 21:15:38
59.9959984
59.9939995
59.993
59.993
59.993
59.9939995
59.9949989
59.9949989
59.9949989
59.9949989
59.9939995
59.993
59.9939995
59.9959984
59.9980011
59.9980011
59.9959984
59.9980011
59.9970016
59.9949989
59.9939995
59.9920006
59.9920006
59.9920006
59.9900017
59.9889984
59.9869995
59.9850006
59.9850006
59.9860001
59.9860001
59.987999
59.9850006
59.9850006
59.9860001
59.9860001
59.9860001
59.9830017
59.9830017
59.9830017
59.9860001
59.987999
59.9900017
59.9900017
59.9910011
59.9920006
59.993
59.9939995
59.9970016
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56337.04
56326.35
56326.35
56318.79
56318.79
56303.38
56303.38
56294.88
56294.88
56303.64
56303.64
56295.32
56295.32
56298.27
56298.27
56290.24
56290.24
56287.61
56287.61
56293.02
56293.02
56283.21
56283.21
56295.32
56295.32
56287.61
56287.61
56287.61
56287.61
56287.61
56283.21
56283.21
56283.21
56283.21
56278.5
56278.5
56278.5
56278.5
56278.5
56278.5
56262.51
56262.51
56262.51
56262.51
56262.51
56287.75
56287.75
56287.75
56287.75
002535
07/18/11 21:15:40
07/18/11 21:15:42
07/18/11 21:15:44
07/18/11 21:15:46
07/18/11 21:15:48
07/18/11 21:15:50
07/18/11 21:15:52
07/18/11 21:15:54
07/18/11 21:15:56
07/18/11 21:15:58
07/18/11 21:16:00
07/18/11 21:16:02
07/18/11 21:16:04
07/18/11 21:16:06
07/18/11 21:16:08
07/18/11 21:16:10
07/18/11 21:16:12
07/18/11 21:16:14
07/18/11 21:16:16
07/18/11 21:16:18
07/18/11 21:16:20
07/18/11 21:16:22
07/18/11 21:16:24
07/18/11 21:16:26
07/18/11 21:16:28
07/18/11 21:16:30
07/18/11 21:16:32
07/18/11 21:16:34
07/18/11 21:16:36
07/18/11 21:16:38
07/18/11 21:16:40
07/18/11 21:16:42
07/18/11 21:16:44
07/18/11 21:16:46
07/18/11 21:16:48
07/18/11 21:16:50
07/18/11 21:16:52
07/18/11 21:16:54
07/18/11 21:16:56
07/18/11 21:16:58
07/18/11 21:17:00
07/18/11 21:17:02
07/18/11 21:17:04
07/18/11 21:17:06
07/18/11 21:17:08
07/18/11 21:17:10
07/18/11 21:17:12
07/18/11 21:17:14
07/18/11 21:17:16
59.9980011
59.9990005
59.9980011
59.9980011
59.9990005
60.0019989
60.0050011
60.0050011
60.0079994
60.0089989
60.0099983
60.0099983
60.0110016
60.0089989
60.0089989
60.0110016
60.012001
60.0130005
60.0159988
60.0200005
60.0200005
60.0219994
60.0200005
60.019001
60.019001
60.019001
60.0180016
60.0169983
60.0169983
60.0169983
60.0159988
60.0159988
60.0180016
60.019001
60.0200005
60.0209999
60.0200005
60.0169983
60.0169983
60.0169983
60.012001
60.0089989
60.0050011
60.0040016
60.0029984
60.0029984
60.0029984
60.0050011
60.0050011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56287.75
56271.19
56271.19
56271.19
56271.19
56271.19
56261.12
56261.12
56261.12
56261.12
56261.12
56275.96
56275.96
56275.96
56275.96
56275.96
56310.49
56310.49
56310.49
56310.49
56310.49
56278.79
56278.79
56278.79
56278.79
56278.79
56275.11
56275.11
56275.11
56275.11
56275.11
56272.93
56272.93
56272.93
56272.93
56272.93
56255.99
56255.99
56255.99
56255.99
56255.99
56254.07
56254.07
56254.07
56254.07
56254.07
56263.52
56263.52
56263.52
002536
07/18/11 21:17:18
07/18/11 21:17:20
07/18/11 21:17:22
07/18/11 21:17:24
07/18/11 21:17:26
07/18/11 21:17:28
07/18/11 21:17:30
07/18/11 21:17:32
07/18/11 21:17:34
07/18/11 21:17:36
07/18/11 21:17:38
07/18/11 21:17:40
07/18/11 21:17:42
07/18/11 21:17:44
07/18/11 21:17:46
07/18/11 21:17:48
07/18/11 21:17:50
07/18/11 21:17:52
07/18/11 21:17:54
07/18/11 21:17:56
07/18/11 21:17:58
07/18/11 21:18:00
07/18/11 21:18:02
07/18/11 21:18:04
07/18/11 21:18:06
07/18/11 21:18:08
07/18/11 21:18:10
07/18/11 21:18:12
07/18/11 21:18:14
07/18/11 21:18:16
07/18/11 21:18:18
07/18/11 21:18:20
07/18/11 21:18:22
07/18/11 21:18:24
07/18/11 21:18:26
07/18/11 21:18:28
07/18/11 21:18:30
07/18/11 21:18:32
07/18/11 21:18:34
07/18/11 21:18:36
07/18/11 21:18:38
07/18/11 21:18:40
07/18/11 21:18:42
07/18/11 21:18:44
07/18/11 21:18:46
07/18/11 21:18:48
07/18/11 21:18:50
07/18/11 21:18:52
07/18/11 21:18:54
60.0060005
60.0019989
59.9990005
59.9980011
59.9949989
59.9910011
59.9900017
59.9889984
59.9910011
59.9910011
59.9900017
59.9920006
59.9939995
59.9949989
59.9939995
59.993
59.9949989
59.9959984
59.9990005
60.0040016
60.0060005
60.007
60.0079994
60.0089989
60.0110016
60.012001
60.0139999
60.0149994
60.0159988
60.0149994
60.0130005
60.012001
60.0110016
60.0089989
60.0099983
60.0099983
60.012001
60.0099983
60.0099983
60.0099983
60.012001
60.0139999
60.0149994
60.0149994
60.0139999
60.0159988
60.0169983
60.0180016
60.0180016
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56263.52
56263.52
56275.39
56275.39
56275.39
56275.39
56275.39
56286.62
56286.62
56286.62
56286.62
56286.62
56275.45
56275.45
56275.45
56275.45
56275.45
56259.86
56259.86
56259.86
56259.86
56259.86
56247.24
56247.24
56247.24
56247.24
56247.24
56253.61
56253.61
56253.61
56253.61
56253.61
56237
56237
56237
56237
56237
56245.64
56245.64
56245.64
56245.64
56245.64
56234.72
56234.72
56234.72
56234.72
56234.72
56222.8
56222.8
002537
07/18/11 21:18:56
07/18/11 21:18:58
07/18/11 21:19:00
07/18/11 21:19:02
07/18/11 21:19:04
07/18/11 21:19:06
07/18/11 21:19:08
07/18/11 21:19:10
07/18/11 21:19:12
07/18/11 21:19:14
07/18/11 21:19:16
07/18/11 21:19:18
07/18/11 21:19:20
07/18/11 21:19:22
07/18/11 21:19:24
07/18/11 21:19:26
07/18/11 21:19:28
07/18/11 21:19:30
07/18/11 21:19:32
07/18/11 21:19:34
07/18/11 21:19:36
07/18/11 21:19:38
07/18/11 21:19:40
07/18/11 21:19:42
07/18/11 21:19:44
07/18/11 21:19:46
07/18/11 21:19:48
07/18/11 21:19:50
07/18/11 21:19:52
07/18/11 21:19:54
07/18/11 21:19:56
07/18/11 21:19:58
07/18/11 21:20:00
07/18/11 21:20:02
07/18/11 21:20:04
07/18/11 21:20:06
07/18/11 21:20:08
07/18/11 21:20:10
07/18/11 21:20:12
07/18/11 21:20:14
07/18/11 21:20:16
07/18/11 21:20:18
07/18/11 21:20:20
07/18/11 21:20:22
07/18/11 21:20:24
07/18/11 21:20:26
07/18/11 21:20:28
07/18/11 21:20:30
07/18/11 21:20:32
60.0159988
60.0169983
60.0159988
60.0139999
60.0110016
60.0079994
60.0040016
60.0029984
60.0029984
60.0050011
60.0050011
60.0040016
60.0060005
60.0060005
60.0079994
60.0099983
60.0110016
60.012001
60.0099983
60.0060005
60.0060005
60.0029984
60.0019989
60.0009995
60.0040016
60.0060005
60.007
60.0110016
60.0130005
60.0139999
60.0159988
60.019001
60.019001
60.026001
60.0299988
60.0299988
60.0289993
60.0279999
60.026001
60.0270004
60.0309982
60.0320015
60.0320015
60.0320015
60.0279999
60.0270004
60.026001
60.026001
60.026001
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56222.8
56222.8
56222.8
56205.51
56205.51
56205.51
56205.51
56205.51
56216.17
56216.17
56216.17
56216.17
56216.17
56203.93
56203.93
56203.93
56203.93
56203.93
56200.13
56200.13
56200.13
56200.13
56200.13
56181.92
56181.92
56181.92
56181.92
56181.92
56187.34
56187.34
56187.34
56187.34
56187.34
56197.92
56197.92
56197.92
56197.92
56197.92
56200.23
56200.23
56200.23
56200.23
56200.23
56147.08
56147.08
56147.08
56147.08
56147.08
56110.36
002538
07/18/11 21:20:34
07/18/11 21:20:36
07/18/11 21:20:38
07/18/11 21:20:40
07/18/11 21:20:42
07/18/11 21:20:44
07/18/11 21:20:46
07/18/11 21:20:48
07/18/11 21:20:50
07/18/11 21:20:52
07/18/11 21:20:54
07/18/11 21:20:56
07/18/11 21:20:58
07/18/11 21:21:00
07/18/11 21:21:02
07/18/11 21:21:04
07/18/11 21:21:06
07/18/11 21:21:08
07/18/11 21:21:10
07/18/11 21:21:12
07/18/11 21:21:14
07/18/11 21:21:16
07/18/11 21:21:18
07/18/11 21:21:20
07/18/11 21:21:22
07/18/11 21:21:24
07/18/11 21:21:26
07/18/11 21:21:28
07/18/11 21:21:30
07/18/11 21:21:32
07/18/11 21:21:34
07/18/11 21:21:36
07/18/11 21:21:38
07/18/11 21:21:40
07/18/11 21:21:42
07/18/11 21:21:44
07/18/11 21:21:46
07/18/11 21:21:48
07/18/11 21:21:50
07/18/11 21:21:52
07/18/11 21:21:54
07/18/11 21:21:56
07/18/11 21:21:58
07/18/11 21:22:00
07/18/11 21:22:02
07/18/11 21:22:04
07/18/11 21:22:06
07/18/11 21:22:08
07/18/11 21:22:10
60.0270004
60.0270004
60.0289993
60.0330009
60.0299988
60.0250015
60.0229988
60.0229988
60.0209999
60.0180016
60.0180016
60.019001
60.0169983
60.0180016
60.0180016
60.0180016
60.0159988
60.0159988
60.0169983
60.0159988
60.0130005
60.012001
60.012001
60.0089989
60.007
60.0089989
60.0089989
60.0099983
60.007
60.0060005
60.007
60.007
60.0060005
60.0050011
60.0079994
60.0089989
60.0110016
60.0110016
60.0130005
60.0149994
60.0159988
60.0149994
60.0149994
60.0169983
60.0200005
60.0209999
60.0200005
60.0149994
60.0139999
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56110.36
56110.36
56110.36
56110.36
56114
56114
56114
56114
56114
56075.31
56075.31
56075.31
56075.31
56075.31
56090.18
56090.18
56090.18
56090.18
56090.18
56087.05
56087.05
56087.05
56087.05
56087.05
56077.73
56077.73
56077.73
56077.73
56077.73
56077.31
56077.31
56077.31
56077.31
56077.31
56076.29
56076.29
56076.29
56076.29
56076.29
56056.73
56056.73
56056.73
56056.73
56056.73
56049.55
56049.55
56049.55
56049.55
56049.55
002539
07/18/11 21:22:12
07/18/11 21:22:14
07/18/11 21:22:16
07/18/11 21:22:18
07/18/11 21:22:20
07/18/11 21:22:22
07/18/11 21:22:24
07/18/11 21:22:26
07/18/11 21:22:28
07/18/11 21:22:30
07/18/11 21:22:32
07/18/11 21:22:34
07/18/11 21:22:36
07/18/11 21:22:38
07/18/11 21:22:40
07/18/11 21:22:42
07/18/11 21:22:44
07/18/11 21:22:46
07/18/11 21:22:48
07/18/11 21:22:50
07/18/11 21:22:52
07/18/11 21:22:54
07/18/11 21:22:56
07/18/11 21:22:58
07/18/11 21:23:00
07/18/11 21:23:02
07/18/11 21:23:04
07/18/11 21:23:06
07/18/11 21:23:08
07/18/11 21:23:10
07/18/11 21:23:12
07/18/11 21:23:14
07/18/11 21:23:16
07/18/11 21:23:18
07/18/11 21:23:20
07/18/11 21:23:22
07/18/11 21:23:24
07/18/11 21:23:26
07/18/11 21:23:28
07/18/11 21:23:30
07/18/11 21:23:32
07/18/11 21:23:34
07/18/11 21:23:36
07/18/11 21:23:38
07/18/11 21:23:40
07/18/11 21:23:42
07/18/11 21:23:44
07/18/11 21:23:46
07/18/11 21:23:48
60.0139999
60.0149994
60.0200005
60.0229988
60.0250015
60.0250015
60.0229988
60.0239983
60.0250015
60.0239983
60.0229988
60.0219994
60.0229988
60.0219994
60.0200005
60.0219994
60.0229988
60.0239983
60.0219994
60.0200005
60.0180016
60.0169983
60.0149994
60.0159988
60.0139999
60.0149994
60.0149994
60.0139999
60.0139999
60.0149994
60.0149994
60.0130005
60.0130005
60.007
60.0060005
60.0060005
60.0050011
60.0029984
60.0029984
60.0029984
60.0040016
60.0019989
60.0029984
60.0050011
60.007
60.0079994
60.0079994
60.0060005
60.0019989
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
56016.81
56016.81
56016.81
56016.81
56016.81
56044.84
56044.84
56044.84
56044.84
56044.84
56023.8
56023.8
56023.8
56023.8
56023.8
55979.94
55979.94
55979.94
55979.94
55979.94
55950.64
55950.64
55950.64
55950.64
55950.64
55934.27
55934.27
55934.27
55934.27
55934.27
55953.24
55953.24
55953.24
55953.24
55953.24
55940.86
55940.86
55940.86
55940.86
55940.86
55935.25
55935.25
55935.25
55935.25
55935.25
55918.13
55918.13
55918.13
55918.13
002540
07/18/11 21:23:50
07/18/11 21:23:52
07/18/11 21:23:54
07/18/11 21:23:56
07/18/11 21:23:58
07/18/11 21:24:00
07/18/11 21:24:02
07/18/11 21:24:04
07/18/11 21:24:06
07/18/11 21:24:08
07/18/11 21:24:10
07/18/11 21:24:12
07/18/11 21:24:14
07/18/11 21:24:16
07/18/11 21:24:18
07/18/11 21:24:20
07/18/11 21:24:22
07/18/11 21:24:24
07/18/11 21:24:26
07/18/11 21:24:28
07/18/11 21:24:30
07/18/11 21:24:32
07/18/11 21:24:34
07/18/11 21:24:36
07/18/11 21:24:38
07/18/11 21:24:40
07/18/11 21:24:42
07/18/11 21:24:44
07/18/11 21:24:46
07/18/11 21:24:48
07/18/11 21:24:50
07/18/11 21:24:52
07/18/11 21:24:54
07/18/11 21:24:56
07/18/11 21:24:58
07/18/11 21:25:00
07/18/11 21:25:02
07/18/11 21:25:04
07/18/11 21:25:06
07/18/11 21:25:08
07/18/11 21:25:10
07/18/11 21:25:12
07/18/11 21:25:14
07/18/11 21:25:16
07/18/11 21:25:18
07/18/11 21:25:20
07/18/11 21:25:22
07/18/11 21:25:24
07/18/11 21:25:26
60.0009995
59.9980011
59.9980011
59.9990005
59.9959984
59.9949989
59.9949989
59.9949989
59.9949989
59.9920006
59.9910011
59.9910011
59.9900017
59.9869995
59.9850006
59.9830017
59.9799995
59.9790001
59.9770012
59.9770012
59.9780006
59.9790001
59.9780006
59.9770012
59.9760017
59.9749985
59.9749985
59.973999
59.9710007
59.9729996
59.973999
59.9720001
59.9690018
59.9679985
59.9679985
59.9700012
59.9690018
59.9690018
59.9729996
59.9729996
59.9729996
59.9720001
59.9729996
59.9790001
59.9799995
59.9790001
59.9780006
59.9729996
59.9720001
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
55918.13
55900.63
55900.63
55900.63
55900.63
55900.63
55903.3
55903.3
55903.3
55903.3
55903.3
55871.44
55871.44
55871.44
55871.44
55871.44
55884.49
55884.49
55884.49
55884.49
55884.49
55860.13
55860.13
55860.13
55860.13
55860.13
55848.38
55848.38
55848.38
55848.38
55848.38
55872.38
55872.38
55872.38
55872.38
55872.38
55877.86
55877.86
55877.86
55877.86
55877.86
55871.46
55871.46
55871.46
55871.46
55871.46
55864.73
55864.73
55864.73
002541
07/18/11 21:25:28
07/18/11 21:25:30
07/18/11 21:25:32
07/18/11 21:25:34
07/18/11 21:25:36
07/18/11 21:25:38
07/18/11 21:25:40
07/18/11 21:25:42
07/18/11 21:25:44
07/18/11 21:25:46
07/18/11 21:25:48
07/18/11 21:25:50
07/18/11 21:25:52
07/18/11 21:25:54
07/18/11 21:25:56
07/18/11 21:25:58
07/18/11 21:26:00
07/18/11 21:26:02
07/18/11 21:26:04
07/18/11 21:26:06
07/18/11 21:26:08
07/18/11 21:26:10
07/18/11 21:26:12
07/18/11 21:26:14
07/18/11 21:26:16
07/18/11 21:26:18
07/18/11 21:26:20
07/18/11 21:26:22
07/18/11 21:26:24
07/18/11 21:26:26
07/18/11 21:26:28
07/18/11 21:26:30
07/18/11 21:26:32
07/18/11 21:26:34
07/18/11 21:26:36
07/18/11 21:26:38
07/18/11 21:26:40
07/18/11 21:26:42
07/18/11 21:26:44
07/18/11 21:26:46
07/18/11 21:26:48
07/18/11 21:26:50
07/18/11 21:26:52
07/18/11 21:26:54
07/18/11 21:26:56
07/18/11 21:26:58
07/18/11 21:27:00
07/18/11 21:27:02
07/18/11 21:27:04
59.9710007
59.9690018
59.9690018
59.9720001
59.9780006
59.9799995
59.9780006
59.9760017
59.9780006
59.9780006
59.9780006
59.9780006
59.9790001
59.9770012
59.9760017
59.9770012
59.9780006
59.980999
59.9830017
59.9840012
59.9900017
59.9970016
60.0019989
60.0009995
59.9990005
59.9990005
59.9970016
59.9949989
59.9959984
59.9990005
60.0029984
60.0040016
60.0050011
60.0040016
60.0029984
60.0050011
60.0029984
60.0009995
60.0019989
60.0040016
60.0060005
60.0060005
60.0040016
60.0019989
60
60.0009995
60.0009995
60.0019989
60.0029984
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
55864.73
55864.73
55853.1
55853.1
55853.1
55853.1
55853.1
55855.3
55855.3
55855.3
55855.3
55855.3
55868.67
55868.67
55868.67
55868.67
55868.67
55869.83
55869.83
55869.83
55869.83
55869.83
55854.58
55854.58
55854.58
55854.58
55854.58
55854.92
55854.92
55854.92
55854.92
55854.92
55820.89
55820.89
55820.89
55820.89
55820.89
55845.93
55845.93
55845.93
55845.93
55845.93
55841.34
55841.34
55841.34
55841.34
55841.34
55830.95
55830.95
002542
07/18/11 21:27:06
07/18/11 21:27:08
07/18/11 21:27:10
07/18/11 21:27:12
07/18/11 21:27:14
07/18/11 21:27:16
07/18/11 21:27:18
07/18/11 21:27:20
07/18/11 21:27:22
07/18/11 21:27:24
07/18/11 21:27:26
07/18/11 21:27:28
07/18/11 21:27:30
07/18/11 21:27:32
07/18/11 21:27:34
07/18/11 21:27:36
07/18/11 21:27:38
07/18/11 21:27:40
07/18/11 21:27:42
07/18/11 21:27:44
07/18/11 21:27:46
07/18/11 21:27:48
07/18/11 21:27:50
07/18/11 21:27:52
07/18/11 21:27:54
07/18/11 21:27:56
07/18/11 21:27:58
07/18/11 21:28:00
07/18/11 21:28:02
07/18/11 21:28:04
07/18/11 21:28:06
07/18/11 21:28:08
07/18/11 21:28:10
07/18/11 21:28:12
07/18/11 21:28:14
07/18/11 21:28:16
07/18/11 21:28:18
07/18/11 21:28:20
07/18/11 21:28:22
07/18/11 21:28:24
07/18/11 21:28:26
07/18/11 21:28:28
07/18/11 21:28:30
07/18/11 21:28:32
07/18/11 21:28:34
07/18/11 21:28:36
07/18/11 21:28:38
07/18/11 21:28:40
07/18/11 21:28:42
60.0040016
60.007
60.0079994
60.0099983
60.0099983
60.0099983
60.0110016
60.0130005
60.0149994
60.0169983
60.019001
60.019001
60.0159988
60.0139999
60.0139999
60.0130005
60.0110016
60.0110016
60.012001
60.0130005
60.0149994
60.0149994
60.0130005
60.0130005
60.012001
60.0089989
60.0079994
60.007
60.007
60.0079994
60.0110016
60.0110016
60.0099983
60.0099983
60.0079994
60.0060005
60.0050011
60.0029984
60
59.9980011
60
59.9990005
59.9959984
59.987999
59.9840012
59.9780006
59.9760017
59.973999
59.973999
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
55830.95
55830.95
55830.95
55816.52
55816.52
55816.52
55816.52
55816.52
55811.95
55811.95
55811.95
55811.95
55811.95
55818.78
55818.78
55818.78
55818.78
55818.78
55815.84
55815.84
55815.84
55815.84
55815.84
55787.84
55787.84
55787.84
55787.84
55787.84
55782.08
55782.08
55782.08
55782.08
55782.08
55755.67
55755.67
55755.67
55755.67
55755.67
55761.66
55761.66
55761.66
55761.66
55761.66
55733.11
55733.11
55733.11
55733.11
55733.11
55732.93
002543
07/18/11 21:28:44
07/18/11 21:28:46
07/18/11 21:28:48
07/18/11 21:28:50
07/18/11 21:28:52
07/18/11 21:28:54
07/18/11 21:28:56
07/18/11 21:28:58
07/18/11 21:29:00
07/18/11 21:29:02
07/18/11 21:29:04
07/18/11 21:29:06
07/18/11 21:29:08
07/18/11 21:29:10
07/18/11 21:29:12
07/18/11 21:29:14
07/18/11 21:29:16
07/18/11 21:29:18
07/18/11 21:29:20
07/18/11 21:29:22
07/18/11 21:29:24
07/18/11 21:29:26
07/18/11 21:29:28
07/18/11 21:29:30
07/18/11 21:29:32
07/18/11 21:29:34
07/18/11 21:29:36
07/18/11 21:29:38
07/18/11 21:29:40
07/18/11 21:29:42
07/18/11 21:29:44
07/18/11 21:29:46
07/18/11 21:29:48
07/18/11 21:29:50
07/18/11 21:29:52
07/18/11 21:29:54
07/18/11 21:29:56
07/18/11 21:29:58
07/18/11 21:30:00
07/18/11 21:30:02
07/18/11 21:30:04
07/18/11 21:30:06
07/18/11 21:30:08
07/18/11 21:30:10
07/18/11 21:30:12
07/18/11 21:30:14
07/18/11 21:30:16
07/18/11 21:30:18
07/18/11 21:30:20
59.9760017
59.973999
59.9799995
59.9860001
59.9889984
59.9889984
59.987999
59.987999
59.9830017
59.9799995
59.9819984
59.9840012
59.9840012
59.980999
59.9799995
59.9790001
59.980999
59.9830017
59.9819984
59.980999
59.9850006
59.9920006
59.9920006
59.9889984
59.9860001
59.9860001
59.9850006
59.9840012
59.9830017
59.9869995
59.987999
59.987999
59.9869995
59.9850006
59.9860001
59.9860001
59.9900017
59.9910011
59.9910011
59.9910011
59.9920006
59.9980011
60.0009995
60.0019989
60.0009995
60.0009995
60.0009995
60.0009995
60.0009995
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
55732.93
55732.93
55732.93
55732.93
55742.22
55742.22
55742.22
55742.22
55742.22
55721.28
55721.28
55721.28
55721.28
55721.28
55691.09
55691.09
55691.09
55691.09
55691.09
55699.67
55699.67
55699.67
55699.67
55699.67
55679.72
55679.72
55679.72
55679.72
55679.72
55654.98
55654.98
55654.98
55654.98
55654.98
55649.36
55649.36
55649.36
55649.36
55649.36
55652
55652
55652
55652
55656.61
55656.61
55656.61
55656.61
55656.61
55656.61
002544
07/18/11 21:30:22
07/18/11 21:30:24
07/18/11 21:30:26
07/18/11 21:30:28
07/18/11 21:30:30
07/18/11 21:30:32
07/18/11 21:30:34
07/18/11 21:30:36
07/18/11 21:30:38
07/18/11 21:30:40
07/18/11 21:30:42
07/18/11 21:30:44
07/18/11 21:30:46
07/18/11 21:30:48
07/18/11 21:30:50
07/18/11 21:30:52
07/18/11 21:30:54
07/18/11 21:30:56
07/18/11 21:30:58
07/18/11 21:31:00
07/18/11 21:31:02
07/18/11 21:31:04
07/18/11 21:31:06
07/18/11 21:31:08
07/18/11 21:31:10
07/18/11 21:31:12
07/18/11 21:31:14
07/18/11 21:31:16
07/18/11 21:31:18
07/18/11 21:31:20
07/18/11 21:31:22
07/18/11 21:31:24
07/18/11 21:31:26
07/18/11 21:31:28
07/18/11 21:31:30
07/18/11 21:31:32
07/18/11 21:31:34
07/18/11 21:31:36
07/18/11 21:31:38
07/18/11 21:31:40
07/18/11 21:31:42
07/18/11 21:31:44
07/18/11 21:31:46
07/18/11 21:31:48
07/18/11 21:31:50
07/18/11 21:31:52
07/18/11 21:31:54
07/18/11 21:31:56
07/18/11 21:31:58
60
60
59.9980011
59.9980011
59.9980011
60.0130005
60.0130005
60.0219994
60.0209999
60.0209999
60.012001
60.012001
60.0130005
60.0169983
60.0169983
60.0180016
60.0200005
60.0219994
60.0229988
60.0229988
60.0229988
60.0219994
60.0219994
60.019001
60.0180016
60.0169983
60.0149994
60.0159988
60.0169983
60.0180016
60.0200005
60.0209999
60.0200005
60.0180016
60.0159988
60.0159988
60.0200005
60.0219994
60.0209999
60.0200005
60.019001
60.019001
60.0180016
60.0149994
60.0200005
60.0200005
60.019001
60.0169983
60.0159988
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
55639.16
55639.16
55639.16
55639.16
55639.16
55612.98
55612.98
55612.98
55612.98
55612.98
55610.47
55610.47
55610.47
55610.47
55610.47
55625.66
55625.66
55625.66
55625.66
55625.66
55610.65
55610.65
55610.65
55610.65
55610.65
55615.12
55615.12
55615.12
55615.12
55615.12
55608.63
55608.63
55608.63
55608.63
55608.63
55575.73
55575.73
55575.73
55575.73
55575.73
55553.67
55553.67
55553.67
55553.67
55553.67
55547.63
55547.63
55547.63
55547.63
002545
07/18/11 21:32:00
07/18/11 21:32:02
07/18/11 21:32:04
07/18/11 21:32:06
07/18/11 21:32:08
07/18/11 21:32:10
07/18/11 21:32:12
07/18/11 21:32:14
07/18/11 21:32:16
07/18/11 21:32:18
07/18/11 21:32:20
07/18/11 21:32:22
07/18/11 21:32:24
07/18/11 21:32:26
07/18/11 21:32:28
07/18/11 21:32:30
07/18/11 21:32:32
07/18/11 21:32:34
07/18/11 21:32:36
07/18/11 21:32:38
07/18/11 21:32:40
07/18/11 21:32:42
07/18/11 21:32:44
07/18/11 21:32:46
07/18/11 21:32:48
07/18/11 21:32:50
07/18/11 21:32:52
07/18/11 21:32:54
07/18/11 21:32:56
07/18/11 21:32:58
07/18/11 21:33:00
07/18/11 21:33:02
07/18/11 21:33:04
07/18/11 21:33:06
07/18/11 21:33:08
07/18/11 21:33:10
07/18/11 21:33:12
07/18/11 21:33:14
07/18/11 21:33:16
07/18/11 21:33:18
07/18/11 21:33:20
07/18/11 21:33:22
07/18/11 21:33:24
07/18/11 21:33:26
07/18/11 21:33:28
07/18/11 21:33:30
07/18/11 21:33:32
07/18/11 21:33:34
07/18/11 21:33:36
60.0169983
60.0149994
60.012001
60.0110016
60.0089989
60.0079994
60.0089989
60.0099983
60.0089989
60.0079994
60.007
60.0060005
60.0040016
60.0050011
60.0050011
60.0060005
60.007
60.007
60.0089989
60.012001
60.0149994
60.0159988
60.0159988
60.0159988
60.0169983
60.019001
60.0180016
60.0149994
60.012001
60.0130005
60.0149994
60.0149994
60.0149994
60.0139999
60.0139999
60.0149994
60.0139999
60.0139999
60.0130005
60.0130005
60.012001
60.0110016
60.012001
60.0130005
60.0130005
60.0130005
60.0130005
60.012001
60.0139999
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
55547.63
55537.41
55537.41
55537.41
55537.41
55537.41
55530.02
55530.02
55530.02
55530.02
55530.02
55517.34
55517.34
55517.34
55517.34
55517.34
55523.41
55523.41
55523.41
55523.41
55523.41
55494.25
55494.25
55494.25
55494.25
55494.25
55513.87
55513.87
55513.87
55513.87
55513.87
55492.56
55492.56
55492.56
55492.56
55492.56
55486.4
55486.4
55486.4
55486.4
55486.4
55473.25
55473.25
55473.25
55473.25
55473.25
55456.91
55456.91
55456.91
002546
07/18/11 21:33:38
07/18/11 21:33:40
07/18/11 21:33:42
07/18/11 21:33:44
07/18/11 21:33:46
07/18/11 21:33:48
07/18/11 21:33:50
07/18/11 21:33:52
07/18/11 21:33:54
07/18/11 21:33:56
07/18/11 21:33:58
07/18/11 21:34:00
07/18/11 21:34:02
07/18/11 21:34:04
07/18/11 21:34:06
07/18/11 21:34:08
07/18/11 21:34:10
07/18/11 21:34:12
07/18/11 21:34:14
07/18/11 21:34:16
07/18/11 21:34:18
07/18/11 21:34:20
07/18/11 21:34:22
07/18/11 21:34:24
07/18/11 21:34:26
07/18/11 21:34:28
07/18/11 21:34:30
07/18/11 21:34:32
07/18/11 21:34:34
07/18/11 21:34:36
07/18/11 21:34:38
07/18/11 21:34:40
07/18/11 21:34:42
07/18/11 21:34:44
07/18/11 21:34:46
07/18/11 21:34:48
07/18/11 21:34:50
07/18/11 21:34:52
07/18/11 21:34:54
07/18/11 21:34:56
07/18/11 21:34:58
07/18/11 21:35:00
60.0130005
60.0139999
60.0149994
60.0159988
60.0159988
60.0169983
60.0169983
60.0159988
60.0169983
60.0139999
60.0110016
60.0110016
60.0089989
60.0089989
60.0079994
60.0079994
60.0099983
60.0110016
60.0130005
60.0159988
60.0159988
60.0149994
60.0159988
60.0139999
60.0130005
60.0110016
60.0110016
60.0110016
60.012001
60.0110016
60.012001
60.0130005
60.0149994
60.0139999
60.0130005
60.0089989
60.0079994
60.0079994
60.0079994
60.0050011
60.0040016
60.0050011
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
55456.91
55456.91
55459.34
55459.34
55459.34
55459.34
55459.34
55426.86
55426.86
55426.86
55426.86
55426.86
55430.13
55430.13
55430.13
55430.13
55430.13
55394.64
55394.64
55394.64
55394.64
55394.64
55386.95
55386.95
55386.95
55386.95
55386.95
55390.64
55390.64
55390.64
55390.64
55390.64
55376.88
55376.88
55376.88
55376.88
55376.88
55370.14
55370.14
55370.14
55370.14
55370.14
002547
Balancing Authority Name: ERCOT
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-286
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 4. worksheet.
20:50:40
20:54:00
Event Frequency Data
60.1
60.05
60
59.95
Copy Data for Pasting
into Form 1
59.9
59.85
59.8
20:35:00
20:37:00
20:39:00
20:41:00
20:43:00
20:45:00
20:47:00
20:49:00
20:51:00
20:53:00
20:55:00
20:57:00
20:59:00
21:01:00
21:03:00
21:05:00
21:07:00
21:09:00
21:11:00
21:13:00
21:15:00
21:17:00
21:19:00
21:21:00
21:23:00
21:25:00
21:27:00
21:29:00
21:31:00
21:33:00
21:35:00
59.75
Step 5. Paste data into FRS Form 1 in the appropriate row on the "BA Event Data" worksheet.
Step 6. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
11/07/18 Date yymmdd
20:50 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
Frequency Hz
002548
60.10
60.08
60.06
596.1496277 Total MW Lost
0
596.14
Monday, July 18, 2011
NCLR Tripped or non-conforming load change
0
MW Net Loss to Grid
60.04
60.00
59.98
FR @ Value C
A Value 60.0084
FPointA
-200
-418.7 MW/0.1 Hz
60.0070
59.96
-400
Frequency - Hz
59.94
59.92
59.90
-600
59.88
59.86
59.84
B Value
59.82
C Value
59.80
59.8660
59.78
59.76
59.74
59.72
59.70
Hz
-800
MW/0.1 Hz
59.8751 -448.212 FR @ Value B 12 to 24
59.8799 -463.988 FR @ Value B 18 to 30
59.8807 -465.091 FR @ Value B 20 to 40
-1000
59.8804 -466.087 FR @ Value B 18 to 52
TZERO
Frequency Hz
Value B 12 to 24 sec
Value B 20 to 40 sec
Interconnection Primary Frequency Response
FR B 12 to 24 sec
FR B 20 to 40 sec
IPFR = Interconnection Primary Frequency Response
59.8807 -467.012 FR @ Value B 20 to 52
-1200
Value B 20 to 52 sec Average Frequency
Value B 18 to 30 sec
Value B 18 to 52 sec
FR B 20 to 52 sec Average MW
FR B 18 to 30 sec
FR B 18 to 52 sec
MW/0.1 Hz Primary Frequency Response
60.02
002549
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
60.012
60.01
60.01
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8807
-0.128
596.15
0.00
-596.15
5.55
-23.95
341.18
365.13
Balancing Authority
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR(Final)
370.68 MW
Initial Response P.U. Performance
1.651 P.U.
Total
Generation
Lost
MW
593.300
593.300
593.300
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
0.00
521.77
312.99
602.70
-625.58
0:03:20
Yes
544.65
22.88
Yes
No
No
-80.93
-602.70
Down
ERCOT
60.000 Hz
8580.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-286 MW/0.1 Hz
1 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
No Evaluation P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-34.323
-28.595
-28.595
(TC)
Delayed
Delivery
Frequency
Response
-34.323
-28.595
-28.595
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
596.150
002550
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
60.011
60.011
60.01
60.011
60.011
60.012
60.012
60.011
60.012
60.013
60.015
60.016
60.015
60.014
60.013
60.012
60.012
60.012
60.013
60.015
60.017
60.017
60.014
60.015
60.013
60.012
60.011
60.008
60.008
60.007
60.007
60.007
60.007
59.989
59.918
59.918
59.88
59.872
59.866
59.867
59.868
59.874
59.876
59.878
59.88
59.883
593.300
593.300
593.300
593.300
593.300
593.300
593.300
585.628
585.628
586.143
586.143
586.795
586.795
585.947
585.947
585.672
585.672
585.116
585.116
584.655
584.655
585.307
585.307
585.211
585.211
585.918
585.918
593.278
593.278
602.701
602.701
602.701
602.701
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
59.881
59.881
59.881
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
-31.465
-31.465
-28.595
-31.465
-31.465
-34.323
-34.323
-31.465
-34.323
-37.181
-42.898
-45.757
-42.898
-40.040
-37.181
-34.323
-34.323
-34.323
-37.181
-42.898
-48.615
-48.615
-40.040
-42.898
-37.181
-34.323
-31.465
-22.878
-22.878
-20.020
-20.020
-20.020
-20.020
31.465
234.522
234.522
343.197
366.075
383.237
380.378
377.520
360.358
354.642
348.925
343.197
334.622
-31.465
-31.465
-28.595
-31.465
-31.465
-34.323
-34.323
-31.465
-34.323
-37.181
-42.898
-45.757
-42.898
-40.040
-37.181
-34.323
-34.323
-34.323
-37.181
-42.898
-48.615
-48.615
-40.040
-42.898
-37.181
-34.323
-31.465
-22.878
-22.878
-20.020
-20.020
-20.020
-20.020
31.465
234.522
234.522
343.197
366.075
383.237
380.378
377.520
360.358
354.642
348.925
343.197
334.622
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
-0.070
966.830
966.830
966.830
0.000
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
593.300
593.230
590.301
590.230
593.018
590.089
587.160
581.373
578.444
581.232
584.020
586.808
589.596
589.526
589.455
586.526
580.739
574.952
574.881
583.386
580.457
586.103
588.891
591.679
600.195
600.125
602.913
602.842
602.772
602.701
654.186
850.987
844.732
947.151
963.773
974.679
965.565
956.451
933.034
921.061
909.088
897.105
882.274
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
752.587
783.302
824.264
852.166
872.585
885.868
894.690
898.951
901.162
901.882
901.484
900.007
622.651
616.395
610.139
603.883
597.628
591.372
585.116
578.860
572.605
566.349
560.093
553.837
622.651
619.523
616.395
613.267
610.139
607.011
603.883
600.756
597.628
594.500
591.372
588.244
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002551
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
20:52:02
20:52:04
20:52:06
20:52:08
20:52:10
20:52:12
20:52:14
20:52:16
20:52:18
20:52:20
20:52:22
20:52:24
20:52:26
20:52:28
20:52:30
20:52:32
20:52:34
59.881
59.88
59.881
59.881
59.88
59.878
59.88
59.88
59.88
59.882
59.883
59.882
59.883
59.88
59.881
59.884
59.892
59.894
59.896
59.9
59.902
59.904
59.903
59.902
59.903
59.902
59.901
59.9
59.901
59.904
59.907
59.91
59.913
59.916
59.916
59.919
59.922
59.924
59.924
59.924
59.925
59.928
59.929
59.932
59.934
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
340.339
343.197
340.339
340.339
343.197
348.925
343.197
343.197
343.197
337.480
334.622
337.480
334.622
343.197
340.339
331.763
308.885
303.157
297.440
285.996
280.279
274.562
277.420
280.279
277.420
280.279
283.137
285.996
283.137
274.562
265.976
257.400
248.825
240.239
240.239
231.664
223.077
217.361
217.361
217.361
214.502
205.916
203.058
194.482
188.765
340.339
343.197
340.339
340.339
343.197
348.925
343.197
343.197
343.197
337.480
334.622
337.480
334.622
343.197
340.339
331.763
308.885
303.157
297.440
285.996
280.279
274.562
277.420
280.279
277.420
280.279
283.137
285.996
283.137
274.562
265.976
257.400
248.825
240.239
240.239
231.664
223.077
217.361
217.361
217.361
214.502
205.916
203.058
194.482
188.765
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
966.830
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
881.735
878.338
869.223
862.968
859.570
859.042
847.059
840.803
834.547
822.575
813.460
810.063
800.949
803.268
794.154
779.323
750.189
738.206
726.233
708.533
696.560
684.587
681.190
677.793
668.679
665.281
661.884
658.487
649.372
634.541
619.699
604.868
590.037
575.195
568.940
554.109
539.267
527.294
521.038
514.782
505.668
490.826
481.712
466.881
454.908
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
898.701
897.344
895.586
893.668
891.773
890.051
887.901
885.658
883.335
880.693
877.892
875.179
872.324
869.766
867.066
864.040
860.245
856.308
852.243
847.889
843.438
838.899
834.518
830.283
826.030
821.908
817.907
814.019
810.099
806.016
801.782
797.406
792.898
788.266
783.697
779.011
774.216
769.375
764.599
759.885
755.178
750.371
745.574
740.684
735.757
547.582
541.326
535.070
528.814
522.559
516.303
510.047
503.791
497.536
491.280
485.024
478.768
472.513
466.257
460.001
453.745
447.490
441.234
434.978
428.722
422.467
416.211
409.955
403.699
397.443
391.188
384.932
378.676
372.420
366.165
359.909
353.653
347.397
341.142
334.886
328.630
322.374
316.119
309.863
303.607
297.351
291.096
284.840
278.584
272.328
585.116
581.988
578.860
575.733
572.605
569.477
566.349
563.221
560.093
556.965
553.837
550.709
547.582
544.454
541.326
538.198
535.070
531.942
528.814
525.686
522.559
519.431
516.303
513.175
510.047
506.919
503.791
500.663
497.536
494.408
491.280
488.152
485.024
481.896
478.768
475.640
472.513
469.385
466.257
463.129
460.001
456.873
453.745
450.617
447.490
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002552
20:52:36
20:52:38
20:52:40
20:52:42
20:52:44
20:52:46
20:52:48
20:52:50
20:52:52
20:52:54
20:52:56
20:52:58
20:53:00
20:53:02
20:53:04
20:53:06
20:53:08
20:53:10
20:53:12
20:53:14
20:53:16
20:53:18
20:53:20
20:53:22
20:53:24
20:53:26
20:53:28
20:53:30
20:53:32
20:53:34
20:53:36
20:53:38
20:53:40
20:53:42
20:53:44
20:53:46
20:53:48
20:53:50
20:53:52
20:53:54
20:53:56
20:53:58
20:54:00
20:54:02
20:54:04
20:54:06
59.935
59.935
59.935
59.935
59.934
59.935
59.938
59.941
59.943
59.948
59.951
59.951
59.953
59.956
59.958
59.958
59.959
59.958
59.958
59.958
59.96
59.962
59.965
59.967
59.97
59.971
59.973
59.971
59.971
59.972
59.974
59.975
59.977
59.979
59.981
59.982
59.984
59.986
59.989
59.991
59.993
59.996
59.999
60.002
60.005
60.005
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
185.896
185.896
185.896
185.896
188.765
185.896
177.321
168.735
163.018
148.715
140.139
140.139
134.423
125.836
120.119
120.119
117.261
120.119
120.119
120.119
114.403
108.675
100.100
94.383
85.797
82.938
77.221
82.938
82.938
80.080
74.363
71.504
65.777
60.060
54.343
51.484
45.757
40.040
31.465
25.737
20.020
11.445
2.858
-5.717
-14.303
-14.303
185.896
185.896
185.896
185.896
188.765
185.896
177.321
168.735
163.018
148.715
140.139
140.139
134.423
125.836
120.119
120.119
117.261
120.119
120.119
120.119
114.403
108.675
100.100
94.383
85.797
82.938
77.221
82.938
82.938
80.080
74.363
71.504
65.777
60.060
54.343
51.484
45.757
40.040
31.465
25.737
20.020
11.445
2.858
-5.717
-14.303
-14.303
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
-6.256
0.000
0.000
0.000
445.783
439.528
433.272
427.016
423.630
414.505
399.674
384.832
372.859
352.300
337.469
331.213
319.241
304.399
292.426
286.170
277.056
273.659
267.403
261.147
249.175
237.191
222.360
210.388
195.546
186.432
174.459
173.920
167.664
158.550
146.577
137.463
125.480
113.507
101.535
92.420
80.437
68.464
53.633
41.650
29.677
14.846
0.004
-8.571
-17.157
-17.157
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
730.842
725.987
721.189
716.444
711.796
707.151
702.420
697.609
692.762
687.755
682.678
677.657
672.609
667.495
662.357
657.274
652.204
647.223
642.290
637.404
632.490
627.548
622.546
617.520
612.436
607.364
602.271
597.290
592.352
587.423
582.469
577.525
572.557
567.568
562.556
557.555
552.533
547.490
542.399
537.289
532.162
526.989
521.771
516.572
511.390
506.308
266.073
259.817
253.561
247.305
241.050
234.794
228.538
222.282
216.027
209.771
203.515
197.259
191.004
184.748
178.492
172.236
165.981
159.725
153.469
147.213
140.957
134.702
128.446
122.190
115.934
109.679
103.423
97.167
90.911
84.656
78.400
72.144
65.888
59.633
53.377
47.121
40.865
34.610
28.354
22.098
15.842
9.587
3.331
3.331
3.331
3.331
444.362
441.234
438.106
434.978
431.850
428.722
425.594
422.467
419.339
416.211
413.083
409.955
406.827
403.699
400.571
397.443
394.316
391.188
388.060
384.932
381.804
378.676
375.548
372.420
369.293
366.165
363.037
359.909
356.781
353.653
350.525
347.397
344.270
341.142
338.014
334.886
331.758
328.630
325.502
322.374
319.247
316.119
312.991
309.925
306.919
303.972
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002553
20:54:08
20:54:10
20:54:12
20:54:14
20:54:16
20:54:18
20:54:20
20:54:22
20:54:24
20:54:26
20:54:28
20:54:30
20:54:32
20:54:34
20:54:36
20:54:38
20:54:40
20:54:42
20:54:44
20:54:46
20:54:48
20:54:50
20:54:52
20:54:54
20:54:56
20:54:58
20:55:00
20:55:02
20:55:04
20:55:06
20:55:08
20:55:10
20:55:12
20:55:14
20:55:16
20:55:18
20:55:20
20:55:22
20:55:24
20:55:26
20:55:28
20:55:30
20:55:32
20:55:34
20:55:36
20:55:38
60.009
60.01
60.011
60.012
60.011
60.013
60.014
60.017
60.021
60.023
60.024
60.025
60.026
60.026
60.028
60.029
60.029
60.03
60.032
60.033
60.033
60.031
60.029
60.03
60.031
60.031
60.032
60.033
60.033
60.033
60.032
60.03
60.033
60.034
60.035
60.037
60.039
60.038
60.046
60.052
60.051
60.05
60.051
60.049
60.05
60.051
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-25.737
-28.595
-31.465
-34.323
-31.465
-37.181
-40.040
-48.615
-60.060
-65.777
-68.635
-71.504
-74.363
-74.363
-80.080
-82.938
-82.938
-85.797
-91.524
-94.383
-94.383
-88.655
-82.938
-85.797
-88.655
-88.655
-91.524
-94.383
-94.383
-94.383
-91.524
-85.797
-94.383
-97.241
-100.100
-105.816
-111.544
-108.675
-131.564
-148.715
-145.856
-142.998
-145.856
-140.139
-142.998
-145.856
-25.737
-28.595
-31.465
-34.323
-31.465
-37.181
-40.040
-48.615
-60.060
-65.777
-68.635
-71.504
-74.363
-74.363
-80.080
-82.938
-82.938
-85.797
-91.524
-94.383
-94.383
-88.655
-82.938
-85.797
-88.655
-88.655
-91.524
-94.383
-94.383
-94.383
-91.524
-85.797
-94.383
-97.241
-100.100
-105.816
-111.544
-108.675
-131.564
-148.715
-145.856
-142.998
-145.856
-140.139
-142.998
-145.856
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-28.591
-31.450
-34.319
-37.177
-34.319
-40.036
-42.894
-51.470
-62.914
-68.631
-71.489
-74.359
-77.217
-77.217
-82.934
-85.793
-85.793
-88.651
-94.379
-97.237
-97.237
-91.509
-85.793
-88.651
-91.509
-91.509
-94.379
-97.237
-97.237
-97.237
-94.379
-88.651
-97.237
-100.096
-102.954
-108.671
-114.399
-111.529
-134.419
-151.569
-148.711
-145.852
-148.711
-142.994
-145.852
-148.711
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
501.213
496.188
491.230
486.338
481.561
476.819
472.137
467.462
462.768
458.107
453.502
448.951
444.454
440.033
435.638
431.293
427.020
422.793
418.588
414.428
410.335
406.352
402.477
398.640
394.841
391.099
387.393
383.722
380.106
376.543
373.055
369.660
366.252
362.873
359.522
356.177
352.840
349.570
346.185
342.729
339.339
336.016
332.719
329.504
326.314
323.147
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
301.081
298.245
295.463
292.733
290.053
287.423
284.840
282.304
279.813
277.366
274.962
272.600
270.279
267.997
265.755
263.549
261.381
259.248
257.150
255.087
253.057
251.059
249.093
247.158
245.253
243.377
241.531
239.712
237.922
236.158
234.420
232.709
231.022
229.360
227.722
226.108
224.517
222.948
221.401
219.876
218.372
216.889
215.427
213.984
212.561
211.156
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002554
20:55:40
20:55:42
20:55:44
20:55:46
20:55:48
20:55:50
20:55:52
20:55:54
20:55:56
20:55:58
20:56:00
20:56:02
20:56:04
20:56:06
20:56:08
20:56:10
20:56:12
20:56:14
20:56:16
20:56:18
20:56:20
20:56:22
20:56:24
20:56:26
20:56:28
20:56:30
20:56:32
20:56:34
20:56:36
20:56:38
20:56:40
20:56:42
20:56:44
20:56:46
20:56:48
20:56:50
20:56:52
20:56:54
20:56:56
20:56:58
20:57:00
20:57:02
20:57:04
20:57:06
20:57:08
20:57:10
60.049
60.048
60.046
60.046
60.042
60.044
60.045
60.045
60.045
60.045
60.045
60.046
60.046
60.045
60.046
60.044
60.046
60.046
60.046
60.047
60.047
60.048
60.05
60.052
60.052
60.049
60.048
60.049
60.051
60.05
60.049
60.048
60.046
60.044
60.043
60.045
60.044
60.04
60.038
60.036
60.035
60.031
60.03
60.03
60.032
60.033
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-140.139
-137.281
-131.564
-131.564
-120.119
-125.836
-128.695
-128.695
-128.695
-128.695
-128.695
-131.564
-131.564
-128.695
-131.564
-125.836
-131.564
-131.564
-131.564
-134.423
-134.423
-137.281
-142.998
-148.715
-148.715
-140.139
-137.281
-140.139
-145.856
-142.998
-140.139
-137.281
-131.564
-125.836
-122.978
-128.695
-125.836
-114.403
-108.675
-102.958
-100.100
-88.655
-85.797
-85.797
-91.524
-94.383
-140.139
-137.281
-131.564
-131.564
-120.119
-125.836
-128.695
-128.695
-128.695
-128.695
-128.695
-131.564
-131.564
-128.695
-131.564
-125.836
-131.564
-131.564
-131.564
-134.423
-134.423
-137.281
-142.998
-148.715
-148.715
-140.139
-137.281
-140.139
-145.856
-142.998
-140.139
-137.281
-131.564
-125.836
-122.978
-128.695
-125.836
-114.403
-108.675
-102.958
-100.100
-88.655
-85.797
-85.797
-91.524
-94.383
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-142.994
-140.135
-134.419
-134.419
-122.974
-128.691
-131.549
-131.549
-131.549
-131.549
-131.549
-134.419
-134.419
-131.549
-134.419
-128.691
-134.419
-134.419
-134.419
-137.277
-137.277
-140.135
-145.852
-151.569
-151.569
-142.994
-140.135
-142.994
-148.711
-145.852
-142.994
-140.135
-134.419
-128.691
-125.832
-131.549
-128.691
-117.257
-111.529
-105.812
-102.954
-91.509
-88.651
-88.651
-94.379
-97.237
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
320.060
317.033
314.082
311.170
308.369
305.567
302.783
300.034
297.320
294.639
291.992
289.360
286.760
284.209
281.672
279.200
276.723
274.276
271.858
269.451
267.073
264.705
262.332
259.953
257.602
255.326
253.091
250.866
248.634
246.442
244.291
242.178
240.121
238.116
236.149
234.172
232.232
230.373
228.564
226.804
225.077
223.428
221.811
220.211
218.598
216.986
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
209.771
208.404
207.054
205.723
204.409
203.111
201.831
200.566
199.318
198.086
196.868
195.666
194.479
193.306
192.148
191.004
189.873
188.756
187.652
186.562
185.484
184.419
183.366
182.325
181.296
180.279
179.274
178.280
177.297
176.325
175.364
174.414
173.474
172.544
171.624
170.715
169.815
168.924
168.044
167.172
166.310
165.456
164.612
163.776
162.949
162.131
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002555
20:57:12
20:57:14
20:57:16
20:57:18
20:57:20
20:57:22
20:57:24
20:57:26
20:57:28
20:57:30
20:57:32
20:57:34
20:57:36
20:57:38
20:57:40
20:57:42
20:57:44
20:57:46
20:57:48
20:57:50
20:57:52
20:57:54
20:57:56
20:57:58
20:58:00
20:58:02
20:58:04
20:58:06
20:58:08
20:58:10
20:58:12
20:58:14
20:58:16
20:58:18
20:58:20
20:58:22
20:58:24
20:58:26
20:58:28
20:58:30
20:58:32
20:58:34
20:58:36
20:58:38
20:58:40
20:58:42
60.033
60.032
60.035
60.038
60.039
60.038
60.039
60.04
60.04
60.039
60.039
60.038
60.037
60.035
60.034
60.034
60.034
60.036
60.034
60.032
60.033
60.034
60.036
60.038
60.04
60.039
60.035
60.035
60.034
60.033
60.029
60.03
60.029
60.028
60.026
60.028
60.03
60.032
60.033
60.035
60.036
60.037
60.034
60.032
60.03
60.028
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-94.383
-91.524
-100.100
-108.675
-111.544
-108.675
-111.544
-114.403
-114.403
-111.544
-111.544
-108.675
-105.816
-100.100
-97.241
-97.241
-97.241
-102.958
-97.241
-91.524
-94.383
-97.241
-102.958
-108.675
-114.403
-111.544
-100.100
-100.100
-97.241
-94.383
-82.938
-85.797
-82.938
-80.080
-74.363
-80.080
-85.797
-91.524
-94.383
-100.100
-102.958
-105.816
-97.241
-91.524
-85.797
-80.080
-94.383
-91.524
-100.100
-108.675
-111.544
-108.675
-111.544
-114.403
-114.403
-111.544
-111.544
-108.675
-105.816
-100.100
-97.241
-97.241
-97.241
-102.958
-97.241
-91.524
-94.383
-97.241
-102.958
-108.675
-114.403
-111.544
-100.100
-100.100
-97.241
-94.383
-82.938
-85.797
-82.938
-80.080
-74.363
-80.080
-85.797
-91.524
-94.383
-100.100
-102.958
-105.816
-97.241
-91.524
-85.797
-80.080
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-97.237
-94.379
-102.954
-111.529
-114.399
-111.529
-114.399
-117.257
-117.257
-114.399
-114.399
-111.529
-108.671
-102.954
-100.096
-100.096
-100.096
-105.812
-100.096
-94.379
-97.237
-100.096
-105.812
-111.529
-117.257
-114.399
-102.954
-102.954
-100.096
-97.237
-85.793
-88.651
-85.793
-82.934
-77.217
-82.934
-88.651
-94.379
-97.237
-102.954
-105.812
-108.671
-100.096
-94.379
-88.651
-82.934
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
215.391
213.827
212.235
210.616
208.999
207.412
205.827
204.243
202.675
201.136
199.611
198.116
196.648
195.221
193.821
192.435
191.062
189.674
188.327
187.018
185.708
184.397
183.072
181.733
180.380
179.052
177.787
176.534
175.305
174.099
172.954
171.806
170.681
169.579
168.510
167.427
166.327
165.213
164.097
162.965
161.831
160.694
159.603
158.545
157.519
156.526
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
161.321
160.519
159.725
158.939
158.161
157.391
156.628
155.873
155.125
154.384
153.651
152.925
152.206
151.494
150.788
150.089
149.397
148.711
148.032
147.359
146.692
146.031
145.377
144.728
144.085
143.448
142.817
142.192
141.572
140.957
140.349
139.745
139.147
138.554
137.966
137.383
136.805
136.232
135.664
135.101
134.543
133.989
133.440
132.896
132.356
131.820
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002556
20:58:44
20:58:46
20:58:48
20:58:50
20:58:52
20:58:54
20:58:56
20:58:58
20:59:00
20:59:02
20:59:04
20:59:06
20:59:08
20:59:10
20:59:12
20:59:14
20:59:16
20:59:18
20:59:20
20:59:22
20:59:24
20:59:26
20:59:28
20:59:30
20:59:32
20:59:34
20:59:36
20:59:38
20:59:40
20:59:42
20:59:44
20:59:46
20:59:48
20:59:50
20:59:52
20:59:54
20:59:56
20:59:58
21:00:00
21:00:02
21:00:04
21:00:06
21:00:08
21:00:10
21:00:12
21:00:14
60.028
60.028
60.028
60.03
60.029
60.03
60.032
60.035
60.035
60.035
60.034
60.033
60.034
60.034
60.034
60.033
60.029
60.027
60.025
60.025
60.026
60.026
60.025
60.026
60.027
60.027
60.028
60.03
60.029
60.03
60.028
60.026
60.027
60.029
60.03
60.032
60.029
60.029
60.032
60.033
60.033
60.032
60.03
60.029
60.033
60.035
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-80.080
-80.080
-80.080
-85.797
-82.938
-85.797
-91.524
-100.100
-100.100
-100.100
-97.241
-94.383
-97.241
-97.241
-97.241
-94.383
-82.938
-77.221
-71.504
-71.504
-74.363
-74.363
-71.504
-74.363
-77.221
-77.221
-80.080
-85.797
-82.938
-85.797
-80.080
-74.363
-77.221
-82.938
-85.797
-91.524
-82.938
-82.938
-91.524
-94.383
-94.383
-91.524
-85.797
-82.938
-94.383
-100.100
-80.080
-80.080
-80.080
-85.797
-82.938
-85.797
-91.524
-100.100
-100.100
-100.100
-97.241
-94.383
-97.241
-97.241
-97.241
-94.383
-82.938
-77.221
-71.504
-71.504
-74.363
-74.363
-71.504
-74.363
-77.221
-77.221
-80.080
-85.797
-82.938
-85.797
-80.080
-74.363
-77.221
-82.938
-85.797
-91.524
-82.938
-82.938
-91.524
-94.383
-94.383
-91.524
-85.797
-82.938
-94.383
-100.100
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-82.934
-82.934
-82.934
-88.651
-85.793
-88.651
-94.379
-102.954
-102.954
-102.954
-100.096
-97.237
-100.096
-100.096
-100.096
-97.237
-85.793
-80.076
-74.359
-74.359
-77.217
-77.217
-74.359
-77.217
-80.076
-80.076
-82.934
-88.651
-85.793
-88.651
-82.934
-77.217
-80.076
-85.793
-88.651
-94.379
-85.793
-85.793
-94.379
-97.237
-97.237
-94.379
-88.651
-85.793
-97.237
-102.954
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
155.540
154.563
153.593
152.609
151.644
150.675
149.690
148.680
147.677
146.683
145.707
144.751
143.791
142.838
141.893
140.966
140.090
139.244
138.425
137.613
136.796
135.986
135.192
134.393
133.590
132.793
131.991
131.174
130.373
129.568
128.789
128.037
127.281
126.509
125.732
124.940
124.185
123.435
122.660
121.880
121.106
120.347
119.614
118.895
118.142
117.375
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
131.290
130.763
130.241
129.723
129.209
128.699
128.194
127.692
127.195
126.701
126.212
125.726
125.244
124.766
124.292
123.821
123.354
122.891
122.431
121.975
121.522
121.072
120.626
120.184
119.744
119.308
118.876
118.446
118.020
117.597
117.176
116.759
116.345
115.934
115.526
115.121
114.719
114.320
113.924
113.530
113.139
112.751
112.366
111.983
111.604
111.226
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002557
21:00:16
21:00:18
21:00:20
21:00:22
21:00:24
21:00:26
21:00:28
21:00:30
21:00:32
21:00:34
21:00:36
21:00:38
21:00:40
21:00:42
21:00:44
21:00:46
21:00:48
21:00:50
21:00:52
21:00:54
21:00:56
21:00:58
21:01:00
21:01:02
21:01:04
21:01:06
21:01:08
21:01:10
21:01:12
21:01:14
21:01:16
21:01:18
21:01:20
21:01:22
21:01:24
21:01:26
21:01:28
21:01:30
21:01:32
21:01:34
21:01:36
21:01:38
21:01:40
21:01:42
21:01:44
21:01:46
60.035
60.031
60.032
60.029
60.027
60.026
60.027
60.027
60.026
60.026
60.028
60.028
60.027
60.026
60.027
60.028
60.027
60.027
60.027
60.027
60.025
60.024
60.024
60.024
60.025
60.025
60.026
60.025
60.023
60.022
60.021
60.02
60.018
60.015
60.013
60.013
60.013
60.014
60.014
60.015
60.017
60.016
60.016
60.016
60.015
60.014
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-100.100
-88.655
-91.524
-82.938
-77.221
-74.363
-77.221
-77.221
-74.363
-74.363
-80.080
-80.080
-77.221
-74.363
-77.221
-80.080
-77.221
-77.221
-77.221
-77.221
-71.504
-68.635
-68.635
-68.635
-71.504
-71.504
-74.363
-71.504
-65.777
-62.918
-60.060
-57.201
-51.484
-42.898
-37.181
-37.181
-37.181
-40.040
-40.040
-42.898
-48.615
-45.757
-45.757
-45.757
-42.898
-40.040
-100.100
-88.655
-91.524
-82.938
-77.221
-74.363
-77.221
-77.221
-74.363
-74.363
-80.080
-80.080
-77.221
-74.363
-77.221
-80.080
-77.221
-77.221
-77.221
-77.221
-71.504
-68.635
-68.635
-68.635
-71.504
-71.504
-74.363
-71.504
-65.777
-62.918
-60.060
-57.201
-51.484
-42.898
-37.181
-37.181
-37.181
-40.040
-40.040
-42.898
-48.615
-45.757
-45.757
-45.757
-42.898
-40.040
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-102.954
-91.509
-94.379
-85.793
-80.076
-77.217
-80.076
-80.076
-77.217
-77.217
-82.934
-82.934
-80.076
-77.217
-80.076
-82.934
-80.076
-80.076
-80.076
-80.076
-74.359
-71.489
-71.489
-71.489
-74.359
-74.359
-77.217
-74.359
-68.631
-65.773
-62.914
-60.056
-54.339
-45.753
-40.036
-40.036
-40.036
-42.894
-42.894
-45.753
-51.470
-48.611
-48.611
-48.611
-45.753
-42.894
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
116.612
115.895
115.172
114.484
113.820
113.170
112.515
111.864
111.228
110.595
109.948
109.305
108.676
108.060
107.440
106.813
106.201
105.592
104.987
104.386
103.808
103.242
102.680
102.122
101.558
100.998
100.432
99.879
99.348
98.828
98.321
97.826
97.352
96.908
96.484
96.063
95.644
95.219
94.796
94.368
93.925
93.493
93.063
92.637
92.221
91.817
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
110.852
110.480
110.110
109.743
109.379
109.017
108.657
108.300
107.946
107.593
107.244
106.896
106.551
106.208
105.867
105.529
105.193
104.859
104.527
104.197
103.870
103.544
103.221
102.900
102.581
102.264
101.949
101.636
101.325
101.015
100.708
100.403
100.100
99.798
99.499
99.201
98.905
98.611
98.319
98.028
97.739
97.452
97.167
96.884
96.602
96.322
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002558
21:01:48
21:01:50
21:01:52
21:01:54
21:01:56
21:01:58
21:02:00
21:02:02
21:02:04
21:02:06
21:02:08
21:02:10
21:02:12
21:02:14
21:02:16
21:02:18
21:02:20
21:02:22
21:02:24
21:02:26
21:02:28
21:02:30
21:02:32
21:02:34
21:02:36
21:02:38
21:02:40
21:02:42
21:02:44
21:02:46
21:02:48
21:02:50
21:02:52
21:02:54
21:02:56
21:02:58
21:03:00
21:03:02
21:03:04
21:03:06
21:03:08
21:03:10
21:03:12
21:03:14
21:03:16
21:03:18
60.013
60.014
60.018
60.018
60.018
60.016
60.017
60.025
60.03
60.032
60.034
60.033
60.033
60.033
60.033
60.034
60.037
60.036
60.034
60.03
60.032
60.031
60.032
60.031
60.029
60.027
60.027
60.023
60.022
60.02
60.018
60.019
60.018
60.019
60.019
60.017
60.016
60.017
60.015
60.014
60.012
60.011
60.011
60.011
60.013
60.013
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-37.181
-40.040
-51.484
-51.484
-51.484
-45.757
-48.615
-71.504
-85.797
-91.524
-97.241
-94.383
-94.383
-94.383
-94.383
-97.241
-105.816
-102.958
-97.241
-85.797
-91.524
-88.655
-91.524
-88.655
-82.938
-77.221
-77.221
-65.777
-62.918
-57.201
-51.484
-54.343
-51.484
-54.343
-54.343
-48.615
-45.757
-48.615
-42.898
-40.040
-34.323
-31.465
-31.465
-31.465
-37.181
-37.181
-37.181
-40.040
-51.484
-51.484
-51.484
-45.757
-48.615
-71.504
-85.797
-91.524
-97.241
-94.383
-94.383
-94.383
-94.383
-97.241
-105.816
-102.958
-97.241
-85.797
-91.524
-88.655
-91.524
-88.655
-82.938
-77.221
-77.221
-65.777
-62.918
-57.201
-51.484
-54.343
-51.484
-54.343
-54.343
-48.615
-45.757
-48.615
-42.898
-40.040
-34.323
-31.465
-31.465
-31.465
-37.181
-37.181
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-40.036
-42.894
-54.339
-54.339
-54.339
-48.611
-51.470
-74.359
-88.651
-94.379
-100.096
-97.237
-97.237
-97.237
-97.237
-100.096
-108.671
-105.812
-100.096
-88.651
-94.379
-91.509
-94.379
-91.509
-85.793
-80.076
-80.076
-68.631
-65.773
-60.056
-54.339
-57.197
-54.339
-57.197
-57.197
-51.470
-48.611
-51.470
-45.753
-42.894
-37.177
-34.319
-34.319
-34.319
-40.036
-40.036
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
91.423
91.023
90.592
90.163
89.737
89.330
88.917
88.440
87.923
87.393
86.850
86.318
85.789
85.263
84.740
84.212
83.662
83.124
82.605
82.121
81.624
81.138
80.646
80.165
79.703
79.259
78.818
78.411
78.013
77.634
77.272
76.905
76.547
76.184
75.823
75.479
75.144
74.804
74.480
74.167
73.870
73.582
73.296
73.011
72.713
72.416
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
96.043
95.767
95.492
95.218
94.946
94.676
94.407
94.140
93.875
93.611
93.348
93.087
92.828
92.570
92.314
92.059
91.805
91.553
91.302
91.053
90.805
90.559
90.314
90.070
89.828
89.587
89.348
89.109
88.872
88.637
88.402
88.169
87.937
87.707
87.478
87.250
87.023
86.797
86.573
86.350
86.128
85.907
85.687
85.469
85.251
85.035
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002559
21:03:20
21:03:22
21:03:24
21:03:26
21:03:28
21:03:30
21:03:32
21:03:34
21:03:36
21:03:38
21:03:40
21:03:42
21:03:44
21:03:46
21:03:48
21:03:50
21:03:52
21:03:54
21:03:56
21:03:58
21:04:00
21:04:02
21:04:04
21:04:06
21:04:08
21:04:10
21:04:12
21:04:14
21:04:16
21:04:18
21:04:20
21:04:22
21:04:24
21:04:26
21:04:28
21:04:30
21:04:32
21:04:34
21:04:36
21:04:38
21:04:40
21:04:42
21:04:44
21:04:46
21:04:48
21:04:50
60.012
60.012
60.012
60.011
60.007
60.004
60.001
59.998
59.998
59.999
60.001
60.002
60.004
60.006
60.006
60.006
60.005
60.005
60.005
60.005
60.005
60.004
60.004
60.005
60.005
60.005
60.002
59.999
59.996
59.998
59.999
60.001
59.999
59.998
59.998
59.998
59.997
59.996
59.995
59.993
59.993
59.993
59.995
59.995
59.996
59.995
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-34.323
-34.323
-34.323
-31.465
-20.020
-11.445
-2.858
5.717
5.717
2.858
-2.858
-5.717
-11.445
-17.161
-17.161
-17.161
-14.303
-14.303
-14.303
-14.303
-14.303
-11.445
-11.445
-14.303
-14.303
-14.303
-5.717
2.858
11.445
5.717
2.858
-2.858
2.858
5.717
5.717
5.717
8.575
11.445
14.303
20.020
20.020
20.020
14.303
14.303
11.445
14.303
-34.323
-34.323
-34.323
-31.465
-20.020
-11.445
-2.858
5.717
5.717
2.858
-2.858
-5.717
-11.445
-17.161
-17.161
-17.161
-14.303
-14.303
-14.303
-14.303
-14.303
-11.445
-11.445
-14.303
-14.303
-14.303
-5.717
2.858
11.445
5.717
2.858
-2.858
2.858
5.717
5.717
5.717
8.575
11.445
14.303
20.020
20.020
20.020
14.303
14.303
11.445
14.303
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-37.177
-37.177
-37.177
-34.319
-22.874
-14.299
-5.713
2.862
2.862
0.004
-5.713
-8.571
-14.299
-20.016
-20.016
-20.016
-17.157
-17.157
-17.157
-17.157
-17.157
-14.299
-14.299
-17.157
-17.157
-17.157
-8.571
0.004
8.590
2.862
0.004
-5.713
0.004
2.862
2.862
2.862
5.721
8.590
11.449
17.165
17.165
17.165
11.449
11.449
8.590
11.449
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
72.128
71.842
71.558
71.282
71.037
70.816
70.619
70.444
70.270
70.090
69.896
69.696
69.482
69.255
69.029
68.804
68.588
68.372
68.158
67.945
67.732
67.528
67.325
67.116
66.908
66.701
66.516
66.353
66.212
66.057
65.897
65.723
65.564
65.412
65.261
65.112
64.969
64.834
64.707
64.594
64.481
64.369
64.244
64.119
63.989
63.865
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
84.820
84.606
84.394
84.182
83.971
83.762
83.554
83.346
83.140
82.935
82.731
82.528
82.326
82.125
81.925
81.726
81.528
81.331
81.135
80.940
80.746
80.553
80.361
80.170
79.979
79.790
79.602
79.414
79.228
79.042
78.858
78.674
78.491
78.309
78.128
77.948
77.768
77.590
77.412
77.235
77.059
76.884
76.710
76.537
76.364
76.192
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002560
21:04:52
21:04:54
21:04:56
21:04:58
21:05:00
21:05:02
21:05:04
21:05:06
21:05:08
21:05:10
21:05:12
21:05:14
21:05:16
21:05:18
21:05:20
21:05:22
21:05:24
21:05:26
21:05:28
21:05:30
21:05:32
21:05:34
21:05:36
21:05:38
21:05:40
59.993
59.99
59.988
59.987
59.987
59.989
59.991
59.993
59.996
59.997
59.995
59.993
59.993
59.992
59.99
59.989
59.988
59.986
59.985
59.985
59.985
59.985
59.983
59.983
59.981
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
20.020
28.595
34.323
37.181
37.181
31.465
25.737
20.020
11.445
8.575
14.303
20.020
20.020
22.878
28.595
31.465
34.323
40.040
42.898
42.898
42.898
42.898
48.615
48.615
54.343
20.020
28.595
34.323
37.181
37.181
31.465
25.737
20.020
11.445
8.575
14.303
20.020
20.020
22.878
28.595
31.465
34.323
40.040
42.898
42.898
42.898
42.898
48.615
48.615
54.343
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
17.165
25.741
31.469
34.327
34.327
28.610
22.882
17.165
8.590
5.721
11.449
17.165
17.165
20.024
25.741
28.610
31.469
37.185
40.044
40.044
40.044
40.044
45.761
45.761
51.488
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
63.756
63.667
63.592
63.524
63.456
63.375
63.282
63.176
63.050
62.919
62.801
62.697
62.593
62.496
62.413
62.336
62.267
62.210
62.161
62.111
62.062
62.012
61.976
61.940
61.917
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
3.331
76.021
75.851
75.681
75.513
75.345
75.178
75.011
74.846
74.681
74.517
74.354
74.191
74.029
73.868
73.708
73.549
73.390
73.232
73.074
72.917
72.761
72.606
72.451
72.297
72.144
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
002561
A Point
20:50:38
FPointA
60.0070
8:50:38 PM
A Value
60.0084
C Value
59.8660
#N/A
Delta FCA -0.142374039
FR C
-418.7 MW/0.1 Hz
Slope A-C dF/dT
#N/A
Hz/second
C Value Maximum Resource Loss 596.1496277
Secondary C Value
No
n/a Time
Tzero
FT+4
FT+10
FT+20
FT+60
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
20:50:38
60.00699997
60.00837517
59.86600113
20:50:38
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec
59.8751
59.8799
59.8807
59.8804
-0.1332
-448.212
-0.1285
-463.988
-0.1277
-465.091
-0.1279
-466.087
-0.00666162
-0.0064259
-0.0063835
-0.0063965
93.5791
90.2678
89.6716
89.8552
0.0262
0.0214
0.0206
0.0209
20:50:38
59.91799927
59.86600113
59.87799835
59.89400101
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss 596.1496277
B Value Average LaaR Loss
0
B Value Average Net Loss 596.1496277
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection
Generation
Primary
Trip
Frequency
MW
Response
FR B
20 to 52 sec
Average
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002562
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-3076.62266
T+0 sec
-659.6334044
T+02 sec
-659.6334044
T+04 sec
-464.3846609
T+06 sec
-437.1447097
T+08 sec
-418.7207395
T+10 sec
-421.6808948
T+12 sec
-424.6832018
T+14 sec
-443.647494
T+16 sec
-450.3466651
T+18 sec
-457.2512559 -467.0124455 T+20 sec
-464.3846609 -467.0124455 T+22 sec
-475.4903869 -467.0124455 T+24 sec
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
59.8751
59.8751
59.8751
59.8751
59.8751
59.8751
59.8751
-448.212
-448.212
-448.212
-448.212
-448.212
-448.212
-448.212
59.8799
59.8799
59.8799
59.8799
-463.988
-463.988
-463.988
-463.988
59.8807
59.8807
59.8807
-465.091
-465.091
-465.091
59.8804
59.8804
59.8804
59.8804
-466.087
-466.087
-466.087
-466.087
002563
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
-468.0284752
-464.3846609
-468.0284752
-468.0284752
-464.3846609
-457.2512559
-464.3846609
-464.3846609
-464.3846609
-471.7299244
-475.4903869
-471.7299244
-475.4903869
-464.3846609
-468.0284752
-479.3112853
-512.2577989
-521.2275427
-530.4990003
-550.0872877
-560.4240483
-571.1567275
-565.7394899
-560.4240483
-565.7394899
-560.4240483
-555.2075602
-550.0872877
-555.2075602
-571.1567275
-588.071452
-605.9951063
-625.0456874
-645.3595755
-645.3595755
-667.0097441
-690.1934327
-706.5445125
-706.5445125
-706.5445125
-715.0140599
-741.7216735
-751.0611462
-780.5461529
-801.5235184
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
-467.0124455
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8799
59.8799
59.8799
-463.988
-463.988
-463.988
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
-465.091
-465.091
-465.091
-465.091
-465.091
-465.091
-465.091
-465.091
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
59.8804
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
-466.087
002564
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
-812.4830279
-812.4830279
-812.4830279
-812.4830279
-801.5235184
-812.4830279
-847.0989403
-884.8458398
-911.9010824
-987.4390927
-1039.041574
-1039.041574
-1076.547708
-1138.257387
-1183.423937
-1183.423937
-1207.378592
-1183.423937
-1183.423937
-1183.423937
-1232.323053
-1285.543109
-1374.40788
-1440.806232
-1553.526994
-1595.070661
-1685.20028
-1595.070661
-1595.070661
-1638.897258
-1734.195728
-1786.12547
-1900.14041
-2029.44027
-2177.622072
-2260.135194
-2445.841584
-2664.343159
-3076.62266
-3431.266835
-3877.36132
-4816.675851
-6359.188118
-9349.509303
-17668.40565
-17668.40565
002565
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
95582.29235
36727.86087
22698.19143
16441.56213
22698.19143
12888.8287
10598.64686
6913.384119
4722.074271
4076.615312
3815.823416
3585.569531
3382.254042
3382.254042
3037.749985
2890.540054
2890.540054
2756.938308
2523.242884
2420.83569
2420.83569
2635.141185
2890.540054
2756.938308
2635.141185
2635.141185
2523.242884
2420.83569
2420.83569
2420.83569
2523.242884
2756.938308
2420.83569
2326.416792
2239.086582
2082.722036
1946.528592
2012.453132
1584.397506
1366.595671
1398.640068
1432.223324
1398.640068
1467.459017
1432.223324
1398.640068
002566
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
1467.459017
1504.472183
1584.397506
1584.397506
1772.9542
1673.470557
1627.801135
1627.801135
1627.801135
1627.801135
1627.801135
1584.397506
1584.397506
1627.801135
1584.397506
1673.470557
1584.397506
1584.397506
1584.397506
1543.4008
1543.4008
1504.472183
1432.223324
1366.595671
1366.595671
1467.459017
1504.472183
1467.459017
1398.640068
1432.223324
1467.459017
1504.472183
1584.397506
1673.470557
1721.776544
1627.801135
1673.470557
1885.013546
2012.453132
2158.075647
2239.086582
2635.141185
2756.938308
2756.938308
2523.242884
2420.83569
002567
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
2420.83569
2523.242884
2239.086582
2012.453132
1946.528592
2012.453132
1946.528592
1885.013546
1885.013546
1946.528592
1946.528592
2012.453132
2082.722036
2239.086582
2326.416792
2326.416792
2326.416792
2158.075647
2326.416792
2523.242884
2420.83569
2326.416792
2158.075647
2012.453132
1885.013546
1946.528592
2239.086582
2239.086582
2326.416792
2420.83569
2890.540054
2756.938308
2890.540054
3037.749985
3382.254042
3037.749985
2756.938308
2523.242884
2420.83569
2239.086582
2158.075647
2082.722036
2326.416792
2523.242884
2756.938308
3037.749985
002568
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
3037.749985
3037.749985
3037.749985
2756.938308
2890.540054
2756.938308
2523.242884
2239.086582
2239.086582
2239.086582
2326.416792
2420.83569
2326.416792
2326.416792
2326.416792
2420.83569
2890.540054
3200.758792
3585.569531
3585.569531
3382.254042
3382.254042
3585.569531
3382.254042
3200.758792
3200.758792
3037.749985
2756.938308
2890.540054
2756.938308
3037.749985
3382.254042
3200.758792
2890.540054
2756.938308
2523.242884
2890.540054
2890.540054
2523.242884
2420.83569
2420.83569
2523.242884
2756.938308
2890.540054
2420.83569
2239.086582
002569
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
2239.086582
2635.141185
2523.242884
2890.540054
3200.758792
3382.254042
3200.758792
3200.758792
3382.254042
3382.254042
3037.749985
3037.749985
3200.758792
3382.254042
3200.758792
3037.749985
3200.758792
3200.758792
3200.758792
3200.758792
3585.569531
3815.823416
3815.823416
3815.823416
3585.569531
3585.569531
3382.254042
3585.569531
4076.615312
4375.669831
4722.074271
5128.040952
6192.868952
8999.542067
12888.8287
12888.8287
12888.8287
10598.64686
10598.64686
8999.542067
6913.384119
7819.717188
7819.717188
7819.717188
8999.542067
10598.64686
002570
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
12888.8287
10598.64686
6192.868952
6192.868952
6192.868952
7819.717188
6913.384119
3585.569531
2756.938308
2523.242884
2326.416792
2420.83569
2420.83569
2420.83569
2420.83569
2326.416792
2082.722036
2158.075647
2326.416792
2756.938308
2523.242884
2635.141185
2523.242884
2635.141185
2890.540054
3200.758792
3200.758792
4076.615312
4375.669831
5128.040952
6192.868952
5610.37688
6192.868952
5610.37688
5610.37688
6913.384119
7819.717188
6913.384119
8999.542067
10598.64686
16441.56213
22698.19143
22698.19143
22698.19143
12888.8287
12888.8287
002571
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
16441.56213
16441.56213
16441.56213
22698.19143
-43350.08266
-13630.79355
-8082.59881
-5746.536054
-5746.536054
-6359.188118
-8082.59881
-9349.509303
-13630.79355
-25104.74667
-25104.74667
-25104.74667
-17668.40565
-17668.40565
-17668.40565
-17668.40565
-17668.40565
-13630.79355
-13630.79355
-17668.40565
-17668.40565
-17668.40565
-9349.509303
-6359.188118
-4816.675851
-5746.536054
-6359.188118
-8082.59881
-6359.188118
-5746.536054
-5746.536054
-5746.536054
-5241.557874
-4816.675851
-4456.781634
-3877.36132
-3877.36132
-3877.36132
-4456.781634
-4456.781634
-4816.675851
-4456.781634
002572
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
596.1496
-3877.36132
-3244.618457
-2925.714649
-2788.918497
-2788.918497
-3076.62266
-3431.266835
-3877.36132
-4816.675851
-5241.557874
-4456.781634
-3877.36132
-3877.36132
-3640.700012
-3244.618457
-3076.62266
-2925.714649
-2664.343159
-2550.42102
-2550.42102
-2550.42102
-2550.42102
-2349.500834
-2349.500834
-2177.622072
002573
Non-Conforming Load sign convention
-
(Data is positive for Load then enter "+" else "-"
Time of Frequency Recover
Value A Pre-Perturbation Av
Value B Post-Perturbation Ave
Value B
FR B
20 to 52 sec 20 to 52 sec
59.8807
-0.1277
-467.012
-0.0063835
89.6716
0.0206
Value A Pre-Perturbation Average
Value B Post-Perturbation Average In
Average periods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Value B
FR B
20 to 52 sec 20 to 52 sec
Average
Average
Frequency
MW
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
Net
Actual
Interchange
MW
60.0120
60.0100
60.0100
593.30
593.30
593.30
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
0.00
0.00
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
0.00
0.00
0.00
12 to 24 second Average
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
BA
Load
MW
57058.09
57058.09
57042.50
FRO
Expected
Primary
Freq Response
MW
-34.323 T-72 sec
-28.595 T-70 sec
-28.595 T-68 sec
T
20:49:28
20:49:30
20:49:32
002574
59.8807
59.8807
59.8807
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-467.012 T+20 sec
-467.012 T+22 sec
-467.012 T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
60.0110
60.0110
60.0100
60.0110
60.0110
60.0120
60.0120
60.0110
60.0120
60.0130
60.0150
60.0160
60.0150
60.0140
60.0130
60.0120
60.0120
60.0120
60.0130
60.0150
60.0170
60.0170
60.0140
60.0150
60.0130
60.0120
60.0110
60.0080
60.0080
60.0070
60.0070
60.0070
60.0070
59.9890
59.9180
59.9180
59.8800
59.8720
59.8660
59.8670
59.8680
59.8740
59.8760
59.8780
59.8800
59.8830
593.30
593.30
593.30
593.30
593.30
593.30
593.30
585.63
585.63
586.14
586.14
586.80
586.80
585.95
585.95
585.67
585.67
585.12
585.12
584.66
584.66
585.31
585.31
585.21
585.21
585.92
585.92
593.28
593.28
602.70
602.70
602.70
602.70
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
57042.50
57042.50
57042.50
57042.50
57050.12
57050.12
57050.12
57057.21
57057.21
57051.74
57051.74
57051.74
57051.74
57037.88
57037.88
57050.43
57050.43
57029.92
57029.92
57033.71
57033.71
57035.56
57035.56
57020.60
57020.60
57030.37
57030.37
57039.15
57039.15
57042.20
57042.20
57089.30
57089.30
56704.13
56704.13
56704.13
56763.97
56763.97
56811.20
56811.20
56864.96
56864.96
56863.43
56863.43
56867.51
56867.51
-31.465
-31.465
-28.595
-31.465
-31.465
-34.323
-34.323
-31.465
-34.323
-37.181
-42.898
-45.757
-42.898
-40.040
-37.181
-34.323
-34.323
-34.323
-37.181
-42.898
-48.615
-48.615
-40.040
-42.898
-37.181
-34.323
-31.465
-22.878
-22.878
-20.020
-20.020
-20.020
-20.020
31.465
234.522
234.522
343.197
366.075
383.237
380.378
377.520
360.358
354.642
348.925
343.197
334.622
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
002575
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
59.8807
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
-467.012
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
20:52:02
20:52:04
20:52:06
20:52:08
20:52:10
20:52:12
20:52:14
20:52:16
20:52:18
20:52:20
20:52:22
20:52:24
20:52:26
20:52:28
20:52:30
20:52:32
20:52:34
59.8810
59.8800
59.8810
59.8810
59.8800
59.8780
59.8800
59.8800
59.8800
59.8820
59.8830
59.8820
59.8830
59.8800
59.8810
59.8840
59.8920
59.8940
59.8960
59.9000
59.9020
59.9040
59.9030
59.9020
59.9030
59.9020
59.9010
59.9000
59.9010
59.9040
59.9070
59.9100
59.9130
59.9160
59.9160
59.9190
59.9220
59.9240
59.9240
59.9240
59.9250
59.9280
59.9290
59.9320
59.9340
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56878.36
56878.36
56886.32
56886.32
56893.13
56893.13
56875.62
56875.62
56890.82
56890.82
56891.07
56891.07
56899.47
56899.47
56874.90
56874.90
56854.81
56854.81
56837.21
56837.21
56827.59
56827.59
56841.84
56841.84
56835.30
56835.30
56837.30
56837.30
56854.15
56854.15
56861.54
56861.54
56861.64
56861.64
56866.16
56866.16
56869.21
56869.21
56876.27
56876.27
56881.39
56881.39
56889.59
56889.59
56893.89
340.339
343.197
340.339
340.339
343.197
348.925
343.197
343.197
343.197
337.480
334.622
337.480
334.622
343.197
340.339
331.763
308.885
303.157
297.440
285.996
280.279
274.562
277.420
280.279
277.420
280.279
283.137
285.996
283.137
274.562
265.976
257.400
248.825
240.239
240.239
231.664
223.077
217.361
217.361
217.361
214.502
205.916
203.058
194.482
188.765
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
002576
20:52:36
20:52:38
20:52:40
20:52:42
20:52:44
20:52:46
20:52:48
20:52:50
20:52:52
20:52:54
20:52:56
20:52:58
20:53:00
20:53:02
20:53:04
20:53:06
20:53:08
20:53:10
20:53:12
20:53:14
20:53:16
20:53:18
20:53:20
20:53:22
20:53:24
20:53:26
20:53:28
20:53:30
20:53:32
20:53:34
20:53:36
20:53:38
20:53:40
20:53:42
20:53:44
20:53:46
20:53:48
20:53:50
20:53:52
20:53:54
20:53:56
20:53:58
20:54:00
20:54:02
20:54:04
20:54:06
59.9350
59.9350
59.9350
59.9350
59.9340
59.9350
59.9380
59.9410
59.9430
59.9480
59.9510
59.9510
59.9530
59.9560
59.9580
59.9580
59.9590
59.9580
59.9580
59.9580
59.9600
59.9620
59.9650
59.9670
59.9700
59.9710
59.9730
59.9710
59.9710
59.9720
59.9740
59.9750
59.9770
59.9790
59.9810
59.9820
59.9840
59.9860
59.9890
59.9910
59.9930
59.9960
59.9990
60.0020
60.0050
60.0050
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56900.44
56900.44
56900.44
56887.58
56887.58
56901.59
56901.59
56915.66
56915.66
56912.21
56912.21
56914.31
56914.31
56907.54
56907.54
56897.04
56897.04
56902.03
56902.03
56903.03
56903.03
56917.74
56917.74
56900.81
56900.81
56914.80
56914.80
56922.52
56922.52
56932.45
56932.45
56920.23
56920.23
56912.88
56912.88
56905.22
56905.22
56915.62
56915.62
56923.03
56923.03
56932.03
56932.03
56926.22
56926.22
56930.33
185.896
185.896
185.896
185.896
188.765
185.896
177.321
168.735
163.018
148.715
140.139
140.139
134.423
125.836
120.119
120.119
117.261
120.119
120.119
120.119
114.403
108.675
100.100
94.383
85.797
82.938
77.221
82.938
82.938
80.080
74.363
71.504
65.777
60.060
54.343
51.484
45.757
40.040
31.465
25.737
20.020
11.445
2.858
-5.717
-14.303
-14.303
002577
20:54:08
20:54:10
20:54:12
20:54:14
20:54:16
20:54:18
20:54:20
20:54:22
20:54:24
20:54:26
20:54:28
20:54:30
20:54:32
20:54:34
20:54:36
20:54:38
20:54:40
20:54:42
20:54:44
20:54:46
20:54:48
20:54:50
20:54:52
20:54:54
20:54:56
20:54:58
20:55:00
20:55:02
20:55:04
20:55:06
20:55:08
20:55:10
20:55:12
20:55:14
20:55:16
20:55:18
20:55:20
20:55:22
20:55:24
20:55:26
20:55:28
20:55:30
20:55:32
20:55:34
20:55:36
20:55:38
60.0090
60.0100
60.0110
60.0120
60.0110
60.0130
60.0140
60.0170
60.0210
60.0230
60.0240
60.0250
60.0260
60.0260
60.0280
60.0290
60.0290
60.0300
60.0320
60.0330
60.0330
60.0310
60.0290
60.0300
60.0310
60.0310
60.0320
60.0330
60.0330
60.0330
60.0320
60.0300
60.0330
60.0340
60.0350
60.0370
60.0390
60.0380
60.0460
60.0520
60.0510
60.0500
60.0510
60.0490
60.0500
60.0510
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56930.33
56935.11
56935.11
56938.24
56938.24
56947.14
56947.14
56946.19
56946.19
56937.30
56937.30
56931.41
56931.41
56924.84
56924.84
56933.16
56933.16
56935.62
56935.62
56957.32
56957.32
56954.23
56954.23
56956.64
56956.64
56956.60
56956.60
56938.90
56938.90
56943.18
56943.18
56939.07
56939.07
56942.44
56942.44
56924.37
56924.37
56907.90
56907.90
56897.80
56897.80
56864.89
56864.89
56842.66
56842.66
56845.28
-25.737
-28.595
-31.465
-34.323
-31.465
-37.181
-40.040
-48.615
-60.060
-65.777
-68.635
-71.504
-74.363
-74.363
-80.080
-82.938
-82.938
-85.797
-91.524
-94.383
-94.383
-88.655
-82.938
-85.797
-88.655
-88.655
-91.524
-94.383
-94.383
-94.383
-91.524
-85.797
-94.383
-97.241
-100.100
-105.816
-111.544
-108.675
-131.564
-148.715
-145.856
-142.998
-145.856
-140.139
-142.998
-145.856
002578
20:55:40
20:55:42
20:55:44
20:55:46
20:55:48
20:55:50
20:55:52
20:55:54
20:55:56
20:55:58
20:56:00
20:56:02
20:56:04
20:56:06
20:56:08
20:56:10
20:56:12
20:56:14
20:56:16
20:56:18
20:56:20
20:56:22
20:56:24
20:56:26
20:56:28
20:56:30
20:56:32
20:56:34
20:56:36
20:56:38
20:56:40
20:56:42
20:56:44
20:56:46
20:56:48
20:56:50
20:56:52
20:56:54
20:56:56
20:56:58
20:57:00
20:57:02
20:57:04
20:57:06
20:57:08
20:57:10
60.0490
60.0480
60.0460
60.0460
60.0420
60.0440
60.0450
60.0450
60.0450
60.0450
60.0450
60.0460
60.0460
60.0450
60.0460
60.0440
60.0460
60.0460
60.0460
60.0470
60.0470
60.0480
60.0500
60.0520
60.0520
60.0490
60.0480
60.0490
60.0510
60.0500
60.0490
60.0480
60.0460
60.0440
60.0430
60.0450
60.0440
60.0400
60.0380
60.0360
60.0350
60.0310
60.0300
60.0300
60.0320
60.0330
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56845.28
56850.62
56850.62
56870.91
56870.91
56854.55
56854.55
56848.62
56848.62
56838.20
56838.20
56838.88
56838.88
56851.80
56851.80
56861.98
56861.98
56851.02
56851.02
56845.13
56845.13
56847.95
56847.95
56843.66
56843.66
56833.39
56833.39
56814.38
56814.38
56817.16
56817.16
56805.52
56805.52
56807.83
56807.83
56827.41
56827.41
56821.69
56821.69
56833.95
56833.95
56860.51
56860.51
56877.59
56877.59
56918.66
-140.139
-137.281
-131.564
-131.564
-120.119
-125.836
-128.695
-128.695
-128.695
-128.695
-128.695
-131.564
-131.564
-128.695
-131.564
-125.836
-131.564
-131.564
-131.564
-134.423
-134.423
-137.281
-142.998
-148.715
-148.715
-140.139
-137.281
-140.139
-145.856
-142.998
-140.139
-137.281
-131.564
-125.836
-122.978
-128.695
-125.836
-114.403
-108.675
-102.958
-100.100
-88.655
-85.797
-85.797
-91.524
-94.383
002579
20:57:12
20:57:14
20:57:16
20:57:18
20:57:20
20:57:22
20:57:24
20:57:26
20:57:28
20:57:30
20:57:32
20:57:34
20:57:36
20:57:38
20:57:40
20:57:42
20:57:44
20:57:46
20:57:48
20:57:50
20:57:52
20:57:54
20:57:56
20:57:58
20:58:00
20:58:02
20:58:04
20:58:06
20:58:08
20:58:10
20:58:12
20:58:14
20:58:16
20:58:18
20:58:20
20:58:22
20:58:24
20:58:26
20:58:28
20:58:30
20:58:32
20:58:34
20:58:36
20:58:38
20:58:40
20:58:42
60.0330
60.0320
60.0350
60.0380
60.0390
60.0380
60.0390
60.0400
60.0400
60.0390
60.0390
60.0380
60.0370
60.0350
60.0340
60.0340
60.0340
60.0360
60.0340
60.0320
60.0330
60.0340
60.0360
60.0380
60.0400
60.0390
60.0350
60.0350
60.0340
60.0330
60.0290
60.0300
60.0290
60.0280
60.0260
60.0280
60.0300
60.0320
60.0330
60.0350
60.0360
60.0370
60.0340
60.0320
60.0300
60.0280
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56918.66
56891.71
56891.71
56894.35
56894.35
56895.17
56895.17
56889.73
56889.73
56892.39
56892.39
56875.33
56874.01
56874.01
56874.01
56881.00
56881.00
56887.45
56887.45
56882.08
56882.08
56879.11
56879.11
56884.36
56884.36
56872.63
56872.63
56865.52
56865.52
56874.48
56874.48
56866.35
56866.35
56868.50
56868.50
56865.58
56865.58
56862.76
56862.76
56871.13
56871.13
56863.48
56863.48
56856.71
56856.71
56859.67
-94.383
-91.524
-100.100
-108.675
-111.544
-108.675
-111.544
-114.403
-114.403
-111.544
-111.544
-108.675
-105.816
-100.100
-97.241
-97.241
-97.241
-102.958
-97.241
-91.524
-94.383
-97.241
-102.958
-108.675
-114.403
-111.544
-100.100
-100.100
-97.241
-94.383
-82.938
-85.797
-82.938
-80.080
-74.363
-80.080
-85.797
-91.524
-94.383
-100.100
-102.958
-105.816
-97.241
-91.524
-85.797
-80.080
002580
20:58:44
20:58:46
20:58:48
20:58:50
20:58:52
20:58:54
20:58:56
20:58:58
20:59:00
20:59:02
20:59:04
20:59:06
20:59:08
20:59:10
20:59:12
20:59:14
20:59:16
20:59:18
20:59:20
20:59:22
20:59:24
20:59:26
20:59:28
20:59:30
20:59:32
20:59:34
20:59:36
20:59:38
20:59:40
20:59:42
20:59:44
20:59:46
20:59:48
20:59:50
20:59:52
20:59:54
20:59:56
20:59:58
21:00:00
21:00:02
21:00:04
21:00:06
21:00:08
21:00:10
21:00:12
21:00:14
60.0280
60.0280
60.0280
60.0300
60.0290
60.0300
60.0320
60.0350
60.0350
60.0350
60.0340
60.0330
60.0340
60.0340
60.0340
60.0330
60.0290
60.0270
60.0250
60.0250
60.0260
60.0260
60.0250
60.0260
60.0270
60.0270
60.0280
60.0300
60.0290
60.0300
60.0280
60.0260
60.0270
60.0290
60.0300
60.0320
60.0290
60.0290
60.0320
60.0330
60.0330
60.0320
60.0300
60.0290
60.0330
60.0350
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56859.67
56860.41
56860.41
56867.31
56867.31
56852.14
56852.14
56838.81
56838.81
56839.64
56839.64
56839.96
56839.96
56841.01
56841.01
56854.90
56854.90
56846.00
56846.00
56833.07
56833.07
56827.28
56827.28
56829.42
56829.42
56846.66
56846.66
56840.57
56840.57
56831.91
56831.91
56833.35
56833.35
56833.63
56833.63
56828.00
56828.00
56828.00
56828.00
56833.80
56833.80
56806.86
56806.86
56813.18
56813.18
56804.27
-80.080
-80.080
-80.080
-85.797
-82.938
-85.797
-91.524
-100.100
-100.100
-100.100
-97.241
-94.383
-97.241
-97.241
-97.241
-94.383
-82.938
-77.221
-71.504
-71.504
-74.363
-74.363
-71.504
-74.363
-77.221
-77.221
-80.080
-85.797
-82.938
-85.797
-80.080
-74.363
-77.221
-82.938
-85.797
-91.524
-82.938
-82.938
-91.524
-94.383
-94.383
-91.524
-85.797
-82.938
-94.383
-100.100
002581
21:00:16
21:00:18
21:00:20
21:00:22
21:00:24
21:00:26
21:00:28
21:00:30
21:00:32
21:00:34
21:00:36
21:00:38
21:00:40
21:00:42
21:00:44
21:00:46
21:00:48
21:00:50
21:00:52
21:00:54
21:00:56
21:00:58
21:01:00
21:01:02
21:01:04
21:01:06
21:01:08
21:01:10
21:01:12
21:01:14
21:01:16
21:01:18
21:01:20
21:01:22
21:01:24
21:01:26
21:01:28
21:01:30
21:01:32
21:01:34
21:01:36
21:01:38
21:01:40
21:01:42
21:01:44
21:01:46
60.0350
60.0310
60.0320
60.0290
60.0270
60.0260
60.0270
60.0270
60.0260
60.0260
60.0280
60.0280
60.0270
60.0260
60.0270
60.0280
60.0270
60.0270
60.0270
60.0270
60.0250
60.0240
60.0240
60.0240
60.0250
60.0250
60.0260
60.0250
60.0230
60.0220
60.0210
60.0200
60.0180
60.0150
60.0130
60.0130
60.0130
60.0140
60.0140
60.0150
60.0170
60.0160
60.0160
60.0160
60.0150
60.0140
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56804.27
56787.34
56787.34
56786.84
56786.84
56773.49
56773.49
56759.37
56759.37
56742.34
56742.34
56734.98
56734.98
56750.62
56750.62
56746.89
56746.89
56753.28
56753.28
56749.96
56749.96
56728.95
56728.95
56723.32
56723.32
56715.22
56715.22
56724.10
56724.10
56718.91
56718.91
56704.99
56704.99
56708.48
56708.48
56730.45
56730.45
56720.16
56720.16
56711.63
56711.63
56708.66
56708.66
56706.61
56706.61
56716.55
-100.100
-88.655
-91.524
-82.938
-77.221
-74.363
-77.221
-77.221
-74.363
-74.363
-80.080
-80.080
-77.221
-74.363
-77.221
-80.080
-77.221
-77.221
-77.221
-77.221
-71.504
-68.635
-68.635
-68.635
-71.504
-71.504
-74.363
-71.504
-65.777
-62.918
-60.060
-57.201
-51.484
-42.898
-37.181
-37.181
-37.181
-40.040
-40.040
-42.898
-48.615
-45.757
-45.757
-45.757
-42.898
-40.040
002582
21:01:48
21:01:50
21:01:52
21:01:54
21:01:56
21:01:58
21:02:00
21:02:02
21:02:04
21:02:06
21:02:08
21:02:10
21:02:12
21:02:14
21:02:16
21:02:18
21:02:20
21:02:22
21:02:24
21:02:26
21:02:28
21:02:30
21:02:32
21:02:34
21:02:36
21:02:38
21:02:40
21:02:42
21:02:44
21:02:46
21:02:48
21:02:50
21:02:52
21:02:54
21:02:56
21:02:58
21:03:00
21:03:02
21:03:04
21:03:06
21:03:08
21:03:10
21:03:12
21:03:14
21:03:16
21:03:18
60.0130
60.0140
60.0180
60.0180
60.0180
60.0160
60.0170
60.0250
60.0300
60.0320
60.0340
60.0330
60.0330
60.0330
60.0330
60.0340
60.0370
60.0360
60.0340
60.0300
60.0320
60.0310
60.0320
60.0310
60.0290
60.0270
60.0270
60.0230
60.0220
60.0200
60.0180
60.0190
60.0180
60.0190
60.0190
60.0170
60.0160
60.0170
60.0150
60.0140
60.0120
60.0110
60.0110
60.0110
60.0130
60.0130
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56716.55
56705.83
56705.83
56696.39
56696.39
56670.62
56670.62
56642.69
56642.69
56644.32
56644.32
56636.41
56636.41
56630.75
56630.75
56620.91
56620.91
56619.00
56619.00
56610.45
56610.45
56598.06
56598.06
56587.05
56589.89
56589.89
56589.89
56581.13
56581.13
56587.69
56587.69
56605.20
56605.20
56592.78
56592.78
56586.05
56586.05
56581.38
56581.38
56576.92
56576.92
56570.90
56570.90
56585.30
56585.30
56579.29
-37.181
-40.040
-51.484
-51.484
-51.484
-45.757
-48.615
-71.504
-85.797
-91.524
-97.241
-94.383
-94.383
-94.383
-94.383
-97.241
-105.816
-102.958
-97.241
-85.797
-91.524
-88.655
-91.524
-88.655
-82.938
-77.221
-77.221
-65.777
-62.918
-57.201
-51.484
-54.343
-51.484
-54.343
-54.343
-48.615
-45.757
-48.615
-42.898
-40.040
-34.323
-31.465
-31.465
-31.465
-37.181
-37.181
002583
21:03:20
21:03:22
21:03:24
21:03:26
21:03:28
21:03:30
21:03:32
21:03:34
21:03:36
21:03:38
21:03:40
21:03:42
21:03:44
21:03:46
21:03:48
21:03:50
21:03:52
21:03:54
21:03:56
21:03:58
21:04:00
21:04:02
21:04:04
21:04:06
21:04:08
21:04:10
21:04:12
21:04:14
21:04:16
21:04:18
21:04:20
21:04:22
21:04:24
21:04:26
21:04:28
21:04:30
21:04:32
21:04:34
21:04:36
21:04:38
21:04:40
21:04:42
21:04:44
21:04:46
21:04:48
21:04:50
60.0120
60.0120
60.0120
60.0110
60.0070
60.0040
60.0010
59.9980
59.9980
59.9990
60.0010
60.0020
60.0040
60.0060
60.0060
60.0060
60.0050
60.0050
60.0050
60.0050
60.0050
60.0040
60.0040
60.0050
60.0050
60.0050
60.0020
59.9990
59.9960
59.9980
59.9990
60.0010
59.9990
59.9980
59.9980
59.9980
59.9970
59.9960
59.9950
59.9930
59.9930
59.9930
59.9950
59.9950
59.9960
59.9950
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56579.29
56575.29
56575.29
56567.70
56567.70
56566.86
56566.86
56567.80
56567.80
56565.92
56565.92
56570.00
56570.00
56565.58
56565.58
56557.96
56557.96
56538.89
56538.89
56537.92
56537.92
56544.36
56544.36
56542.68
56542.68
56554.31
56554.31
56543.29
56543.29
56531.34
56531.34
56542.45
56542.45
56546.61
56546.61
56538.92
56538.92
56548.07
56548.07
56542.02
56542.02
56531.91
56531.91
56528.67
56528.67
56528.46
-34.323
-34.323
-34.323
-31.465
-20.020
-11.445
-2.858
5.717
5.717
2.858
-2.858
-5.717
-11.445
-17.161
-17.161
-17.161
-14.303
-14.303
-14.303
-14.303
-14.303
-11.445
-11.445
-14.303
-14.303
-14.303
-5.717
2.858
11.445
5.717
2.858
-2.858
2.858
5.717
5.717
5.717
8.575
11.445
14.303
20.020
20.020
20.020
14.303
14.303
11.445
14.303
002584
21:04:52
21:04:54
21:04:56
21:04:58
21:05:00
21:05:02
21:05:04
21:05:06
21:05:08
21:05:10
21:05:12
21:05:14
21:05:16
21:05:18
21:05:20
21:05:22
21:05:24
21:05:26
21:05:28
21:05:30
21:05:32
21:05:34
21:05:36
21:05:38
21:05:40
59.9930
59.9900
59.9880
59.9870
59.9870
59.9890
59.9910
59.9930
59.9960
59.9970
59.9950
59.9930
59.9930
59.9920
59.9900
59.9890
59.9880
59.9860
59.9850
59.9850
59.9850
59.9850
59.9830
59.9830
59.9810
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
56528.46
56519.61
56519.61
56512.20
56512.20
56514.52
56514.52
56508.47
56508.47
56512.15
56512.15
56508.86
56508.86
56503.34
56503.34
56510.09
56510.09
56514.67
56514.67
56501.90
56501.90
56510.46
56510.46
56504.74
56504.74
20.020
28.595
34.323
37.181
37.181
31.465
25.737
20.020
11.445
8.575
14.303
20.020
20.020
22.878
28.595
31.465
34.323
40.040
42.898
42.898
42.898
42.898
48.615
48.615
54.343
002585
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8751
-0.133
596.15
0.00
-596.15
0.00
-23.95
357.09
381.04
381.04
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-653.000
-653.000
-54.6898
815.3177
870.0075
-68.52%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
57050.256
56857.573
-192.683
-144.622
-32.32%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
12 to 24 second Average Period Evaluation
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
1.565 P.U.
1.565 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002586
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
59.875
59.875
59.875
59.875
59.875
59.875
59.875
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
56857.573
56857.573
56857.573
56857.573
56857.573
56857.573
56857.573
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
357.092
357.092
357.092
357.092
357.092
357.092
357.092
977.194
977.194
977.194
977.194
977.194
977.194
977.194
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
59.880
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002587
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
002588
002589
002590
002591
002592
002593
002594
002595
002596
002597
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8799
-0.129
596.15
0.00
-596.15
0.00
-23.95
343.61
367.56
367.56
0.00
0.00
0.00
0.00
0.00
0.00
0.00
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -653.000 MW/0.1 Hz
Post-Perturbation Bias Setting -653.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -54.6898 MW
EPFR for Bias Setting Post-Perturbation Average 784.5325 MW
EPFR for Bias Setting Delta 839.2223 MW
Primary Frequency Response Delivery of Bias -71.04%
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8802
-0.128
596.15
0.00
-596.15
0.00
-23.95
342.68
366.63
366.63
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Pre-Perturbation BA Load 57050.256 MW
Post-Perturbation BA Load 56872.132 MW
Pre to Post Perturbation BA Load Change -178.124 MW
Load Dampening Frequency Response -138.598 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response -29.88%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
1.622 P.U.
1.622 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.626
1.626
Pumped
Hydro
Load (-) Gen (+)
MW
002598
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
56872.132
56872.132
56872.132
56872.132
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
343.608
343.608
343.608
343.608
963.711
963.711
963.711
963.711
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002599
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000 56872.132
-653.000 56872.132
-653.000 56872.132
343.608
343.608
343.608
963.711 T+26 sec
963.711 T+28 sec
963.711 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002600
002601
002602
002603
002604
002605
002606
002607
002608
002609
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-653.000
-653.000
-54.6898
782.4109
837.1008
-71.22%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
57050.256
56878.664
-171.591
-133.854
-28.78%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8804
-0.128
596.15
0.00
-596.15
0.00
-23.95
341.93
365.88
365.88
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.629 P.U.
1.629 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002610
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
56878.664
56878.664
56878.664
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
342.679
342.679
342.679
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
962.782 T+20 sec
962.782 T+22 sec
962.782 T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
59.880
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002611
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
56878.664
56878.664
56878.664
56878.664
56878.664
56878.664
56878.664
56878.664
342.679
342.679
342.679
342.679
342.679
342.679
342.679
342.679
962.782
962.782
962.782
962.782
962.782
962.782
962.782
962.782
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
59.880
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002612
002613
002614
002615
002616
002617
002618
002619
002620
002621
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-653.000
-653.000
-54.6898
780.6965
835.3864
-71.36%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
57050.256
56882.859
-167.397
-130.850
-28.08%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, July 18, 2011
20:50:40
20:54:00
60.0084
59.8807
-0.128
596.15
0.00
-596.15
0.00
-23.95
341.18
365.13
365.13
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
20:49:28
20:49:30
20:49:32
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.633 P.U.
1.633 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002622
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
56882.859
56882.859
56882.859
56882.859
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
341.928
341.928
341.928
341.928
962.031
962.031
962.031
962.031
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
20:49:34
20:49:36
20:49:38
20:49:40
20:49:42
20:49:44
20:49:46
20:49:48
20:49:50
20:49:52
20:49:54
20:49:56
20:49:58
20:50:00
20:50:02
20:50:04
20:50:06
20:50:08
20:50:10
20:50:12
20:50:14
20:50:16
20:50:18
20:50:20
20:50:22
20:50:24
20:50:26
20:50:28
20:50:30
20:50:32
20:50:34
20:50:36
20:50:38
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.008
596.150
596.150
596.150
596.150
596.150
596.150
596.150
596.150
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
20:50:40
20:50:42
20:50:44
20:50:46
20:50:48
20:50:50
20:50:52
20:50:54
20:50:56
20:50:58
20:51:00
20:51:02
20:51:04
59.881
59.881
59.881
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002623
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
56882.859
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
341.928
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
962.031
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
20:51:06
20:51:08
20:51:10
20:51:12
20:51:14
20:51:16
20:51:18
20:51:20
20:51:22
20:51:24
20:51:26
20:51:28
20:51:30
20:51:32
20:51:34
20:51:36
20:51:38
20:51:40
20:51:42
20:51:44
20:51:46
20:51:48
20:51:50
20:51:52
20:51:54
20:51:56
20:51:58
20:52:00
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
59.881
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002624
002625
002626
002627
002628
002629
002630
002631
002632
002633
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-653.000
-653.000
-54.6898
778.9891
833.6789
-71.51%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
57050.256
56884.002
-166.254
-130.223
-27.89%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
002634
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
57050.256
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-23.953
-653.000
-653.000
-653.000
56884.002
56884.002
56884.002
341.181
341.181
341.181
961.283
961.283
961.283
002635
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
-653.000
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
56884.002
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
341.181
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
961.283
002636
Monday, July 18, 2011
Balancing Authority
60.04
1.633
ERCOT
60.0084
1.633
Initial P.U. Performance
Initial P.U. Performance Adjusted
1200.0
20 to 52 second Average Period Evaluation
60.02
60
1000.0
961.283
59.98
59.96
800.0
MW
Frequency - Hz
59.94
59.92
600.0
59.9
59.8807
59.88
400.0
59.86
596.15
59.84
200.0
59.82
59.8
59.78
20:49:40
0.00
20:49:50
20:50:00
20:50:10
Hz
20:50:20
20:50:30
Average Frequency
20:50:40
MW
20:50:50
Average MW
20:51:00
20:51:10
EPFR for FRO Adjusted
20:51:20
20:51:30
0.0
20:51:40
002637
Monday, July 18, 2011
ERCOT
No Evaluation
Sustained P.U. Performance
without Adjustments
60.08
1200.0
60.06
60.04
1000.0
60.02
60
800.0
59.98
600.0
59.94
MW
Frequency - Hz
59.96
59.92
400.0
59.9
59.88
200.0
59.86
59.84
0.0
59.82
59.8
-200.0
59.78
59.76
-400.0
20:49:40 20:50:40 20:51:40 20:52:40 20:53:40 20:54:40 20:55:40 20:56:40 20:57:40 20:58:40 20:59:40 21:00:40 21:01:40 21:02:40 21:03:40 21:04:40 21:05:40
Hz
Lost MW
Recovery Period Target MW
Recovery Period Ramp MW
002638
Interconnection Performance
Date
Monday, July 18, 2011
A Point
Time
FPointA
Hz
20:50:38
60.0070
A Value
Hz
60.0084
t(0) Time
20:50:40
C Value
Hz
59.8660
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8751428 -448.21208 59.8798572
-463.9878 59.8807061 -465.09106 59.8804446 -466.08657 59.8807061 -467.01245
002639
Value A Data
Total
Generation
Frequency
Lost
Hz
MW
60.008375
596.15
BA Performance
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Value B
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
0.00
-653 57050.26
Bias
Setting
EPFR
Frequency
MW
Hz
-54.6898 59.875143
12 to 24 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
002640
Value B
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
1.565
Initial
Performance
Unadjusted
P.U.
1.565
Sustained
Performance
P.U.
No Evaluation
18 to 30 second Average Period Evaluation
BA
BA
Bias
Total
Bias
Load
Setting
Generation
Setting
EPFR
Frequency
Lost
MW/0.1 Hz
MW
MW
Hz
MW
-653 56857.57 815.3177 59.879857
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
1.622
002641
Value B
Initial
Performance
Unadjusted
P.U.
1.622
Sustained
Performance
P.U.
No Evaluation
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
Frequency
MW/0.1 Hz
MW
MW
Hz
-653 56872.13 784.5325 59.880182
20 to 40 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
1.626
Initial
Performance
Unadjusted
P.U.
1.626
Sustained
Performance
P.U.
No Evaluation
002642
Value B
18 to 52 second Average Period Evaluation
BA
BA
Bias
Total
Bias
Load
Setting
Generation
Setting
EPFR
Frequency
Lost
MW/0.1 Hz
MW
MW
Hz
MW
-653 56878.66 782.4109 59.880445
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Value B
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
1.629
Initial
Performance
Unadjusted
P.U.
1.629
Sustained
Performance
P.U.
No Evaluation
BA
BA
Bias
Bias
Load
Setting
Setting
EPFR
Frequency
MW/0.1 Hz
MW
MW
Hz
-653 56882.86 780.6965 59.880706
002643
20 to 52 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
0.00
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
1.633
Initial
Performance
Unadjusted
P.U.
1.633
Sustained
Performance
P.U.
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-653
BA
Load
Bias
Setting
EPFR
MW
MW
56884 778.9891
002644
Steps
1
2
3
4
5
6
7
8
9
10
Steps
A
B
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Total Lost Generation: enter the MW data of the units that tripped as a single generator where the value typically goes to zero at t(0).
Column D: not applicable
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: not applicable
Column H: not applicable
Column I: not applicable
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F, G and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must be at 3 second sample rate for the full 25 minute minimum collection period that starts a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event.
The spreadsheet will work with larger sample size data.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data. The data must be numbers not text.
Once data is in place in the "Data" worksheet, determine when the beginning of the event occurred. This is accomplished by knowing the UTC event time from the master event list.
Convert the UTC event time to your PI data time and then scroll through the Data worksheet column B data of frequency and observe when frequency moves from the normal, pre-event frequency.
This will usually be a single change in frequency of 0.008 to 0.010 Hz more or less. Note the row number in the worksheet that this change occurs. In this sample data spreadsheet this occurs in row 313 of the data.
Edit cell "C8" of the "Entry Data" worksheet, change the formula in the cell "C8" to reference the row number identified in step 5 above. In the sample data of this workbook this formula is: "=Data!A313"
Determine the end of the event to be evaluated. Use the same rules that are used for DCS only look at frequency instead of ACE. Scroll down the frequency data in column B of the "Data" worksheet until frequency reaches 60 Hz or the
pre-disturbance value. Note the row number in the worksheet that this occurs. In this sample data spreadsheet this occurs in row 424.
Edit cell "C11" of the "Entry Data" worksheet, change the formula in the cell "C11" to reference the row number identified in step 7 above. In the sample data of this workbook this formula is: "=Data!A424"
Skip for single BA Interconnections.
Use the "copy" button provided to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized in the correct order on worksheet "Form 1 Summary Data" of this workbook.
Use PasteSpecial/Values when pasting the data into FRS Form 1 on the appropriate event row.
To be completed once at the initial setup of the evaluation spreadsheet for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Entry Data" worksheet. For example: "NYISO".
Enter your Balancing Authorities Frequency Response Obligation in cell "B2" of the "Entry Data" worksheet. For example: -80 MW/0.1 Hz (This value could change annually)
Note: For ease of use, only the necessary worksheets are displayed. If you are interested in viewing graphs and other hidden worksheets, select the "tab" at the bottom, right click, select unhide and select the worksheet you wish to unhide.
wish to unhide.
002645
002646
mm/dd/yy hh:mm:ss
Frequency
Time (T)
Hz
10/12/09 02:12:00
10/12/09 02:12:03
10/12/09 02:12:06
10/12/09 02:12:09
10/12/09 02:12:12
10/12/09 02:12:15
10/12/09 02:12:18
10/12/09 02:12:21
10/12/09 02:12:24
10/12/09 02:12:27
10/12/09 02:12:30
10/12/09 02:12:33
10/12/09 02:12:36
10/12/09 02:12:39
10/12/09 02:12:42
10/12/09 02:12:45
10/12/09 02:12:48
10/12/09 02:12:51
10/12/09 02:12:54
10/12/09 02:12:57
10/12/09 02:13:00
10/12/09 02:13:03
10/12/09 02:13:06
10/12/09 02:13:09
10/12/09 02:13:12
10/12/09 02:13:15
10/12/09 02:13:18
10/12/09 02:13:21
10/12/09 02:13:24
10/12/09 02:13:27
10/12/09 02:13:30
10/12/09 02:13:33
10/12/09 02:13:36
10/12/09 02:13:39
10/12/09 02:13:42
10/12/09 02:13:45
10/12/09 02:13:48
10/12/09 02:13:51
10/12/09 02:13:54
10/12/09 02:13:57
10/12/09 02:14:00
10/12/09 02:14:03
10/12/09 02:14:06
10/12/09 02:14:09
59.980999
59.9799995
59.9819984
59.980999
59.980999
59.9819984
59.9790001
59.9799995
59.9830017
59.9860001
59.9799995
59.9760017
59.9790001
59.980999
59.9869995
59.9900017
59.9939995
59.9949989
59.9949989
59.9949989
59.9939995
59.9939995
59.9970016
60.0009995
60.0009995
60.0029984
60.0050011
60.0029984
60.0009995
60.0029984
60.0050011
60.0009995
60.0009995
60.0040016
60.0040016
60.0040016
60.0029984
60.0019989
60.0009995
59.9990005
59.9970016
59.9980011
59.9949989
59.993
Total
Lost
Generation
MW
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
351.3615112
0
351.3615112
0
351.3615112
0
357.9475098
0
357.9475098
0
357.9475098
0
357.9475098
0
357.9475098
0
360.2347412
0
360.2347412
0
360.2347412
0
360.2347412
0
360.2347412
0
346.5258789
0
346.5258789
0
346.5258789
0
346.5258789
0
346.5258789
0
296.4433594
0
296.4433594
0
296.4433594
0
296.4433594
0
296.4433594
0
341.0611572
0
341.0611572
0
341.0611572
0
341.0611572
0
341.0611572
0
322.8262939
0
322.8262939
0
322.8262939
0
322.8262939
0
322.8262939
0
321.5444031
0
321.5444031
0
321.5444031
0
321.5444031
0
321.5444031
0
362.136261
0
362.136261
0
362.136261
0
362.136261
0
362.136261
0
336.3117981
0
Transferred
Frequency
Response
n/a
Contingent
BA
Lost Generation
n/a
BA
Bias
Setting
MW/0.1 Hz
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
BA
Load
MW
7500
7500.33
7500.66
7500.99
7501.32
7501.65
7501.98
7502.31
7502.64
7502.97
7503.3
7503.63
7503.96
7504.29
7504.62
7504.95
7505.28
7505.61
7505.94
7506.27
7506.6
7506.93
7507.26
7507.59
7507.92
7508.25
7508.58
7508.91
7509.24
7509.57
7509.9
7510.23
7510.56
7510.89
7511.22
7511.55
7511.88
7512.21
7512.54
7512.87
7513.2
7513.53
7513.86
7514.19
LaaR Tripped
0
002647
10/12/09 02:14:12
10/12/09 02:14:15
10/12/09 02:14:18
10/12/09 02:14:21
10/12/09 02:14:24
10/12/09 02:14:27
10/12/09 02:14:30
10/12/09 02:14:33
10/12/09 02:14:36
10/12/09 02:14:39
10/12/09 02:14:42
10/12/09 02:14:45
10/12/09 02:14:48
10/12/09 02:14:51
10/12/09 02:14:54
10/12/09 02:14:57
10/12/09 02:15:00
10/12/09 02:15:03
10/12/09 02:15:06
10/12/09 02:15:09
10/12/09 02:15:12
10/12/09 02:15:15
10/12/09 02:15:18
10/12/09 02:15:21
10/12/09 02:15:24
10/12/09 02:15:27
10/12/09 02:15:30
10/12/09 02:15:33
10/12/09 02:15:36
10/12/09 02:15:39
10/12/09 02:15:42
10/12/09 02:15:45
10/12/09 02:15:48
10/12/09 02:15:51
10/12/09 02:15:54
10/12/09 02:15:57
10/12/09 02:16:00
10/12/09 02:16:03
10/12/09 02:16:06
10/12/09 02:16:09
10/12/09 02:16:12
10/12/09 02:16:15
10/12/09 02:16:18
10/12/09 02:16:21
10/12/09 02:16:24
10/12/09 02:16:27
10/12/09 02:16:30
10/12/09 02:16:33
10/12/09 02:16:36
59.9959984
59.9990005
60.0050011
60.007
60.0050011
60.0019989
59.9970016
59.9990005
60.007
60.0099983
60.0089989
60.0029984
59.9949989
59.9939995
60
60.0009995
59.9980011
59.9949989
59.9860001
59.9860001
59.987999
59.9889984
59.9869995
59.9850006
59.9830017
59.9819984
59.9840012
59.9850006
59.9869995
59.9900017
59.9869995
59.9830017
59.9790001
59.9830017
59.9860001
59.987999
59.9830017
59.9780006
59.9790001
59.9889984
59.987999
59.9830017
59.9910011
59.9889984
59.993
59.9949989
59.9980011
59.9980011
59.9990005
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
336.3117981
336.3117981
336.3117981
336.3117981
316.4430542
316.4430542
316.4430542
316.4430542
316.4430542
325.4642944
325.4642944
325.4642944
325.4642944
325.4642944
336.6141663
336.6141663
336.6141663
336.6141663
336.6141663
316.7261658
316.7261658
316.7261658
316.7261658
316.7261658
320.1955261
320.1955261
320.1955261
320.1955261
320.1955261
341.8661499
341.8661499
341.8661499
341.8661499
341.8661499
348.5978394
348.5978394
348.5978394
348.5978394
348.5978394
329.085022
329.085022
329.085022
329.085022
329.085022
342.4182434
342.4182434
342.4182434
342.4182434
342.4182434
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7514.52
7514.85
7515.18
7515.51
7515.84
7516.17
7516.5
7516.83
7517.16
7517.49
7517.82
7518.15
7518.48
7518.81
7519.14
7519.47
7519.8
7520.13
7520.46
7520.79
7521.12
7521.45
7521.78
7522.11
7522.44
7522.77
7523.1
7523.43
7523.76
7524.09
7524.42
7524.75
7525.08
7525.41
7525.74
7526.07
7526.4
7526.73
7527.06
7527.39
7527.72
7528.05
7528.38
7528.71
7529.04
7529.37
7529.7
7530.03
7530.36
002648
10/12/09 02:16:39
10/12/09 02:16:42
10/12/09 02:16:45
10/12/09 02:16:48
10/12/09 02:16:51
10/12/09 02:16:54
10/12/09 02:16:57
10/12/09 02:17:00
10/12/09 02:17:03
10/12/09 02:17:06
10/12/09 02:17:09
10/12/09 02:17:12
10/12/09 02:17:15
10/12/09 02:17:18
10/12/09 02:17:21
10/12/09 02:17:24
10/12/09 02:17:27
10/12/09 02:17:30
10/12/09 02:17:33
10/12/09 02:17:36
10/12/09 02:17:39
10/12/09 02:17:42
10/12/09 02:17:45
10/12/09 02:17:48
10/12/09 02:17:51
10/12/09 02:17:54
10/12/09 02:17:57
10/12/09 02:18:00
10/12/09 02:18:03
10/12/09 02:18:06
10/12/09 02:18:09
10/12/09 02:18:12
10/12/09 02:18:15
10/12/09 02:18:18
10/12/09 02:18:21
10/12/09 02:18:24
10/12/09 02:18:27
10/12/09 02:18:30
10/12/09 02:18:33
10/12/09 02:18:36
10/12/09 02:18:39
10/12/09 02:18:42
10/12/09 02:18:45
10/12/09 02:18:48
10/12/09 02:18:51
10/12/09 02:18:54
10/12/09 02:18:57
10/12/09 02:19:00
10/12/09 02:19:03
59.9949989
59.9920006
59.9949989
60.0009995
60.0029984
60.0089989
60.0089989
60.012001
60.0110016
60.0079994
60.007
60.012001
60.0130005
60.0099983
60.007
60.0089989
60.0060005
60.0089989
60.0089989
60.0089989
60.0089989
60.0040016
60.0009995
59.993
59.9910011
59.9920006
59.9939995
59.9939995
59.9949989
59.9900017
59.9900017
59.9830017
59.9770012
59.9889984
59.9949989
59.9939995
59.9889984
59.9860001
59.9840012
59.9850006
59.9860001
59.9860001
59.9799995
59.980999
59.9889984
60.007
60.007
59.9860001
59.980999
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
338.7946472
338.7946472
338.7946472
338.7946472
338.7946472
335.9309998
335.9309998
335.9309998
335.9309998
335.9309998
339.7124023
339.7124023
339.7124023
339.7124023
339.7124023
332.0246582
332.0246582
332.0246582
332.0246582
332.0246582
330.7590332
330.7590332
330.7590332
330.7590332
330.7590332
323.4199524
323.4199524
323.4199524
323.4199524
323.4199524
342.3509216
342.3509216
342.3509216
342.3509216
342.3509216
345.0818176
345.0818176
345.0818176
345.0818176
345.0818176
346.537384
346.537384
346.537384
346.537384
346.537384
342.9057617
342.9057617
342.9057617
342.9057617
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7530.69
7531.02
7531.35
7531.68
7532.01
7532.34
7532.67
7533
7533.33
7533.66
7533.99
7534.32
7534.65
7534.98
7535.31
7535.64
7535.97
7536.3
7536.63
7536.96
7537.29
7537.62
7537.95
7538.28
7538.61
7538.94
7539.27
7539.6
7539.93
7540.26
7540.59
7540.92
7541.25
7541.58
7541.91
7542.24
7542.57
7542.9
7543.23
7543.56
7543.89
7544.22
7544.55
7544.88
7545.21
7545.54
7545.87
7546.2
7546.53
002649
10/12/09 02:19:06
10/12/09 02:19:09
10/12/09 02:19:12
10/12/09 02:19:15
10/12/09 02:19:18
10/12/09 02:19:21
10/12/09 02:19:24
10/12/09 02:19:27
10/12/09 02:19:30
10/12/09 02:19:33
10/12/09 02:19:36
10/12/09 02:19:39
10/12/09 02:19:42
10/12/09 02:19:45
10/12/09 02:19:48
10/12/09 02:19:51
10/12/09 02:19:54
10/12/09 02:19:57
10/12/09 02:20:00
10/12/09 02:20:03
10/12/09 02:20:06
10/12/09 02:20:09
10/12/09 02:20:12
10/12/09 02:20:15
10/12/09 02:20:18
10/12/09 02:20:21
10/12/09 02:20:24
10/12/09 02:20:27
10/12/09 02:20:30
10/12/09 02:20:33
10/12/09 02:20:36
10/12/09 02:20:39
10/12/09 02:20:42
10/12/09 02:20:45
10/12/09 02:20:48
10/12/09 02:20:51
10/12/09 02:20:54
10/12/09 02:20:57
10/12/09 02:21:00
10/12/09 02:21:03
10/12/09 02:21:06
10/12/09 02:21:09
10/12/09 02:21:12
10/12/09 02:21:15
10/12/09 02:21:18
10/12/09 02:21:21
10/12/09 02:21:24
10/12/09 02:21:27
10/12/09 02:21:30
59.973999
59.9760017
59.973999
59.9770012
59.9790001
59.9819984
59.9869995
59.987999
59.9869995
59.9869995
59.9850006
59.9840012
59.9830017
59.9889984
59.987999
59.9840012
59.9830017
59.980999
59.9830017
59.9860001
59.9869995
59.9850006
59.9799995
59.9830017
59.9790001
59.9790001
59.980999
59.9799995
59.980999
59.9799995
59.9770012
59.9790001
59.9790001
59.9760017
59.9720001
59.9710007
59.9729996
59.9729996
59.9710007
59.9749985
59.9770012
59.9749985
59.9799995
59.9790001
59.9819984
59.9819984
59.9819984
59.980999
59.9840012
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
342.9057617
340.0943909
340.0943909
340.0943909
340.0943909
340.0943909
342.7711792
342.7711792
342.7711792
342.7711792
342.7711792
342.9099121
342.9099121
342.9099121
342.9099121
342.9099121
343.2860107
343.2860107
343.2860107
343.2860107
343.2860107
331.8529663
331.8529663
331.8529663
331.8529663
331.8529663
329.9882202
329.9882202
329.9882202
329.9882202
329.9882202
255.4441681
255.4441681
255.4441681
255.4441681
255.4441681
254.8383026
254.8383026
254.8383026
254.8383026
254.8383026
257.1469727
257.1469727
257.1469727
257.1469727
257.1469727
262.2893677
262.2893677
262.2893677
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7546.86
7547.19
7547.52
7547.85
7548.18
7548.51
7548.84
7549.17
7549.5
7549.83
7550.16
7550.49
7550.82
7551.15
7551.48
7551.81
7552.14
7552.47
7552.8
7553.13
7553.46
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
002650
10/12/09 02:21:33
10/12/09 02:21:36
10/12/09 02:21:39
10/12/09 02:21:42
10/12/09 02:21:45
10/12/09 02:21:48
10/12/09 02:21:51
10/12/09 02:21:54
10/12/09 02:21:57
10/12/09 02:22:00
10/12/09 02:22:03
10/12/09 02:22:06
10/12/09 02:22:09
10/12/09 02:22:12
10/12/09 02:22:15
10/12/09 02:22:18
10/12/09 02:22:21
10/12/09 02:22:24
10/12/09 02:22:27
10/12/09 02:22:30
10/12/09 02:22:33
10/12/09 02:22:36
10/12/09 02:22:39
10/12/09 02:22:42
10/12/09 02:22:45
10/12/09 02:22:48
10/12/09 02:22:51
10/12/09 02:22:54
10/12/09 02:22:57
10/12/09 02:23:00
10/12/09 02:23:03
10/12/09 02:23:06
10/12/09 02:23:09
10/12/09 02:23:12
10/12/09 02:23:15
10/12/09 02:23:18
10/12/09 02:23:21
10/12/09 02:23:24
10/12/09 02:23:27
10/12/09 02:23:30
10/12/09 02:23:33
10/12/09 02:23:36
10/12/09 02:23:39
10/12/09 02:23:42
10/12/09 02:23:45
10/12/09 02:23:48
10/12/09 02:23:51
10/12/09 02:23:54
10/12/09 02:23:57
59.9850006
59.9889984
59.993
59.9980011
59.9980011
60.007
60.0099983
60.0139999
60.0130005
60.0079994
60.0099983
60.019001
60.0229988
60.0200005
60.0209999
60.0200005
60.019001
60.0219994
60.0250015
60.026001
60.0200005
60.0180016
60.0180016
60.019001
60.019001
60.0219994
60.0219994
60.0200005
60.0200005
60.0200005
60.0200005
60.0209999
60.0180016
60.0139999
60.0139999
60.0130005
60.0099983
60.0110016
60.0110016
60.012001
60.0089989
60.0089989
60.0089989
60.0019989
59.9990005
59.9949989
59.9970016
59.9980011
59.9980011
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
262.2893677
262.2893677
256.6479492
256.6479492
256.6479492
256.6479492
256.6479492
256.307251
256.307251
256.307251
256.307251
256.307251
249.0863953
249.0863953
249.0863953
249.0863953
249.0863953
253.7424774
253.7424774
253.7424774
253.7424774
253.7424774
257.4212036
257.4212036
257.4212036
257.4212036
257.4212036
261.7382202
261.7382202
261.7382202
261.7382202
261.7382202
271.8759766
271.8759766
271.8759766
271.8759766
271.8759766
262.0734863
262.0734863
262.0734863
262.0734863
262.0734863
260.3644104
260.3644104
260.3644104
260.3644104
260.3644104
352.6443787
352.6443787
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
002651
10/12/09 02:24:00
10/12/09 02:24:03
10/12/09 02:24:06
10/12/09 02:24:09
10/12/09 02:24:12
10/12/09 02:24:15
10/12/09 02:24:18
10/12/09 02:24:21
10/12/09 02:24:24
10/12/09 02:24:27
10/12/09 02:24:30
10/12/09 02:24:33
10/12/09 02:24:36
10/12/09 02:24:39
10/12/09 02:24:42
10/12/09 02:24:45
10/12/09 02:24:48
10/12/09 02:24:51
10/12/09 02:24:54
10/12/09 02:24:57
10/12/09 02:25:00
10/12/09 02:25:03
10/12/09 02:25:06
10/12/09 02:25:09
10/12/09 02:25:12
10/12/09 02:25:15
10/12/09 02:25:18
10/12/09 02:25:21
10/12/09 02:25:24
10/12/09 02:25:27
10/12/09 02:25:30
10/12/09 02:25:33
10/12/09 02:25:36
10/12/09 02:25:39
10/12/09 02:25:42
10/12/09 02:25:45
10/12/09 02:25:48
10/12/09 02:25:51
10/12/09 02:25:54
10/12/09 02:25:57
10/12/09 02:26:00
10/12/09 02:26:03
10/12/09 02:26:06
10/12/09 02:26:09
10/12/09 02:26:12
10/12/09 02:26:15
10/12/09 02:26:18
10/12/09 02:26:21
10/12/09 02:26:24
59.9949989
59.9949989
59.993
59.987999
59.9819984
59.9819984
59.9819984
59.9840012
59.9780006
59.9780006
59.9749985
59.973999
59.9790001
59.9799995
59.9799995
59.9840012
59.987999
59.987999
59.9920006
59.9910011
59.9910011
59.993
59.9959984
60.0019989
60.0029984
60.0040016
60.0040016
60.0019989
60.0079994
60.0099983
60.0099983
60.0110016
60.0139999
60.0130005
60.0110016
60.0110016
60.0219994
60.0169983
60.0130005
60.0139999
60.0169983
60.019001
60.019001
60.0270004
60.026001
60.0219994
60.0169983
60.019001
60.019001
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
352.6443787
352.6443787
352.6443787
354.8956604
354.8956604
354.8956604
354.8956604
354.8956604
340.4693604
340.4693604
340.4693604
340.4693604
340.4693604
337.6429138
337.6429138
337.6429138
337.6429138
337.6429138
284.3608398
284.3608398
284.3608398
284.3608398
284.3608398
260.4679871
260.4679871
260.4679871
260.4679871
260.4679871
253.1415405
253.1415405
253.1415405
253.1415405
253.1415405
251.9298706
251.9298706
251.9298706
251.9298706
251.9298706
250.6741943
250.6741943
250.6741943
250.6741943
250.6741943
253.6318665
253.6318665
253.6318665
253.6318665
253.6318665
246.9573059
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
002652
10/12/09 02:26:27
10/12/09 02:26:30
10/12/09 02:26:33
10/12/09 02:26:36
10/12/09 02:26:39
10/12/09 02:26:42
10/12/09 02:26:45
10/12/09 02:26:48
10/12/09 02:26:51
10/12/09 02:26:54
10/12/09 02:26:57
10/12/09 02:27:00
10/12/09 02:27:03
10/12/09 02:27:06
10/12/09 02:27:09
10/12/09 02:27:12
10/12/09 02:27:15
10/12/09 02:27:18
10/12/09 02:27:21
10/12/09 02:27:24
10/12/09 02:27:27
10/12/09 02:27:30
10/12/09 02:27:33
10/12/09 02:27:36
10/12/09 02:27:39
10/12/09 02:27:42
10/12/09 02:27:45
10/12/09 02:27:48
10/12/09 02:27:51
10/12/09 02:27:54
10/12/09 02:27:57
10/12/09 02:28:00
10/12/09 02:28:03
10/12/09 02:28:06
10/12/09 02:28:09
10/12/09 02:28:12
10/12/09 02:28:15
10/12/09 02:28:18
10/12/09 02:28:21
10/12/09 02:28:24
10/12/09 02:28:27
10/12/09 02:28:30
10/12/09 02:28:33
10/12/09 02:28:36
10/12/09 02:28:39
10/12/09 02:28:42
10/12/09 02:28:45
10/12/09 02:28:48
10/12/09 02:28:51
60.0209999
60.0209999
60.019001
60.0219994
60.0309982
60.0369987
60.0359993
60.0460014
60.0480003
60.0429993
60.0410004
60.0410004
60.0390015
60.0429993
60.0449982
60.0410004
60.0410004
60.0390015
59.9780006
59.8359985
59.8689995
59.8909988
59.8800011
59.875
59.8829994
59.8860016
59.8849983
59.8880005
59.8899994
59.894001
59.8930016
59.894001
59.8909988
59.8849983
59.8849983
59.887001
59.8880005
59.8899994
59.8889999
59.8730011
59.8569984
59.8520012
59.8580017
59.8660011
59.8650017
59.8660011
59.8709984
59.8790016
59.8800011
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
246.9573059
246.9573059
246.9573059
246.9573059
254.5417786
254.5417786
254.5417786
254.5417786
165.1016846
165.1016846
165.1016846
165.1016846
165.1016846
165.4763947
165.4763947
165.4763947
165.4763947
165.4763947
206.4591064
206.4591064
206.4591064
206.4591064
206.4591064
211.2560425
211.2560425
211.2560425
211.2560425
211.2560425
214.3466949
214.3466949
214.3466949
214.3466949
214.3466949
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
215.598175
215.598175
215.598175
218.3272552
218.3272552
218.3272552
218.3272552
218.3272552
217.379425
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7570
7569
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7570
7568
7565
7560
7563
7564
7566
7570
7570
7570
7570
002653
10/12/09 02:28:54
10/12/09 02:28:57
10/12/09 02:29:00
10/12/09 02:29:03
10/12/09 02:29:06
10/12/09 02:29:09
10/12/09 02:29:12
10/12/09 02:29:15
10/12/09 02:29:18
10/12/09 02:29:21
10/12/09 02:29:24
10/12/09 02:29:27
10/12/09 02:29:30
10/12/09 02:29:33
10/12/09 02:29:36
10/12/09 02:29:39
10/12/09 02:29:42
10/12/09 02:29:45
10/12/09 02:29:48
10/12/09 02:29:51
10/12/09 02:29:54
10/12/09 02:29:57
10/12/09 02:30:00
10/12/09 02:30:03
10/12/09 02:30:06
10/12/09 02:30:09
10/12/09 02:30:12
10/12/09 02:30:15
10/12/09 02:30:18
10/12/09 02:30:21
10/12/09 02:30:24
10/12/09 02:30:27
10/12/09 02:30:30
10/12/09 02:30:33
10/12/09 02:30:36
10/12/09 02:30:39
10/12/09 02:30:42
10/12/09 02:30:45
10/12/09 02:30:48
10/12/09 02:30:51
10/12/09 02:30:54
10/12/09 02:30:57
10/12/09 02:31:00
10/12/09 02:31:03
10/12/09 02:31:06
10/12/09 02:31:09
10/12/09 02:31:12
10/12/09 02:31:15
10/12/09 02:31:18
59.8860016
59.8899994
59.8889999
59.8930016
59.9029999
59.9020004
59.9039993
59.9070015
59.9160004
59.9160004
59.9179993
59.9199982
59.9199982
59.9169998
59.9210014
59.9230003
59.9249992
59.9280014
59.9319992
59.9269981
59.9309998
59.9290009
59.9309998
59.9370003
59.9449997
59.9490013
59.9420013
59.9410019
59.9449997
59.9480019
59.9490013
59.9510002
59.9529991
59.9510002
59.9519997
59.9519997
59.9519997
59.9539986
59.9529991
59.9529991
59.9539986
59.9539986
59.9570007
59.9560013
59.9560013
59.9550018
59.9609985
59.9620018
59.9679985
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
217.379425
217.379425
217.379425
217.379425
214.8303528
214.8303528
214.8303528
214.8303528
214.8303528
227.6559143
227.6559143
227.6559143
227.6559143
227.6559143
225.0180817
225.0180817
225.0180817
225.0180817
225.0180817
228.3651581
228.3651581
228.3651581
228.3651581
228.3651581
234.0753326
234.0753326
234.0753326
234.0753326
234.0753326
228.7981567
228.7981567
228.7981567
228.7981567
228.7981567
229.4669647
249.3375702
249.3375702
249.3375702
249.3375702
249.3375702
258.2781677
258.2781677
258.2781677
258.2781677
258.2781677
258.4063721
258.4063721
258.4063721
258.4063721
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7570
7569
7575
7573
7571
7573
7575
7577
7577
7578
7579
7580
7581
7585
7588
7589
7589
7590
7590
7590
7591
7591
7591
7592
7592
7593
7594
7595
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
002654
10/12/09 02:31:21
10/12/09 02:31:24
10/12/09 02:31:27
10/12/09 02:31:30
10/12/09 02:31:33
10/12/09 02:31:36
10/12/09 02:31:39
10/12/09 02:31:42
10/12/09 02:31:45
10/12/09 02:31:48
10/12/09 02:31:51
10/12/09 02:31:54
10/12/09 02:31:57
10/12/09 02:32:00
10/12/09 02:32:03
10/12/09 02:32:06
10/12/09 02:32:09
10/12/09 02:32:12
10/12/09 02:32:15
10/12/09 02:32:18
10/12/09 02:32:21
10/12/09 02:32:24
10/12/09 02:32:27
10/12/09 02:32:30
10/12/09 02:32:33
10/12/09 02:32:36
10/12/09 02:32:39
10/12/09 02:32:42
10/12/09 02:32:45
10/12/09 02:32:48
10/12/09 02:32:51
10/12/09 02:32:54
10/12/09 02:32:57
10/12/09 02:33:00
10/12/09 02:33:03
10/12/09 02:33:06
10/12/09 02:33:09
10/12/09 02:33:12
10/12/09 02:33:15
10/12/09 02:33:18
10/12/09 02:33:21
10/12/09 02:33:24
10/12/09 02:33:27
10/12/09 02:33:30
10/12/09 02:33:33
10/12/09 02:33:36
10/12/09 02:33:39
10/12/09 02:33:42
10/12/09 02:33:45
59.9659996
59.9679985
59.9700012
59.9700012
59.9690018
59.9700012
59.9710007
59.9729996
59.9760017
59.9780006
59.9760017
59.9760017
59.9780006
59.9799995
59.9819984
59.9799995
59.9790001
59.9790001
59.9830017
59.9840012
59.987999
59.9869995
59.9869995
59.993
59.9920006
59.9889984
59.9860001
59.9830017
59.987999
59.9959984
59.9980011
60.0009995
59.9990005
59.9990005
60.0019989
60.007
60.0079994
60.0139999
60.0169983
60.0209999
60.0169983
60.019001
60.0229988
60.0250015
60.0209999
60.0239983
60.0239983
60.0200005
60.0250015
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
258.4063721
260.5388794
260.5388794
260.5388794
260.5388794
260.5388794
257.8820801
257.8820801
257.8820801
257.8820801
257.8820801
258.5886536
258.5886536
258.5886536
258.5886536
258.5886536
261.9061584
261.9061584
261.9061584
261.9061584
261.9061584
256.7478027
256.7478027
256.7478027
256.7478027
256.7478027
167.4319763
167.4319763
167.4319763
167.4319763
167.4319763
164.9734039
164.9734039
164.9734039
164.9734039
164.9734039
157.6280823
157.6280823
157.6280823
157.6280823
157.6280823
155.5317078
155.5317078
155.5317078
155.5317078
155.5317078
160.4472351
160.4472351
160.4472351
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
002655
10/12/09 02:33:48
10/12/09 02:33:51
10/12/09 02:33:54
10/12/09 02:33:57
10/12/09 02:34:00
10/12/09 02:34:03
10/12/09 02:34:06
10/12/09 02:34:09
10/12/09 02:34:12
10/12/09 02:34:15
10/12/09 02:34:18
10/12/09 02:34:21
10/12/09 02:34:24
10/12/09 02:34:27
10/12/09 02:34:30
10/12/09 02:34:33
10/12/09 02:34:36
10/12/09 02:34:39
10/12/09 02:34:42
10/12/09 02:34:45
10/12/09 02:34:48
10/12/09 02:34:51
10/12/09 02:34:54
10/12/09 02:34:57
10/12/09 02:35:00
10/12/09 02:35:03
10/12/09 02:35:06
10/12/09 02:35:09
10/12/09 02:35:12
10/12/09 02:35:15
10/12/09 02:35:18
10/12/09 02:35:21
10/12/09 02:35:24
10/12/09 02:35:27
10/12/09 02:35:30
10/12/09 02:35:33
10/12/09 02:35:36
10/12/09 02:35:39
10/12/09 02:35:42
10/12/09 02:35:45
10/12/09 02:35:48
10/12/09 02:35:51
10/12/09 02:35:54
10/12/09 02:35:57
10/12/09 02:36:00
10/12/09 02:36:03
10/12/09 02:36:06
10/12/09 02:36:09
10/12/09 02:36:12
60.0200005
60.0200005
60.0219994
60.0219994
60.0209999
60.0229988
60.0219994
60.019001
60.0180016
60.0180016
60.019001
60.019001
60.0149994
60.0159988
60.0130005
60.012001
60.0099983
60.007
60.0089989
60.0089989
60.0029984
59.9990005
59.9920006
59.9910011
59.9920006
59.987999
59.9850006
59.9840012
59.9840012
59.9819984
59.9819984
59.9790001
59.9760017
59.9760017
59.9819984
59.9780006
59.973999
59.9760017
59.9770012
59.9749985
59.9690018
59.9700012
59.9729996
59.9780006
59.9780006
59.9749985
59.9760017
59.9749985
59.9690018
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
160.4472351
160.4472351
163.9586029
163.9586029
163.9586029
163.9586029
163.9586029
166.0724487
166.0724487
166.0724487
166.0724487
166.0724487
163.7665863
163.7665863
163.7665863
163.7665863
163.7665863
165.1016846
165.1016846
165.1016846
165.1016846
165.1016846
165.4763947
165.4763947
165.4763947
165.4763947
165.4763947
206.4591064
206.4591064
206.4591064
206.4591064
206.4591064
211.2560425
211.2560425
211.2560425
211.2560425
211.2560425
214.3466949
214.3466949
214.3466949
214.3466949
214.3466949
212.172699
212.172699
212.172699
212.172699
212.172699
215.598175
215.598175
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
002656
10/12/09 02:36:15
10/12/09 02:36:18
10/12/09 02:36:21
10/12/09 02:36:24
10/12/09 02:36:27
10/12/09 02:36:30
10/12/09 02:36:33
10/12/09 02:36:36
10/12/09 02:36:39
10/12/09 02:36:42
10/12/09 02:36:45
10/12/09 02:36:48
10/12/09 02:36:51
10/12/09 02:36:54
10/12/09 02:36:57
10/12/09 02:37:00
10/12/09 02:37:03
10/12/09 02:37:06
10/12/09 02:37:09
10/12/09 02:37:12
10/12/09 02:37:15
10/12/09 02:37:18
10/12/09 02:37:21
10/12/09 02:37:24
10/12/09 02:37:27
10/12/09 02:37:30
10/12/09 02:37:33
10/12/09 02:37:36
10/12/09 02:37:39
10/12/09 02:37:42
10/12/09 02:37:45
10/12/09 02:37:48
10/12/09 02:37:51
10/12/09 02:37:54
10/12/09 02:37:57
10/12/09 02:38:00
10/12/09 02:38:03
10/12/09 02:38:06
10/12/09 02:38:09
10/12/09 02:38:12
10/12/09 02:38:15
10/12/09 02:38:18
10/12/09 02:38:21
10/12/09 02:38:24
10/12/09 02:38:27
10/12/09 02:38:30
10/12/09 02:38:33
10/12/09 02:38:36
10/12/09 02:38:39
59.9659996
59.9659996
59.9690018
59.9679985
59.9650002
59.9700012
59.9720001
59.9669991
59.9690018
59.9690018
59.9669991
59.9659996
59.9650002
59.9669991
59.9650002
59.9640007
59.9700012
59.9690018
59.9679985
59.9650002
59.9700012
59.9679985
59.9650002
59.9690018
59.9669991
59.9659996
59.9790001
59.9830017
59.973999
59.9650002
59.9620018
59.9609985
59.9609985
59.9630013
59.9589996
59.9510002
59.9529991
59.9570007
59.9560013
59.9630013
59.9609985
59.9630013
59.9630013
59.9679985
59.9679985
59.9700012
59.9729996
59.9650002
59.9669991
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
215.598175
215.598175
215.598175
218.3272552
218.3272552
218.3272552
218.3272552
218.3272552
217.379425
217.379425
217.379425
217.379425
217.379425
214.8303528
214.8303528
214.8303528
214.8303528
214.8303528
227.6559143
227.6559143
227.6559143
227.6559143
227.6559143
225.0180817
225.0180817
225.0180817
225.0180817
225.0180817
228.3651581
228.3651581
228.3651581
228.3651581
228.3651581
234.0753326
234.0753326
234.0753326
234.0753326
234.0753326
228.7981567
228.7981567
228.7981567
228.7981567
228.7981567
229.4669647
229.4669647
229.4669647
229.4669647
229.4669647
228.9801636
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
002657
10/12/09 02:38:42
10/12/09 02:38:45
10/12/09 02:38:48
10/12/09 02:38:51
10/12/09 02:38:54
10/12/09 02:38:57
10/12/09 02:39:00
10/12/09 02:39:03
10/12/09 02:39:06
10/12/09 02:39:09
10/12/09 02:39:12
10/12/09 02:39:15
10/12/09 02:39:18
10/12/09 02:39:21
10/12/09 02:39:24
10/12/09 02:39:27
10/12/09 02:39:30
10/12/09 02:39:33
10/12/09 02:39:36
10/12/09 02:39:39
10/12/09 02:39:42
10/12/09 02:39:45
10/12/09 02:39:48
10/12/09 02:39:51
10/12/09 02:39:54
10/12/09 02:39:57
10/12/09 02:40:00
10/12/09 02:40:03
10/12/09 02:40:06
10/12/09 02:40:09
10/12/09 02:40:12
10/12/09 02:40:15
10/12/09 02:40:18
10/12/09 02:40:21
10/12/09 02:40:24
10/12/09 02:40:27
10/12/09 02:40:30
10/12/09 02:40:33
10/12/09 02:40:36
10/12/09 02:40:39
10/12/09 02:40:42
10/12/09 02:40:45
10/12/09 02:40:48
10/12/09 02:40:51
10/12/09 02:40:54
10/12/09 02:40:57
10/12/09 02:41:00
10/12/09 02:41:03
10/12/09 02:41:06
59.9720001
59.9760017
59.9690018
59.9729996
59.9780006
59.980999
59.980999
59.9819984
59.9840012
59.9819984
59.9790001
59.9799995
59.9780006
59.9799995
59.9799995
59.9780006
59.9720001
59.9710007
59.973999
59.9749985
59.9720001
59.9690018
59.973999
59.9720001
59.9720001
59.9770012
59.9780006
59.9760017
59.973999
59.9770012
59.9780006
59.9790001
59.9770012
59.973999
59.9710007
59.9710007
59.9679985
59.9659996
59.9710007
59.9729996
59.9690018
59.9720001
59.9729996
59.9700012
59.973999
59.9819984
59.9850006
59.9850006
59.9889984
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
228.9801636
228.9801636
228.9801636
228.9801636
219.9755554
219.9755554
219.9755554
219.9755554
219.9755554
229.0892487
229.0892487
229.0892487
229.0892487
229.0892487
229.663269
229.663269
229.663269
229.663269
229.663269
229.2338562
229.2338562
229.2338562
229.2338562
229.2338562
231.4098816
231.4098816
231.4098816
231.4098816
231.4098816
218.6222839
218.6222839
218.6222839
218.6222839
218.6222839
213.5358582
213.5358582
213.5358582
213.5358582
213.5358582
225.6518555
225.6518555
225.6518555
225.6518555
225.6518555
212.5736389
212.5736389
212.5736389
212.5736389
212.5736389
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
002658
10/12/09 02:41:09
10/12/09 02:41:12
10/12/09 02:41:15
10/12/09 02:41:18
10/12/09 02:41:21
10/12/09 02:41:24
10/12/09 02:41:27
10/12/09 02:41:30
10/12/09 02:41:33
10/12/09 02:41:36
10/12/09 02:41:39
10/12/09 02:41:42
10/12/09 02:41:45
10/12/09 02:41:48
10/12/09 02:41:51
10/12/09 02:41:54
10/12/09 02:41:57
10/12/09 02:42:00
10/12/09 02:42:03
10/12/09 02:42:06
10/12/09 02:42:09
10/12/09 02:42:12
10/12/09 02:42:15
10/12/09 02:42:18
10/12/09 02:42:21
10/12/09 02:42:24
10/12/09 02:42:27
10/12/09 02:42:30
10/12/09 02:42:33
10/12/09 02:42:36
10/12/09 02:42:39
10/12/09 02:42:42
10/12/09 02:42:45
10/12/09 02:42:48
10/12/09 02:42:51
10/12/09 02:42:54
10/12/09 02:42:57
10/12/09 02:43:00
10/12/09 02:43:03
10/12/09 02:43:06
10/12/09 02:43:09
10/12/09 02:43:12
10/12/09 02:43:15
10/12/09 02:43:18
10/12/09 02:43:21
10/12/09 02:43:24
10/12/09 02:43:27
10/12/09 02:43:30
10/12/09 02:43:33
59.9889984
59.9869995
59.9900017
59.9959984
60.0009995
60.0040016
60.0060005
60.0139999
60.019001
60.0250015
60.026001
60.0289993
60.0289993
60.0359993
60.0369987
60.0359993
60.0410004
60.0439987
60.0429993
60.0480003
60.0460014
60.0429993
60.0429993
60.0429993
60.0429993
60.0400009
60.0410004
60.0390015
60.0359993
60.0330009
60.0340004
60.0369987
60.0349998
60.0330009
60.0359993
60.0340004
60.0320015
60.0340004
60.0330009
60.0349998
60.0349998
60.0390015
60.0369987
60.0359993
60.0340004
60.0369987
60.0369987
60.0379982
60.0400009
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
219.8972931
219.8972931
219.8972931
219.8972931
219.8972931
231.1753998
231.1753998
231.1753998
231.1753998
231.1753998
226.6341248
226.6341248
226.6341248
226.6341248
226.6341248
227.2550659
227.2550659
227.2550659
227.2550659
227.2550659
229.2902222
229.2902222
229.2902222
229.2902222
229.2902222
221.4613647
221.4613647
221.4613647
221.4613647
221.4613647
241.2743683
241.2743683
241.2743683
241.2743683
241.2743683
243.0718536
243.0718536
243.0718536
243.0718536
243.0718536
241.6702118
241.6702118
241.6702118
241.6702118
241.6702118
228.1493073
228.1493073
228.1493073
228.1493073
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
002659
10/12/09 02:43:36
10/12/09 02:43:39
10/12/09 02:43:42
10/12/09 02:43:45
10/12/09 02:43:48
10/12/09 02:43:51
10/12/09 02:43:54
10/12/09 02:43:57
10/12/09 02:44:00
10/12/09 02:44:03
10/12/09 02:44:06
10/12/09 02:44:09
10/12/09 02:44:12
10/12/09 02:44:15
10/12/09 02:44:18
10/12/09 02:44:21
10/12/09 02:44:24
10/12/09 02:44:27
10/12/09 02:44:30
10/12/09 02:44:33
10/12/09 02:44:36
10/12/09 02:44:39
10/12/09 02:44:42
10/12/09 02:44:45
10/12/09 02:44:48
10/12/09 02:44:51
10/12/09 02:44:54
10/12/09 02:44:57
10/12/09 02:45:00
10/12/09 02:45:03
10/12/09 02:45:06
10/12/09 02:45:09
10/12/09 02:45:12
10/12/09 02:45:15
10/12/09 02:45:18
10/12/09 02:45:21
10/12/09 02:45:24
10/12/09 02:45:27
10/12/09 02:45:30
10/12/09 02:45:33
10/12/09 02:45:36
10/12/09 02:45:39
10/12/09 02:45:42
10/12/09 02:45:45
10/12/09 02:45:48
10/12/09 02:45:51
10/12/09 02:45:54
10/12/09 02:45:57
10/12/09 02:46:00
60.0449982
60.0449982
60.0429993
60.0400009
60.0460014
60.0419998
60.0390015
60.0390015
60.0369987
60.0340004
60.0320015
60.0309982
60.0270004
60.0309982
60.0309982
60.0309982
60.0390015
60.0390015
60.0369987
60.0349998
60.0400009
60.0419998
60.0359993
60.0400009
60.0449982
60.0480003
60.0439987
60.0439987
60.0439987
60.0400009
60.0449982
60.0439987
60.0390015
60.0419998
60.0410004
60.0379982
60.0369987
60.0390015
60.0400009
60.0390015
60.0379982
60.0390015
60.0369987
60.0369987
60.0390015
60.0379982
60.0349998
60.0330009
60.0299988
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
228.1493073
235.1289825
235.1289825
235.1289825
235.1289825
235.1289825
246.433136
246.433136
246.433136
246.433136
246.433136
236.5535431
236.5535431
236.5535431
236.5535431
236.5535431
230.2975616
230.2975616
230.2975616
230.2975616
230.2975616
231.1755371
231.1755371
231.1755371
231.1755371
231.1755371
225.61763
225.61763
225.61763
225.61763
225.61763
230.7344208
230.7344208
230.7344208
230.7344208
230.7344208
234.8471069
234.8471069
234.8471069
234.8471069
234.8471069
228.9609222
228.9609222
228.9609222
228.9609222
228.9609222
231.1779175
231.1779175
231.1779175
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
002660
10/12/09 02:46:03
10/12/09 02:46:06
10/12/09 02:46:09
10/12/09 02:46:12
10/12/09 02:46:15
10/12/09 02:46:18
10/12/09 02:46:21
10/12/09 02:46:24
10/12/09 02:46:27
10/12/09 02:46:30
10/12/09 02:46:33
10/12/09 02:46:36
10/12/09 02:46:39
10/12/09 02:46:42
10/12/09 02:46:45
10/12/09 02:46:48
10/12/09 02:46:51
10/12/09 02:46:54
10/12/09 02:46:57
10/12/09 02:47:00
10/12/09 02:47:03
10/12/09 02:47:06
10/12/09 02:47:09
10/12/09 02:47:12
10/12/09 02:47:15
10/12/09 02:47:18
10/12/09 02:47:21
10/12/09 02:47:24
10/12/09 02:47:27
10/12/09 02:47:30
10/12/09 02:47:33
10/12/09 02:47:36
10/12/09 02:47:39
10/12/09 02:47:42
10/12/09 02:47:45
10/12/09 02:47:48
10/12/09 02:47:51
10/12/09 02:47:54
10/12/09 02:47:57
10/12/09 02:48:00
10/12/09 02:48:03
10/12/09 02:48:06
10/12/09 02:48:09
10/12/09 02:48:12
10/12/09 02:48:15
10/12/09 02:48:18
10/12/09 02:48:21
10/12/09 02:48:24
10/12/09 02:48:27
60.0320015
60.0369987
60.0419998
60.0359993
60.0309982
60.0309982
60.0340004
60.0320015
60.0379982
60.0439987
60.0419998
60.0400009
60.0400009
60.0429993
60.0410004
60.0379982
60.0429993
60.0419998
60.0359993
60.0410004
60.0419998
60.0429993
60.0359993
60.0390015
60.0369987
60.0349998
60.0349998
60.0359993
60.0299988
60.0299988
60.0309982
60.0320015
60.0309982
60.0320015
60.0320015
60.0369987
60.0400009
60.0419998
60.0359993
60.0410004
60.0400009
60.0359993
60.0379982
60.0410004
60.0400009
60.0330009
60.0340004
60.0400009
60.0410004
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
231.1779175
231.1779175
236.4892883
236.4892883
236.4892883
236.4892883
236.4892883
245.0389252
245.0389252
245.0389252
245.0389252
245.0389252
223.6056824
223.6056824
223.6056824
223.6056824
223.6056824
231.1193542
231.1193542
231.1193542
231.1193542
231.1193542
237.2066498
237.2066498
237.2066498
237.2066498
237.2066498
240.5163727
240.5163727
240.5163727
240.5163727
240.5163727
237.5660553
237.5660553
237.5660553
237.5660553
237.5660553
231.5814209
231.5814209
231.5814209
231.5814209
231.5814209
235.8508453
235.8508453
235.8508453
235.8508453
235.8508453
233.5599823
233.5599823
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
002661
10/12/09 02:48:30
10/12/09 02:48:33
10/12/09 02:48:36
10/12/09 02:48:39
10/12/09 02:48:42
10/12/09 02:48:45
10/12/09 02:48:48
10/12/09 02:48:51
10/12/09 02:48:54
10/12/09 02:48:57
10/12/09 02:49:00
10/12/09 02:49:03
10/12/09 02:49:06
10/12/09 02:49:09
10/12/09 02:49:12
10/12/09 02:49:15
10/12/09 02:49:18
10/12/09 02:49:21
10/12/09 02:49:24
10/12/09 02:49:27
10/12/09 02:49:30
10/12/09 02:49:33
10/12/09 02:49:36
10/12/09 02:49:39
10/12/09 02:49:42
10/12/09 02:49:45
10/12/09 02:49:48
10/12/09 02:49:51
10/12/09 02:49:54
10/12/09 02:49:57
10/12/09 02:50:00
10/12/09 02:50:03
10/12/09 02:50:06
10/12/09 02:50:09
10/12/09 02:50:12
10/12/09 02:50:15
10/12/09 02:50:18
10/12/09 02:50:21
10/12/09 02:50:24
10/12/09 02:50:27
10/12/09 02:50:30
10/12/09 02:50:33
10/12/09 02:50:36
10/12/09 02:50:39
10/12/09 02:50:42
10/12/09 02:50:45
10/12/09 02:50:48
10/12/09 02:50:51
10/12/09 02:50:54
60.0369987
60.0359993
60.0379982
60.0390015
60.0340004
60.0330009
60.0340004
60.0289993
60.0309982
60.0299988
60.026001
60.0219994
60.0239983
60.0229988
60.0209999
60.0229988
60.026001
60.026001
60.0239983
60.0239983
60.0229988
60.0229988
60.026001
60.0289993
60.0239983
60.0209999
60.0250015
60.0250015
60.026001
60.0239983
60.0229988
60.026001
60.0200005
60.0200005
60.0149994
60.0159988
60.0149994
60.0149994
60.0169983
60.012001
60.0079994
60.0019989
59.9990005
60.0019989
60.0040016
60.0009995
59.993
59.9920006
59.9869995
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
233.5599823
233.5599823
233.5599823
219.0099945
219.0099945
219.0099945
219.0099945
219.0099945
205.338913
205.338913
205.338913
205.338913
205.338913
236.2853546
236.2853546
236.2853546
236.2853546
236.2853546
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
002662
10/12/09 02:50:57
10/12/09 02:51:00
10/12/09 02:51:03
10/12/09 02:51:06
10/12/09 02:51:09
10/12/09 02:51:12
10/12/09 02:51:15
10/12/09 02:51:18
10/12/09 02:51:21
10/12/09 02:51:24
10/12/09 02:51:27
10/12/09 02:51:30
10/12/09 02:51:33
10/12/09 02:51:36
10/12/09 02:51:39
10/12/09 02:51:42
10/12/09 02:51:45
10/12/09 02:51:48
10/12/09 02:51:51
10/12/09 02:51:54
10/12/09 02:51:57
10/12/09 02:52:00
10/12/09 02:52:03
10/12/09 02:52:06
10/12/09 02:52:09
10/12/09 02:52:12
10/12/09 02:52:15
10/12/09 02:52:18
10/12/09 02:52:21
10/12/09 02:52:24
10/12/09 02:52:27
10/12/09 02:52:30
10/12/09 02:52:33
10/12/09 02:52:36
10/12/09 02:52:39
10/12/09 02:52:42
10/12/09 02:52:45
10/12/09 02:52:48
10/12/09 02:52:51
10/12/09 02:52:54
10/12/09 02:52:57
10/12/09 02:53:00
10/12/09 02:53:03
10/12/09 02:53:06
10/12/09 02:53:09
10/12/09 02:53:12
10/12/09 02:53:15
10/12/09 02:53:18
10/12/09 02:53:21
59.9850006
59.9860001
59.9840012
59.9799995
59.9770012
59.9760017
59.9720001
59.9770012
59.9749985
59.9710007
59.9710007
59.9790001
59.9799995
59.9819984
59.9819984
59.980999
59.9790001
59.9760017
59.9780006
59.9760017
59.9780006
59.9710007
59.9700012
59.9710007
59.9900017
59.9990005
59.9990005
59.9990005
60.0029984
60.0050011
60.0099983
60.0200005
60.0219994
60.0250015
60.0250015
60.0229988
60.0289993
60.0289993
60.0279999
60.0309982
60.0320015
60.0330009
60.0299988
60.0209999
60.019001
60.0169983
60.0169983
60.0149994
60.0149994
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
002663
10/12/09 02:53:24
10/12/09 02:53:27
10/12/09 02:53:30
10/12/09 02:53:33
10/12/09 02:53:36
10/12/09 02:53:39
10/12/09 02:53:42
10/12/09 02:53:45
10/12/09 02:53:48
10/12/09 02:53:51
10/12/09 02:53:54
10/12/09 02:53:57
10/12/09 02:54:00
10/12/09 02:54:03
10/12/09 02:54:06
10/12/09 02:54:09
10/12/09 02:54:12
10/12/09 02:54:15
10/12/09 02:54:18
10/12/09 02:54:21
10/12/09 02:54:24
10/12/09 02:54:27
10/12/09 02:54:30
10/12/09 02:54:33
10/12/09 02:54:36
10/12/09 02:54:39
10/12/09 02:54:42
10/12/09 02:54:45
10/12/09 02:54:48
10/12/09 02:54:51
10/12/09 02:54:54
10/12/09 02:54:57
10/12/09 02:55:00
10/12/09 02:55:03
10/12/09 02:55:06
10/12/09 02:55:09
10/12/09 02:55:12
10/12/09 02:55:15
10/12/09 02:55:18
10/12/09 02:55:21
10/12/09 02:55:24
10/12/09 02:55:27
10/12/09 02:55:30
10/12/09 02:55:33
10/12/09 02:55:36
10/12/09 02:55:39
10/12/09 02:55:42
10/12/09 02:55:45
10/12/09 02:55:48
60.0089989
60.0079994
60.0050011
60.0050011
59.9990005
59.9970016
60
59.9980011
59.9939995
59.9920006
59.987999
59.9850006
59.987999
59.987999
59.9830017
59.9830017
59.9860001
59.9869995
59.9860001
59.9850006
59.9830017
59.9819984
59.9799995
59.9780006
59.9749985
59.9729996
59.9760017
59.9760017
59.9819984
59.9790001
59.9770012
59.9770012
59.9780006
59.9780006
59.9830017
59.980999
59.9780006
59.9790001
59.9790001
59.9830017
59.9900017
59.9920006
59.9900017
59.987999
59.9900017
59.993
59.993
59.9939995
59.993
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
002664
10/12/09 02:55:51
10/12/09 02:55:54
10/12/09 02:55:57
10/12/09 02:56:00
10/12/09 02:56:03
10/12/09 02:56:06
10/12/09 02:56:09
10/12/09 02:56:12
10/12/09 02:56:15
10/12/09 02:56:18
10/12/09 02:56:21
10/12/09 02:56:24
10/12/09 02:56:27
10/12/09 02:56:30
10/12/09 02:56:33
10/12/09 02:56:36
10/12/09 02:56:39
10/12/09 02:56:42
10/12/09 02:56:45
10/12/09 02:56:48
10/12/09 02:56:51
10/12/09 02:56:54
10/12/09 02:56:57
10/12/09 02:57:00
10/12/09 02:57:03
10/12/09 02:57:06
10/12/09 02:57:09
10/12/09 02:57:12
10/12/09 02:57:15
10/12/09 02:57:18
10/12/09 02:57:21
10/12/09 02:57:24
10/12/09 02:57:27
10/12/09 02:57:30
10/12/09 02:57:33
10/12/09 02:57:36
10/12/09 02:57:39
10/12/09 02:57:42
10/12/09 02:57:45
10/12/09 02:57:48
10/12/09 02:57:51
10/12/09 02:57:54
10/12/09 02:57:57
10/12/09 02:58:00
10/12/09 02:58:03
10/12/09 02:58:06
10/12/09 02:58:09
10/12/09 02:58:12
10/12/09 02:58:15
59.9889984
59.9860001
59.9850006
59.9869995
59.9860001
59.9850006
59.9819984
59.9819984
59.9869995
59.9970016
60
60.0029984
60.0029984
60.0029984
60.0019989
60.0040016
60.0050011
60.0089989
60.012001
60.0209999
60.0219994
60.0200005
60.0180016
60.0200005
60.0200005
60.0180016
60.019001
60.0180016
60.0169983
60.0159988
60.0159988
60.0139999
60.0139999
60.0130005
60.0149994
60.0159988
60.019001
60.0209999
60.0200005
60.0239983
60.026001
60.026001
60.0219994
60.0219994
60.0239983
60.0289993
60.0279999
60.0320015
60.0349998
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
223.0157318
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
-420
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
002665
10/12/09 02:58:18
10/12/09 02:58:21
10/12/09 02:58:24
10/12/09 02:58:27
10/12/09 02:58:30
10/12/09 02:58:33
10/12/09 02:58:36
10/12/09 02:58:39
10/12/09 02:58:42
10/12/09 02:58:45
10/12/09 02:58:48
10/12/09 02:58:51
10/12/09 02:58:54
10/12/09 02:58:57
10/12/09 02:59:00
10/12/09 02:59:03
10/12/09 02:59:06
10/12/09 02:59:09
10/12/09 02:59:12
10/12/09 02:59:15
10/12/09 02:59:18
10/12/09 02:59:21
10/12/09 02:59:24
10/12/09 02:59:27
10/12/09 02:59:30
10/12/09 02:59:33
10/12/09 02:59:36
10/12/09 02:59:39
10/12/09 02:59:42
10/12/09 02:59:45
10/12/09 02:59:48
10/12/09 02:59:51
10/12/09 02:59:54
10/12/09 02:59:57
10/12/09 03:00:00
10/12/09 03:00:03
10/12/09 03:00:06
10/12/09 03:00:09
10/12/09 03:00:12
10/12/09 03:00:15
10/12/09 03:00:18
10/12/09 03:00:21
10/12/09 03:00:24
10/12/09 03:00:27
10/12/09 03:00:30
10/12/09 03:00:33
10/12/09 03:00:36
10/12/09 03:00:39
10/12/09 03:00:42
60.0279999
60.0209999
60.0239983
60.0250015
60.0219994
60.0229988
60.0200005
60.0200005
60.0200005
60.0169983
60.012001
60.0099983
60.0099983
60.0099983
60.012001
60.012001
60.0139999
60.0130005
60.0110016
60.0099983
60.0099983
60.0110016
60.0159988
60.0180016
60.019001
60.019001
60.0200005
60.0180016
60.0159988
60.0159988
60.0229988
60.0219994
60.0149994
60.0159988
60.0169983
60.0099983
60.0040016
59.9949989
59.9819984
59.973999
59.9700012
59.9679985
59.9679985
59.9720001
59.9659996
59.9640007
59.9659996
59.9630013
59.9650002
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002666
10/12/09 03:00:45
10/12/09 03:00:48
10/12/09 03:00:51
10/12/09 03:00:54
10/12/09 03:00:57
10/12/09 03:01:00
10/12/09 03:01:03
10/12/09 03:01:06
10/12/09 03:01:09
10/12/09 03:01:12
10/12/09 03:01:15
10/12/09 03:01:18
10/12/09 03:01:21
10/12/09 03:01:24
10/12/09 03:01:27
10/12/09 03:01:30
10/12/09 03:01:33
10/12/09 03:01:36
10/12/09 03:01:39
10/12/09 03:01:42
10/12/09 03:01:45
10/12/09 03:01:48
10/12/09 03:01:51
10/12/09 03:01:54
10/12/09 03:01:57
10/12/09 03:02:00
10/12/09 03:02:03
10/12/09 03:02:06
10/12/09 03:02:09
10/12/09 03:02:12
10/12/09 03:02:15
10/12/09 03:02:18
10/12/09 03:02:21
10/12/09 03:02:24
10/12/09 03:02:27
10/12/09 03:02:30
10/12/09 03:02:33
10/12/09 03:02:36
10/12/09 03:02:39
10/12/09 03:02:42
10/12/09 03:02:45
10/12/09 03:02:48
10/12/09 03:02:51
10/12/09 03:02:54
10/12/09 03:02:57
10/12/09 03:03:00
10/12/09 03:03:03
10/12/09 03:03:06
10/12/09 03:03:09
59.9679985
59.9700012
59.9700012
59.9720001
59.9760017
59.9749985
59.9770012
59.9760017
59.973999
59.973999
59.973999
59.9770012
59.9790001
59.9830017
59.9850006
59.9799995
59.9790001
59.9869995
59.9860001
59.9799995
59.9819984
59.9850006
59.9869995
59.9920006
59.9959984
59.9970016
59.9970016
59.9970016
59.9959984
59.9959984
59.9980011
60.0089989
60.0099983
60.0050011
60.0040016
60.0029984
60.0009995
60.0040016
60.007
60.0079994
60.0079994
60.0060005
60.0060005
60
59.9990005
60
60.0040016
60.0130005
60.0149994
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002667
10/12/09 03:03:12
10/12/09 03:03:15
10/12/09 03:03:18
10/12/09 03:03:21
10/12/09 03:03:24
10/12/09 03:03:27
10/12/09 03:03:30
10/12/09 03:03:33
10/12/09 03:03:36
10/12/09 03:03:39
10/12/09 03:03:42
10/12/09 03:03:45
10/12/09 03:03:48
10/12/09 03:03:51
10/12/09 03:03:54
10/12/09 03:03:57
10/12/09 03:04:00
10/12/09 03:04:03
10/12/09 03:04:06
10/12/09 03:04:09
10/12/09 03:04:12
10/12/09 03:04:15
10/12/09 03:04:18
10/12/09 03:04:21
10/12/09 03:04:24
10/12/09 03:04:27
10/12/09 03:04:30
10/12/09 03:04:33
10/12/09 03:04:36
10/12/09 03:04:39
10/12/09 03:04:42
10/12/09 03:04:45
10/12/09 03:04:48
10/12/09 03:04:51
10/12/09 03:04:54
10/12/09 03:04:57
10/12/09 03:05:00
10/12/09 03:05:03
10/12/09 03:05:06
10/12/09 03:05:09
10/12/09 03:05:12
10/12/09 03:05:15
10/12/09 03:05:18
10/12/09 03:05:21
10/12/09 03:05:24
10/12/09 03:05:27
10/12/09 03:05:30
10/12/09 03:05:33
10/12/09 03:05:36
60.012001
60.0089989
60.0079994
60.0110016
60.0130005
60.0159988
60.0180016
60.019001
60.0130005
60.0110016
60.0089989
60.0079994
60.0110016
60.0149994
60.0209999
60.0180016
60.019001
60.019001
60.0219994
60.0250015
60.0299988
60.0270004
60.0209999
60.0229988
60.0200005
60.0239983
60.0219994
60.0219994
60.0250015
60.0229988
60.0200005
60.0180016
60.0079994
60.012001
60.019001
60.019001
60.0159988
60.0149994
60.0139999
60.0159988
60.019001
60.0159988
60.0139999
60.0180016
60.0229988
60.0239983
60.026001
60.0239983
60.0200005
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002668
10/12/09 03:05:39
10/12/09 03:05:42
10/12/09 03:05:45
10/12/09 03:05:48
10/12/09 03:05:51
10/12/09 03:05:54
10/12/09 03:05:57
10/12/09 03:06:00
10/12/09 03:06:03
10/12/09 03:06:06
10/12/09 03:06:09
10/12/09 03:06:12
10/12/09 03:06:15
10/12/09 03:06:18
10/12/09 03:06:21
10/12/09 03:06:24
10/12/09 03:06:27
10/12/09 03:06:30
10/12/09 03:06:33
10/12/09 03:06:36
10/12/09 03:06:39
10/12/09 03:06:42
10/12/09 03:06:45
10/12/09 03:06:48
10/12/09 03:06:51
10/12/09 03:06:54
10/12/09 03:06:57
10/12/09 03:07:00
10/12/09 03:07:03
10/12/09 03:07:06
10/12/09 03:07:09
10/12/09 03:07:12
10/12/09 03:07:15
10/12/09 03:07:18
10/12/09 03:07:21
10/12/09 03:07:24
10/12/09 03:07:27
10/12/09 03:07:30
10/12/09 03:07:33
10/12/09 03:07:36
10/12/09 03:07:39
10/12/09 03:07:42
10/12/09 03:07:45
10/12/09 03:07:48
10/12/09 03:07:51
10/12/09 03:07:54
10/12/09 03:07:57
10/12/09 03:08:00
10/12/09 03:08:03
60.019001
60.0250015
60.0279999
60.0309982
60.0289993
60.026001
60.0289993
60.0330009
60.0299988
60.0159988
60.019001
60.0279999
60.0209999
60.0149994
60.012001
60.0139999
60.0130005
60.0159988
60.0159988
60.0130005
60.007
59.9939995
59.993
59.993
59.9939995
59.9939995
59.993
59.987999
59.9850006
59.9819984
59.9799995
59.980999
59.9819984
59.9799995
59.9799995
59.9799995
59.9830017
59.980999
59.980999
59.980999
59.980999
59.9799995
59.9780006
59.9790001
59.9780006
59.9760017
59.9749985
59.9749985
59.9790001
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002669
10/12/09 03:08:06
10/12/09 03:08:09
10/12/09 03:08:12
10/12/09 03:08:15
10/12/09 03:08:18
10/12/09 03:08:21
10/12/09 03:08:24
10/12/09 03:08:27
10/12/09 03:08:30
10/12/09 03:08:33
10/12/09 03:08:36
10/12/09 03:08:39
10/12/09 03:08:42
10/12/09 03:08:45
10/12/09 03:08:48
10/12/09 03:08:51
10/12/09 03:08:54
10/12/09 03:08:57
10/12/09 03:09:00
10/12/09 03:09:03
10/12/09 03:09:06
10/12/09 03:09:09
10/12/09 03:09:12
10/12/09 03:09:15
10/12/09 03:09:18
10/12/09 03:09:21
10/12/09 03:09:24
10/12/09 03:09:27
10/12/09 03:09:30
10/12/09 03:09:33
10/12/09 03:09:36
10/12/09 03:09:39
10/12/09 03:09:42
10/12/09 03:09:45
10/12/09 03:09:48
10/12/09 03:09:51
10/12/09 03:09:54
10/12/09 03:09:57
10/12/09 03:10:00
10/12/09 03:10:03
10/12/09 03:10:06
10/12/09 03:10:09
10/12/09 03:10:12
10/12/09 03:10:15
10/12/09 03:10:18
10/12/09 03:10:21
10/12/09 03:10:24
10/12/09 03:10:27
10/12/09 03:10:30
59.9749985
59.9760017
59.9770012
59.9749985
59.9790001
59.9799995
59.9780006
59.9790001
59.9830017
59.9869995
59.9840012
59.9799995
59.9799995
59.9790001
59.9749985
59.9790001
59.9830017
59.9830017
59.9900017
59.9869995
59.9760017
59.9790001
59.9830017
59.9790001
59.9780006
59.9749985
59.9889984
59.9990005
59.9889984
59.9860001
59.9830017
59.9819984
59.9900017
59.9949989
59.9900017
59.9889984
59.9959984
60
60.0040016
60.0040016
59.9990005
59.9980011
59.9959984
60.0009995
60.0009995
60.0029984
60.0040016
60.0040016
60.0060005
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002670
10/12/09 03:10:33
10/12/09 03:10:36
10/12/09 03:10:39
10/12/09 03:10:42
10/12/09 03:10:45
10/12/09 03:10:48
10/12/09 03:10:51
10/12/09 03:10:54
10/12/09 03:10:57
10/12/09 03:11:00
10/12/09 03:11:03
10/12/09 03:11:06
10/12/09 03:11:09
10/12/09 03:11:12
10/12/09 03:11:15
10/12/09 03:11:18
10/12/09 03:11:21
10/12/09 03:11:24
10/12/09 03:11:27
10/12/09 03:11:30
10/12/09 03:11:33
10/12/09 03:11:36
10/12/09 03:11:39
10/12/09 03:11:42
10/12/09 03:11:45
10/12/09 03:11:48
10/12/09 03:11:51
10/12/09 03:11:54
10/12/09 03:11:57
10/12/09 03:12:00
60.0029984
60.0060005
60.0089989
60.0099983
60.0089989
60.0149994
60.0139999
60.0089989
60.0079994
60.0099983
60.0089989
60.0130005
60.0139999
60.012001
60.0099983
60.007
60.0029984
60
59.9980011
59.9990005
60.0019989
60.0029984
59.9990005
60.0009995
59.9949989
59.9869995
59.987999
59.9900017
59.9920006
59.9920006
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
002671
002672
002673
002674
002675
002676
002677
002678
002679
002680
002681
002682
002683
Balancing Authority Name: HQ
Balancing Authority Frequency Response
Obligation (FRO from FRS Form 1)
-141
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Determine Time of T(0) and edit formula in cell "C8" to reference the correct row of the "Data"
Step 2. worksheet.
T(0) is the first change in frequency of about 0.010 Hz (10 mHz) which should be the first scan
of frequency data of the event.
Step 3. Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Hit the big blue button to copy your data for pasting into FRS Form 1 "BA Event Data"
Step 4. worksheet.
2:27:21
2:32:54
Event Frequency Data
60.1
60.05
60
59.95
Copy Data for Pasting
into Form 1
59.9
59.85
59.8
59.75
59.7
Step 5. Paste data into FRS Form 1 in the appropriate row on the "BA Event Data" worksheet.
Step 6. Save this workbook using the following file name format:MyBA_yymmdd_hhmm_FRS_Form2.xlsm
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
Frequency Hz
002684
60.08
60.06
633
0
633
Total MW Lost
Monday, October 12, 2009
0
NCLR Tripped or non-conforming load change
MW Net Loss to Grid
60.04
60.02
60.00
59.98
-200
A Value 60.0417
FPointA
FR @ Value C
-307.7 MW/0.1 Hz
60.0390
-400
59.96
Frequency - Hz
59.94
59.92
59.90
-600
59.88
59.86
59.84
59.8360
59.82
C Value
59.80
59.76
59.74
59.70
Hz
-800
MW/0.1 Hz
59.8823 -397.436 FR @ Value B 12 to 24
59.8844 -402.634 FR @ Value B 18 to 30
59.8887 -415.164 FR @ Value B 20 to 40
59.78
59.72
B Value
-1000
59.8879 -411.959 FR @ Value B 18 to 52
TZERO
Frequency Hz
Value B 12 to 24 sec
Value B 20 to 40 sec
Interconnection Primary Frequency Response
FR B 12 to 24 sec
FR B 20 to 40 sec
IPFR = Interconnection Primary Frequency Response
59.8887 -413.862 FR @ Value B 20 to 52
-1200
Value B 20 to 52 sec Average Frequency
Value B 18 to 30 sec
Value B 18 to 52 sec
FR B 20 to 52 sec Average MW
FR B 18 to 30 sec
FR B 18 to 52 sec
MW/0.1 Hz Primary Frequency Response
60.10
002685
scan rate
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
60.027
60.027
60.026
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8887
-0.153
633.00
0.00
-633.00
0.00
-58.87
156.92
215.79
Balancing Authority
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
EPFR(Final)
215.79 MW
Initial Response P.U. Performance
2.933 P.U.
Total
Generation
Lost
MW
633.000
633.000
633.000
Value B
20 to 52 sec
Average
Frequency
Average
MW
Grid Nominal Frequency
Capacity @ Droop for Minimum Performance
Droop Setting
Deadband Setting
Hz Span
Frequency Response Obligation (FRO)
TC (frequency response filter constant)
Low Hz
0.00
437.58
348.10
633.00
-693.63
0:05:33
Yes
498.21
60.63
Yes
No
No
-195.42
-633.00
Down
HQ
60.000 Hz
4230.0 MW
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
-141 MW/0.1 Hz
1 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
No Evaluation P.U. Sustianed Response P.U. Performance
FRO
(EPFR)
Expected
Primary
Frequency
Response
-38.071
-38.071
-36.661
(TC)
Delayed
Delivery
Frequency
Response
-38.071
-38.071
-36.661
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
Generator
Trip
MW
633.000
002686
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
60.022
60.022
60.017
60.019
60.019
60.019
60.021
60.021
60.021
60.019
60.019
60.022
60.031
60.031
60.037
60.036
60.036
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.039
60.043
60.045
60.045
60.041
60.041
60.041
60.039
59.978
59.978
59.836
59.836
59.869
59.891
59.891
59.88
59.875
59.875
59.883
59.886
59.886
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
-31.019
-31.019
-23.968
-26.791
-26.791
-26.791
-29.610
-29.610
-29.610
-26.791
-26.791
-31.019
-43.708
-43.708
-52.168
-50.759
-50.759
-64.862
-67.680
-67.680
-60.629
-57.811
-57.811
-57.811
-54.992
-54.992
-60.629
-63.447
-63.447
-57.811
-57.811
-57.811
-54.992
31.019
31.019
231.242
231.242
184.711
153.692
153.692
169.198
176.250
176.250
164.971
160.738
160.738
-31.019
-31.019
-23.968
-26.791
-26.791
-26.791
-29.610
-29.610
-29.610
-26.791
-26.791
-31.019
-43.708
-43.708
-52.168
-50.759
-50.759
-64.862
-67.680
-67.680
-60.629
-57.811
-57.811
-57.811
-54.992
-54.992
-60.629
-63.447
-63.447
-57.811
-57.811
-57.811
-54.992
31.019
31.019
231.242
231.242
184.711
153.692
153.692
169.198
176.250
176.250
164.971
160.738
160.738
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
0.972
848.792
848.792
848.792
0.000
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
633.000
633.972
634.945
633.099
634.071
635.044
638.835
639.807
636.552
624.836
625.808
618.320
620.702
621.674
608.544
606.697
607.670
615.694
619.485
620.457
621.430
625.221
626.193
621.528
619.682
620.655
627.264
628.237
629.209
633.000
719.011
714.845
910.902
906.736
856.039
820.854
816.688
828.029
830.915
826.749
811.304
802.905
798.739
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
716.928
781.586
812.874
821.507
821.398
820.725
821.638
822.669
823.077
822.007
820.415
818.747
691.783
687.617
683.451
679.285
675.119
670.953
666.787
662.622
658.456
654.290
650.124
645.958
691.783
689.700
687.617
685.534
683.451
681.368
679.285
677.202
675.119
673.036
670.953
668.870
633
633
633
633
633
633
633
633
633
633
633
633
633
002687
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
2:28:43
2:28:45
2:28:47
2:28:49
2:28:51
2:28:53
2:28:55
2:28:57
2:28:59
2:29:01
2:29:03
2:29:05
2:29:07
2:29:09
2:29:11
2:29:13
2:29:15
59.885
59.888
59.888
59.89
59.894
59.894
59.893
59.894
59.894
59.891
59.885
59.885
59.885
59.887
59.887
59.888
59.89
59.89
59.889
59.873
59.873
59.857
59.852
59.852
59.858
59.866
59.866
59.865
59.866
59.866
59.871
59.879
59.879
59.88
59.886
59.886
59.89
59.889
59.889
59.893
59.903
59.903
59.902
59.904
59.904
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
162.152
157.919
157.919
155.101
149.459
149.459
150.868
149.459
149.459
153.692
162.152
162.152
162.152
159.329
159.329
157.919
155.101
155.101
156.510
179.068
179.068
201.632
208.678
208.678
200.218
188.938
188.938
190.348
188.938
188.938
181.892
170.608
170.608
169.198
160.738
160.738
155.101
156.510
156.510
150.868
136.770
136.770
138.179
135.361
135.361
162.152
157.919
157.919
155.101
149.459
149.459
150.868
149.459
149.459
153.692
162.152
162.152
162.152
159.329
159.329
157.919
155.101
155.101
156.510
179.068
179.068
201.632
208.678
208.678
200.218
188.938
188.938
190.348
188.938
188.938
181.892
170.608
170.608
169.198
160.738
160.738
155.101
156.510
156.510
150.868
136.770
136.770
138.179
135.361
135.361
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
848.792
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
795.988
787.589
783.423
776.438
766.630
762.464
759.708
754.132
749.966
750.034
754.328
750.163
745.997
739.007
734.841
729.266
722.281
718.116
715.359
733.751
729.585
747.983
750.863
746.698
734.071
718.626
714.460
711.703
706.128
701.962
690.750
675.300
671.134
665.559
652.932
648.766
638.963
636.206
632.041
622.232
603.969
599.803
597.046
590.062
585.896
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
817.122
815.153
813.170
811.009
808.544
806.118
803.798
801.433
799.093
796.960
795.184
793.383
791.561
789.614
787.658
785.644
783.532
781.422
779.358
777.976
776.552
775.736
775.045
774.279
773.221
771.821
770.387
768.956
767.460
765.937
764.228
762.252
760.271
758.256
756.061
753.872
751.574
749.311
747.056
744.701
742.095
739.508
736.964
734.387
731.826
641.792
637.626
633.460
629.294
625.128
620.962
616.797
612.631
608.465
604.299
600.133
595.967
591.801
587.635
583.469
579.303
575.137
570.971
566.806
562.640
558.474
554.308
550.142
545.976
541.810
537.644
533.478
529.312
525.146
520.981
516.815
512.649
508.483
504.317
500.151
495.985
491.819
487.653
483.487
479.321
475.155
470.990
466.824
462.658
458.492
666.787
664.705
662.622
660.539
658.456
656.373
654.290
652.207
650.124
648.041
645.958
643.875
641.792
639.709
637.626
635.543
633.460
631.377
629.294
627.211
625.128
623.045
620.962
618.879
616.797
614.714
612.631
610.548
608.465
606.382
604.299
602.216
600.133
598.050
595.967
593.884
591.801
589.718
587.635
585.552
583.469
581.386
579.303
577.220
575.137
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002688
2:29:17
2:29:19
2:29:21
2:29:23
2:29:25
2:29:27
2:29:29
2:29:31
2:29:33
2:29:35
2:29:37
2:29:39
2:29:41
2:29:43
2:29:45
2:29:47
2:29:49
2:29:51
2:29:53
2:29:55
2:29:57
2:29:59
2:30:01
2:30:03
2:30:05
2:30:07
2:30:09
2:30:11
2:30:13
2:30:15
2:30:17
2:30:19
2:30:21
2:30:23
2:30:25
2:30:27
2:30:29
2:30:31
2:30:33
2:30:35
2:30:37
2:30:39
2:30:41
2:30:43
2:30:45
2:30:47
59.907
59.916
59.916
59.916
59.918
59.918
59.92
59.92
59.92
59.917
59.921
59.921
59.923
59.925
59.925
59.928
59.932
59.932
59.927
59.931
59.931
59.929
59.931
59.931
59.937
59.945
59.945
59.949
59.942
59.942
59.941
59.945
59.945
59.948
59.949
59.949
59.951
59.953
59.953
59.951
59.952
59.952
59.952
59.952
59.952
59.954
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
131.128
118.439
118.439
118.439
115.621
115.621
112.803
112.803
112.803
117.030
111.388
111.388
108.570
105.751
105.751
101.518
95.881
95.881
102.933
97.290
97.290
100.109
97.290
97.290
88.830
77.550
77.550
71.908
81.778
81.778
83.187
77.550
77.550
73.317
71.908
71.908
69.090
66.271
66.271
69.090
67.680
67.680
67.680
67.680
67.680
64.862
131.128
118.439
118.439
118.439
115.621
115.621
112.803
112.803
112.803
117.030
111.388
111.388
108.570
105.751
105.751
101.518
95.881
95.881
102.933
97.290
97.290
100.109
97.290
97.290
88.830
77.550
77.550
71.908
81.778
81.778
83.187
77.550
77.550
73.317
71.908
71.908
69.090
66.271
66.271
69.090
67.680
67.680
67.680
67.680
67.680
64.862
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
577.497
560.643
556.477
552.311
545.326
541.161
534.176
530.010
525.844
525.906
516.098
511.932
504.948
497.963
493.797
485.398
475.596
471.430
474.315
464.507
460.341
458.994
452.009
447.843
435.217
419.772
415.606
405.798
411.502
407.336
404.579
394.776
390.610
382.211
376.636
372.470
365.486
358.502
354.336
352.988
347.413
343.247
339.081
334.915
330.749
323.765
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
729.211
726.401
723.616
720.853
718.066
715.302
712.516
709.751
707.006
704.342
701.614
698.905
696.173
693.420
690.685
687.911
685.080
682.269
679.568
676.811
674.071
671.383
668.674
665.981
663.201
660.303
657.424
654.498
651.705
648.928
646.183
643.389
640.612
637.803
634.995
632.202
629.394
626.572
623.766
621.003
618.239
615.489
612.753
610.029
607.317
604.591
454.326
450.160
445.994
441.828
437.662
433.496
429.330
425.165
420.999
416.833
412.667
408.501
404.335
400.169
396.003
391.837
387.671
383.505
379.339
375.174
371.008
366.842
362.676
358.510
354.344
350.178
346.012
341.846
337.680
333.514
329.349
325.183
321.017
316.851
312.685
308.519
304.353
300.187
296.021
291.855
287.689
283.523
279.358
275.192
271.026
266.860
573.054
570.971
568.889
566.806
564.723
562.640
560.557
558.474
556.391
554.308
552.225
550.142
548.059
545.976
543.893
541.810
539.727
537.644
535.561
533.478
531.395
529.312
527.229
525.146
523.063
520.981
518.898
516.815
514.732
512.649
510.566
508.483
506.400
504.317
502.234
500.151
498.068
495.985
493.902
491.819
489.736
487.653
485.570
483.487
481.404
479.321
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002689
2:30:49
2:30:51
2:30:53
2:30:55
2:30:57
2:30:59
2:31:01
2:31:03
2:31:05
2:31:07
2:31:09
2:31:11
2:31:13
2:31:15
2:31:17
2:31:19
2:31:21
2:31:23
2:31:25
2:31:27
2:31:29
2:31:31
2:31:33
2:31:35
2:31:37
2:31:39
2:31:41
2:31:43
2:31:45
2:31:47
2:31:49
2:31:51
2:31:53
2:31:55
2:31:57
2:31:59
2:32:01
2:32:03
2:32:05
2:32:07
2:32:09
2:32:11
2:32:13
2:32:15
2:32:17
2:32:19
59.953
59.953
59.953
59.954
59.954
59.954
59.957
59.957
59.956
59.956
59.956
59.955
59.961
59.961
59.962
59.968
59.968
59.966
59.968
59.968
59.97
59.97
59.97
59.969
59.97
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.976
59.976
59.978
59.98
59.98
59.982
59.98
59.98
59.979
59.979
59.979
59.983
59.984
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
66.271
66.271
66.271
64.862
64.862
64.862
60.629
60.629
62.038
62.038
62.038
63.447
54.992
54.992
53.577
45.122
45.122
47.941
45.122
45.122
42.298
42.298
42.298
43.708
42.298
42.298
40.889
38.071
38.071
33.838
31.019
31.019
33.838
33.838
33.838
31.019
28.201
28.201
25.382
28.201
28.201
29.610
29.610
29.610
23.968
22.558
66.271
66.271
66.271
64.862
64.862
64.862
60.629
60.629
62.038
62.038
62.038
63.447
54.992
54.992
53.577
45.122
45.122
47.941
45.122
45.122
42.298
42.298
42.298
43.708
42.298
42.298
40.889
38.071
38.071
33.838
31.019
31.019
33.838
33.838
33.838
31.019
28.201
28.201
25.382
28.201
28.201
29.610
29.610
29.610
23.968
22.558
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
321.008
316.842
312.677
307.101
302.935
298.770
290.371
286.205
283.448
279.282
275.116
272.359
259.738
255.572
249.992
237.371
233.205
231.857
224.873
220.707
213.717
209.551
205.385
202.629
197.053
192.888
187.312
180.328
176.162
167.763
160.779
156.613
155.265
151.100
146.934
139.949
132.965
128.799
121.815
120.467
116.301
113.545
109.379
105.213
95.405
89.829
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
601.890
599.201
596.523
593.843
591.174
588.516
585.830
583.155
580.503
577.860
575.228
572.617
569.943
567.279
564.612
561.885
559.169
556.486
553.790
551.104
548.405
545.715
543.036
540.376
537.715
535.062
532.408
529.741
527.082
524.401
521.707
519.023
516.367
513.720
511.082
508.431
505.768
503.113
500.447
497.808
495.177
492.563
489.956
487.357
484.726
482.094
262.694
258.528
254.362
250.196
246.030
241.864
237.698
233.533
229.367
225.201
221.035
216.869
212.703
208.537
204.371
200.205
196.039
191.873
187.707
183.542
179.376
175.210
171.044
166.878
162.712
158.546
154.380
150.214
146.048
141.882
137.717
133.551
129.385
125.219
121.053
116.887
112.721
108.555
104.389
100.223
96.057
91.891
87.726
83.560
79.394
75.228
477.238
475.155
473.073
470.990
468.907
466.824
464.741
462.658
460.575
458.492
456.409
454.326
452.243
450.160
448.077
445.994
443.911
441.828
439.745
437.662
435.579
433.496
431.413
429.330
427.247
425.165
423.082
420.999
418.916
416.833
414.750
412.667
410.584
408.501
406.418
404.335
402.252
400.169
398.086
396.003
393.920
391.837
389.754
387.671
385.588
383.505
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002690
2:32:21
2:32:23
2:32:25
2:32:27
2:32:29
2:32:31
2:32:33
2:32:35
2:32:37
2:32:39
2:32:41
2:32:43
2:32:45
2:32:47
2:32:49
2:32:51
2:32:53
2:32:55
2:32:57
2:32:59
2:33:01
2:33:03
2:33:05
2:33:07
2:33:09
2:33:11
2:33:13
2:33:15
2:33:17
2:33:19
2:33:21
2:33:23
2:33:25
2:33:27
2:33:29
2:33:31
2:33:33
2:33:35
2:33:37
2:33:39
2:33:41
2:33:43
2:33:45
2:33:47
2:33:49
2:33:51
59.984
59.988
59.987
59.987
59.987
59.993
59.993
59.992
59.989
59.989
59.986
59.983
59.983
59.988
59.996
59.996
59.998
60.001
60.001
59.999
59.999
59.999
60.002
60.007
60.007
60.008
60.014
60.014
60.017
60.021
60.021
60.017
60.019
60.019
60.023
60.025
60.025
60.021
60.024
60.024
60.024
60.02
60.02
60.025
60.02
60.02
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
22.558
16.921
18.331
18.331
18.331
9.870
9.870
11.279
15.512
15.512
19.740
23.968
23.968
16.921
5.642
5.642
2.818
-1.409
-1.409
1.409
1.409
1.409
-2.818
-9.870
-9.870
-11.279
-19.740
-19.740
-23.968
-29.610
-29.610
-23.968
-26.791
-26.791
-32.428
-35.252
-35.252
-29.610
-33.838
-33.838
-33.838
-28.201
-28.201
-35.252
-28.201
-28.201
22.558
16.921
18.331
18.331
18.331
9.870
9.870
11.279
15.512
15.512
19.740
23.968
23.968
16.921
5.642
5.642
2.818
-1.409
-1.409
1.409
1.409
1.409
-2.818
-9.870
-9.870
-11.279
-19.740
-19.740
-23.968
-29.610
-29.610
-23.968
-26.791
-26.791
-32.428
-35.252
-35.252
-29.610
-33.838
-33.838
-33.838
-28.201
-28.201
-35.252
-28.201
-28.201
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
-4.166
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
85.663
75.861
73.104
68.938
64.772
52.145
47.980
45.223
45.290
41.124
41.186
41.248
37.082
25.870
10.425
6.259
-0.731
-4.959
-4.959
-2.140
-2.140
-2.140
-6.368
-13.419
-13.419
-14.829
-23.289
-23.289
-27.517
-33.159
-33.159
-27.517
-30.341
-30.341
-35.978
-38.802
-38.802
-33.159
-37.387
-37.387
-37.387
-31.750
-31.750
-38.802
-31.750
-31.750
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
479.468
476.813
474.174
471.543
468.918
466.247
463.583
460.935
458.321
455.713
453.139
450.596
448.059
445.485
442.848
440.218
437.578
434.943
432.341
429.785
427.259
424.762
422.270
419.766
417.291
414.836
412.360
409.913
407.469
405.021
402.600
400.237
397.884
395.557
393.224
390.902
388.604
386.360
384.118
381.900
379.705
377.562
375.441
373.306
371.228
369.172
71.062
66.896
62.730
58.564
54.398
50.232
46.066
41.901
37.735
33.569
29.403
25.237
21.071
16.905
12.739
8.573
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
381.422
379.339
377.257
375.174
373.091
371.008
368.925
366.842
364.759
362.676
360.593
358.510
356.427
354.344
352.261
350.178
348.095
346.037
344.004
341.994
340.008
338.046
336.106
334.189
332.293
330.420
328.567
326.736
324.925
323.135
321.364
319.613
317.881
316.168
314.473
312.797
311.139
309.499
307.876
306.271
304.682
303.110
301.554
300.014
298.491
296.983
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002691
2:33:53
2:33:55
2:33:57
2:33:59
2:34:01
2:34:03
2:34:05
2:34:07
2:34:09
2:34:11
2:34:13
2:34:15
2:34:17
2:34:19
2:34:21
2:34:23
2:34:25
2:34:27
2:34:29
2:34:31
2:34:33
2:34:35
2:34:37
2:34:39
2:34:41
2:34:43
2:34:45
2:34:47
2:34:49
2:34:51
2:34:53
2:34:55
2:34:57
2:34:59
2:35:01
2:35:03
2:35:05
2:35:07
2:35:09
2:35:11
2:35:13
2:35:15
2:35:17
2:35:19
2:35:21
2:35:23
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.022
60.022
60.019
60.018
60.018
60.018
60.019
60.019
60.019
60.015
60.015
60.016
60.013
60.013
60.012
60.01
60.01
60.007
60.009
60.009
60.009
60.003
60.003
59.999
59.992
59.992
59.991
59.992
59.992
59.988
59.985
59.985
59.984
59.984
59.984
59.982
59.982
59.982
59.979
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-28.201
-31.019
-31.019
-31.019
-29.610
-29.610
-32.428
-31.019
-31.019
-26.791
-25.382
-25.382
-25.382
-26.791
-26.791
-26.791
-21.149
-21.149
-22.558
-18.331
-18.331
-16.921
-14.098
-14.098
-9.870
-12.688
-12.688
-12.688
-4.228
-4.228
1.409
11.279
11.279
12.688
11.279
11.279
16.921
21.149
21.149
22.558
22.558
22.558
25.382
25.382
25.382
29.610
-28.201
-31.019
-31.019
-31.019
-29.610
-29.610
-32.428
-31.019
-31.019
-26.791
-25.382
-25.382
-25.382
-26.791
-26.791
-26.791
-21.149
-21.149
-22.558
-18.331
-18.331
-16.921
-14.098
-14.098
-9.870
-12.688
-12.688
-12.688
-4.228
-4.228
1.409
11.279
11.279
12.688
11.279
11.279
16.921
21.149
21.149
22.558
22.558
22.558
25.382
25.382
25.382
29.610
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-31.750
-34.569
-34.569
-34.569
-33.159
-33.159
-35.978
-34.569
-34.569
-30.341
-28.932
-28.932
-28.932
-30.341
-30.341
-30.341
-24.699
-24.699
-26.108
-21.880
-21.880
-20.471
-17.647
-17.647
-13.419
-16.238
-16.238
-16.238
-7.777
-7.777
-2.140
7.730
7.730
9.139
7.730
7.730
13.372
17.600
17.600
19.009
19.009
19.009
21.833
21.833
21.833
26.060
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
367.137
365.108
363.100
361.112
359.150
357.208
355.271
353.360
351.468
349.614
347.786
345.974
344.181
342.397
340.631
338.881
337.174
335.483
333.801
332.154
330.523
328.913
327.330
325.762
324.227
322.694
321.174
319.668
318.212
316.770
315.365
314.016
312.678
311.359
310.044
308.741
307.473
306.235
305.006
303.795
302.593
301.401
300.232
299.072
297.921
296.798
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
295.490
294.012
292.550
291.102
289.668
288.249
286.844
285.453
284.075
282.711
281.360
280.022
278.697
277.384
276.084
274.797
273.521
272.258
271.006
269.766
268.538
267.321
266.115
264.920
263.735
262.562
261.399
260.247
259.105
257.973
256.851
255.738
254.636
253.543
252.460
251.386
250.322
249.266
248.220
247.183
246.154
245.134
244.122
243.119
242.125
241.138
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002692
2:35:25
2:35:27
2:35:29
2:35:31
2:35:33
2:35:35
2:35:37
2:35:39
2:35:41
2:35:43
2:35:45
2:35:47
2:35:49
2:35:51
2:35:53
2:35:55
2:35:57
2:35:59
2:36:01
2:36:03
2:36:05
2:36:07
2:36:09
2:36:11
2:36:13
2:36:15
2:36:17
2:36:19
2:36:21
2:36:23
2:36:25
2:36:27
2:36:29
2:36:31
2:36:33
2:36:35
2:36:37
2:36:39
2:36:41
2:36:43
2:36:45
2:36:47
2:36:49
2:36:51
2:36:53
2:36:55
59.976
59.976
59.976
59.982
59.982
59.978
59.974
59.974
59.976
59.977
59.977
59.975
59.969
59.969
59.97
59.973
59.973
59.978
59.978
59.978
59.975
59.976
59.976
59.975
59.969
59.969
59.966
59.966
59.966
59.969
59.968
59.968
59.965
59.97
59.97
59.972
59.967
59.967
59.969
59.969
59.969
59.967
59.966
59.966
59.965
59.967
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
33.838
33.838
33.838
25.382
25.382
31.019
36.661
36.661
33.838
32.428
32.428
35.252
43.708
43.708
42.298
38.071
38.071
31.019
31.019
31.019
35.252
33.838
33.838
35.252
43.708
43.708
47.941
47.941
47.941
43.708
45.122
45.122
49.350
42.298
42.298
39.480
46.531
46.531
43.708
43.708
43.708
46.531
47.941
47.941
49.350
46.531
33.838
33.838
33.838
25.382
25.382
31.019
36.661
36.661
33.838
32.428
32.428
35.252
43.708
43.708
42.298
38.071
38.071
31.019
31.019
31.019
35.252
33.838
33.838
35.252
43.708
43.708
47.941
47.941
47.941
43.708
45.122
45.122
49.350
42.298
42.298
39.480
46.531
46.531
43.708
43.708
43.708
46.531
47.941
47.941
49.350
46.531
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
30.288
30.288
30.288
21.833
21.833
27.470
33.112
33.112
30.288
28.879
28.879
31.703
40.158
40.158
38.749
34.521
34.521
27.470
27.470
27.470
31.703
30.288
30.288
31.703
40.158
40.158
44.391
44.391
44.391
40.158
41.573
41.573
45.800
38.749
38.749
35.930
42.982
42.982
40.158
40.158
40.158
42.982
44.391
44.391
45.800
42.982
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
295.701
294.613
293.534
292.430
291.334
290.270
289.238
288.213
287.186
286.161
285.144
284.146
283.189
282.240
281.292
280.336
279.387
278.418
277.456
276.502
275.571
274.642
273.720
272.810
271.939
271.074
270.231
269.395
268.565
267.725
266.897
266.074
265.273
264.453
263.638
262.819
262.031
261.248
260.462
259.680
258.905
258.144
257.394
256.650
255.915
255.176
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
240.160
239.190
238.228
237.273
236.327
235.388
234.456
233.533
232.616
231.707
230.805
229.910
229.022
228.141
227.267
226.400
225.540
224.686
223.839
222.998
222.164
221.336
220.514
219.699
218.889
218.086
217.289
216.497
215.712
214.932
214.158
213.390
212.627
211.870
211.118
210.372
209.631
208.895
208.165
207.440
206.720
206.005
205.295
204.590
203.890
203.195
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002693
2:36:57
2:36:59
2:37:01
2:37:03
2:37:05
2:37:07
2:37:09
2:37:11
2:37:13
2:37:15
2:37:17
2:37:19
2:37:21
2:37:23
2:37:25
2:37:27
2:37:29
2:37:31
2:37:33
2:37:35
2:37:37
2:37:39
2:37:41
2:37:43
2:37:45
2:37:47
2:37:49
2:37:51
2:37:53
2:37:55
2:37:57
2:37:59
2:38:01
2:38:03
2:38:05
2:38:07
2:38:09
2:38:11
2:38:13
2:38:15
2:38:17
2:38:19
2:38:21
2:38:23
2:38:25
2:38:27
59.967
59.965
59.964
59.964
59.97
59.969
59.969
59.968
59.965
59.965
59.97
59.968
59.968
59.965
59.969
59.969
59.967
59.966
59.966
59.979
59.983
59.983
59.974
59.965
59.965
59.962
59.961
59.961
59.961
59.963
59.963
59.959
59.951
59.951
59.953
59.957
59.957
59.956
59.963
59.963
59.961
59.963
59.963
59.963
59.968
59.968
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
46.531
49.350
50.759
50.759
42.298
43.708
43.708
45.122
49.350
49.350
42.298
45.122
45.122
49.350
43.708
43.708
46.531
47.941
47.941
29.610
23.968
23.968
36.661
49.350
49.350
53.577
54.992
54.992
54.992
52.168
52.168
57.811
69.090
69.090
66.271
60.629
60.629
62.038
52.168
52.168
54.992
52.168
52.168
52.168
45.122
45.122
46.531
49.350
50.759
50.759
42.298
43.708
43.708
45.122
49.350
49.350
42.298
45.122
45.122
49.350
43.708
43.708
46.531
47.941
47.941
29.610
23.968
23.968
36.661
49.350
49.350
53.577
54.992
54.992
54.992
52.168
52.168
57.811
69.090
69.090
66.271
60.629
60.629
62.038
52.168
52.168
54.992
52.168
52.168
52.168
45.122
45.122
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
42.982
45.800
47.210
47.210
38.749
40.158
40.158
41.573
45.800
45.800
38.749
41.573
41.573
45.800
40.158
40.158
42.982
44.391
44.391
26.060
20.418
20.418
33.112
45.800
45.800
50.028
51.443
51.443
51.443
48.619
48.619
54.261
65.540
65.540
62.722
57.079
57.079
58.489
48.619
48.619
51.443
48.619
48.619
48.619
41.573
41.573
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
254.441
253.722
253.012
252.307
251.579
250.859
250.145
249.441
248.755
248.074
247.374
246.688
246.006
245.343
244.666
243.993
243.334
242.684
242.038
241.337
240.622
239.912
239.247
238.627
238.011
237.412
236.822
236.235
235.652
235.064
234.480
233.916
233.392
232.871
232.344
231.803
231.265
230.735
230.178
229.625
229.083
228.536
227.993
227.452
226.894
226.339
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
202.505
201.820
201.139
200.463
199.791
199.125
198.462
197.805
197.151
196.502
195.858
195.217
194.581
193.949
193.322
192.698
192.079
191.464
190.852
190.245
189.642
189.042
188.447
187.855
187.267
186.683
186.102
185.525
184.952
184.383
183.817
183.254
182.695
182.140
181.588
181.039
180.494
179.952
179.414
178.879
178.347
177.818
177.293
176.770
176.251
175.735
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002694
2:38:29
2:38:31
2:38:33
2:38:35
2:38:37
2:38:39
2:38:41
2:38:43
2:38:45
2:38:47
2:38:49
2:38:51
2:38:53
2:38:55
2:38:57
2:38:59
2:39:01
2:39:03
2:39:05
2:39:07
2:39:09
2:39:11
2:39:13
2:39:15
2:39:17
2:39:19
2:39:21
2:39:23
2:39:25
2:39:27
2:39:29
2:39:31
2:39:33
2:39:35
2:39:37
2:39:39
2:39:41
2:39:43
2:39:45
2:39:47
2:39:49
2:39:51
2:39:53
2:39:55
2:39:57
2:39:59
59.968
59.97
59.97
59.973
59.965
59.965
59.967
59.972
59.972
59.976
59.969
59.969
59.973
59.978
59.978
59.981
59.981
59.981
59.982
59.984
59.984
59.982
59.979
59.979
59.98
59.978
59.978
59.98
59.98
59.98
59.978
59.972
59.972
59.971
59.974
59.974
59.975
59.972
59.972
59.969
59.974
59.974
59.972
59.972
59.972
59.977
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
45.122
42.298
42.298
38.071
49.350
49.350
46.531
39.480
39.480
33.838
43.708
43.708
38.071
31.019
31.019
26.791
26.791
26.791
25.382
22.558
22.558
25.382
29.610
29.610
28.201
31.019
31.019
28.201
28.201
28.201
31.019
39.480
39.480
40.889
36.661
36.661
35.252
39.480
39.480
43.708
36.661
36.661
39.480
39.480
39.480
32.428
45.122
42.298
42.298
38.071
49.350
49.350
46.531
39.480
39.480
33.838
43.708
43.708
38.071
31.019
31.019
26.791
26.791
26.791
25.382
22.558
22.558
25.382
29.610
29.610
28.201
31.019
31.019
28.201
28.201
28.201
31.019
39.480
39.480
40.889
36.661
36.661
35.252
39.480
39.480
43.708
36.661
36.661
39.480
39.480
39.480
32.428
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
41.573
38.749
38.749
34.521
45.800
45.800
42.982
35.930
35.930
30.288
40.158
40.158
34.521
27.470
27.470
23.242
23.242
23.242
21.833
19.009
19.009
21.833
26.060
26.060
24.651
27.470
27.470
24.651
24.651
24.651
27.470
35.930
35.930
37.340
33.112
33.112
31.703
35.930
35.930
40.158
33.112
33.112
35.930
35.930
35.930
28.879
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
225.788
225.231
224.678
224.115
223.589
223.066
222.538
221.993
221.450
220.894
220.371
219.850
219.316
218.764
218.216
217.659
217.105
216.555
216.003
215.446
214.893
214.351
213.823
213.299
212.773
212.259
211.747
211.230
210.716
210.205
209.704
209.229
208.757
208.291
207.817
207.344
206.871
206.411
205.954
205.511
205.051
204.594
204.147
203.702
203.259
202.800
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
175.222
174.712
174.205
173.702
173.201
172.703
172.208
171.716
171.227
170.740
170.257
169.776
169.298
168.823
168.350
167.881
167.414
166.949
166.487
166.028
165.572
165.118
164.666
164.217
163.771
163.327
162.886
162.447
162.010
161.576
161.144
160.715
160.288
159.863
159.440
159.020
158.602
158.187
157.773
157.362
156.953
156.546
156.142
155.739
155.339
154.941
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002695
2:40:01
2:40:03
2:40:05
2:40:07
2:40:09
2:40:11
2:40:13
2:40:15
2:40:17
2:40:19
2:40:21
2:40:23
2:40:25
2:40:27
2:40:29
2:40:31
2:40:33
2:40:35
2:40:37
2:40:39
2:40:41
2:40:43
2:40:45
2:40:47
2:40:49
2:40:51
2:40:53
2:40:55
2:40:57
2:40:59
2:41:01
2:41:03
2:41:05
2:41:07
2:41:09
2:41:11
2:41:13
2:41:15
2:41:17
2:41:19
2:41:21
2:41:23
2:41:25
2:41:27
2:41:29
2:41:31
59.978
59.978
59.976
59.974
59.974
59.977
59.978
59.978
59.979
59.977
59.977
59.974
59.971
59.971
59.971
59.968
59.968
59.966
59.971
59.971
59.973
59.969
59.969
59.972
59.973
59.973
59.97
59.974
59.974
59.982
59.985
59.985
59.985
59.989
59.989
59.989
59.987
59.987
59.99
59.996
59.996
60.001
60.004
60.004
60.006
60.014
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
31.019
31.019
33.838
36.661
36.661
32.428
31.019
31.019
29.610
32.428
32.428
36.661
40.889
40.889
40.889
45.122
45.122
47.941
40.889
40.889
38.071
43.708
43.708
39.480
38.071
38.071
42.298
36.661
36.661
25.382
21.149
21.149
21.149
15.512
15.512
15.512
18.331
18.331
14.098
5.642
5.642
-1.409
-5.642
-5.642
-8.461
-19.740
31.019
31.019
33.838
36.661
36.661
32.428
31.019
31.019
29.610
32.428
32.428
36.661
40.889
40.889
40.889
45.122
45.122
47.941
40.889
40.889
38.071
43.708
43.708
39.480
38.071
38.071
42.298
36.661
36.661
25.382
21.149
21.149
21.149
15.512
15.512
15.512
18.331
18.331
14.098
5.642
5.642
-1.409
-5.642
-5.642
-8.461
-19.740
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
27.470
27.470
30.288
33.112
33.112
28.879
27.470
27.470
26.060
28.879
28.879
33.112
37.340
37.340
37.340
41.573
41.573
44.391
37.340
37.340
34.521
40.158
40.158
35.930
34.521
34.521
38.749
33.112
33.112
21.833
17.600
17.600
17.600
11.963
11.963
11.963
14.781
14.781
10.548
2.093
2.093
-4.959
-9.192
-9.192
-12.010
-23.289
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
202.340
201.882
201.434
200.996
200.560
200.115
199.669
199.225
198.780
198.344
197.911
197.490
197.083
196.677
196.274
195.883
195.495
195.115
194.720
194.326
193.928
193.545
193.165
192.775
192.385
191.996
191.619
191.231
190.844
190.432
190.011
189.593
189.176
188.748
188.322
187.898
187.483
187.070
186.649
186.209
185.772
185.320
184.860
184.403
183.941
183.454
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
154.545
154.151
153.759
153.369
152.981
152.595
152.211
151.829
151.449
151.071
150.695
150.321
149.949
149.578
149.210
148.843
148.478
148.116
147.754
147.395
147.038
146.682
146.328
145.976
145.626
145.277
144.930
144.585
144.241
143.899
143.559
143.220
142.883
142.548
142.214
141.882
141.552
141.223
140.896
140.570
140.246
139.923
139.602
139.282
138.964
138.648
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002696
2:41:33
2:41:35
2:41:37
2:41:39
2:41:41
2:41:43
2:41:45
2:41:47
2:41:49
2:41:51
2:41:53
2:41:55
2:41:57
2:41:59
2:42:01
2:42:03
2:42:05
2:42:07
2:42:09
2:42:11
2:42:13
2:42:15
2:42:17
2:42:19
2:42:21
60.014
60.019
60.025
60.025
60.026
60.029
60.029
60.029
60.036
60.036
60.037
60.036
60.036
60.041
60.044
60.044
60.043
60.048
60.048
60.046
60.043
60.043
60.043
60.043
60.043
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-19.740
-26.791
-35.252
-35.252
-36.661
-40.889
-40.889
-40.889
-50.759
-50.759
-52.168
-50.759
-50.759
-57.811
-62.038
-62.038
-60.629
-67.680
-67.680
-64.862
-60.629
-60.629
-60.629
-60.629
-60.629
-19.740
-26.791
-35.252
-35.252
-36.661
-40.889
-40.889
-40.889
-50.759
-50.759
-52.168
-50.759
-50.759
-57.811
-62.038
-62.038
-60.629
-67.680
-67.680
-64.862
-60.629
-60.629
-60.629
-60.629
-60.629
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-23.289
-30.341
-38.802
-38.802
-40.211
-44.439
-44.439
-44.439
-54.309
-54.309
-55.718
-54.309
-54.309
-61.360
-65.588
-65.588
-64.178
-71.230
-71.230
-68.412
-64.178
-64.178
-64.178
-64.178
-64.178
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
182.970
182.471
181.956
181.442
180.928
180.406
179.887
179.370
178.833
178.298
177.763
177.233
176.706
176.164
175.616
175.071
174.530
173.977
173.426
172.884
172.353
171.825
171.300
170.776
170.256
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
4.407
138.333
138.019
137.707
137.396
137.087
136.779
136.473
136.168
135.864
135.562
135.261
134.961
134.663
134.367
134.071
133.777
133.485
133.193
132.903
132.614
132.327
132.041
131.756
131.472
131.190
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
002697
A Point
2:27:19
FPointA
60.0390
2:27:19 AM
A Value
60.0417
C Value
59.8360
#N/A
Delta FCA -0.205751419
FR C
-307.7 MW/0.1 Hz
Slope A-C dF/dT
#N/A
Hz/second
C Value Maximum Resource Loss
633
Secondary C Value
No
n/a Time
Tzero
FT+4
FT+10
FT+20
FT+60
A Point
FPointA
A Value
C Value
Delta FC
B Frequency Value
Delta FB
Slope B dF/dT
RatioB-C
Sustainability Index
2:27:19
60.03900146
60.04174995
59.83599854
2:27:19
#N/A
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec
59.8823
59.8844
59.8887
59.8879
-0.1595
-397.436
-0.1573
-402.634
-0.1530
-415.164
-0.1538
-411.959
-0.00797319
-0.00786606
-0.0076522
-0.0076903
77.5032
76.4617
74.3829
74.7530
-0.0172
-0.0193
-0.0236
-0.0228
2:27:19
59.83599854
59.89099884
59.88299942
59.88999939
Interconnection Evaluation
ncy recovery period (indicates ramp direction during recovery period)
B Value Average Resource Loss
B Value Average LaaR Loss
B Value Average Net Loss
Interconnection Bias Setting
IPFR as a % of Bias Setting
Interconnection Total Energy
Interconnection Peak Energy
633
0
633
-660
0.00%
37446
62339
Generator Generator Generator Generator Generator Generator
Trip
Trip
Trip
Trip
Trip
Trip
MW
MW
MW
MW
MW
MW
Interconnection Bias Total
EI
ERCOT
WECC
-6349
-660
-2024
60.07%
Frequency and Interconnection Frequency Response @ different Average periods of B
LaaR
Trip
MW
Total Interconnection
Generation
Primary
Trip
Frequency
MW
Response
FR B
20 to 52 sec
Average
MW
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
MW/0.1 Hz
0
0
0
0
T-72 sec
T-70 sec
T-68 sec
002698
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
-992.9518715
T+0 sec
-992.9518715
T+02 sec
-307.6527991
T+04 sec
-307.6527991
T+06 sec
-366.424467
T+08 sec
-419.8973949
T+10 sec
-419.8973949
T+12 sec
-391.3473627
T+14 sec
-379.6102991
T+16 sec
-379.6102991
T+18 sec
-398.7388161 -413.8616294 T+20 sec
-406.4248062 -413.8616294 T+22 sec
-406.4248062 -413.8616294 T+24 sec
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
59.8823
-397.436
-397.436
-397.436
-397.436
-397.436
-397.436
-397.436
59.8844
59.8844
59.8844
59.8844
-402.634
-402.634
-402.634
-402.634
59.8887
59.8887
59.8887
-415.164
-415.164
-415.164
59.8879
59.8879
59.8879
59.8879
-411.959
-411.959
-411.959
-411.959
002699
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-403.823545
-411.7087472
-411.7087472
-417.1318913
-428.4294489
-428.4294489
-425.5508021
-428.4294489
-428.4294489
-419.8973949
-403.823545
-403.823545
-403.823545
-409.0497134
-409.0497134
-411.7087472
-417.1318913
-417.1318913
-414.4025773
-375.113655
-375.113655
-342.6223677
-333.5990109
-333.5990109
-344.4930857
-360.1731048
-360.1731048
-358.1364499
-360.1731048
-360.1731048
-370.7140109
-388.9440669
-388.9440669
-391.3473627
-406.4248062
-406.4248062
-417.1318913
-414.4025773
-414.4025773
-425.5508021
-456.2159654
-456.2159654
-452.9532326
-459.5260437
-459.5260437
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
-413.8616294
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
59.8844
59.8844
59.8844
-402.634
-402.634
-402.634
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
-415.164
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
59.8879
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
-411.959
002700
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-469.7641853
-503.3813709
-503.3813709
-503.3813709
-511.5123133
-511.5123133
-519.9102408
-519.9102408
-519.9102408
-507.4142711
-524.2300283
-524.2300283
-533.054344
-542.1808237
-542.1808237
-556.4906082
-576.7614466
-576.7614466
-551.625258
-571.5565384
-571.5565384
-561.4235515
-571.5565384
-571.5565384
-604.2977913
-654.2618117
-654.2618117
-682.4897773
-634.5952999
-634.5952999
-628.2999262
-654.2618117
-654.2618117
-675.2137373
-682.4897773
-682.4897773
-697.522655
-713.2326922
-713.2326922
-697.522655
-705.2902008
-705.2902008
-705.2902008
-705.2902008
-705.2902008
-721.3561067
002701
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-713.2326922
-713.2326922
-713.2326922
-721.3561067
-721.3561067
-721.3561067
-746.9095132
-746.9095132
-738.2038481
-738.2038481
-738.2038481
-729.6987841
-783.8871531
-783.8871531
-793.7487838
-858.2882148
-858.2882148
-835.6396928
-858.2882148
-858.2882148
-882.2455379
-882.2455379
-882.2455379
-870.1248106
-882.2455379
-882.2455379
-894.7087159
-920.722164
-920.722164
-962.7637841
-992.9518715
-992.9518715
-962.7637841
-962.7637841
-962.7637841
-992.9518715
-1025.094375
-1025.094375
-1059.387442
-1025.094375
-1025.094375
-1008.767148
-1008.767148
-1008.767148
-1077.478991
-1096.126776
002702
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-1096.126776
-1177.652688
-1156.155039
-1156.155039
-1156.155039
-1298.463571
-1298.463571
-1272.377809
-1199.964942
-1199.964942
-1135.428184
-1077.478991
-1077.478991
-1177.652688
-1383.559028
-1383.559028
-1446.894991
-1553.355039
-1553.355039
-1480.722366
-1480.722366
-1480.722366
-1592.410652
-1821.583534
-1821.583534
-1875.525877
-2281.079827
-2281.079827
-2557.403899
-3050.59568
-3050.59568
-2557.403899
-2782.546357
-2782.546357
-3375.793958
-3779.459105
-3779.459105
-3050.59568
-3565.856925
-3565.856925
-3565.856925
-2910.412207
-2910.412207
-3779.459105
-2910.412207
-2910.412207
002703
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2910.412207
-3204.966721
-3204.966721
-3204.966721
-3050.59568
-3050.59568
-3375.793958
-3204.966721
-3204.966721
-2782.546357
-2665.442968
-2665.442968
-2665.442968
-2782.546357
-2782.546357
-2782.546357
-2366.305198
-2366.305198
-2458.146093
-2201.780031
-2201.780031
-2127.808579
-1993.59827
-1993.59827
-1821.583534
-1932.760492
-1932.760492
-1932.760492
-1633.480849
-1633.480849
-1480.722366
-1272.377809
-1272.377809
-1247.319517
-1272.377809
-1272.377809
-1177.652688
-1115.431399
-1115.431399
-1096.126776
-1096.126776
-1096.126776
-1059.387442
-1059.387442
-1059.387442
-1008.767148
002704
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-962.7637841
-962.7637841
-962.7637841
-1059.387442
-1059.387442
-992.9518715
-934.3045072
-934.3045072
-962.7637841
-977.6248387
-977.6248387
-948.2935794
-870.1248106
-870.1248106
-882.2455379
-920.722164
-920.722164
-992.9518715
-992.9518715
-992.9518715
-948.2935794
-962.7637841
-962.7637841
-948.2935794
-870.1248106
-870.1248106
-835.6396928
-835.6396928
-835.6396928
-870.1248106
-858.2882148
-858.2882148
-824.757832
-882.2455379
-882.2455379
-907.5290656
-846.8125437
-846.8125437
-870.1248106
-870.1248106
-870.1248106
-846.8125437
-835.6396928
-835.6396928
-824.757832
-846.8125437
002705
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-846.8125437
-824.757832
-814.1557393
-814.1557393
-882.2455379
-870.1248106
-870.1248106
-858.2882148
-824.757832
-824.757832
-882.2455379
-858.2882148
-858.2882148
-824.757832
-870.1248106
-870.1248106
-846.8125437
-835.6396928
-835.6396928
-1008.767148
-1077.478991
-1077.478991
-934.3045072
-824.757832
-824.757832
-793.7487838
-783.8871531
-783.8871531
-783.8871531
-803.8227626
-803.8227626
-764.9517206
-697.522655
-697.522655
-713.2326922
-746.9095132
-746.9095132
-738.2038481
-803.8227626
-803.8227626
-783.8871531
-803.8227626
-803.8227626
-803.8227626
-858.2882148
-858.2882148
002706
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-858.2882148
-882.2455379
-882.2455379
-920.722164
-824.757832
-824.757832
-846.8125437
-907.5290656
-907.5290656
-962.7637841
-870.1248106
-870.1248106
-920.722164
-992.9518715
-992.9518715
-1041.958821
-1041.958821
-1041.958821
-1059.387442
-1096.126776
-1096.126776
-1059.387442
-1008.767148
-1008.767148
-1025.094375
-992.9518715
-992.9518715
-1025.094375
-1025.094375
-1025.094375
-992.9518715
-907.5290656
-907.5290656
-894.7087159
-934.3045072
-934.3045072
-948.2935794
-907.5290656
-907.5290656
-870.1248106
-934.3045072
-934.3045072
-907.5290656
-907.5290656
-907.5290656
-977.6248387
002707
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-992.9518715
-992.9518715
-962.7637841
-934.3045072
-934.3045072
-977.6248387
-992.9518715
-992.9518715
-1008.767148
-977.6248387
-977.6248387
-934.3045072
-894.7087159
-894.7087159
-894.7087159
-858.2882148
-858.2882148
-835.6396928
-894.7087159
-894.7087159
-920.722164
-870.1248106
-870.1248106
-907.5290656
-920.722164
-920.722164
-882.2455379
-934.3045072
-934.3045072
-1059.387442
-1115.431399
-1115.431399
-1115.431399
-1199.964942
-1199.964942
-1199.964942
-1156.155039
-1156.155039
-1223.229162
-1383.559028
-1383.559028
-1553.355039
-1676.895074
-1676.895074
-1770.657333
-2281.079827
002708
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
633
-2281.079827
-2782.546357
-3779.459105
-3779.459105
-4019.308514
-4964.462289
-4964.462289
-4964.462289
-11007.4396
-11007.4396
-13322.93473
-11007.4396
-11007.4396
-84446.38779
28148.79593
28148.79593
50667.83267
10127.38187
10127.38187
14888.93244
50667.83267
50667.83267
50667.83267
50667.83267
50667.83267
002709
Non-Conforming Load sign convention
-
(Data is positive for Load then enter "+" else "-"
Time of Frequency Recover
Value A Pre-Perturbation Av
Value B Post-Perturbation Ave
Value B
FR B
20 to 52 sec 20 to 52 sec
59.8887
-0.1530
-413.862
-0.0076522
74.3829
-0.0236
Value A Pre-Perturbation Average
Value B Post-Perturbation Average In
Average periods of B
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Value B
FR B
20 to 52 sec 20 to 52 sec
Average
Average
Frequency
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Net
Actual
Interchange
MW
60.0270
60.0270
60.0260
633.00
633.00
633.00
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
253.63
253.63
253.63
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Ramping
Units
Gen (+)
MW
0.00
0.00
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
0.00
0.00
0.00
12 to 24 second Average
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
-420.00
-420.00
-420.00
BA
Load
MW
7593.39
7593.39
7593.72
FRO
Expected
Primary
Freq Response
MW
-38.071 T-72 sec
-38.071 T-70 sec
-36.661 T-68 sec
T
2:26:09
2:26:11
2:26:13
002710
59.8887
59.8887
59.8887
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
-413.862 T+20 sec
-413.862 T+22 sec
-413.862 T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
60.0220
60.0220
60.0170
60.0190
60.0190
60.0190
60.0210
60.0210
60.0210
60.0190
60.0190
60.0220
60.0310
60.0310
60.0370
60.0360
60.0360
60.0460
60.0480
60.0480
60.0430
60.0410
60.0410
60.0410
60.0390
60.0390
60.0430
60.0450
60.0450
60.0410
60.0410
60.0410
60.0390
59.9780
59.9780
59.8360
59.8360
59.8690
59.8910
59.8910
59.8800
59.8750
59.8750
59.8830
59.8860
59.8860
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
633.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
253.63
253.63
253.63
253.63
253.63
246.96
246.96
246.96
246.96
246.96
246.96
246.96
254.54
254.54
254.54
254.54
254.54
254.54
165.10
165.10
165.10
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7594.05
7594.05
7594.38
7594.71
7594.71
7595.04
7595.37
7595.37
7595.70
7596.03
7596.03
7596.36
7596.69
7596.69
7597.02
7597.35
7597.35
7597.68
7598.01
7598.01
7598.34
7598.67
7598.67
7599.00
7599.33
7599.33
7599.66
7599.99
7599.99
7600.32
7600.65
7600.65
7600.98
7601.31
7601.31
7570.00
7570.00
7569.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
-31.019
-31.019
-23.968
-26.791
-26.791
-26.791
-29.610
-29.610
-29.610
-26.791
-26.791
-31.019
-43.708
-43.708
-52.168
-50.759
-50.759
-64.862
-67.680
-67.680
-60.629
-57.811
-57.811
-57.811
-54.992
-54.992
-60.629
-63.447
-63.447
-57.811
-57.811
-57.811
-54.992
31.019
31.019
231.242
231.242
184.711
153.692
153.692
169.198
176.250
176.250
164.971
160.738
160.738
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
002711
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
59.8887
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
-413.862
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
2:28:43
2:28:45
2:28:47
2:28:49
2:28:51
2:28:53
2:28:55
2:28:57
2:28:59
2:29:01
2:29:03
2:29:05
2:29:07
2:29:09
2:29:11
2:29:13
2:29:15
59.8850
59.8880
59.8880
59.8900
59.8940
59.8940
59.8930
59.8940
59.8940
59.8910
59.8850
59.8850
59.8850
59.8870
59.8870
59.8880
59.8900
59.8900
59.8890
59.8730
59.8730
59.8570
59.8520
59.8520
59.8580
59.8660
59.8660
59.8650
59.8660
59.8660
59.8710
59.8790
59.8790
59.8800
59.8860
59.8860
59.8900
59.8890
59.8890
59.8930
59.9030
59.9030
59.9020
59.9040
59.9040
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7568.00
7568.00
7565.00
7560.00
7560.00
7563.00
7564.00
7564.00
7566.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7570.00
7569.00
7575.00
7575.00
7573.00
7571.00
7571.00
7573.00
7575.00
7575.00
162.152
157.919
157.919
155.101
149.459
149.459
150.868
149.459
149.459
153.692
162.152
162.152
162.152
159.329
159.329
157.919
155.101
155.101
156.510
179.068
179.068
201.632
208.678
208.678
200.218
188.938
188.938
190.348
188.938
188.938
181.892
170.608
170.608
169.198
160.738
160.738
155.101
156.510
156.510
150.868
136.770
136.770
138.179
135.361
135.361
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
002712
2:29:17
2:29:19
2:29:21
2:29:23
2:29:25
2:29:27
2:29:29
2:29:31
2:29:33
2:29:35
2:29:37
2:29:39
2:29:41
2:29:43
2:29:45
2:29:47
2:29:49
2:29:51
2:29:53
2:29:55
2:29:57
2:29:59
2:30:01
2:30:03
2:30:05
2:30:07
2:30:09
2:30:11
2:30:13
2:30:15
2:30:17
2:30:19
2:30:21
2:30:23
2:30:25
2:30:27
2:30:29
2:30:31
2:30:33
2:30:35
2:30:37
2:30:39
2:30:41
2:30:43
2:30:45
2:30:47
59.9070
59.9160
59.9160
59.9160
59.9180
59.9180
59.9200
59.9200
59.9200
59.9170
59.9210
59.9210
59.9230
59.9250
59.9250
59.9280
59.9320
59.9320
59.9270
59.9310
59.9310
59.9290
59.9310
59.9310
59.9370
59.9450
59.9450
59.9490
59.9420
59.9420
59.9410
59.9450
59.9450
59.9480
59.9490
59.9490
59.9510
59.9530
59.9530
59.9510
59.9520
59.9520
59.9520
59.9520
59.9520
59.9540
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
228.80
228.80
229.47
229.47
249.34
249.34
249.34
249.34
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7577.00
7577.00
7577.00
7578.00
7579.00
7579.00
7580.00
7581.00
7581.00
7585.00
7588.00
7588.00
7589.00
7589.00
7589.00
7590.00
7590.00
7590.00
7590.00
7591.00
7591.00
7591.00
7591.00
7591.00
7592.00
7592.00
7592.00
7593.00
7594.00
7594.00
7595.00
7655.00
7655.00
7656.00
7656.00
7656.00
7657.00
7657.00
7657.00
7658.00
7658.00
7658.00
7659.00
7659.00
7659.00
7659.00
131.128
118.439
118.439
118.439
115.621
115.621
112.803
112.803
112.803
117.030
111.388
111.388
108.570
105.751
105.751
101.518
95.881
95.881
102.933
97.290
97.290
100.109
97.290
97.290
88.830
77.550
77.550
71.908
81.778
81.778
83.187
77.550
77.550
73.317
71.908
71.908
69.090
66.271
66.271
69.090
67.680
67.680
67.680
67.680
67.680
64.862
002713
2:30:49
2:30:51
2:30:53
2:30:55
2:30:57
2:30:59
2:31:01
2:31:03
2:31:05
2:31:07
2:31:09
2:31:11
2:31:13
2:31:15
2:31:17
2:31:19
2:31:21
2:31:23
2:31:25
2:31:27
2:31:29
2:31:31
2:31:33
2:31:35
2:31:37
2:31:39
2:31:41
2:31:43
2:31:45
2:31:47
2:31:49
2:31:51
2:31:53
2:31:55
2:31:57
2:31:59
2:32:01
2:32:03
2:32:05
2:32:07
2:32:09
2:32:11
2:32:13
2:32:15
2:32:17
2:32:19
59.9530
59.9530
59.9530
59.9540
59.9540
59.9540
59.9570
59.9570
59.9560
59.9560
59.9560
59.9550
59.9610
59.9610
59.9620
59.9680
59.9680
59.9660
59.9680
59.9680
59.9700
59.9700
59.9700
59.9690
59.9700
59.9700
59.9710
59.9730
59.9730
59.9760
59.9780
59.9780
59.9760
59.9760
59.9760
59.9780
59.9800
59.9800
59.9820
59.9800
59.9800
59.9790
59.9790
59.9790
59.9830
59.9840
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
249.34
249.34
249.34
258.28
258.28
258.28
258.28
258.28
258.28
258.28
258.28
258.41
258.41
258.41
258.41
258.41
258.41
258.41
260.54
260.54
260.54
260.54
260.54
260.54
260.54
260.54
257.88
257.88
257.88
257.88
257.88
257.88
257.88
258.59
258.59
258.59
258.59
258.59
258.59
258.59
258.59
261.91
261.91
261.91
261.91
261.91
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7660.00
7660.00
7660.00
7661.00
7661.00
7661.00
7625.40
7625.40
7625.73
7626.06
7626.06
7626.39
7626.72
7626.72
7627.05
7627.38
7627.38
7627.71
7628.04
7628.04
7628.37
7628.70
7628.70
7629.03
7629.36
7629.36
7629.69
7630.02
7630.02
7630.35
7630.68
7630.68
7631.01
7631.34
7631.34
7631.67
7632.00
7632.00
7632.33
7632.66
7632.66
7632.99
7633.32
7633.32
7633.65
7633.98
66.271
66.271
66.271
64.862
64.862
64.862
60.629
60.629
62.038
62.038
62.038
63.447
54.992
54.992
53.577
45.122
45.122
47.941
45.122
45.122
42.298
42.298
42.298
43.708
42.298
42.298
40.889
38.071
38.071
33.838
31.019
31.019
33.838
33.838
33.838
31.019
28.201
28.201
25.382
28.201
28.201
29.610
29.610
29.610
23.968
22.558
002714
2:32:21
2:32:23
2:32:25
2:32:27
2:32:29
2:32:31
2:32:33
2:32:35
2:32:37
2:32:39
2:32:41
2:32:43
2:32:45
2:32:47
2:32:49
2:32:51
2:32:53
2:32:55
2:32:57
2:32:59
2:33:01
2:33:03
2:33:05
2:33:07
2:33:09
2:33:11
2:33:13
2:33:15
2:33:17
2:33:19
2:33:21
2:33:23
2:33:25
2:33:27
2:33:29
2:33:31
2:33:33
2:33:35
2:33:37
2:33:39
2:33:41
2:33:43
2:33:45
2:33:47
2:33:49
2:33:51
59.9840
59.9880
59.9870
59.9870
59.9870
59.9930
59.9930
59.9920
59.9890
59.9890
59.9860
59.9830
59.9830
59.9880
59.9960
59.9960
59.9980
60.0010
60.0010
59.9990
59.9990
59.9990
60.0020
60.0070
60.0070
60.0080
60.0140
60.0140
60.0170
60.0210
60.0210
60.0170
60.0190
60.0190
60.0230
60.0250
60.0250
60.0210
60.0240
60.0240
60.0240
60.0200
60.0200
60.0250
60.0200
60.0200
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
261.91
261.91
256.75
256.75
256.75
256.75
256.75
256.75
256.75
256.75
167.43
167.43
167.43
167.43
167.43
167.43
167.43
164.97
164.97
164.97
164.97
164.97
164.97
164.97
164.97
157.63
157.63
157.63
157.63
157.63
157.63
157.63
155.53
155.53
155.53
155.53
155.53
155.53
155.53
155.53
160.45
160.45
160.45
160.45
160.45
160.45
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7633.98
7634.31
7634.64
7634.64
7634.97
7635.30
7635.30
7635.63
7635.96
7635.96
7636.29
7636.62
7636.62
7636.95
7637.28
7637.28
7637.61
7637.94
7637.94
7638.27
7638.60
7638.60
7638.93
7639.26
7639.26
7639.59
7639.92
7639.92
7640.25
7640.58
7640.58
7640.91
7641.24
7641.24
7641.57
7641.90
7641.90
7642.23
7642.56
7642.56
7642.89
7643.22
7643.22
7643.55
7643.88
7643.88
22.558
16.921
18.331
18.331
18.331
9.870
9.870
11.279
15.512
15.512
19.740
23.968
23.968
16.921
5.642
5.642
2.818
-1.409
-1.409
1.409
1.409
1.409
-2.818
-9.870
-9.870
-11.279
-19.740
-19.740
-23.968
-29.610
-29.610
-23.968
-26.791
-26.791
-32.428
-35.252
-35.252
-29.610
-33.838
-33.838
-33.838
-28.201
-28.201
-35.252
-28.201
-28.201
002715
2:33:53
2:33:55
2:33:57
2:33:59
2:34:01
2:34:03
2:34:05
2:34:07
2:34:09
2:34:11
2:34:13
2:34:15
2:34:17
2:34:19
2:34:21
2:34:23
2:34:25
2:34:27
2:34:29
2:34:31
2:34:33
2:34:35
2:34:37
2:34:39
2:34:41
2:34:43
2:34:45
2:34:47
2:34:49
2:34:51
2:34:53
2:34:55
2:34:57
2:34:59
2:35:01
2:35:03
2:35:05
2:35:07
2:35:09
2:35:11
2:35:13
2:35:15
2:35:17
2:35:19
2:35:21
2:35:23
60.0200
60.0220
60.0220
60.0220
60.0210
60.0210
60.0230
60.0220
60.0220
60.0190
60.0180
60.0180
60.0180
60.0190
60.0190
60.0190
60.0150
60.0150
60.0160
60.0130
60.0130
60.0120
60.0100
60.0100
60.0070
60.0090
60.0090
60.0090
60.0030
60.0030
59.9990
59.9920
59.9920
59.9910
59.9920
59.9920
59.9880
59.9850
59.9850
59.9840
59.9840
59.9840
59.9820
59.9820
59.9820
59.9790
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
160.45
163.96
163.96
163.96
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
166.07
166.07
166.07
166.07
163.77
163.77
163.77
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
206.46
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7644.21
7644.54
7644.54
7644.87
7645.20
7645.20
7645.53
7645.86
7645.86
7646.19
7646.52
7646.52
7646.85
7647.18
7647.18
7647.51
7647.84
7647.84
7648.17
7648.50
7648.50
7648.83
7649.16
7649.16
7649.49
7649.82
7649.82
7650.15
7650.48
7650.48
7650.81
7651.14
7651.14
7651.47
7651.80
7651.80
7652.13
7652.46
7652.46
7652.79
7616.00
7616.00
7626.00
7632.00
7632.00
7632.00
-28.201
-31.019
-31.019
-31.019
-29.610
-29.610
-32.428
-31.019
-31.019
-26.791
-25.382
-25.382
-25.382
-26.791
-26.791
-26.791
-21.149
-21.149
-22.558
-18.331
-18.331
-16.921
-14.098
-14.098
-9.870
-12.688
-12.688
-12.688
-4.228
-4.228
1.409
11.279
11.279
12.688
11.279
11.279
16.921
21.149
21.149
22.558
22.558
22.558
25.382
25.382
25.382
29.610
002716
2:35:25
2:35:27
2:35:29
2:35:31
2:35:33
2:35:35
2:35:37
2:35:39
2:35:41
2:35:43
2:35:45
2:35:47
2:35:49
2:35:51
2:35:53
2:35:55
2:35:57
2:35:59
2:36:01
2:36:03
2:36:05
2:36:07
2:36:09
2:36:11
2:36:13
2:36:15
2:36:17
2:36:19
2:36:21
2:36:23
2:36:25
2:36:27
2:36:29
2:36:31
2:36:33
2:36:35
2:36:37
2:36:39
2:36:41
2:36:43
2:36:45
2:36:47
2:36:49
2:36:51
2:36:53
2:36:55
59.9760
59.9760
59.9760
59.9820
59.9820
59.9780
59.9740
59.9740
59.9760
59.9770
59.9770
59.9750
59.9690
59.9690
59.9700
59.9730
59.9730
59.9780
59.9780
59.9780
59.9750
59.9760
59.9760
59.9750
59.9690
59.9690
59.9660
59.9660
59.9660
59.9690
59.9680
59.9680
59.9650
59.9700
59.9700
59.9720
59.9670
59.9670
59.9690
59.9690
59.9690
59.9670
59.9660
59.9660
59.9650
59.9670
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
211.26
211.26
211.26
211.26
211.26
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
217.38
217.38
214.83
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7625.00
7623.00
7621.00
33.838
33.838
33.838
25.382
25.382
31.019
36.661
36.661
33.838
32.428
32.428
35.252
43.708
43.708
42.298
38.071
38.071
31.019
31.019
31.019
35.252
33.838
33.838
35.252
43.708
43.708
47.941
47.941
47.941
43.708
45.122
45.122
49.350
42.298
42.298
39.480
46.531
46.531
43.708
43.708
43.708
46.531
47.941
47.941
49.350
46.531
002717
2:36:57
2:36:59
2:37:01
2:37:03
2:37:05
2:37:07
2:37:09
2:37:11
2:37:13
2:37:15
2:37:17
2:37:19
2:37:21
2:37:23
2:37:25
2:37:27
2:37:29
2:37:31
2:37:33
2:37:35
2:37:37
2:37:39
2:37:41
2:37:43
2:37:45
2:37:47
2:37:49
2:37:51
2:37:53
2:37:55
2:37:57
2:37:59
2:38:01
2:38:03
2:38:05
2:38:07
2:38:09
2:38:11
2:38:13
2:38:15
2:38:17
2:38:19
2:38:21
2:38:23
2:38:25
2:38:27
59.9670
59.9650
59.9640
59.9640
59.9700
59.9690
59.9690
59.9680
59.9650
59.9650
59.9700
59.9680
59.9680
59.9650
59.9690
59.9690
59.9670
59.9660
59.9660
59.9790
59.9830
59.9830
59.9740
59.9650
59.9650
59.9620
59.9610
59.9610
59.9610
59.9630
59.9630
59.9590
59.9510
59.9510
59.9530
59.9570
59.9570
59.9560
59.9630
59.9630
59.9610
59.9630
59.9630
59.9630
59.9680
59.9680
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
214.83
214.83
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
228.80
228.80
229.47
229.47
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7621.00
7623.00
7625.00
7625.00
7627.00
7628.00
7628.00
7628.00
7629.00
7629.00
7630.00
7631.00
7631.00
7635.00
7638.00
7638.00
7639.00
7642.00
7642.00
7644.00
7645.00
7645.00
7647.00
7648.00
7648.00
7649.00
7650.00
7650.00
7651.00
7652.00
7652.00
7653.00
7654.00
7654.00
7655.00
7655.00
7655.00
7656.00
7656.00
7656.00
7657.00
7657.00
7657.00
7658.00
7658.00
7658.00
46.531
49.350
50.759
50.759
42.298
43.708
43.708
45.122
49.350
49.350
42.298
45.122
45.122
49.350
43.708
43.708
46.531
47.941
47.941
29.610
23.968
23.968
36.661
49.350
49.350
53.577
54.992
54.992
54.992
52.168
52.168
57.811
69.090
69.090
66.271
60.629
60.629
62.038
52.168
52.168
54.992
52.168
52.168
52.168
45.122
45.122
002718
2:38:29
2:38:31
2:38:33
2:38:35
2:38:37
2:38:39
2:38:41
2:38:43
2:38:45
2:38:47
2:38:49
2:38:51
2:38:53
2:38:55
2:38:57
2:38:59
2:39:01
2:39:03
2:39:05
2:39:07
2:39:09
2:39:11
2:39:13
2:39:15
2:39:17
2:39:19
2:39:21
2:39:23
2:39:25
2:39:27
2:39:29
2:39:31
2:39:33
2:39:35
2:39:37
2:39:39
2:39:41
2:39:43
2:39:45
2:39:47
2:39:49
2:39:51
2:39:53
2:39:55
2:39:57
2:39:59
59.9680
59.9700
59.9700
59.9730
59.9650
59.9650
59.9670
59.9720
59.9720
59.9760
59.9690
59.9690
59.9730
59.9780
59.9780
59.9810
59.9810
59.9810
59.9820
59.9840
59.9840
59.9820
59.9790
59.9790
59.9800
59.9780
59.9780
59.9800
59.9800
59.9800
59.9780
59.9720
59.9720
59.9710
59.9740
59.9740
59.9750
59.9720
59.9720
59.9690
59.9740
59.9740
59.9720
59.9720
59.9720
59.9770
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
229.47
229.47
229.47
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
228.98
228.98
219.98
219.98
219.98
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
229.09
229.09
229.09
229.66
229.66
229.66
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7659.00
7659.00
7659.00
7659.00
7660.00
7660.00
7660.00
7661.00
7661.00
7661.00
7662.00
7662.00
7662.00
7663.00
7663.00
7663.00
7664.00
7664.00
7664.00
7665.00
7665.00
7666.00
7666.00
7666.00
7667.00
7668.00
7668.00
7668.00
7669.00
7669.00
7669.00
7670.00
7670.00
7670.00
7671.00
7671.00
7671.00
7672.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
45.122
42.298
42.298
38.071
49.350
49.350
46.531
39.480
39.480
33.838
43.708
43.708
38.071
31.019
31.019
26.791
26.791
26.791
25.382
22.558
22.558
25.382
29.610
29.610
28.201
31.019
31.019
28.201
28.201
28.201
31.019
39.480
39.480
40.889
36.661
36.661
35.252
39.480
39.480
43.708
36.661
36.661
39.480
39.480
39.480
32.428
002719
2:40:01
2:40:03
2:40:05
2:40:07
2:40:09
2:40:11
2:40:13
2:40:15
2:40:17
2:40:19
2:40:21
2:40:23
2:40:25
2:40:27
2:40:29
2:40:31
2:40:33
2:40:35
2:40:37
2:40:39
2:40:41
2:40:43
2:40:45
2:40:47
2:40:49
2:40:51
2:40:53
2:40:55
2:40:57
2:40:59
2:41:01
2:41:03
2:41:05
2:41:07
2:41:09
2:41:11
2:41:13
2:41:15
2:41:17
2:41:19
2:41:21
2:41:23
2:41:25
2:41:27
2:41:29
2:41:31
59.9780
59.9780
59.9760
59.9740
59.9740
59.9770
59.9780
59.9780
59.9790
59.9770
59.9770
59.9740
59.9710
59.9710
59.9710
59.9680
59.9680
59.9660
59.9710
59.9710
59.9730
59.9690
59.9690
59.9720
59.9730
59.9730
59.9700
59.9740
59.9740
59.9820
59.9850
59.9850
59.9850
59.9890
59.9890
59.9890
59.9870
59.9870
59.9900
59.9960
59.9960
60.0010
60.0040
60.0040
60.0060
60.0140
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
218.62
218.62
218.62
218.62
213.54
213.54
213.54
213.54
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
225.65
225.65
212.57
212.57
212.57
212.57
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7675.00
7676.00
7677.00
7677.00
7678.00
7679.00
7679.00
7680.00
7681.00
7681.00
7682.00
7684.00
7684.00
7685.00
7687.00
7687.00
7689.00
7690.00
7690.00
7692.00
7692.00
7692.00
7693.00
7693.00
7693.00
7694.00
7694.00
31.019
31.019
33.838
36.661
36.661
32.428
31.019
31.019
29.610
32.428
32.428
36.661
40.889
40.889
40.889
45.122
45.122
47.941
40.889
40.889
38.071
43.708
43.708
39.480
38.071
38.071
42.298
36.661
36.661
25.382
21.149
21.149
21.149
15.512
15.512
15.512
18.331
18.331
14.098
5.642
5.642
-1.409
-5.642
-5.642
-8.461
-19.740
002720
2:41:33
2:41:35
2:41:37
2:41:39
2:41:41
2:41:43
2:41:45
2:41:47
2:41:49
2:41:51
2:41:53
2:41:55
2:41:57
2:41:59
2:42:01
2:42:03
2:42:05
2:42:07
2:42:09
2:42:11
2:42:13
2:42:15
2:42:17
2:42:19
2:42:21
60.0140
60.0190
60.0250
60.0250
60.0260
60.0290
60.0290
60.0290
60.0360
60.0360
60.0370
60.0360
60.0360
60.0410
60.0440
60.0440
60.0430
60.0480
60.0480
60.0460
60.0430
60.0430
60.0430
60.0430
60.0430
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
229.29
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
-420.00
7694.00
7695.00
7695.00
7695.00
7695.00
7696.00
7696.00
7696.00
7697.00
7697.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.00
7698.33
7698.66
7698.66
7698.99
7699.32
7699.32
7699.65
7699.98
7699.98
-19.740
-26.791
-35.252
-35.252
-36.661
-40.889
-40.889
-40.889
-50.759
-50.759
-52.168
-50.759
-50.759
-57.811
-62.038
-62.038
-60.629
-67.680
-67.680
-64.862
-60.629
-60.629
-60.629
-60.629
-60.629
002721
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+12 to T(+24)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+12 to T(+24)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8823
-0.159
633.00
0.00
-633.00
44.46
-58.87
165.98
224.84
269.30
0.00
165.43
0.00
0.00
0.00
0.00
165.43
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
209.89
0.00
0.00
0.00
0.00
209.89
44.46
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+30)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+30)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-420.000
-420.000
-175.3498
494.3985
669.7483
-94.51%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-18.936
-4.77%
MW
MW
MW
MW/0.1 Hz
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
12 to 24 second Average Period Evaluation
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
18 to 30 second Average Period Evaluation
2.815 P.U.
2.351 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
Net
Dynamic
Actual
Schedules
Interchange Imp(-) Exp (+)
MW
MW
002722
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.882
59.882
59.882
59.882
59.882
59.882
59.882
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
165.430
165.430
165.430
165.430
165.430
165.430
165.430
165.430
209.885
209.885
209.885
209.885
209.885
209.885
209.885
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
165.977
165.977
165.977
165.977
165.977
165.977
165.977
902.300
902.300
902.300
902.300
902.300
902.300
902.300
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.884
59.884
59.884
59.884
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002723
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.884
59.884
59.884
0.000
0.000
0.000
0.000
0.000
0.000
002724
002725
002726
002727
002728
002729
002730
002731
002732
002733
Date:
Time of T(0)
o 60 Hz or Pre-Perturbation Hz
age Frequency [T(-2 ) to T(-16)]
ge Frequency [T(+18 to T(+30)]
bation Delta Frequency Actual
erchange MW [T(-2 ) to T(-16)]
rchange MW [T(+18 to T(+30)]
n Interchange Delta MW Actual
Net Total Adjustments
FRO Pre-Perturbation Average
FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
e JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8844
-0.157
633.00
0.00
-633.00
45.83
-58.87
162.96
221.82
267.65
0.00
165.43
0.00
0.00
0.00
0.00
165.43
st JOU Dynamic Schedules MW
ost Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
rred Frequency Response MW
ngent BA Lost Generation MW
Post Perturbation Adjustments
Net Total Adjustments MW
0.00
211.26
0.00
0.00
0.00
0.00
211.26
45.83
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting -420.000 MW/0.1 Hz
Post-Perturbation Bias Setting -420.000 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average -175.3498 MW
EPFR for Bias Setting Post-Perturbation Average 485.3989 MW
EPFR for Bias Setting Delta 660.7487 MW
Primary Frequency Response Delivery of Bias -95.80%
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8892
-0.153
633.00
0.00
-633.00
47.23
-58.87
156.25
215.12
262.35
0.00
165.43
0.00
0.00
0.00
0.00
165.43
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
212.66
0.00
0.00
0.00
0.00
212.66
47.23
Pre-Perturbation BA Load 7600.196 MW
Post-Perturbation BA Load 7570.000 MW
Pre to Post Perturbation BA Load Change
-30.196 MW
Load Dampening Frequency Response
-19.194 MW/0.1 Hz
Load Dampening % of Total BA Frequency Response
-4.77%
eriod Evaluation
nitial P.U. Performance for FRO
Performance Adjusted for FRO
NonConforming
Load
Load (-)
MW
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+40)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+40)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
20 to 40 second Average Period Evaluation
2.854 P.U.
2.365 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
2.943
2.413
Pumped
Hydro
Load (-) Gen (+)
MW
002734
165.430
165.430
165.430
165.430
165.430
165.430
165.430
165.430
211.256
211.256
211.256
211.256
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
162.955
162.955
162.955
162.955
900.649
900.649
900.649
900.649
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
165.430
165.430
165.430
165.430
165.430
165.430
165.430
165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.889
59.889
59.889
0.000
0.000
0.000
0.000
0.000
0.000
212.661
212.661
212.661
0.000
0.000
0.000
002735
211.256
211.256
211.256
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000 7570.000
-420.000 7570.000
-420.000 7570.000
162.955
162.955
162.955
900.649 T+26 sec
900.649 T+28 sec
900.649 T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
212.661
212.661
212.661
212.661
212.661
212.661
212.661
212.661
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002736
002737
002738
002739
002740
002741
002742
002743
002744
002745
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-420.000
-420.000
-175.3498
465.4341
640.7839
-98.79%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.792
-4.77%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+18 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+18 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8879
-0.154
633.00
0.00
-633.00
47.23
-58.87
158.00
216.87
264.10
0.00
165.43
0.00
0.00
0.00
0.00
165.43
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
212.66
0.00
0.00
0.00
0.00
212.66
47.23
MW
MW
MW
MW
MW
MW
MW
MW
EPFR for Bias Setting Pre-Pertur
EPFR for Bias Setting Post-Pertur
Primary Frequency Response
Load Dampening % of Total BA Frequ
18 to 52 second Average Period Evaluation
P.U.
P.U.
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
2.919 P.U.
2.397 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Ramping
Frequency
Units
Response
Gen (+) Rec (-) Del (+)
MW
MW/0.1 Hz
002746
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
156.253
156.253
156.253
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
895.352 T+20 sec
895.352 T+22 sec
895.352 T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
165.430
165.430
165.430
165.430
165.430
165.430
165.430
165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.888
59.888
59.888
59.888
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
212.662
212.662
212.662
212.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002747
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
156.253
156.253
156.253
156.253
156.253
156.253
156.253
156.253
895.352
895.352
895.352
895.352
895.352
895.352
895.352
895.352
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
59.888
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
212.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002748
002749
002750
002751
002752
002753
002754
002755
002756
002757
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
-420.000
-420.000
-175.3498
470.6329
645.9827
-97.99%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.633
-4.77%
MW
MW
MW
MW/0.1 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Net Total Adjustments
EPFR for FRO Pre-Perturbation Average
EPFR for FRO Post-Perturbation Average
EPFR for FRO Delta
EPFR for FRO Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
Pre Ramping Units MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
Monday, October 12, 2009
2:27:21
2:32:54
60.0417
59.8887
-0.153
633.00
0.00
-633.00
47.31
-58.87
156.92
215.79
263.11
0.00
165.43
0.00
0.00
0.00
0.00
165.43
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
Post Ramping Units MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
212.74
0.00
0.00
0.00
0.00
212.74
47.31
MW
MW
MW
MW
MW
MW
MW
MW
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
EPFR for Bias Setting Pre-Perturbation Average
EPFR for Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
Primary Frequency Response Delivery of Bias
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
20 to 52 second Average Period Evaluation
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
T
T-72 sec
T-70 sec
T-68 sec
2:26:09
2:26:11
2:26:13
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
2.933 P.U.
2.406 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Ramping
Units
Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
002758
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7570.000
7570.000
7570.000
7570.000
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
157.998
157.998
157.998
157.998
897.098
897.098
897.098
897.098
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:15
2:26:17
2:26:19
2:26:21
2:26:23
2:26:25
2:26:27
2:26:29
2:26:31
2:26:33
2:26:35
2:26:37
2:26:39
2:26:41
2:26:43
2:26:45
2:26:47
2:26:49
2:26:51
2:26:53
2:26:55
2:26:57
2:26:59
2:27:01
2:27:03
2:27:05
2:27:07
2:27:09
2:27:11
2:27:13
2:27:15
2:27:17
2:27:19
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
633.000
633.000
633.000
633.000
633.000
633.000
633.000
633.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
165.430
165.430
165.430
165.430
165.430
165.430
165.430
165.430
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
2:27:21
2:27:23
2:27:25
2:27:27
2:27:29
2:27:31
2:27:33
2:27:35
2:27:37
2:27:39
2:27:41
2:27:43
2:27:45
59.889
59.889
59.889
0.000
0.000
0.000
0.000
0.000
0.000
212.744
212.744
212.744
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002759
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
157.998
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
897.098
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
2:27:47
2:27:49
2:27:51
2:27:53
2:27:55
2:27:57
2:27:59
2:28:01
2:28:03
2:28:05
2:28:07
2:28:09
2:28:11
2:28:13
2:28:15
2:28:17
2:28:19
2:28:21
2:28:23
2:28:25
2:28:27
2:28:29
2:28:31
2:28:33
2:28:35
2:28:37
2:28:39
2:28:41
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
212.744
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
002760
002761
002762
002763
002764
002765
002766
002767
002768
002769
Pre-Perturbation Bias Setting
Post-Perturbation Bias Setting
r Bias Setting Pre-Perturbation Average
Bias Setting Post-Perturbation Average
EPFR for Bias Setting Delta
ry Frequency Response Delivery of Bias
-420.000
-420.000
-175.3498
467.4349
642.7847
-98.48%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
e to Post Perturbation BA Load Change
Load Dampening Frequency Response
ning % of Total BA Frequency Response
7600.196
7570.000
-30.196
-19.730
-4.77%
MW
MW
MW
MW/0.1 Hz
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Frequency
Response
Obligation
EPFR
MW
Expected
Net
Actual
Interchange
MW
002770
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
7600.196
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-58.867
-420.000
-420.000
-420.000
7570.000
7570.000
7570.000
156.925
156.925
156.925
896.107
896.107
896.107
002771
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
-420.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
7570.000
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
156.925
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
896.107
002772
Monday, October 12, 2009
HQ
No Evaluation
Sustained P.U. Performance
without Adjustments
60.08
1000.0
60.06
60.04
60.02
800.0
60
59.98
59.96
600.0
59.92
MW
Frequency - Hz
59.94
59.9
400.0
59.88
59.86
59.84
200.0
59.82
59.8
59.78
0.0
59.76
59.74
59.72
2:26:21
2:27:21
2:28:21
2:29:21
2:30:21
Hz
2:31:21
Lost MW
2:32:21
2:33:21
2:34:21
2:35:21
Recovery Period Target MW
2:36:21
2:37:21
2:38:21
2:39:21
Recovery Period Ramp MW
2:40:21
2:41:21
-200.0
2:42:21
002773
Interconnection Performance
Date
Monday, October 12, 2009
A Point
Time
2:27:19
FPointA
Hz
60.0390
A Value
Hz
60.0417
t(0) Time
2:27:21
C Value
Hz
59.8360
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
Value B
FR B
12 to 24 sec 12 to 24 sec 18 to 30 sec 18 to 30 sec 20 to 40 sec 20 to 40 sec 18 to 52 sec 18 to 52 sec 20 to 52 sec 20 to 52 sec
Average
Average
Average
Average
Average
Average
Average
Average
Average
Average
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
Frequency
MW
59.8822861 -397.43625 59.8844288 -402.63425 59.888706 -415.16368 59.8879445 -411.95878 59.888706 -413.86163
002774
Value A Data
Total
Generation
Frequency
Lost
Hz
MW
60.04175
633.00
BA Performance
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
165.43
0.00
0.00
Value B
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
0.00
-420 7600.196
Bias
Setting
EPFR
Frequency
MW
Hz
-175.35 59.882286
12 to 24 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
209.89
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
002775
Value B
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
2.351
Initial
Performance
Unadjusted
P.U.
2.815
Sustained
Performance
P.U.
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-420
BA
Load
18 to 30 second Average Period Evaluation
Bias
Total
Setting
Generation
EPFR
Frequency
Lost
MW
MW
Hz
MW
7570 494.3985 59.884429
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
211.26
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
2.365
002776
Value B
Initial
Performance
Unadjusted
P.U.
2.854
Sustained
Performance
P.U.
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-420
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7570 485.3989 59.889182
20 to 40 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
212.66
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
2.413
Initial
Performance
Unadjusted
P.U.
2.943
Sustained
Performance
P.U.
No Evaluation
002777
Value B
BA
Bias
Setting
MW/0.1 Hz
-420
BA
Load
18 to 52 second Average Period Evaluation
Bias
Total
Setting
Generation
EPFR
Frequency
Lost
MW
MW
Hz
MW
7570 465.4341 59.887945
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
212.66
0.00
0.00
Value B
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
2.397
Initial
Performance
Unadjusted
P.U.
2.919
Sustained
Performance
P.U.
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-420
BA
Load
Bias
Setting
EPFR
Frequency
MW
MW
Hz
7570 470.6329 59.888706
002778
20 to 52 second Average Period Evaluation
Total
Generation
Lost
MW
0.00
JOU
Dynamic
Schedules
n/a
NonConforming
Pumped
Ramping
Load
Hydro
Units
Load (-)
Load (-) Gen (+)
n/a
MW
MW
0.00
212.74
0.00
0.00
Transferred
Frequency
Response
n/a
0.00
Contingent
BA
Lost Generation
n/a
0.00
Initial
Performance
Adjusted
P.U.
2.406
Initial
Performance
Unadjusted
P.U.
2.933
Sustained
Performance
P.U.
No Evaluation
BA
Bias
Setting
MW/0.1 Hz
-420
BA
Load
Bias
Setting
EPFR
MW
MW
7570 467.4349
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002779
Standards Announcement
Project 2007-12 Frequency Response
Initial Ballot Window and Non-Binding Poll
Now Open: Nov. 30 – Dec. 9, 2011
Available Now
An initial ballot of BAL-003-1 – Frequency Response and Frequency Bias Setting and its associated
implementation plan, and a non-binding poll of the associated VRFs and VSLs, are open through 8 p.m.
Eastern on Friday, December 9, 2011.
In addition to the standard and implementation plan, the following documents have been posted for
stakeholder review and comment:
•
Consideration of Comments Report – Provides a summary of the modifications made to the
proposed standard and supporting documents based on comments submitted during the
formal comment period that ended March 7, 2011
•
Frequency Response Standard Background Document – Provides an explanation of each of the
proposed requirements; identifies how the proposed standard proposes to address FERC
directives from Order 693; and on the last page provides an overview of the field trial
(currently in Step 4)
•
Attachment A – ERO’s Process for assigning a Frequency Response Obligation and Frequency
Bias Setting to each Balancing Authority
•
Attachment B – ERO’s Process for Adjusting Minimum Frequency Bias Setting
•
FRS Form 1 (four versions - one for each of the four Interconnections) and FRS Form 2 (seven
versions – two to collect data for Interconnections with a single Balancing Authority at two
second and three second intervals; five to collect data for Interconnections with multiple
Balancing Authorities at two second, three second, four second, five second and six second
intervals) – Both Form 1 and Form 2 are proposed for the ERO’s use (in conjunction with
Attachment A) in determining each Interconnection’s necessary amount of Frequency
Response for allocation to Balancing Authorities. Instructions are now on the first page of
each FRS Form 1 and FRS Form 2
•
Mapping Document - Identifies each requirement in the already approved BAL-003-0.1b and
identifies how that requirement has been treated in the revisions proposed in BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002780
•
Unofficial comment form in Word format – This is for informal use when compiling responses
– the final must be submitted electronically.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and opinion for the non-binding poll from the following page:
https://standards.nerc.net/CurrentBallots.aspx
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, December 9, 2011. Please use this
electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page.
Special Instructions for Submitting Comments with a Ballot
Please note that comments submitted during the formal comment period, the ballot for the standard,
and the non-binding poll of VRFs and VSLs all use the same electronic form, and it is NOT necessary for
ballot pool members to submit more than one set of comments (one through the electronic form, one
with the ballot, and one with the non-binding poll). The drafting team requests that all stakeholders
(ballot pool members as well as other stakeholders) submit all comments through the electronic
comment form.
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at [email protected]. An off-line, unofficial
copy of the comment form is posted on the project page.
Next Steps
The drafting team will consider all comments and determine what changes to make in response to
stakeholder input from the comments.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. The proposed standard’s intent is
to collect data needed to accurately analyze existing Frequency Response, set a minimum Frequency
Response obligation, provide a uniform calculation of Frequency Bias Settings that transition to values
closer to Frequency Response, and encourage coordinated AGC operation. There is evidence of
continuing decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be analyzed, and the reasons for the decline in Frequency Response
Standards Announcement Project 2007-12 – Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002781
can be identified. Once Frequency Response has been analyzed and confirmed, requirements can be
modified to maintain reliability.
Additional information is available on the project webpage.
A stakeholder interested in following the Frequency Response Standard Drafting Team’s development
of BAL-003-1 may monitor meeting agendas and notes on the team’s “Related Files” web page or may
submit a request to join the team’s “plus” email list to receive meeting agendas and meeting notes as
they are distributed to the team. To join the team’s “plus” email list, send a note to
[email protected] and include the project’s name in the subject line.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement Project 2007-12 – Frequency Response
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002782
Standards Announcement
Project 2007-12 Frequency Response
Ballot Pool Windows Now Open: Oct. 25 – Nov. 23, 2011
Formal Comment Period Open: Oct. 25 – Dec. 8, 2011
Initial Ballot and Non-Binding Poll Window: Nov. 29 – Dec. 8, 2011
Available Now
BAL-003-1 – Frequency Response and Frequency Bias Setting, an implementation plan and several
additional associated documents (listed below) have been posted for a formal comment period
and initial ballot that will end at 8 p.m. Eastern on Thursday, December 8, 2011. Ballot pools are
being formed and the ballot pool windows are open through 8 a.m. Eastern on Wednesday,
November 23.
The following associated documents have been posted for stakeholder review and comment:
•
Consideration of Comments Report – Provides a summary of the modifications made to the
proposed standard and supporting documents based on comments submitted during the
formal comment period that ended March 7, 2011
•
Frequency Response Standard Background Document – Provides an explanation of each of the
proposed requirements; identifies how the proposed standard proposes to address FERC
directives from Order 693; and on the last page provides an overview of the field trial
(currently in Step 4)
•
Attachment A – ERO’s Process for assigning a Frequency Response Obligation and Frequency
Bias Setting to each Balancing Authority
•
Attachment B – ERO’s Process for Adjusting Minimum Frequency Bias Setting
•
FRS Form 1 (four versions - one for each of the four Interconnections) and FRS Form 2 (seven
versions – two to collect data for Interconnections with a single Balancing Authority at two
second and three second intervals; five to collect data for Interconnections with multiple
Balancing Authorities at two second, three second, four second and five second intervals) –
Both forms are proposed for the ERO’s use (in conjunction with Attachment A) in determining
each Interconnection’s necessary amount of Frequency Response for allocation to Balancing
Authorities. Instructions are now on the first page of each FRS Form 1 and FRS Form 2
•
Mapping Document - Identifies each requirement in the already approved BAL-003-0.1b and
identifies how that requirement has been treated in the revisions proposed in BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002783
•
Unofficial comment form in Word format – This is for informal use when compiling responses
– the final must be submitted electronically
Instructions for Joining Ballot Pools for BAL-003-1 and Associated VRFs/VSLs
Two separate ballot pools are being formed – one ballot pool for Registered Ballot Body (RBB)
members interested in balloting of BAL-003-1, and a second for RBB members interested in
casting an opinion during the non-binding poll of VRFs and VSLs associated with BAL-003-1. RBB
members who join the ballot pool for the standard will not be automatically entered in the ballot
pool for the non-binding poll, but must elect to join the second ballot pool.
To join the ballot pool to be eligible to vote in the upcoming ballots and non-binding poll go to:
Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another
by using their “ballot pool list server.” (Once the balloting begins, ballot pool members are
prohibited from using the ballot pool list servers.)
The list server for the initial ballot is: [email protected]
Non-Binding Poll list server: [email protected]
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at [email protected]. An off-line, unofficial
copy of the comment form is posted on the project page.
Next Steps
The drafting team is planning a webinar in November to explain changes to the most recent draft
of BAL-003-1. The date and registration information will be announced as soon as the details are
finalized. An initial ballot of BAL-003-1 will be conducted beginning on Tuesday, November 29,
2011 through 8 p.m. Eastern on Thursday, December 8, 2011.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of
the bulk power system, particularly during disturbances and restoration. The proposed standard’s
intent is to collect data needed to accurately analyze existing Frequency Response, set a minimum
Frequency Response obligation, provide a uniform calculation of Frequency Bias Settings that
transition to values closer to Frequency Response, and encourage coordinated AGC operation.
There is evidence of continuing decline in Frequency Response over the past 10 years, but no
confirmed reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be analyzed, and the
Standards Announcement – 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002784
reasons for the decline in Frequency Response can be identified. Once Frequency Response has
been analyzed and confirmed, requirements can be modified to maintain reliability.
Additional information is available on the project webpage.
A stakeholder interested in following the Frequency Response Standard Drafting Team’s
development of BAL-003-1 may monitor meeting agendas and notes on the team’s “Related Files”
web page or may submit a request to join the team’s “plus” email list to receive meeting agendas
and meeting notes as they are distributed to the team. To join the team’s “plus” e-mail list, send
an e-mail to: [email protected]. Please include the drafting team name in your e-mail request.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or
assistance, please contact Monica Benson at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement – 2007-12 Frequency Response
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002785
Standards Announcement
Project 2007-12 Frequency Response
Ballot Pool Windows Now Open: Oct. 25 – Nov. 23, 2011
Formal Comment Period Open: Oct. 25 – Dec. 8, 2011
Initial Ballot and Non-Binding Poll Window: Nov. 29 – Dec. 8, 2011
Available Now
BAL-003-1 – Frequency Response and Frequency Bias Setting, an implementation plan and several
additional associated documents (listed below) have been posted for a formal comment period
and initial ballot that will end at 8 p.m. Eastern on Thursday, December 8, 2011. Ballot pools are
being formed and the ballot pool windows are open through 8 a.m. Eastern on Wednesday,
November 23.
The following associated documents have been posted for stakeholder review and comment:
•
Consideration of Comments Report – Provides a summary of the modifications made to the
proposed standard and supporting documents based on comments submitted during the
formal comment period that ended March 7, 2011
•
Frequency Response Standard Background Document – Provides an explanation of each of the
proposed requirements; identifies how the proposed standard proposes to address FERC
directives from Order 693; and on the last page provides an overview of the field trial
(currently in Step 4)
•
Attachment A – ERO’s Process for assigning a Frequency Response Obligation and Frequency
Bias Setting to each Balancing Authority
•
Attachment B – ERO’s Process for Adjusting Minimum Frequency Bias Setting
•
FRS Form 1 (four versions - one for each of the four Interconnections) and FRS Form 2 (seven
versions – two to collect data for Interconnections with a single Balancing Authority at two
second and three second intervals; five to collect data for Interconnections with multiple
Balancing Authorities at two second, three second, four second and five second intervals) –
Both forms are proposed for the ERO’s use (in conjunction with Attachment A) in determining
each Interconnection’s necessary amount of Frequency Response for allocation to Balancing
Authorities. Instructions are now on the first page of each FRS Form 1 and FRS Form 2
•
Mapping Document - Identifies each requirement in the already approved BAL-003-0.1b and
identifies how that requirement has been treated in the revisions proposed in BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002786
•
Unofficial comment form in Word format – This is for informal use when compiling responses
– the final must be submitted electronically
Instructions for Joining Ballot Pools for BAL-003-1 and Associated VRFs/VSLs
Two separate ballot pools are being formed – one ballot pool for Registered Ballot Body (RBB)
members interested in balloting of BAL-003-1, and a second for RBB members interested in
casting an opinion during the non-binding poll of VRFs and VSLs associated with BAL-003-1. RBB
members who join the ballot pool for the standard will not be automatically entered in the ballot
pool for the non-binding poll, but must elect to join the second ballot pool.
To join the ballot pool to be eligible to vote in the upcoming ballots and non-binding poll go to:
Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another
by using their “ballot pool list server.” (Once the balloting begins, ballot pool members are
prohibited from using the ballot pool list servers.)
The list server for the initial ballot is: [email protected]
Non-Binding Poll list server: [email protected]
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at [email protected]. An off-line, unofficial
copy of the comment form is posted on the project page.
Next Steps
The drafting team is planning a webinar in November to explain changes to the most recent draft
of BAL-003-1. The date and registration information will be announced as soon as the details are
finalized. An initial ballot of BAL-003-1 will be conducted beginning on Tuesday, November 29,
2011 through 8 p.m. Eastern on Thursday, December 8, 2011.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of
the bulk power system, particularly during disturbances and restoration. The proposed standard’s
intent is to collect data needed to accurately analyze existing Frequency Response, set a minimum
Frequency Response obligation, provide a uniform calculation of Frequency Bias Settings that
transition to values closer to Frequency Response, and encourage coordinated AGC operation.
There is evidence of continuing decline in Frequency Response over the past 10 years, but no
confirmed reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be analyzed, and the
Standards Announcement – 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002787
reasons for the decline in Frequency Response can be identified. Once Frequency Response has
been analyzed and confirmed, requirements can be modified to maintain reliability.
Additional information is available on the project webpage.
A stakeholder interested in following the Frequency Response Standard Drafting Team’s
development of BAL-003-1 may monitor meeting agendas and notes on the team’s “Related Files”
web page or may submit a request to join the team’s “plus” email list to receive meeting agendas
and meeting notes as they are distributed to the team. To join the team’s “plus” e-mail list, send
an e-mail to: [email protected]. Please include the drafting team name in your e-mail request.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or
assistance, please contact Monica Benson at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement – 2007-12 Frequency Response
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002788
Standards Announcement
Project 2007-12 Frequency Response
Initial Ballot and Non-Binding Poll Results
Now Available
An initial ballot and non-binding poll of BAL and its implementation plan concluded on December 9, 2011.
Voting statistics are listed below, and the Ballot Results webpage provides a link to the detailed initial ballot
results.
Initial Ballot Results
Quorum: 93.92%
Approval: 30.82%
Non-Binding Poll Results
89.49% of those who registered to participate provided an opinion or abstention; 37% of those who
provided an opinion indicated support for the VRFs and VSLs that were proposed.
Next Steps
The drafting team will consider all comments received during the comment period and ballot.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately following
the sudden loss of generation or load, is a critical component to the reliable operation of the bulk power
system, particularly during disturbances and restoration. The proposed standard’s intent is to collect data
needed to accurately analyze existing Frequency Response, set a minimum Frequency Response obligation,
provide a uniform calculation of Frequency Bias Settings that transition to values closer to Frequency
Response, and encourage coordinated AGC operation. There is evidence of continuing decline in Frequency
Response over the past 10 years, but no confirmed reason for the apparent decline. The proposed standard
requires entities to provide data so that Frequency Response in each of the Interconnections can be
analyzed, and the reasons for the decline in Frequency Response can be identified. Once Frequency
Response has been analyzed and confirmed, requirements can be modified to maintain reliability.
Additional information is available on the project webpage.
A stakeholder interested in following the Frequency Response Standard Drafting Team’s development of
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002789
BAL-003-1 may monitor meeting agendas and notes on the team’s “Related Files” webpage or may submit a
request to join the team’s “plus” email list to receive meeting agendas and meeting notes as they are
distributed to the team. To join the team’s “plus” email list, send a note to [email protected] and include
the project’s name in the subject line.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2007-12
2
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002790
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-12 Frequency Response Initial Ballot_in
Password
Ballot Period: 11/29/2011 - 12/9/2011
Ballot Type: Initial
Log in
Total # Votes: 340
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 362
Quorum: 93.92 % The Quorum has been reached
Weighted Segment
30.82 %
Vote:
Ballot Results: The standard will proceed to a successive ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
92
11
79
28
80
48
0
9
6
9
362
#
Votes
1
1
1
1
1
1
0
0.6
0.4
0.9
7.9
#
Votes
Fraction
23
2
19
7
16
14
0
3
0
3
87
Negative
Fraction
0.338
0.2
0.288
0.389
0.302
0.318
0
0.3
0
0.3
2.435
Abstain
No
# Votes Vote
45
8
47
11
37
30
0
3
4
6
191
0.662
0.8
0.712
0.611
0.698
0.682
0
0.3
0.4
0.6
5.465
13
1
10
8
22
4
0
3
1
0
62
11
0
3
2
5
0
0
0
1
0
22
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Member
Ballot
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
James Armke
Scott J Kinney
Kevin Smith
Gregory S Miller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
Negative
Negative
Affirmative
Abstain
Negative
Negative
Abstain
Comments
View
View
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Raj Rana
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Joseph Turano Jr.
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Gordon Pietsch
Negative
Negative
Negative
Abstain
Affirmative
Negative
View
View
View
Negative
Negative
Affirmative
Affirmative
Abstain
View
View
View
Affirmative
Abstain
Negative
View
Negative
View
Negative
Negative
Negative
Affirmative
View
View
View
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Cole C Brodine
Negative
Negative
View
View
Abstain
Negative
Negative
Abstain
Negative
View
Negative
View
Randy MacDonald
Negative
View
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brad Chase
Ryan Millard
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Abstain 002791
Negative
View
Negative
View
Michael Moltane
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
View
View
View
View
View
View
View
View
Dale Dunckel
Denise M Lietz
Rajendrasinh D Rana
John C. Allen
Tim Kelley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
Abstain
Abstain
Negative
Negative
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Kathryn Spence
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Angela L Summer
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Patrick Woods
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Brian Glover
Paul C Caldwell
David Kiguel
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
Negative 002792View
Affirmative
Affirmative
Affirmative
View
Negative
View
Negative
View
Negative
View
Negative
View
Negative
View
Affirmative
Negative
View
Affirmative
Affirmative
Negative
Affirmative
View
Negative
Negative
View
Abstain
Affirmative
Negative
View
Negative
View
Negative
View
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Abstain
Negative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
LaGen
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
David Anderson
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
Affirmative002793
Negative
View
Negative
View
Negative
Negative
Negative
View
Negative
Negative
View
Negative
View
Abstain
Negative
View
Negative
View
Tim Beyrle
Affirmative
Nicholas Zettel
John Allen
David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Richard Comeaux
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
Negative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
Abstain
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Abstain
Negative
Negative
Abstain
Affirmative
Abstain
Abstain
Abstain
Negative
Abstain
Abstain
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Edison Mission Energy
Electric Power Supply Association
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Henry E. LuBean
Negative 002794View
John D Martinsen
Negative
View
Mike Ramirez
Hao Li
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Negative
Negative
View
View
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Abstain
Mike D Kukla
Negative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Jeanie Doty
Paul Cummings
Negative
Abstain
Negative
Abstain
Negative
Max Emrick
Brian Horton
Steve Rose
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Ellen Oswald
John R Cashin
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
S N Fernando
David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Allen D Schriver
Hari Modi
William O. Thompson
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
View
View
View
View
View
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Negative
Abstain
Abstain
Negative
Abstain
Negative
Abstain
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
Abstain
Abstain
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Abstain
Negative
Affirmative
Abstain
Negative
View
View
View
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
Joseph O'Brien
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
Michael C Hill
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
Abstain 002795
Negative
View
Affirmative
Abstain
Abstain
Abstain
Negative
View
Affirmative
Affirmative
Negative
View
Affirmative
Affirmative
Negative
View
Abstain
Negative
Negative
Abstain
Affirmative
View
Negative
Negative
View
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
6
6
6
6
6
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Energy Mark, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative 002796
Affirmative
View
Affirmative
Peter H Kinney
David F. Lemmons
Edward C Stein
Roger C Zaklukiewicz
James A Maenner
Robert Blohm
Howard F. Illian
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Negative
View
Negative
Affirmative
Negative
Abstain
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
View
Negative
View
Negative
Negative
Abstain
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
View
View
View
View
View
View
View
Donald Nelson
Diane J Barney
Thomas Dvorsky
Jerome Murray
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=155b1519-a4da-491d-a9ec-2ec0d49cdab0[12/12/2011 12:24:11 PM]
View
View
View
View
View
View
View
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002797
2007-12 Frequency Response
Non-Binding Poll Results
Ballot Results
Non-Binding Poll
2007-12 Non-binding Poll
Name:
Poll Period: 11/29/2011 - 12/9/2011
Total # Opinions: 206
Total Ballot Pool: 333
89.49% of those who registered to participate provided an opinion or
abstention; 36% of those who provided an opinion indicated support for the
Summary Results: VRFs and VSLs that were proposed.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Organization
Member
Ameren Services
Kirit Shah
American Electric Power
Paul B. Johnson
Associated Electric Cooperative, Inc. John Bussman
Avista Corp.
Scott J Kinney
Balancing Authority of Northern
Kevin Smith
California
Baltimore Gas & Electric Company
Gregory S Miller
BC Hydro and Power Authority
Patricia Robertson
Beaches Energy Services
Joseph S Stonecipher
Bonneville Power Administration
Donald S. Watkins
Brazos Electric Power Cooperative,
Tony Kroskey
Inc.
Central Maine Power Company
Joseph Turano Jr.
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Chang G Choi
Power
Clark Public Utilities
Jack Stamper
Colorado Springs Utilities
Paul Morland
Christopher L de
Consolidated Edison Co. of New York
Graffenried
CPS Energy
Richard Castrejana
Dairyland Power Coop.
Robert W. Roddy
Dayton Power & Light Co.
Hertzel Shamash
Deseret Power
James Tucker
Dominion Virginia Power
Michael S Crowley
Duke Energy Carolina
Douglas E. Hils
East Kentucky Power Coop.
George S. Carruba
Empire District Electric Co.
Ralph F Meyer
Non-Binding Poll Results – Project 2007-12 Frequency Response
Opinion
Comments
Negative
View
Affirmative
Abstain
View
Negative
Abstain
Abstain
Negative
Negative
View
Affirmative
Affirmative
Negative
Negative
View
View
Negative
View
Abstain
Affirmative
Negative
Negative
View
Negative
Negative
Affirmative
View
View
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002798
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative
Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New
Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of
Okanogan County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Edward J Davis
William J Smith
Affirmative
Abstain
View
Affirmative
Abstain
Negative
View
Negative
View
Dennis Minton
Mike O'Neil
Luther E. Fair
Gordon Pietsch
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Abstain
Negative
Affirmative
View
Negative
Negative
View
View
Abstain
Negative
Negative
Abstain
Abstain
View
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Cole C Brodine
Abstain
Randy MacDonald
Negative
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Doug Peterchuck
Brad Chase
Ryan Millard
John C. Collins
John T Walker
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Abstain
Negative
Negative
Negative
Affirmative
Laurie Williams
Affirmative
Kenneth D. Brown
View
View
View
View
Abstain
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Non-Binding Poll Results – Project 2007-12 Frequency Response
Abstain
Affirmative
Negative
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002799
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission
Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
California ISO
Electric Reliability Council of Texas,
Inc.
Independent Electricity System
Operator
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System
Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Bartow, Florida
City of Clewiston
City of Garland
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
1
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Kathryn Spence
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Affirmative
Negative
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Charles B Manning
Affirmative
Barbara Constantinescu
Affirmative
Marie Knox
Alden Briggs
Affirmative
Abstain
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Matt Culverhouse
Lynne Mila
Ronnie C Hoeinghaus
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Non-Binding Poll Results – Project 2007-12 Frequency Response
View
View
View
View
Abstain
Abstain
Negative
View
Abstain
Abstain
Abstain
Negative
Negative
Abstain
Abstain
Abstain
Negative
Negative
Negative
Abstain
Negative
Negative
Abstain
Negative
View
View
View
View
View
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002800
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
CPS Energy
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations
Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of
Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Jose Escamilla
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Negative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Charles A. Freibert
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Negative
Abstain
Abstain
Negative
Steven M. Jackson
Abstain
Negative
Abstain
Negative
Michael Schiavone
Affirmative
William SeDoris
David Anderson
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Affirmative
Negative
Negative
Abstain
Negative
Non-Binding Poll Results – Project 2007-12 Frequency Response
View
View
View
Abstain
Daniel D Kurowski
John S Bos
Tony Eddleman
Marilyn Brown
View
Negative
Affirmative
Abstain
View
View
View
View
View
View
View
View
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002801
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
Progress Energy Carolinas
Sam Waters
Public Service Electric and Gas Co.
Jeffrey Mueller
Public Utility District No. 1 of Clallam
David Proebstel
County
Puget Sound Energy, Inc.
Erin Apperson
Sacramento Municipal Utility District James Leigh-Kendall
Salt River Project
John T. Underhill
Santee Cooper
James M Poston
Seattle City Light
Dana Wheelock
Seminole Electric Cooperative, Inc. James R Frauen
Snohomish County PUD No. 1
Mark Oens
South Carolina Electric & Gas Co.
Hubert C Young
Tacoma Public Utilities
Travis Metcalfe
Tampa Electric Co.
Ronald L Donahey
Tennessee Valley Authority
Ian S Grant
Tri-State G & T Association, Inc.
Janelle Marriott
Westar Energy
Bo Jones
Xcel Energy, Inc.
Michael Ibold
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
American Municipal Power
Kevin Koloini
Blue Ridge Power Agency
Duane S Dahlquist
City of Austin dba Austin Energy
Reza Ebrahimian
City of Clewiston
Kevin McCarthy
City of New Smyrna Beach Utilities
Tim Beyrle
Commission
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri John Allen
Consumers Energy
David Frank Ronk
Detroit Edison Company
Daniel Herring
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Thomas Richards
Georgia System Operations
Guy Andrews
Corporation
Imperial Irrigation District
Diana U Torres
Madison Gas and Electric Co.
Joseph DePoorter
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Public Utility District No. 1 of Douglas
Henry E. LuBean
County
Public Utility District No. 1 of
John D Martinsen
Snohomish County
Sacramento Municipal Utility District Mike Ramirez
Seattle City Light
Hao Li
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
AEP Service Corp.
Brock Ondayko
Non-Binding Poll Results – Project 2007-12 Frequency Response
Affirmative
Abstain
View
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
View
View
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Abstain
View
View
View
Abstain
Affirmative
Abstain
Abstain
Abstain
View
Negative
View
Abstain
Negative
Negative
View
Affirmative
Affirmative
Abstain
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002802
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
Arizona Public Service Co.
Edward Cambridge
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Black Hills Corp
George Tatar
Boise-Kuna Irrigation District/dba
Mike D Kukla
Lucky peak power plant project
Bonneville Power Administration
Francis J. Halpin
BrightSource Energy, Inc.
Chifong Thomas
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul Cummings
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Max Emrick
Power
City Water, Light & Power of
Steve Rose
Springfield
Colorado Springs Utilities
Jennifer Eckels
Consolidated Edison Co. of New York Wilket (Jack) Ng
Consumers Energy Company
David C Greyerbiehl
CPS Energy
Robert Stevens
Detroit Edison Company
Christy Wicke
Dominion Resources, Inc.
Mike Garton
Duke Energy
Dale Q Goodwine
Edison Mission Energy
Ellen Oswald
Electric Power Supply Association
John R Cashin
FirstEnergy Solutions
Kenneth Dresner
Florida Municipal Power Agency
David Schumann
Great River Energy
Preston L Walsh
Green Country Energy
Greg Froehling
Indeck Energy Services, Inc.
Rex A Roehl
JEA
John J Babik
Kissimmee Utility Authority
Mike Blough
Lakeland Electric
James M Howard
Liberty Electric Power LLC
Daniel Duff
Lincoln Electric System
Dennis Florom
Los Angeles Department of Water &
Kenneth Silver
Power
Luminant Generation Company LLC Mike Laney
Manitoba Hydro
S N Fernando
Massachusetts Municipal Wholesale
David Gordon
Electric Company
MEAG Power
Steven Grego
MidAmerican Energy Co.
Christopher Schneider
Muscatine Power & Water
Mike Avesing
Nebraska Public Power District
Don Schmit
New York Power Authority
Gerald Mannarino
NextEra Energy
Allen D Schriver
Northern California Power Agency
Hari Modi
Non-Binding Poll Results – Project 2007-12 Frequency Response
Abstain
Negative
Abstain
Abstain
Abstain
Affirmative
Negative
Negative
Negative
Abstain
Negative
View
View
View
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Abstain
Abstain
Negative
Negative
Abstain
Negative
Abstain
Negative
Abstain
Negative
View
View
View
View
View
View
View
View
Negative
Affirmative
Negative
View
Abstain
Abstain
Affirmative
Negative
Abstain
Negative
Affirmative
Abstain
View
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002803
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities
Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
William O. Thompson
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Non-Binding Poll Results – Project 2007-12 Frequency Response
Negative
View
Negative
Abstain
Abstain
Negative
Negative
Affirmative
Abstain
View
View
Abstain
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Abstain
Affirmative
Negative
Negative
Negative
Abstain
Negative
Abstain
Negative
Negative
Abstain
Negative
Negative
View
View
View
View
View
View
View
Negative
Abstain
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Negative
View
View
View
View
View
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002804
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
10
10
10
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Northern Indiana Public Service Co.
Omaha Public Power District
Paul Shipps
Eric Ruskamp
Negative
Negative
Brad Packer
Negative
Brad Jones
Daniel Prowse
Dennis Kimm
Joseph O'Brien
David Ried
Claston Augustus
Orlando Utilities Commission
Sunanon
PacifiCorp
Scott L Smith
Platte River Power Authority
Carol Ballantine
PPL EnergyPlus LLC
Mark A Heimbach
Progress Energy
John T Sturgeon
PSEG Energy Resources & Trade LLC Peter Dolan
Public Utility District No. 1 of Chelan
Hugh A. Owen
County
Sacramento Municipal Utility District Diane Enderby
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown
Seattle City Light
Dennis Sismaet
Seminole Electric Cooperative, Inc. Trudy S. Novak
Snohomish County PUD No. 1
William T Moojen
South California Edison Company
Lujuanna Medina
Southern Company Generation and
John J. Ciza
Energy Marketing
Tacoma Public Utilities
Michael C Hill
Tampa Electric Co.
Benjamin F Smith II
Tennessee Valley Authority
Marjorie S. Parsons
Westar Energy
Grant L Wilkerson
Western Area Power Administration Peter H Kinney
UGP Marketing
Xcel Energy, Inc.
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Energy Mark, Inc.
Howard F. Illian
JDRJC Associates
Jim Cyrulewski
Power Energy Group LLC
Peggy Abbadini
Utility Services, Inc.
Brian Evans-Mongeon
Volkmann Consulting, Inc.
Terry Volkmann
California Energy Commission
William M Chamberlain
Commonwealth of Massachusetts
Donald Nelson
Department of Public Utilities
Florida Reliability Coordinating
Linda Campbell
Council
Midwest Reliability Organization
James D Burley
New York State Reliability Council
Alan Adamson
Non-Binding Poll Results – Project 2007-12 Frequency Response
Affirmative
Negative
Abstain
Affirmative
Negative
View
View
View
Negative
Abstain
Abstain
Negative
Affirmative
Abstain
View
Abstain
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
View
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
View
View
Affirmative
Abstain
Affirmative
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002805
10
10
10
10
10
10
Northeast Power Coordinating
Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating
Council
Guy V. Zito
Negative
View
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Negative
Abstain
Abstain
Affirmative
View
Steven L. Rueckert
Negative
View
Non-Binding Poll Results – Project 2007-12 Frequency Response
View
9
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002806
Name (26 Responses)
Organization (26 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
Question 1 (36 Responses)
Question 1 Comments (43 Responses)
Question 2 (37 Responses)
Question 2 Comments (43 Responses)
Question 3 (32 Responses)
Question 3 Comments (43 Responses)
Question 4 (32 Responses)
Question 4 Comments (43 Responses)
Question 5 (37 Responses)
Question 5 Comments (43 Responses)
Question 6 (40 Responses)
Question 6 Comments (43 Responses)
Question 7 (36 Responses)
Question 7 Comments (43 Responses)
Question 8 (37 Responses)
Question 8 Comments (43 Responses)
Question 9 (33 Responses)
Question 9 Comments (43 Responses)
Question 10 (0 Responses)
Question 10 Comments (43 Responses)
Southwest Power Pool Regional Entity
Emily Pennel
Yes
Yes
Yes
Yes
Measures are more specific and measurable than seen in the past. This is a positive improvement.
Yes
Hard to follow the language for the VSL for R1. Suggest using formulas for ease of interpretation or
provide an example in the Supporting Documentation.
Yes
Yes
Yes
Need to clarify that 2012 Bias setting will be based on 1% of peak load or generation until approval of
BAL-003-1 by FERC establishing the .08% of peak load or generation minimum threshold.
Yes
Bonneville Power Administration
Chris Higgins
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002807
No
Regarding R1, BPA believes that adding additional requirements in R1 by referencing Attachment A
does not add clarity. FRO should be a calculation that the BA’s can do themselves and included within
the standard. Can Form 1 be changed outside of the standard drafting process? BPA doesn’t believe
that Form 1 should be allowed to be changed outside of the standard drafting process. As drafted,
Requirement R1 requires Balancing Authorities or Reserve Sharing Groups (RSGs) to achieve an
annual Frequency Response Measure (FRM) that is equal to or more negative than its Frequency
Response Obligation (FRO). As RSGs exist today, FRM performance by an RSG is not contemplated in
the definition of FRM and appears to apply more towards 'secondary response'. BPA recommends
clarifying this concept and possibly including an example in the background document to help explain
how this would work. Regarding R2, BPA believes each BA should be able to calculate its own
frequency bias setting without ERO validation. The standard can require the BA to use Form 1, if the
BA doesn’t use Form 1 correctly, then the BA would be in violation of the standard. BPA believes that
R3 should include a minimal amount of time (suggesting a couple of hours per year) to allow for
testing other modes. Requirement R3 requires each Balancing Authority not receiving Overlap
Regulation Service to operate its AGC in Tie Line Bias mode… unless such operation would have an
Adverse Reliability Impact on the Balancing Authority’s Area. There may be occasions in which an
entity needs to perform testing or other instances where it is necessary or desirable to operate in a
mode other than Tie Line Bias that does not qualify as an Adverse Reliability Impact, but never the
less is necessary or desired. BPA recommends including language that would permit operation other
than Tie Line Bias mode provided the Reliability Coordinator was notified. BPA seeks clarification from
the drafting team as to whether or not there will be any conflicts between proposed Requirement R3
and the requirements of FERC-approved regional reliability standard BAL-004-WECC-1 – Automatic
Time Error Correction. BPA agrees with the concept of R4, however, BPA again disagrees with the
ERO validation of the frequency bias setting. BPA believes that reducing frequency bias obligation is
detrimental to reliability. It seems that lowering the Minimum Frequency Bias Setting from 1% to .8%
will result in a lower response, which in turn will lower the natural frequency response. BPA believes
that over time, it would seem that this pattern would lead to poorer response. BPA believes that R5
should read “greater than or equal to one of the following” not “ at least equal to”. The requirement
should be a part of Form 1 or included in R2. For variable bias, the minimum percentage should be
based on the forecasted month peak.
Yes
No
BPA believes that historian data should be able to be used for evidence.
No
BPA believes that R1 needs to be more clear and concise as to what is being conveyed in the
requirement. It is difficult to understand. The proposed VSLs for Requirement R1 treats a BA that did
not meet the FRO requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be consistent regardless
of what the other entities within the interconnection are doing. Suggest removing the interconnection
performance from the VSLs and developing four increasing levels of BA failure to meet its FRO. BPA
believes that conforming changes to the VSLs would need to be made for any changes to the
Requirements as suggested in the comments to the standard.
No
BPA believes that Attachment A adds additional requirements to the standard. Confusion exists
between Attachment A and the Background Document. Attachment A states peak load allocation is
based on “Projected” Peak Loads and Generation, but the Background Document states it will use
“historical” Peak Load and Generation. 3a: it may take longer than 8 seconds in some disturbances.
This should be 10 seconds. .05 Hz Delta F is not low enough for the Western Interconnection, it
should be .075Hz to ensure there is measurable frequency response for the interconnection. Also,
under frequency should be set at 59.95 Hz. BPA does not believe there is a reliability need to include
over frequency events. 3b: It is unclear if the 18 seconds is setting the B point. If this is the B point,
BPA believes it should be changed to 25 seconds for the Western Interconnection. 4. Please define
relatively steady and near 60 Hz. 6: For the Western Interconnection, BPA believes this needs to be
10 minutes at the top of the hour. As mid hour scheduling becomes more prevalent, the ramping at
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002808
the bottom of the hour will have to be taken into account. FRO for the interconnection: Starting
frequency should be the FTL limit. With RBC in place, the frequency is seldom at 60 Hz. BPA
understands the theory behind setting the base obligation to the values listed in table 2. BPA would
like to know if there were any studies performed to validate setting the FRO for the interconnection to
such a low level? BA FRO and frequency bias setting: BPA does not agree with ERO assigning a
Frequency Bias setting to each BA. This calculation is indicated as the initial FRO allocation, what is
the process for changing it? BPA believes this should go through the standard drafting process for any
changes. The calculation should use Peak online capacity, not the installed capacity. This would lead
to the denominator being 2 X Peak projected load for the interconnection. BPA has approximately
35,000 MW of installed generation, and has never seen the actual coincidental generation go over
21,000 MW. Again, BPA doesn’t believe the ERO should be validating the frequency bias setting. It is
unclear to BPA how variable bias is being addressed in the standard.
No
BPA understands the concept and we disagree with it. As the ERO continues to lower the required
minimum frequency bias setting for an interconnection, the BA’s that have frequency response higher
than the 1% will have a higher percentage of the frequency response of the interconnection. Also, this
standard is primarily measuring AGC response, not natural frequency response; therefore not
lowering the limit is appropriate.
No
BPA believes the form is not easily understood and is overly complicated for what it is trying to
accomplish. BPA believes the form might work for an internal evaluation, just not for an external
audit. Compliance is based on this form. BPA believes the standard needs to be simplified and
possibly returned to a data gathering standard.
BPA believes that an entity is not measuring frequency response from 20 – 52 seconds; rather, that
the entity is measuring AGC response which is based on the frequency bias term. This leads to a
circular argument, because that entity would be using frequency bias setting in AGC to calculate
frequency bias setting for the next year. Also, because an entity is measuring AGC response and net
interchange and not taking pre-disturbance ACE into account, a BA frequency response may not be
reflected in the spreadsheet. Example: If the BA has a positive ACE of 300 MW and the frequency
component of ACE during an event is 200MW. Immediately following the disturbance, natural
frequency response will drive net interchange up by 200MW. During the time frame being measured
(20-52sec), AGC response will drive the on control generation down by the original 300 MW ACE,
which will look like the BA had an opposite response at the interconnections in the amount of 100MW.
Form 1: It is unclear in Form 1 how variable bias BA’s would implement this standard. There is a note
identifying a tab to use, but it is unclear if that is the only requirement for variable bias BA’s. In the
comment responses to BPA, it was indicated that “the SDT will provide additional and sufficient
direction related to variable bias after review of this issue during the field trial.” BPA finds this
response unacceptable and believes that it needs to be addressed in the standard prior to approval.
BPA believes the standard should be easy to understand and implement and should not rely on the
judgment of the ERO. BPA believes this standard needs to be simplified. BPA believes this standard is
unclear as to if there is an upper limit to the amount of frequency response expected of the Balancing
Authorities under this standard. Except for Table 2 in Attachment A, there is no discussion of an
amount of Frequency Response expected on a total basis. Balancing Authorities need to know for how
many tenths of a hertz they are to respond so they can determine how to plan to meet this
requirement. The documents do not appear to provide any boundary on the maximum amount of
Frequency Response that a BA will provide, i.e. it is not clear what will happen if an event occurs in
the Eastern Interconnection that causes the frequency to drop to less than 59.6 Hz or in the Western
Interconnection that causes the frequency to drop to less than 59.5 Hz, or if that event is excluded
from the list used to calculate the Balancing Authorities’ response or is it included with an expectation
that it counts the same as any other event. Without a clear statement of what is expected, including
whether there is a limit on that expectation or not, it is unclear what is expected of the Balancing
Authorities. Lastly, BPA asks, why are there no requirements on governor installation, settings, and
operation for a frequency response standard?
Howard F. Illian
Energy Mark, Inc.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002809
Yes
No
Comment 1: The timing requirements for implementing the Frequency Bias Setting are not specified
for BAs participating in Overlap Regulation Service. The requirements indicate the value that should
be used for the Frequency Bias Setting, but they do not indicate when those settings should be
implemented. Comment 2: The term "Tie Line Bias mode" in Requirement R3 is not sufficiently
defined to make this requirement enforceable. Any operating mode labeled as "Tie Line Bias mode" on
an EMS that uses interchange scheduled and frequency error as inputs will meet the standard
requirement as stated. This loop-hole exists because the NERC definition of "Tie Line Bias" fails to
define the term in enough detail to actually limit AGC operation to the specified mode of operation.
One way to improve this requirement would be to redefine Tie Line Bias in the NERC Glossary as a
mode that uses the NERC ACE Equation as defined in BAL-001 as the basis for AGC action when the
EMS is in Tie Line Bias mode. Comment 3: The standard is silent on how a BA receiving Overlap
Regulation Service should set its Frequency Bias Setting. Unless this is explicitly stated, it will be up
to the auditors to determine the value of the Frequency Bias Setting for BAs receiving Overlap
Regulation Service. Comment 4: In general, the requirements indicate what the responsible BAs
should do and when. The requirements do not indicate what the BAs that are not responsible should
do and when, ie. how they are relieved from responsibility. This may create problems when the
auditors are required to interpret the standards for BAs that have appropriately shifted responsibilites
to others.
No
Comment 5: See comments in the non-binding poll.
Yes
Yes
No
Comment 6: "If the ERO cannot identify in a given evaluation period 25 frequency excursion events
satisfying the limits specified in criteria 3 below, then similar acceptable events from the previous
evaluation period also satisfying listed criteria will be included with the data set by the ERO for
determining FRS compliance." I believe that the better alternative in this case would be to use the
lesser number of events. This is partly based on the consideration that if there are fewer events, the
risk to the interconnection for that year was less that expected, and as a result, evaluation of fewer
events will not compromise interconnection reliability. If fewer than 25 events are available in any
year, the selection criteria should be adjusted to select more events. Comment 7: There are a number
of problems with the use of "median" Frequency Response of the measured events. These problems
make a choice other than median preferable. The following comments list some of those problems.
Comment 8: The current standard uses average Frequency Response of selected events. This makes
the current standard incompatible with the use of median. Comment 9: If a BA reconfigures during a
measurement year, that reconfiguration will create a bi-modal distribution of the Frequency Response
events. Median is incapable of representing a bi-modal distribution. The use of median will result in a
standard that is incapable of measuring compliance effectively for an BA that is reconfigured during a
measurement year (Dec 1 thru Nov 30). Comment 10: Any attempt to purchase additional Frequency
Response from another BA for a portion of a measurement year will also cause a bi-modal distribution
making the purchase of Frequency Response only effective for entire measurement years. Comment
11: Median is a non-linear measurement method. Because it is a non-linear measurement method,
there is no valid way to manage partial year measurements. Comment 12: I will offer an alternative
to median to the SDT before the end of the development of responses to these comments. Comment
13: The Minimum Frequency Bias Setting and the Frequency Response Obligation are both based on a
method that assigns responsibility based on a Peak Load / Peak Generation share of the
interconnection. However, the method used to set the Minimum Frequency Bias Setting is different
than the method used to determine the Frequency Response Obligation. Using these two different
methods could result in the Minimum Frequency Bias Setting being less that the FRO for a BA. The
best way to correct this problem is to use that same allocation methodology for determining the FRO
and the Minimum Frequency Bias Setting. This can be easily accomplished by modifying R5 to use the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002810
FRO allocation method to determine the Minimum Frequency Bias Setting. This calculation would
divide the numerator from the FRO allocation equation, divide it by two and multiply it by the
percentage specified in Attachment B. In fact, the current FRS Form 1 uses this equation with
projected rather than historic data. The best alternative would be to modify the R5 in the standard to
match the FRO allocation method and modify FRS Form 1 to use historic data instead of projected
data. This would result in only one set of Peak Load and Peak Generation data throughout the
standard, rather than three different sets of data as currently written. When multiple sets of the same
or similar data are used within a single standard, it only creates confusion and errors in the result.
No
Comment 14: Some of the information in this document concerning the Frequency Bias Setting for
BAs participating in Overlap Regulation should be moved to the Supporting Document. This change
would help in addressing Comments 3 & 4 under Question 2.
Yes
Comment 15: This Yes answer assumes that the SDT addresses Comment 13 under Question 6 in
these comments.
Yes
Comment 16: In the Consideration of Comments document, the SDT stated that the regression
calculation in FRS Form 1 had been corrected. The regression calculation is still incorrect. Comment
17: Attachment A contains the following statement; "**In the Base Obligation measure for Texas,
1150 MW (Load Resources triggered by Under Frequency Relays at 59.70 Hz) was reduced from its
Contingency Protection Criteria level of 2750 MW to get 229 MW/0.1 Hz. This was reduced to
accurately account for designed response from Load Resources within 30 cycles." This load triggered
by Under Frequency Relays is a unidirectional response. It responds as frequency drops but does not
provide the alternative response as frequency recovers. The result is a continuous frequency response
that may be insufficient for increasing frequency events. Additionally, it is only available once even for
oscillatory frequency events. This type of response is very useful to supplement the continuous, bidirectional response provided by governors, load and other resources, but its overuse can lead to
reliability issues when it is relied upon too much. This standard fails to put any limit on the use of this
type of unidirectional, single use resource for meeting the Frequency Response requirements in this
standard. Since this kind of Frequency Response is significantly less expensive than continuous,
bidirectional response, its inclusion without limitations creates a significant reliability loop hole in this
standard. Although, it is unlikely that this problem can be corrected within the current standard
development timeline, NERC should initiate investigations that will result in the setting of appropriate
limits and valuation of the use of these types of resources before there is significant penetration to
comply with this standard. Illustrating this problem is easily done by evaluating an interconnection
with 100% of its Frequency Response provided by unidirectional, step response resources. An
interconnection configured in this manner in unstable and cannot survive even a small disturbance.
Failure to close this loophole quickly could compromise interconnection reliability. Comment 18: The
problem described in Comment 17 exists partially because the FRR SDT has failed to provide a
comprehensive definition of Frequency Response as part of this standard. Without a good definition,
the default definition becomes "any response that improves the measurement method" as
implemented. As with the previous comment, NERC should address this weakness in a timely manner.
Otherwise, it may face the undesirable task of disallowing response that improves the measure or
modifying the measure to prevent inappropriate abuse. For example, a step load response that occurs
15 seconds after a frequency event will improve the Frequency Response as measured by this
standard, but will not contribute to limiting the Arrested Frequency Response and will have little
positive affect on reliability.
Don McInnis
Florida Power & Light Company
Yes
Yes
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002811
Could not find the Risk Severity Levels in the documents.
No
What is meant by documented formulae for M5? Is a one time snapshoot of the AGC formual
sufficien? The concept is ok but this needs clarification of proof.
No
For R1 the low and high level descriptions appear to be identical and the high level is less than the
medium risk level. For R3 there should be low, medium, and high levels. One BA not operating to TLB
does not jepordize the Interconnection. Additionally, computer failures, database loads etc may
require some period where TLB is not in service. Suggestion would be Lower VSL operation off of TLB
for more than 5 but < 8 continuous hours or accumlative during the year of more than 8 < 16 hours.
Medium VSL would be operation off of TLB for more than 8 but <16 continuous hours or accumlative
during the year of more than 16 <24 hours. High VSL would be operation off of TLB for more than 16
<24 continuous hours or accumlative during the year of more than 36 <48 hours. Severe VLS would
be >24 continuous hours off of TLB or accumlative of > 48.
No
In the table on page2 the asterick references a statement that the 59.7Hz used in Florida is a special
protection scheme. This is incorrect. The special protection scheme setting was 59.82Hz and was
done away with in 2005 or earlier. The 59.7Hz setting used within the FRCC is based on FRCC TWG
studies that require this level of setting to protect the state in the event of a separation and to protect
nuclear equipment. FPL supports the use of the C(N-2) critiera. Additionally, the reference to the
FERC714 report that is currently in the background data should be made part of attachment A not
separated. FPL fully agrees with Table 1 The formula used to derive the FRO is inconsistant with the
definition used for requirement R5. R5 states that the load is " within the BA's metered boundary".
The load used in the formulae is taken from FERC714. The yearly peak demand used in R5 should be
the peak monthly load from June, July or August as reported on FERC714 to be compatible with the
FRO formula.
Yes
No
There is no technical justification provided either in the attachment or background data for the initial
starting value of 0.8%. This is acceptable but is arbitary. Additionally, the last sentense on page 1 of
Attachment B should be changed to read " the ERO must reduce ( in absolute value) the minimum
Frequency Bias Settings for BA's within that Interconnection, by 0.1 percentage point from its
previous annual value, to better match the Frequency Bias Setting to the natural Frequency Response
or provide technical justification for not implementing the reduction
Yes
This standard is an excellent start on a very difficult topic and the technical explainations are very
sound. Requirement R1 needs to be modificed somewhat as it currently implies that if a BA is a
member of a RSG the frequency response obligation automatically assumed to be a RSG obligation.
The RSG role may be strictly for reserves with the members of the BA meeting their own FRO.
Perhaps a footnote stating that the FRO and reserve obligations can be separated out.
Carlos J. Macias
FPL
Yes
No
3. – How many seconds of observation for “Delta F”? Does “Point C” in a. refer to “Figure 1 – Classic
Frequency Excursion and Recovery” from NERC’s Survey Instructions document dated September 1,
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002812
2010? If so it should be included in this document along with the added 8 and 18 second time lines
being shown. What is a “narrow range” in item b.? 4. – Better define “relatively steady” (i.e. within a
specific range and state it?) Also, “near 60.000 Hz” is not precise enough (i.e. if the event begins
below 60.000 Hz, what range or time error correction is to be considered acceptable?) Is the “A”
value also part of the figure cited in 3? 5. - Is the “B” value also part of the figure cited in 3? 6. –
Change “should be excluded” to “will be excluded”. 7. – Better explain “the cleanest 2 or 3 frequency
excursion events” or remove the word “cleanest”. Page 2 paragraph 5: Provide specific dates for the
“quarterly postings” and where these will be posted (i.e. Internet address or other). Clarify the
December 15 ERO annual post date with the dates stated for same posting on Page 3 paragraph 5
and the BA’s January 10 deadline. The BA posts 30 days from which date? This is confusing. Page 2
Table 2: What of starting event frequencies that are < 60 Hz? Why is the “Highest UFLS” 59.6 when
the Florida setting for its load is 59.7? Page 3 FRO equation: Page 4 of the “Frequency Response
Standard Background Document, October 2011” also shows this equation but uses different terms.
Make the same on both documents. In the Background Document each component of the numerator
is explained and reference is made to FERC Form 714 to obtain these values. There is no reference to
this form for the denominator values. All of this needs to be made clear with reference to FERC Form
714 on Attachment A.
Yes
Yes
Last paragraph: As stated, would that make the Minimum Frequency Bias Setting 0.7% of peak load
or generation? A numerical example shown would help clarify this paragraph.
No
FRS Form 2 – Two-second Sample Data Instructions tab/worksheet: What is referred to as or meant
by the ‘master event list’? 4. – Regarding 2 second sample rate for 25 minutes starting 2 minutes
before event begins and 15 minutes after it begins, does this add up to 25 minutes or are additional
minutes being required for collection? Also, FPL can report frequency at this rate, but can only report
load in MW every four seconds. Move to 4 second sample rate. 6-8. – Possible to add button to autopopulate cells C8 and C11 in ‘Entry Data’ tab from the new column C and cell identifying the desired
frequency change time and simplify these steps? 10. – Clarify where the “Copy” button is. Is it the
one in the ‘Data’ tab or worksheet? Entry Data tab/worksheet: Step 6 should also be or be moved to
the “Instructions” worksheet. Are the values in column C in the “Data” worksheet labeled “Total Lost
Generation” the same as those in column AQ in the “Evaluation” worksheet? If so, why are they not
both labeled “Net Actual Interchange”? What is the definition of “Non Conforming Load” in column E?
FRS Form 1 – Eastern Interconnection Instructions tab/worksheet: Step 4 – Send to whom and to
what address at NERC?
Mauricio Guardado
Los Angeles Department of Water and Power
No
LADWP recommends the following change to the definition of Frequency Bias Setting (replace the
word "discourage" with the word "prevent"). LADWP believes that this change increases the clarity of
the definition: Original A number, either fixed or variable, usually expressed in MW/0.1 Hz, included
in a Balancing Authority’s Area Control Error equation to account for the Balancing Authority’s
Frequency Response contribution to the Interconnection, and discourage response withdrawal through
secondary control systems. Proposed Change A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account for the
Balancing Authority’s Frequency Response contribution to the Interconnection, and prevent response
withdrawal through secondary control systems
No
LADWP has a concern with Requirement 3. The requirement should provide allowance for legitimate
circumstances when an entity cannot run on Tie Line Bias mode and not have an Adverse Reliability
Impact on the Balancing Authority’s Area. An entity should not be penalized when these legitimate
circumstances occur. LADWP believes that the Frequency Response Standard Background Document,
on Page 8, lists examples of legitimate circumstances: - Telemetry problems that lead the operator to
believe ACE is significantly in error. - The frequency input to AGC is not reflective of the BA’s true
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002813
frequency (such as if the control center were operating a local generator and disconnected from the
Interconnection). - During restoration (where one BA might be controlling frequency while another to
which it is connected is managing interchange between them). - For training purposes. - Many AGC
systems will automatically switch to an alternate mode if the EMS determines Tie Line Bias control
could lead to problems. LADWP believes that the language in Requirement 4 needs to be clarified and
recommends the following change: - R4. Each Balancing Authority that is performing Overlap
Regulation Service shall modify its Frequency Bias Setting in its ACE calculation to be equivalent to
either (i) the sum of the Frequency Bias Settings of the participating Balancing Authorities as
validated by the ERO, or (ii) the Frequency Bias Setting as calculated based on the entire area being
combined and thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium][Time Horizon: Operations Planning] LADWP believes the language in
Requirement 5 needs to be modified to be consistent with that of the second paragraph of Attachment
B. LADWP recommends the addition of “natural frequency response” as a third bullet item to
Requirement 5. The revised requirement would read: - R5. In order to ensure adequate control
response, each Balancing Authority shall use a monthly average Frequency Bias Setting whose
absolute value is at least equal to one of the following: [Risk Factor: Medium ][Time Horizon:
Operations Planning] • The minimum percentage of the Balancing Authority Area’s estimated yearly
Peak Demand within its metered boundary per 0.1 Hz change as specified by the ERO in accordance
with Attachment B. • The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation-only Balancing Authority, per 0.1 Hz change as specified by the ERO
in accordance with Attachment B. • The natural frequency response
Yes
LADWP agrees with the following VRFs: - R1 - Medium - R2 - Medium - R3 - Medium - R4 - Medium R5 - Medium
No
LADWP recommends that the Measures for Requirement 3 and Requirement 5 reflect their comments
to Question 2.
No
LADWP recommends that either the VSL for Requirement 3 reflects its comments to Question 2, or
that these comments be addressed as an exception in the Measure for Requirement 3.
No
LADWP considers the increase in number of events to analyze (now 25) to be excessive. Previous
years analyses typically involved 4-6 events; a permanent five-fold increase is not justified. LADWP
suggests reducing the baseline number of events from 25 to 12 per year. Analysis of a larger number
of events could be requested on a year-by-year basis if conditions warrant, but should not be
mandatory for all regions in all years.
Yes
LADWP notes that the document “BAL-003-1 Background Document” seems to be reasonable.
Yes
LADWP notes that Attachment B seems to be reasonable
No
LADWP notes that Form 2 is not compatible with prior versions of Excel—it won’t even open in Excel
2003 (which is still widely used)—and requests that all spreadsheets and calculation tools developed
under 2007-12 be revised to support common software of the past 10 years.
LADWP supports project 2007-12’s general approach to frequency response, and is prepared to
support the ballot once several problematic details are corrected. LADWP notes that the time allowed
to analyze the final “official” set of 25 events for each year, from Dec 15 to Jan 10, is relatively short
and coincides with the holiday vacation season. Could this time either be extended by 2-4 weeks or
shifted to another part of the year (in addition to reducing the number of events to be analyzed)?
LADWP would like to see addressed in the Standard how the case is to be addressed where a BA
simply has no frequency response information to provide, as could happen for a small 1-2 generator
BA which has its generators out of service for an extended period for maintenance or upgrades.
Assuming the BA purchases frequency response services from another entity during this period, is the
BA out of compliance with the proposed Standard simply because it has no data report? And how is its
next-year obligation to be computed? These issues should be addressed in the Measures or Additional
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002814
Compliance information. If these are issues for “lawyers” as the Standards Drafting Team indicated
during the November 14, 2011, webinar then the team should engage a NERC lawyer to resolve them
prior to releasing the Standard for ballot.
Thomas Washburn
FMPP
Yes
No
• R1. Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an annual
Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on FRS Form 1) that
is equal to or more negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each BA or RSG to maintain an adequate level of Frequency
Response in the Interconnection. [Risk Factor: Medium ][Time Horizon: Operations Assessment] The
BA does not have control over the frequency responsive generation. There needs to be a requirement
that the GOP shall set frequency response for the generators as directed by the BA. • R5. In order to
ensure adequate control response, each Balancing Authority shall use a monthly average Frequency
Bias Setting whose absolute value is {greater than or (<= add these words)} {at least (<= delete
these words)} equal to one of the following: [Risk Factor: Medium ][Time Horizon: Operations
Planning] • The minimum percentage of the Balancing Authority Area’s estimated yearly Peak
Demand within its metered boundary per 0.1 Hz change as specified by the ERO in accordance with
Attachment B. • The minimum percentage of the Balancing Authority Area’s estimated yearly peak
generation for a generation-only Balancing Authority, per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
Yes
Yes
Yes
No
• Item 2 should be changed as follows: The ERO will identify at least 25 frequency excursion events in
each Interconnection for calculating the Frequency Bias Setting and the FRM. If the ERO cannot
identify in a given evaluation period 25 frequency excursion events satisfying the limits specified in
criteria 3 below, then similar acceptable events from the previous evaluation period also satisfying
listed criteria will be included with the data set by the ERO for determining FRS compliance. (as
written this item could cause double jeopardy for event from the previous period) • Under FRO for the
Interconnection the first sentence should be changed as follows: “The ERO {Each Interconnection
(delete these words)} will establish target contingency protection criteria for each Interconnection.”
(each Interconnection is not a governing entity) • The footnote under Table 2 of Attachment A should
be changed as follows: The Eastern Interconnection set point listed is a compromise value for the
highest UFLS step setting of 59.5Hz used in the east and the {special protection scheme’s (delete
these words)} highest UFLS step setting of 59.7Hz used in Florida. It is extremely unlikely that an
event elsewhere in the Eastern Interconnection would cause the Florida UFLS {special protection
scheme (delete these words)} to “false trip”. (this is not a special protection system; it is just an
UFLS)
Yes
Yes
Yes
Alice Ireland
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002815
Xcel Energy
Yes
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and appears to apply more
towards 'secondary response'. Recommend clarifiying this concept and possibly include an example in
the background document to help explain how this would work. R3 - recommend modifying the
language to permit AGC out of TLB mode if the RC is notified; also remove the "to ensure coordinated
control" as this is not essential for the requirement. Our reasoning behind the suggested change to
notification of the RC is that there are occassions where an entity would need to perform testing, etc
and it could be argued that testing would not be sufficient justification for meeting the Adverse
Reliability Impact definition. Here is proposed revised language: Each Balancing Authority not
receiving Overlap Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line
Bias mode, unless the Balancing Authority's Reliability Coordinator has been informed and the
duration is [insert time constraint language here].
No
Based on our suggested changes to R3 in response to Question 2, the drafting team should modify M3
to be consistent with the proposed language.
Yes
No
Confusion exists around the “peak load” in that the Attachment A states the allocation is based on
Projected Peak Loads and Generation but the Background Document states it will use a historical Peak
and Generation to make the allocation. Also, for the BA installed capacity, where does that value
come from and does NERC obtain that from FERC form data or does the BA provide that information
somewhere specific to this effort? Additionally, there appears to be a difference in how FRO is
calculated in Attachment A and what is described in the Background Document. These differences
should be reconciled such that both documents address the same approach. If installed capacity is
used in the equation, how are variable/intermittent resources (e.g. wind, solar) accounted for? At full
capacity?
No
Same comment here as the one in question 6.
No
There could be some confusion caused by the Attachment B due to the use of the word “initially”
when the reference is made to the current standard. The drafting team should change the word
“initially” to “currently” or strike it to avoid the potential confusion.
Yes
It would be useful if the drafting team could develop a completed form as an example to help entities
better understand the methodologies used in the form.
It is not clear if there is an upper limit to the amount of frequency response expected of the Balancing
Authorities under this standard. Except for Table 2 in Attachment A, there is no discussion of an
amount of FR expected on a total basis. Balancing Authorities need to know for how many tenths of a
hertz they are to respond so they can determine how to plan to meet this requirement. The
documents do not appear to provide any boundary on the maximum amount of FR that a BA will
provide, i.e. it is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is the BA expected
to provide a limitless amount of frequency response?). Also, is that event excluded from the list used
to calculate the Balancing Authorities’ response or is it included with an expectation that it counts the
same as any other event. Without a clear statement of what is expected, including whether there is a
limit on that expectation or not, the Balancing Authorities can not know what is expected of them and
therefore can not plan appropriately.
Kathleen Goodman
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002816
ISO New England Inc
No
The FRM definition should not refer to FORM 1. Also, we offer the following alternative wording for
frequency bias setting; “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included
in a Balancing Authority’s Area Control Error equation to approximate the frequency response
provided by the assets within the respective Balancing Authority’s area.”
No
We do not agree with placing a requirement on Balancing Authorities, as generators are the main
supplier of “discretionary” frequency response. Also, the requirement refers to an attached form,
which is not part of the standard and therefore not enforceable.
Yes
No
The sampling interval needs to be tuned on a per Interconnection basis to support HQTE’s
characteristics
No
The violation severity levels for R1 seem to be reasonable. However, the technical writing needs to be
enhanced for clarity
No
We suggest the SDT to first determine if the materials in the revised Attachment A & B are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former, then
Requirement R1 should not mention Attachment A at all. If it is the latter, then the as-written
Attachment A is a mix bag as it on the one hand describes the ERO’s process for supporting the
Frequency Response Standard (FRS), in other words, the method and criteria it uses to calculate the
frequency bias settings and the FRM, and on the other hand the BA’s obligations to support this
process. We strongly disagree that the latter requirements be imbedded in an attachment, especially
one that is supposed to provide the technical background and guideline for another entity which, by
the way, is not held responsible for complying with the proposed method. An appendix is not
regarded as a mandatory requirement. Additionally, BAL-003-1- Attachment A 1. Criterion 5 needs to
be re-written for clarity. 2. Criterion 7 refers to the “cleanest events”. Perhaps a statement of what
constitutes a “clean event” is needed to avoid possible controversy in the future. 3. The use of 59.6
Hz as the highest UFLS setting seems flawed. It should either be 59.7 Hz as a deliberate choice to
protect Florida interests, or, it should be 59.5 Hz without concern for Florida’s unique settings. 4. In
the last 2 sentences at the end of the section on Frequency Response Obligation, it refers to an
Interconnection being able to offer “alternate FRO protection criteria”. It seems that the
Interconnection should have been an integral part of establishing its obligation. Also, it states that the
“ERO will confirm” the “alternate FRO protection criteria”. Does this mean the ERO unconditionally
approves it, or evaluates with a right of rejection? Please clarify. 5. In the formula for determining the
Balancing Authority’s FRO allocation, installed capacity is used. Does the industry have a clear and
consistent definition for installed capacity? Also, with greater wind energy development, the delivered
capacity over longer time horizons will be substantially less than nameplate machine ratings. Also, the
background document refers to the use of peak generation instead of installed capacity. Which shall
be used? Please clarify. 6. Very recent studies have shown that the 18-52 second sampling interval
does not work well for the Quebec Interconnection, in part due to the excellent and high level of
response found in that Interconnection. The standard needs to be modified such that the sampling
interval is that which works the best for each individual interconnection. 7. Attachment A needs to
define the point A sampling interval.
No
See first comment in 6 above. Also, Frequency Response Standard Background Document – 1. Cite
Attachment B in addition to Attachment A in the discussion of requirement 1. 2. The Balancing
Authority allocation method specified in this document does not agree with that in Attachment A. 3.
Drop the speculation on page 4 that most Balancing Authorities will be compliant. While it may be a
commonly held belief by many that there is adequate frequency response right now, that assessment
should be made after a targeted level of reliability has been defined and approved. The same
comment applies on page 12. 4. On page 6, drop the inappropriate recommendation of getting
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002817
frequency response through supplemental regulation. It is inappropriate to try to substitute a “minute
plus” product that is deployed centrally by the Balancing Authority for a “sub-minute” product that is
deployed automatically without any Balancing Authority action. When a pseudo-tie is used, changes in
the ACE values due to supplemental regulation are unrelated to and not coordinated with the need to
deploy frequency response. Not only should this approach not be offered as an alternative, but the
FRSDT should actively conduct research to determine if supplemental regulation via a pseudo-tie
should be deliberately REMOVED from any actual net interchange calculation that may include it! This
comment also applies to the mentioning of supplemental regulation on page 11 as well. 5. On page 7,
the reference to a 24 hour window on each side of the frequency bias setting implementation date is
inconsistent with the wording of the requirement. The requirement says that any time within the
designated date is acceptable. 6. On page 8, the inclusion of “for training purposes” as a reason to
not operate in tie line bias control should be dropped. This sort of training can be done in a training
simulator. Alternatively, if it is determined that it should be supported, then the requirement needs to
be reworded to allow it explicitly. 7. On page 14, the sentence: “This approach would only provide
feedback for performance during that specific event and would not provide insight into the depth of
response or other limitations” is difficult to understand. The paragraph would read better by simply
dropping it.
No
We suggest the SDT to first determine if the materials in the revised Attachment A & B are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former, then
Requirement R1 should not mention Attachment A at all. If it is the latter, then the as-written
Attachment A is a mix bag as it on the one hand describes the ERO’s process for supporting the
Frequency Response Standard (FRS), in other words, the method and criteria it uses to calculate the
frequency bias settings and the FRM, and on the other hand the BA’s obligations to support this
process. We strongly disagree that the latter requirements be imbedded in an attachment, especially
one that is supposed to provide the technical background and guideline for another entity which, by
the way, is not held responsible for complying with the proposed method. An appendix is not
regarded as a mandatory requirement.
Yes
ISO New England will not vote to approve the standard because it fails to place requirements on
generators to provide frequency response. There are four substantive problems: • Using 59.6 Hz as
an Eastern Interconnection UFLS instead of an actual value of either 59.5 Hz or 59.7 Hz • Using
installed capacity in determining the Frequency Response Obligation • The sampling interval needs to
be tuned on a per Interconnection basis to support HQTE’s characteristics • Do not advocate the use
of supplemental regulation as a method of procuring frequency response Additionally, the SDT must
decide on what the purpose of this standard is. If it is to respond to Order 693 then the standard
misses the point of defining how often to run Frequency Response Surveys; it does not crisply define
the “Interconnection” obligations. If the SDT does want to focus on performance then the issue of
who is the default provider must be addressed. As the IRC has noted previously, all BAs do not own
the service providers. To create standards that apply to entities that are dependent on other function
entities to comply with a standard requirement is of great concern.
Imperial Irrigation District
Jesus Sammy Alcaraz
Yes
Yes
Yes
Yes
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002818
Yes
Yes
Yes
Yes
No Additonal Comments
Salt River Project
Cindy Oder
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
John Tolo
Tucson Electric Power
Yes
No
R1: TEP feels that the FRO should be able to be calculated by the BA and that Form 1 changes should
be treated via the Standard drafting process. R2: TEP feels that use Form 1 should be required by the
Standard. Further, BAs should calculate its own frequency bias setting without ERO intervention. R3:
Operating outside Tie Line Bias mode should be allowed during a year to allow for the testing of other
modes. R4: Agree with the concept, but without ERO intervention. R5: Should read "greater than or
equal to".
Yes
No
It should be clear that historical data may be used to show compliance.
No
VSL's could be clearer and simpler. Allowance for the testing of other AGC modes should be
considered.
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002819
Attachment A creates additional requirements to the BAL-003-1 Standard. The arrested value of
frequency observed within 8 seconds may not be long enough in some instances. The delta F in the
West should be greater than 0.05 Hz to ensure a measurable frequency response. West Under
Frequency should be set at 59.95 Hz. There is no reliability concern for Over Frequency. Does 18
seconds after the start of the disturbance set point B? Pre-disturbance frequency should be relatively
steady and near 60.000 Hz is vague. TEP feels that the ERO should not need to validate a BAs
frequency bias setting.
Yes
No
Reducing a BAs frequency bias setting may have an adverse impact on recovering from a frequency
event once you get past the first 8-10 seconds. A larger bias will allow for actual and sustained AGC
generator responses. Industry focus should be on generator governor response within the first 8-10
seconds.
No
TEP feels that Form 2 is a useful tool for internal BA use and should not be used for compliance
purposes.
The BAL-003-1 Standard should be simplified and should not rely on the judgement of the ERO.
Thanks to the drafting team for their efforts and for taking on this important aspect of Interconnection
reliability.
Dennis Sismaet
Seattle City Light
No
LADWP and SCL recommend the following change (in red) to the definition of Frequency Bias Setting.
LADWP believes that this change increases the clarity of the definition: Original A number, either fixed
or variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error
equation to account for the Balancing Authority’s Frequency Response contribution to the
Interconnection, and discourage response withdrawal through secondary control systems. Proposed
Change A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing Authority’s Frequency Response
contribution to the Interconnection, and discourage prevent response withdrawal through secondary
control systems
No
• LADWP and SCL have a concern with Requirement 3. The requirement should provide allowance for
legitimate circumstances when an entity cannot run on Tie Line Bias mode and not have an Adverse
Reliability Impact on the Balancing Authority’s Area. An entity should not be penalized when these
legitimate circumstances occur. LADWP believes that the Frequency Response Standard Background
Document, on Page 8, lists examples of legitimate circumstances: - Telemetry problems that lead the
operator to believe ACE is significantly in error. - The frequency input to AGC is not reflective of the
BA’s true frequency (such as if the control center were operating a local generator and disconnected
from the Interconnection). - During restoration (where one BA might be controlling frequency while
another to which it is connected is managing interchange between them). - For training purposes. Many AGC systems will automatically switch to an alternate mode if the EMS determines Tie Line Bias
control could lead to problems. • LADWP and SCL believe that the language in Requirement 4 needs
to be clarified and recommends the following change (in red): R4. Each Balancing Authority that is
performing Overlap Regulation Service shall modify its Frequency Bias Setting in its ACE calculation to
be equivalent to either (i) the sum of the Frequency Bias Settings of the participating Balancing
Authorities as validated by the ERO, or (ii) calculate the Frequency Bias Setting as calculated based
on the entire area being combined and thereby represent the Frequency Response for the combined
area being controlled. [Risk Factor: Medium][Time Horizon: Operations Planning] • LADWP and SCL
believes the language in Requirement 5 needs to be modified to be consistent with that of the second
paragraph of Attachment B. SCL recommends the addition of “natural frequency response” as a third
bullet item to Requirement 5 (in red). The revised requirement would read: R5. In order to ensure
adequate control response, each Balancing Authority shall use a monthly average Frequency Bias
Setting whose absolute value is at least equal to one of the following: [Risk Factor: Medium ][Time
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002820
Horizon: Operations Planning] • The minimum percentage of the Balancing Authority Area’s estimated
yearly Peak Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B. • The minimum percentage of the Balancing Authority Area’s
estimated yearly peak generation for a generation-only Balancing Authority, per 0.1 Hz change as
specified by the ERO in accordance with Attachment B. • The natural frequency response
Yes
LADWP and SCL agree with the following VRFs: - R1 - Medium - R2 - Medium - R3 - Medium - R4 Medium - R5 - Medium
No
LADWP and SCL recommend that the Measures for Requirement 3 and Requirement 5 reflect their
comments to Question 2.
No
LADWP and SCL recommend that either the VSL for Requirement 3 reflects its comments to Question
2, or that these comments be addressed as an exception in the Measure for Requirement 3.
No
• LADWP and SCL consider the increase in number of events to analyze (now 25) to be excessive.
Previous years analyses typically involved 4-6 events; a permanent five-fold increase is not justified.
SCL suggests reducing the baseline number of events from 25 to 12 per year. Analysis of a larger
number of events could be requested on a year-by-year basis if conditions warrant, but should not be
mandatory for all regions in all years.
Yes
• LADWP and SCL note that the document “BAL-003-1 Background Document” seems to be
reasonable.
Yes
• LADWP and SCL note that Attachment B seems to be reasonable.
No
• LADWP and SCL note that Form 2 is not compatible with prior versions of Excel—it won’t even open
in Excel 2003 (which is still widely used)—and requests that all spreadsheets and calculation tools
developed under 2007-12 be revised to support common software of the past 10 years.
• LADWP and SCL support project 2007-12’s general approach to frequency response, and is prepared
to support the ballot once several problematic details are corrected. • LADWP and SCL note that the
time allowed to analyze the final “official” set of 25 events for each year, from Dec 15 to Jan 10, is
relatively short and coincides with the holiday vacation season. Could this time either be extended by
2-4 weeks or shifted to another part of the year (in addition to reducing the number of events to be
analyzed)? • LADWP and SCL would like to see addressed in the Standard how the case is to be
addressed where a BA simply has no frequency response information to provide, as could happen for
a small 1-2 generator BA which has its generators out of service for an extended period for
maintenance or upgrades. Assuming the BA purchases frequency response services from another
entity during this period, is the BA out of compliance with the proposed Standard simply because it
has no data report? And how is its next-year obligation to be computed? These issues should be
addressed in the Measures or Additional Compliance information. If these are issues for “lawyers” as
the Standards Drafting Team indicated during the November 14, 2011, webinar then the team should
engage a NERC lawyer to resolve them prior to releasing the Standard for ballot. • Finally, SCL points
out that the proposed Standard introduces a new obligation on applicable entities to maintain
frequency responsive reserves. Although this obligation does not appear to be unreasonable or
problematic in general, compliance may prove difficult for some entities and in some localized areas.
Progress Energy
Jim Eckelkamp
No
PGN supports the collective comments of SERC members.We feel that the last phrase of the definition
of Frequency Bias Setting is more of an explanation of a function rather than a definition. While the
SERC OC Standards Review Group understands the statement, we do not feel it belongs in the
definition of the Frequency Bias Setting and a period should be inserted after the word
“Interconnection”. Should the definition for Frequency Response Measure (FRM) be specific to the BA,
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002821
similar to the definition for Frequency Response Obligation (FRO)?
No
PGN supports the collective comments of SERC members.We feel that the utilization of the term,
“Reserve Sharing Group”, is not consistent with the definition in the NERC Glossary of Terms, and
should be deleted, applicability should be clarified or replaced with a new term, such as “Frequency
Response Sharing”. R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode
Yes
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
Yes
Yes
No
PGN supports the collective comments of SERC members. We suggest the SDT consider a term other
than “Initial’ in the title for Table 1. We suggest “Proposed Frequency Bias Setting” for Table 1
Yes
PGN Supports the collective comments of SERC members. We feel that frequency response is a
function of a contingency event and the Purpose Statement should recognize this relationship. We
suggest the following Purpose Statement. Purpose: To require sufficient Frequency Response from the
Balancing Authority to maintain Interconnection Frequency within predefined bounds by arresting
frequency deviations due to a contingency event and supporting frequency until the frequency is
restored. To provide consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Michael Falvo
Independent Electricity System Operator
No
In our previous comments, we suggested to drop the definitions for the terms FRM and FRO in favor
of providing the needed wording in the standard itself to take care of the specific details. The SDT did
not adopt our suggestion with the reason that these definitions will be used by other standards in the
future. That’s fair enough. However, the FRM definition: “The median of all the Frequency Response
observations reported annually on FRS Form 1” is problematic. It references an FRS Form 1 which is
not included in the definition itself but is in fact an attachment to a standard. In the current NERC
Glossary of Terms, there is no such precedence that a definition must rely on the requirements or
details in a standard for completeness. Also, it is very cumbersome that when changes are made to
FRS Form 1, the definition must be posted for industry comment and balloting, and vice versa. When
other standards begin using the term, there will be cross references between standards. This further
complicates the update/maintenance problem without any appreciable value. Once again, we strongly
urge the SDT to consider dropping these definitions, and have the details fully specified in the
standard body. This will eliminate the cross reference issues. After all, the definition for FRM is a
simple sentence and does not provide any clarity or specific details that cannot be addressed by
providing the appropriate wording in a requirement. With this cross-reference issue, combined with
the issues associated with Attachments A and B (see our comments under Q6, below), we are unable
to support this standard at this time.
Yes
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002822
No
M4: This measure does not read quite right. Something seems to be missing in the part that says:
“…showing when Overlap Regulation Service is provided including Frequency Bias Setting calculation
to demonstrate compliance with Requirement R4.” This part might have read something like:
“…showing that when it performed Overlap Regulation Service, it modified its Frequency Bias Setting
in its ACE calculation or it calculated the Frequency Bias Setting meeting the conditions specified in
Requirement R4.”
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should have been
“…Reserve Sharing Group’s…”. Alternatively, the wording after “interconnection’s FRO” could be
revised to: “…and the Balancing Authority’s or the Reserve Sharing Group’s FRM was…”
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two separate documents
(Attachments A and B), the modified Attachment A is problematic. As many commenters indicated,
the previous Attachment A, other than the section providing guidance on event selection, appears to
be explanatory, contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment A should include
only the event selection process and calculations associated with the requirements, including an
explanation of what is necessary if variable Frequency Bias Settings are implemented. If other
"requirements" need to be specified, such as the reporting time frame stipulated on page 3 of
Attachment A, they should be moved to the standard itself but not imbedded in an attachment. We
suggest the SDT to first determine if the materials in the revised Attachment A (and Attachment B)
are “Guideline” or “Technical Background”, or are they “requirements”. If it is the former, then
Requirement R1 should not mention Attachment A at all. If it is the latter, then the as-written
Attachment A is a mix bag as it on the one hand describes the ERO’s process for supporting the
Frequency Response Standard (FRS) (in other words, the method and criteria it uses to calculate the
frequency bias settings and the FRM), and on the other hand the BA’s obligations to support this
process. We strongly disagree that the latter requirements be imbedded in an attachment, especially
one that is supposed to provide the technical background and guideline for another entity which, by
the way, is not held responsible for complying with the proposed method. Further, there are no
measures developed for the requirements stipulated/imbedded in Attachment A so how can the
Responsible Entity (BA, in this case) be assessed for compliance? We suggest the SDT to move those
requirements on the BA to the main standard, and turn Attachment A into an appendix describing the
calculation process. An appendix is not regarded as a mandatory requirement. Similar comments
apply to Attachment B. Finally, the two Attachments are listed in Section F – Associated Documents.
This Section is generally used to list reference documents that are NOT standard requirements. We
suggest the SDT review and revise this listing depending on its final determination of the status of the
two Attachments (or their revisions, where appropriate).
We do not have an opinion on whether or not the Background Document provides sufficient clarity to
the development of the standard. We do, however, suggest that the SDT consider our comments in
Q6 above, and move some of the information from Attachments A and B to or combine with the
Background Document, to provide all the technical basis and background behind the elements
stipulated in the requirements.
No
Please see our comments under Q6. In brief, we do not agree with including a process description
type of document as part of the standard requirement.
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet file. Apart from
that, however, there are other sheets added to the previous Form 1. But this Comment form makes
no mention of the changes, nor is there a question on the additional information requested. We have
a concern over this omission of attention or oversight. Compared to the previous version, Form 1 has
been significantly expanded to include not only additional sheets but much more comprehensive data
requirements even on the Data Entry sheet itself. This makes data submission a very time-consuming
task but the justification for requiring detailed data entry has not been provided. We question the
need for such expansion on data entry requirements. We have yet to see the reason for expanding
Form 1 in assisting a BA to provide the data needed to comply with the standard, hence we do not
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002823
see how adding a Form 2 can help in that regard. We suggest the SDT to look at the basic need for
data submission that would suffice to support the FRS reporting process. Where the SDT deems
additional data entry sheets to be necessary, it should provide the rationale for expanding from a 2
sheet form into a multiple sheet form for additional data collection.
The proposed implementation plan conflicts with Ontario regulatory practice respecting the effective
date of the standard. It is suggested that this conflict be removed by appending to the
implementation plan wording, after “applicable regulatory approval” in Section 1.3 and 1.4 of the
draft standard, and in the two bullets in the draft implementation plan, to the following effect: “, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.”
Northeast Power Coordinating Council
Guy Zito
No
The FRM definition should not refer to FORM 1. Also, suggest the following wording for frequency bias
setting: “A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to approximate the frequency response provided by the assets
within the respective Balancing Authority’s area.”
No
The requirements should not be directed at Balancing Authorities, as generators are the main supplier
of “discretionary” frequency response. Requirement R1 refers to an attached form, which is not part
of the standard and therefore not enforceable.
Yes
No
The sampling interval needs to be tuned on a per Interconnection basis to support HQTE’s
characteristics.
No
The violation severity levels for R1 are reasonable. The technical writing needs to be enhanced for
clarity.
No
The SDT has to first determine if the materials in the revised Attachment A & B are “Guideline” or
Technical Background”, or are they “requirements”. If it is the former, then Requirement R1 should
not mention Attachment A at all. If it is the latter, then the as written Attachment A is confusing as it
describes the ERO’s process for supporting the Frequency Response Standard (FRS) (the method and
criteria it uses to calculate the frequency bias settings and the FRM), and at the same time the BA’s
obligations to support this process. The latter requirements should not be imbedded in an attachment,
especially one that is supposed to provide the technical background and guideline for another entity
which is not held responsible for complying with the proposed method. An appendix is not regarded
as a mandatory requirement. Additionally, regarding BAL-003-1- Attachment A 1. Criterion 5 needs to
be re-written for clarity. 2. Criterion 7 refers to “cleanest events”. A statement of what constitutes a
“clean event” is needed to avoid possible controversy in the future. 3. The use of 59.6 Hz as the
highest UFLS setting is flawed. It should either be 59.7 Hz as a deliberate choice to protect Florida
interests, or it should be 59.5 Hz without concern for Florida’s unique settings. 4. In the last 2
sentences at the end of the section on Frequency Response Obligation, it refers to an Interconnection
being able to offer “alternate FRO protection criteria”. The Interconnection should have been an
integral part of establishing its obligation. It is stated that the “ERO will confirm” the “alternate FRO
protection criteria”. Does this mean the ERO unconditionally approves it, or evaluates with a right of
rejection? Please clarify. 5. In the formula for determining the Balancing Authority’s FRO allocation,
installed capacity is used. Does the industry have a clear and consistent definition for installed
capacity? Also, with greater wind energy development, the delivered capacity over longer time
horizons will be substantially less than nameplate machine ratings. The background document refers
to the use of peak generation instead of installed capacity. Which shall be used? Please clarify. 6.
Recent studies have shown that the 18-52 second sampling interval does not work well for the
Quebec Interconnection, in part due to the excellent and high level of response found in that
Interconnection. The standard needs to be modified such that the sampling interval is that which
works the best for each individual interconnection. 7. Attachment A needs to define the point A
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002824
sampling interval.
No
Refer to the first comment in Question 6. For the Frequency Response Standard Background
Document – 1. Cite Attachment B in addition to Attachment A in the discussion of requirement R1. 2.
The Balancing Authority allocation method specified in this document does not agree with that in
Attachment A. 3. Drop the speculation on page 4 that most Balancing Authorities will be compliant.
While it may be a commonly held belief by many that there is adequate frequency response right
now, that assessment should be made after a targeted level of reliability has been defined and
approved. The same comment applies on page 12. 4. On page 6, drop the inappropriate
recommendation of getting frequency response through supplemental regulation. It is inappropriate to
try to substitute a “minute plus” product that is deployed centrally by the Balancing Authority for a
“sub-minute” product that is deployed automatically without any Balancing Authority action. When a
pseudo-tie is used, changes in the ACE values due to supplemental regulation are unrelated to and
not coordinated with the need to deploy frequency response. Not only should this approach not be
offered as an alternative, but the FRSDT should actively conduct research to determine if
supplemental regulation via a pseudo-tie should be deliberately REMOVED from any actual net
interchange calculation that may include it. This comment also applies to the mentioning of
supplemental regulation on page 11 as well. 5. On page 7, the reference to a 24 hour window on each
side of the frequency bias setting implementation date is inconsistent with the wording of the
standard. The standard states that any time within the designated date is acceptable. 6. On page 8,
the inclusion of “for training purposes” as a reason to not operate in tie line bias control should be
dropped. This training can be done in a training simulator. If it is determined that it should be
supported, then the requirement needs to be reworded to allow it explicitly. 7. On page 14, the
sentence: “This approach would only provide feedback for performance during that specific event and
would not provide insight into the depth of response or other limitations” is difficult to understand.
The paragraph would read better by simply deleting the sentence.
No
Refer to the first comment in Question 6.
Yes
This standard as written does not place requirements on generators to provide frequency response.
There are four substantive problems: • Using 59.6 Hz as an Eastern Interconnection UFLS instead of
an actual value of either 59.5 Hz or 59.7 Hz. • Using installed capacity in determining the Frequency
Response Obligation. • The sampling interval needs to be tuned on a per Interconnection basis to
support HQTE’s characteristics. • Do not advocate the use of supplemental regulation as a method of
procuring frequency response. It must be decided as to what the purpose of this standard is. If it is to
respond to Order 693 then the standard misses the target of defining how often to run Frequency
Response Surveys; it does not crisply define the “Interconnection” obligations. If performance is the
focus, then the issue of who is the default provider must be addressed. All BAs do not own the service
providers. To create standards that apply to entities that are dependent on other functional entities to
comply with a standard requirement is of great concern. FRS Form 1 is listed as being an Associated
Document. Will it be attached to the standard? The acronym FRS is used in the standard. FRS should
be spelled out before its acronym is used. If FRS Form 1 will not be an appendix or an attachment to
the document, then a link should be provided to it, or instructions given on how to find it.
John Bussman
Associated Electric Cooperative Inc
Yes
The FRO definition incorrectly applies the historically narrow Balancing Authority scope of
responsibility, while the FRM definition does not address applicability at all. But the BAL-003-1
Standard itself identifies RSGs (where applicable) and BAs as the Responsible Entities within scope of
this standard. For consistency, AECI recommends using “Responsible Entities (e.g. Reserve Sharing
Groups - where applicable, and Balancing Authorities)” in both the FRO and FRM definitions.
Rationale: This change should help future-proof the definition, should more specific “frequency
response” or “spinning reserve” sharing groups later surface within our industry. AECI agrees with the
Frequency Bias Setting definition’s inclusion of a bit more functionality than typical. We however
recommend replacing “to account for the Balancing Authority’s Frequency Response contribution to
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002825
the Interconnection, and discourage response withdrawal through secondary control systems”, with
“to support their Frequency Response contribution to the Interconnection”. Rationale: Readability, and
clarity on the “discouraging withdrawal…” phrase, which should reside in the Background document.
Yes
Yes
Yes
Yes
The VSLs appear reasonable for the risk and particularly where they assess higher severity when the
BA or RSG Interconnection's performance was sub-standard as well.
Yes
Yes
Yes
This is a very important document, providing bounds and rationale for and future changes, as well as
initial settings going into ballot. As such, it is AECI's understanding that, upon going into effect, this
BAL-003-1 will utilize these initial settings.
No
AECI believes the SDT could spare our industry both confusion and inconsistency, by specifying that
identified Interconnection Disturbances include both Point A and Point B to the hour, minute, and
second. While this introduces some risk of Entities over-automating their data-reports, the benefits
for Eastern Interconnection respondents would be tremendous. Cautions and disclaimers should be
placed on both Form 1 and Form 2, to assure respondents manually inspect their frequency data and
pinpoint the specific inflection-point samples.
SDT Webinar responses, this standard still needs to address: 1) anticipated shifts in an Entity's FRO,
due to large changes in base generation or load, and 2) likely non-compliance for single-unit
generation-only BAs (R5.2?) Please address prior to second ballot.
Rich Salgo
NV Energy
Yes
No
Requirement 1 seems to be the only one that has any applicability to an RSG; however, it is unclear
under what circumstances this requirement applies to an RSG. Suggest changing the R1 to be
addressed solely to BA's or alternatively, explain under Applicability section 1.2 what "where
applicable" means.
Yes
Medium appears to be reasonable and appropriate.
Yes
No
For R1, suggest that the VSL's not be dependent upon the aggregate performance of the BA's within
an interconnection.
No
It is not clear whether the calculation of FRO is to utilize projections of BA load as in Att A, or past
data reported in FERC Form 1 as per the Background Document.
Yes
This is a good reference; however see response to Question 6 in that there appears to be a
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002826
discprepancy between Att A and the Background Document with regard to FRO calculation.
No
In Attachment B, it seems unclear whether the initial FB setting is supposed to be 1% of BA peak load
or 0.8% as shown in the table. In general, I was extremely confused about what the required FB
setting should be. R5 indicates a percentage of load found in Att B, but Att B indicates the greater of
Natural Frequency Response or 1% of peak, and then the table that follows indicates 0.8%. At this
point, I have no idea what is being stated for the requirement.
Yes
Thad Ness
American Electric Power
No
R1: Clarification is needed regarding the responsibility of a BA that is a member of a Reserve Sharing
Group. R2 and R3: What does “coordinated control” mean? There no leverage for the BA to require
the generator to carry their burden of addressing governor settings or droop settings, yet the BA is
obligated to meet some performance measures. This revision adds new performance measure
responsibilities on the BA who likely has no direct control over every resource affecting their
performance within their footprint. We are not necessarily challenging the performance measures
themselves, nor their underlying objectives, however AEP views this as a gap in responsibilities which
potentially effects reliability.
Yes
No
It is not clear for R1 what the exact delineations are among Lower, Medium, High, and Severe VSL’s.
Yes
A frequency response observation should not be used spanning multiple years, or if there does, there
should at least be a reset period.
Yes
Yes
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
1. The specified time interval from 20 seconds to 52 seconds for SEFRD measurement ignores the
primary frequency response which happens in first 20 seconds and is responsible for arresting the
frequency dip. We suggest using the average over the complete interval of 0 to 52 seconds. 2. The
difference between Low and High VSL for R1 is not clear. Similarly the difference between Medium
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002827
and Severe is not clear.
RoLynda Shumpert
South Carolina Electric and Gas
No
The last phrase of the definition of Frequency Bias Setting is more of an explanation of a function
rather than a definition. Therefore, we do not feel it belongs in the definition of the Frequency Bias
Setting and a period should be inserted after the word “Interconnection”. Should the definition for
Frequency Response Measure (FRM) be specific to the BA, similar to the definition for Frequency
Response Obligation (FRO)?
No
The utilization of the term, “Reserve Sharing Group”, is not consistent with the definition in the NERC
Glossary of Terms, and should be deleted, applicability should be clarified or replaced with a new
term, such as “Frequency Response Sharing”. R4 should clarify that a BA performing Overlap
Regulation Service should still be required to operate its AGC in “Tie Line Bias” mode.
Yes
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
Yes
Yes
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We suggest “Proposed
Frequency Bias Setting” for Table 1
Yes
We feel that frequency response is a function of a contingency event and the Purpose Statement
should recognize this relationship. We suggest the following insertion in the Purpose Statement.
Purpose: To require sufficient Frequency Response from the Balancing Authority to maintain
Interconnection Frequency within predefined bounds by arresting frequency deviations (due to a
contingency event) and supporting frequency until the frequency is restored. To provide consistent
methods for measuring Frequency Response and determining the Frequency Bias Setting.
Louis C. Guidry
Cleco Corporation
Yes
Yes
No
Please note Cleco does not use the VRFs therefore we feel too much energy and time is spent on the
VRFs. The SDT needs to concentrate on the requirements and measurements.
Yes
No
The VSLs for R2 are based on 5, 15 and 25 days. What was the justification for these values? Could
we just as well use 10, 20 and 30 or some other set of values? In R3, we understand that brief
periods of operation outside of TLB control are allowable providing 1) continued operation in TLB
control would create ARI on the Interconnection or 2) that justification is provided for the periods
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002828
when TLB is not used. For example, if something happens within our EMS that disables TLB control we
are compliant if we document the period as an EMS malfunction?
Yes
We appreciate the effort of the SDT in developing Attachment A. It was very helpful in weeding
through BAL-003.
Yes
We appreciate the effort of the SDT in developing the Background Document. It provided insight on
how the SDT got the proposed standard to where it is with this posting.
Yes
Yes
Requirement 5, bullet 2 does not make any allowance for a single generator generator-only BAs. If
that BAs generator is out-of-service, the BA cannot satisfy this requirement. This could also apply to
other generation-only BAs which have a very limited number of generating units. Also, RSGs/BAs
which experience resource changes throughout the year have no mechanism for adjusting their FRO.
MRO NSRF
Will Smith
No
The FRM definition: “The median of all the Frequency Response observations reported annually on
FRS Form 1” is problematic. It references an FRS Form 1 which is not included in the definition itself
but is in fact an attachment to a standard. In the current NERC Glossary of Terms, there is no such
precedence that a definition must rely on the requirements or details in a standard for completeness.
Additionally, the definition of Frequency Bias Setting should focus on what it is. Balancing Authorities
do not supply energy. Suggest revising it to: Frequency Bias Setting A number, either fixed or
variable, usually expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control Error
equation to approximate the expected natural response provided by the assets within the respective
Balancing Authority’s area.
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and appears to apply more
towards 'secondary response'. Recommend clarifiying this concept and possibly include an example in
the background document to help explain how this would work. R2 - Please add the word “range” inbetween the words “date” and “specified”. The background document specifies that there is a 72-hour
period to implement the FBS setting (See Background document Page 7). R2, as written, does not
reflect the period for which an entity may implement the ERO validated Bias into ACE. Also see our
comment on #7 as to the length of the comment period. Question 7 comment is provided to assist
the SDT; Note from question 7: (Page 7 (3rd paragraph) of the Background document states “Given
the fact that BA’s can encounter staffing or EMS change issues coincident with the date the ERO sets
for new Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date. 1. The Standard itself does not state this provision (24 hour window on each side
of target date) as indicated. 2. The SDT accurately addresses the fact that BA’s could have EMS or
staffing issues during implementation of the ERO validated FBS. The current stated 72-hour window is
not long enough for implementation of the FBS as there may be a host of issues that could impact
implementation. We suggest that a seven day window be used for implementation of the FBS.) R3 –
Recommend the term “Adverse Reliability Impact” be removed from Requirement 3. Based on the
NERC definition of the term, a smaller entity could never operate its AGC outside of TLB mode due to
their impact on the BES not likely to result in “instability or Cascading”. To ensure a more consistent
and equitable approach when applying this Requirement, recommend the drafting team incorporate
the reliability reasons listed within the Background Document into the actual Requirement.
Additionally, the phrase “effectively coordinated control” should be removed as this is not essential to
the Requirement and introduces ambiguity in its application. To this end, the following revisions are
proposed: R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively coordinated control,
unless such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002829
meets one or more of the following conditions. • Telemetry problems that lead the operator to believe
ACE is significantly in error. • The frequency input to AGC is not reflective of the BA’s true frequency
(such as if the control center were operating a local generator and disconnected from the
Interconnection). • During restoration (where one BA might be controlling frequency while another to
which it is connected is managing interchange between them). • For training purposes. • Many AGC
systems will automatically switch to an alternative mode if the EMS determines Tie Line Bias control
could lead to problems. • For single BA Interconnections, Flat Frequency and Tie Line Bias are
equivalent. • The Reliability Coordinator has been informed and the duration is [insert time constraint
language here]. R5 – Recommend to delete the phrase “In order to ensure control response”. Such
phrases can be needless causes of debate. If a BA uses one of the bulleted methods but does not get
“adequate response” then is the BA non-compliant? What is “adequate response”? Who decides if the
response is adequate? Please clarify.
Yes
No
Based on suggested changes to R3 in response to Question 2, the drafting team should modify M3 to
be consistent with the proposed language. Additionally, M1 should be revised to not reference a
specific Form. The Form may be the format of choice but it should not be an implied requirement.
Measures 3 and 4 identify the use of “operating logs” as evidence. Measure 2 identifies hard copy and
electronic evidence, “or other evidence”. We suggest calling out specifically “operator logs” for M2
also, in case there are system problems in capturing hard copy or electronic evidence during the short
time window for implementation.
No
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO requirement differently
depending on whether or not the Interconnection met the FRO requirement. The obligation of the BA
to meet its allocated FRO should be consistent regardless of what the other entities within the
interconnection are doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet the FRO.
No
Confusion exists around the “peak load” in that Attachment A states the allocation is based on
Projected Peak Loads and Generation but the Background Document states it will use a historical Peak
and Generation to make the allocation. Also, for the BA installed capacity, where is that value derived
from and does NERC obtain that from FERC form data or does the BA provide that information
somewhere specific to this effort? Additionally, there appears to be a difference in how FRO is
calculated in Attachment A and what is described in the Background Document. These differences
should be reconciled such that both documents address the same approach. If installed capacity is
used in the equation, how are variable/intermittent resources (e.g. wind, solar) accounted for? At full
capacity? Please clarify. We suggest the SDT clarify if the materials in the revised Attachment A (and
Attachment B) are “Guideline” or “Technical Background”, or “requirements
No
the MRO NSRF has restated the same answer as in question 6 on purpose. Confusion exists around
the “peak load” in that Attachment A states the allocation is based on Projected Peak Loads and
Generation but the Background Document states it will use a historical Peak and Generation to make
the allocation. Also, for the BA installed capacity, where is that value derived from and does NERC
obtain that from FERC form data or does the BA provide that information somewhere specific to this
effort? Additionally, there appears to be a difference in how FRO is calculated in Attachment A and
what is described in the Background Document. These differences should be reconciled such that both
documents address the same approach. If installed capacity is used in the equation, how are
variable/intermittent resources (e.g. wind, solar) accounted for? At full capacity? Please clarify. Page
7 (3rd paragraph) of the Background document states “Given the fact that BA’s can encounter staffing
or EMS change issues coincident with the date the ERO sets for new Frequency Bias Setting
implementation, the standard provides a 24 hour window on each side of the target date. 1) The
Standard itself does not state this provision (24 hour window on each side of target date) as
indicated. 2) The SDT accurately addresses the fact that BA’s could have EMS or staffing issues during
implementation of the ERO validated FBS. The current stated 72-hour window is not long enough for
implementation of the FBS as there may be a host of issues that could impact implementation. We
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002830
suggest that a seven day window be used for implementation of the FBS.
No
: There could be some confusion caused by the Attachment B due to the use of the word “initially”
when the reference is made to the current standard. The drafting team should change the word
“initially” to “currently” or strike it to avoid the potential confusion. The second paragraph of
Attachment B (which contains the two bullets): The words “initially 1%” in the second bullet
contradict with the Table 1 on Attachment B, which states “Initial” and “0.8%”. Suggest deleting the
parenthetical in the second bullet as when BAL-003-1 is effective it would be referencing an old
Standard version. If the initial minimum is intended to be 1% say so in the Table 1.
Yes
: It would be useful if the drafting team could develop a completed form as an example to help
entities better understand the methodologies used in the form
It is not clear if there is an upper limit to the amount of frequency response expected of the Balancing
Authorities under this standard. Except for Table 2 in Attachment A, there is no discussion of an
amount of FR expected on a total basis. Balancing Authorities need to know for how many tenths of a
hertz they are to respond so they can determine how to plan to meet this requirement. The
documents do not appear to provide any boundary on the maximum amount of FR that a BA will
provide, i.e. it is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is the BA expected
to provide a limitless amount of frequency response?). Also, is that event excluded from the list used
to calculate the Balancing Authorities’ response or is it included with an expectation that it counts the
same as any other event. Without a clear statement of what is expected, including whether there is a
limit on that expectation or not, the Balancing Authorities cannot know what is expected of them and
therefore cannot plan appropriately. In the first paragraph of R5 delete “at least” and replace with
“greater than or”. This phrase would now read “…absolute value is greater than or equal to one of the
following:” “Equal to or greater than” accurately identifies the expectation, the current phrasing will
lead to confusion and mis-interpretation. Bullet #1 of R5: The minimum % is based upon the
“estimated yearly Peak Demand”. During the NERC webinar it was mentioned that this minimum
would move to being based on historical reporting of Peak Demand. Where does the SDT stand on
this item? Please provide clarification.
SERC OC Standards Review Group
Gerald Beckerle
No
We feel that the last phrase of the definition of Frequency Bias Setting is more of an explanation of a
function rather than a definition. While the SERC OC Standards Review Group understands the
statement, we do not feel it belongs in the definition of the Frequency Bias Setting and a period
should be inserted after the word “Interconnection”. Should the definition for Frequency Response
Measure (FRM) be specific to the BA, similar to the definition for Frequency Response Obligation
(FRO)?
No
We feel that the utilization of the term, “Reserve Sharing Group”, is not consistent with the definition
in the NERC Glossary of Terms, and should be deleted, applicability should be clarified or replaced
with a new term, such as “Frequency Response Sharing”. R2 exempts BAs participating in Overlap
Regulation Service from implementing the Frequency Bias Setting on the date specified by the ERO,
and R4 states how the BA performing Overlap Regulation Service will modify its Frequency Bias
Setting but does not state when the setting will be implemented. The exemption for BAs participating
in Overlap Regulation Service should either be deleted from R2 or language stating the
implementation date of the frequency bias setting needs to be included in R4. R4 should clarify that a
BA performing Overlap Regulation Service should still be required to operate its AGC in “Tie Line Bias”
mode.
Yes
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002831
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”. VSL for R1:
The draft VSLs for R1 uses the summation of FRM for all BAs within an Interconnection as a factor in
determining the applicable VSL. This does not seem consistent with R1. R1 is about a single BA and
the individual BA’s frequency response performance as measured by the FRM for that specific BA.
Including the FRM summation of the Interconnection expands R1. It appears that a BA that is noncompliant with R1 could end up with either a Low/Medium or High/Severe VSL based upon the FRO
performance of the Interconnection. The FRM performance of the Interconnection is beyond the
knowledge and control of a single BA and should not be a determinate of the applicable VSL. Is there
a technical basis for selection of the 1%, 30% and 15MW/.1 Hz VSL breakpoints? Does the Lower VSL
give a 1% dead band to a BA’s FRO? If so, will this be acceptable to NERC/FERC? VSL for R2: The VSL
should reflect the language used in the requirement. R2 says a BA “not participating in Overlap
Regulation service shall ….”, while the VSL says a BA “not receiving Overlap Regulation Service…..”
The VSL language is not consistent with the requirement. VSLs for R5: Since Frequency Bias Setting
is expressed as a negative value, the terms “absolute value” and “less than” must be used carefully.
Wouldn’t the “absolute value” of a BA’s Frequency Bias Setting always be positive and thus it could
never be less than the minimum specified by the ERO (a negative value)?
No
The definition of Single Event Frequency Response Data (SEFRD) was struck from the draft standard
but still appears in Attachment A. Since R1 of the standard references Attachment A, would the
definition of SEFRD still be applicable? If the definition is to be totally struck, we don’t think the term
should be used in Attachment A.
No
Portions of the Background Document do not appear to be complete or finished. The Background
Document should be edited to be consistent with changes made to the standard or other related
documents (eg. elimination of the definition of SEFRD and any revisions to the draft BAL-003-1).
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We suggest “Proposed
Frequency Bias Setting” for Table 1
Yes
We feel that frequency response is a function of a contingency event and the Purpose Statement
should recognize this relationship. We suggest the following insertion (in quotation marks) in the
Purpose Statement: Purpose: To require sufficient Frequency Response from the Balancing Authority
to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations
“due to a contingency event” and supporting frequency until the frequency is restored. To provide
consistent methods for measuring Frequency Response and determining the Frequency Bias Setting.
Southern Company
Antonio Grayson
No
We suggest adding BA to the definition of Frequency Response Measure (FRM), similar to the
definition for Frequency Response Obligation (FRO).
Yes
No
VSL for R2: We suggest the language in the VSL be consistent with the language used in the
Requirement. The VSL for R2 says a BA ‘not receiving Overlap Regulation Service…….’ R2 says a BA
‘not participating in Overlap Regulation service shall …….’ VSLs for R5: Since Frequency Bias Setting is
expressed as a negative value, the terms “absolute value” and “less than” must be used carefully.
This VSL uses “absolute value” when referring to the BA’s Frequency Bias Setting, but does not use
“absolute value” when referring to the Frequency Response Obligation, or minimum value specified by
the ERO. Consider revising this VSL so that a true comparison can be made.
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002832
We suggest increasing the delta f for the East to be the same value as the West or larger. The reason
for this is that the 0.04Hz suggested is too close to the governor deadbands of .036Hz. This would
potentially omit frequency response that some units may provide for a larger excursion but not for
those close to the deadband.
No
We suggest the Background Document should be edited to be consistent with changes made to the
standard or other related documents (eg. Any revisions to draft BAL-003-1 and removal of the
definition of SEFRD).
No
We suggest using the words, ‘Proposed Frequency Bias Setting’ in the Title of Table 1 instead of the
word, ‘Initial’.
Yes
We suggest adding the words, ‘due to a contigency event’, after the word, ‘deviations’, in the Purpose
statement because we feel that frequency response occurs due to a contigency event.
SPP Standards Review Group
Robert Rhodes
Yes
Yes
Yes
Yes
No
The VSLs for R2 are based on 5, 15 and 25 days. What was the justification for these values? Could
we just as well use 10, 20 and 30 or some other set of values? In R3, we understand that brief
periods of operation outside of TLB control are allowable providing 1) continued operation in TLB
control would create ARI on the Interconnection or 2) that justification is provided for the periods
when TLB is not used. For example, if something happens within our EMS that disables TLB control
are we compliant if we document the period as an EMS malfunction?
Yes
We appreciate the effort of the SDT in developing Attachment A. It was very helpful in weeding
through BAL-003.
Yes
We also appreciate the effort of the SDT in developing the Background Document. It provided insight
on how the SDT got the proposed standard to where it is with this posting.
Yes
Yes
Requirement 5, bullet 2 does not make any allowance for a single generator, generator-only BA. If
that BA's generator is out-of-service, the BA cannot satisfy this requirement. This could also apply to
other generation-only BAs which have a very limited number of generating units. Also, RSGs/BAs
which experience resource changes (permanently removing generation from service) throughout the
year have no mechanism for adjusting their FRO during the year.
H. Steven Myers
ERCOT
No
RE: Frequency Response Obligation (FRO) definition: ERCOT suggests changing “Balancing
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002833
Authority’s” to “Balancing Authority Area’s” as follows: The Balancing Authority Area’s share of the
required Frequency Response needed for the reliable operation of an Interconnection. A BA that does
not own generation resources cannot provide Frequency Response, it can only schedule and dispatch
available resources capable of such; . The BA should be responsible for taking action to schedule
resources that are capable of frequency response, and monitoring to assure frequency response
performance. The GOP (possibly the LSE when demand side performance is involved) must be
accountable for performing. However, there is nothing in this requirement to encourage the owner of
a resource who chooses not to provide frequency response to come to the table. There is nothing in
this standard that uniformly requires all frequency response providers to perform. This is likely to be
detrimental to the performance of a BAA and unfairly sanctions those willing to perform to to assure
reliability while others are not required to perform.
No
Measure should be modified to align with revised Requirements per ERCOT’s comments on #1.
No
Refer to comments in #1.
No
While there is no problem with the calculation involved, it is unclear why the SDT elected to assign a
grid performance element in this standard to the ERO, who has no functional (registered) role in grid
performance. Since this is a cook-book calculation and transfer of data on frequency performance,
why not assign it to the BA?
Kasia Mihalchuk
Manitoba Hydro
No
It is not clear why the term “Single Event Frequency Response Data (SEFRD)” has been removed
from the standard but is still used and defined in the Background Document and Attachment A.
No
Regarding R1: 1. Neither R1 nor the referenced Attachment A clarifies the FRM requirements for an
RSG to comply versus a BA. In particular (i) At p.3, Attachment A states that the ERO is responsible
for “annually assigning an FRO and Frequency Bias Setting to each BA.” No mention is made of RSGs.
(ii) Attachment A only references RSGs in the context of reporting obligations for Form 1 (at p.4) and
(iii) Compared to BAL-002-0 R1.1, which clearly states that the BA may elect to fulfill its obligation
through an RSG and that in such cases the RSG has the same responsibilities as each BA (that is a
participant in the RSG). 2. It should be clarified that this requirement applies to a BA, where the BA
doesn’t belong to an RSG, OR to an RSG. As it is currently drafted, the standard applies to each BA
and each RSG. It is redundant in that each BA would need to comply, whether or not they are a
member of an RSG that would also be required to comply. Further, the NERC Glossary definition of an
RSG is a group of BAs that collectively maintain, allocate and supply operating reserves. No mention
is made of the agreement including the sharing or delegation of responsibility related to FRM.
Accordingly, the standard should only reference a BA being able to delegate responsibility to an RSG if
the RSG Agreement allows for such delegation. 3. R1 does not specify where or how the FRO is
determined. Presumably this would be determined by the ERO pursuant to Attachment A. 4. The
phrase “to ensure that sufficient Frequency Response …” should be separated from the requirement
as it is (i) not descriptive of the required actions; (ii) redundant with the stated purpose at the
beginning of the standard. In general, such a drafting technique should be avoided as it may allow
Responsible Entities to argue that a violation has not occurred where the specific action that is
described has not been taken, but the purpose referenced in the requirement has been met.
Regarding R2: 1. It is not clear from R2 who determines the Frequency Bias Setting for “validation”
by the ERO and how the FBS is determined. (Presumably done by the BA in accordance with
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002834
Attachment B). Based on Background document, should refer to those “published” by ERO. The BA’s
FBS may not be validated, and may be modified before posting. 2. Attachment B does not refer to the
ERO “validating” FBS. 3. Attachment B refers to an RSG calculating FBS, but the standard does not.
Yes
No
It should be clarified that R1 requirement applies to a BA, where the BA doesn’t belong to an RSG, or
to an RSG. As it is currently drafted, the standard applies to each BA and each RSG. It is redundant in
that each BA would need to comply, whether or not they are a member of an RSG that would also be
required to comply. Further, the NERC Glossary definition of an RSG is a group of BAs that collectively
maintain, allocate and supply operating reserves. No mention is made of the agreement including the
sharing or delegation of responsibility related to FRM. Accordingly, the standard should only reference
a BA being able to delegate responsibility to an RSG if the RSG Agreement allows for such delegation.
No
The Violation Severity Levels for R1 penalize entities more severely depending on how the
interconnection as a whole has performed. MH believes that BAs should only be held accountable for
issues within their control and that the VSLs for R1 should be revised accordingly.
No
1. p.2 refers to each “Interconnection” establishing target contingency protection criteria. However,
an “Interconnection” as defined in the NERC Glossary is an electrical system, not a Responsible Entity.
This should be revised to clarify which Responsible Entities must establish the protection criteria. 2.
Table 2, although entitled “Interconnection Frequency Response Obligations” does not use the term
FRO in the Table itself. This terminology should be consistent. 3. There is no clear statement in
Attachment A identifying the significance of Table 2. The previous paragraph identifies Table 2 as
listing “default targets”, but how does this relate to the FRO referenced in R1? 4. The “Note” on p.2
regarding the ERO being able to use additional events that don’t satisfy the criteria is unreasonable as
drafted. Since these events are used to calculate the Frequency Bias Setting and FRM (as per p.1,
s.2), the selection of events should not be at the unfettered discretion of the ERO. As drafted, no
grounds or criteria must be satisfied.
Yes
Please see MH’s response to Question 1 regarding the term Single Event Frequency Response Data.
Additionally, the discussion in this document is useful in clarifying the intent of the drafting team, but
some of this clarification would best be incorporated into the Standard itself. Ex. RSG requirement on
page 6. Also on page 7 Attachment A does not specify what validation is and how it is done.
Attachment A refers to BA providing FBS data to ERO which then validates and publishes. This should
be reflected in R2.
Yes
Yes
The Applicability of BAL-003-1 should be clarified. Specifically, Section 1.2 should be changed from
“Reserve Sharing Groups (where applicable)” to “Reserve Sharing Group whose intent includes
meeting Frequency Response Obligations”. Regarding Data Retention: 1. As the standard is currently
drafted, both the BA and the RSG would be required to retain data or evidence to show compliance
with requirements R1 and M1. It is unclear whether this is the intention, or whether it would be
acceptable that just one or the other would maintain such records. 2. In the first and second
paragraph, the reference to ‘three calendar years’ should be specified to be the ‘previous three
calendar years’. 3. In the third paragraph, it should be clarified who is required to keep information
related to non compliance if the BA belongs to an RSG – the BA or the RSG or both. 4. In the fourth
paragraph, it should be clarified for what length of time the last audit records must be retained.
Western Electricity Coordinating Council
Steve Rueckert
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002835
No
Agree with the changes made to this latest version of BAL-003-1. However, additional clarity could be
added by addressing the following: R1- It is not clear what is intended by "Reserve Sharing Group".
As RSGs exist today, FRM performance by an RSG is not contemplated in the definition of FRM and
appears to apply more towards 'secondary response'. Recommend clarifiying this concept and possibly
include an example in the background document to help explain how this would work. R3 - There may
be occasions in which an entity has a legitimate reason or a need to operate in a mode other than Tie
Line Bias but that does not qualify as an Adverse Reliability Impact. Recommend including language
that would permit limited operation in a mode other than Tie Line Bias mode provided the Reliability
Coordinator was notified. R3 – Has the drafting team considered whether or not the language of
Requirement R3 will have any conflict or coordination issue with the FERC-approved regional reliability
standards BAL-004-WECC-1 – Automatic Time Error Correction? R5 – Suggest changing the language
“at least equal to” to “greater than or equal to” for clarity.
No
The proposed VSLs for Requirement R1 treat a BA that did not meet the FRO requirement differently
depending on whether or not the Interconnection met the FRO requirement. The obligation of the BA
to meet its allocated FRO should be consistent regardless of what the other entities within the
interconnection are doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
No
There is disagreement between Attachment A and the Background Document. Attachment A states
peak load allocation is based on “Projected” Peak Loads and Generation, but the Background
Document states it will use “historical” Peak Load and Generation. The allocation methodology of FRO
among the BAs in the equation on page 3 of Attachment A favors BAs with more load than more
installed capacity. Peak load is served but not all installed capacity is always dispatched.
No
See response to question 6.
Reducing frequency bias obligation is detrimental to reliability. Lowering the Minimum Frequency Bias
Setting from 1% to .8% (as identified in Table 1, Attachment B) will result in a lower value being
used by those Balancing Authorities with a natural frequency response below the current required
1%, which in turn will lower the natural frequency response. Over time it seems this pattern would
lead to poorer response. Is there an upper limit to the amount of frequency response expected of the
Balancing Authorities? How many tenths of a hertz is a Balancing Authority or Reserve Sharing Group
expected to respond to. The documents do not appear to provide any boundary on the maximum
amount of Frequency Response that a BA will provide. It is not clear what will happen if an event
occurs in the Eastern Interconnection that causes the frequency to drop to less than 59.6 Hz or in the
Western Interconnection that causes the frequency to drop to less than 59.5 Hz. Will that event be
excluded from the list used to calculate the Balancing Authorities’ response? Will it be included with
an expectation that it counts the same as any other event? Without a clear statement of what is
expected, including whether there is a limit on that expectation or not, it is unclear what is expected
of the Balancing Authorities. As Drafted, is there the possibility that a Balancing Authority may fail to
meet their FRO if surrounding BAs provide significantly more than required. Can over performers
cause average performers to fail when they would have otherwise met their requirement. The
documents do not provide guidance on how intermittent or variable generation is to be treated
Referencing Attachment A may be adding requirements. You may wish to consider adding language in
Requirement R1 that specifically requires the completion of the Attachments or Forms. There are no
requirements on governor installation, settings, or operation. Addition of governor operation
requirements seems essential for a frequency response standard. Without some sort of governor
response to require the individual generators to perform, a Balancing Authority with significant
amounts of generation for which it has no control over is at a disadvantage.
Curtis Crews
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002836
Texas Reliability Entity
Yes
We suggest that the Severe VSL for R3 is confusing and should be clarified as follows: “A Balancing
Authority not receiving Overlap Regulation service failed to operate AGC in Tie Line Bias mode, when
operation in Tie Line Bias mode would not have had an Adverse Reliability Impact on the Balancing
Authority’s Area.”
No
We have a number of concerns regarding Attachment A which are set forth below: 1. Regarding the
formula for “Initial FRO Allocation” on page 3 of Attachment A, the terms for “BA installed capacity”
and “Interconnection installed capacity” are undefined and could be subject to manipulation and
dispute. We suggest that this formula be revised to mirror the calculation based on well-established
FERC Form 714 data that is discussed in the Background document, which is based on actual
generation output. 2. In Attachment A, all references to “Texas” should be changed to “ERCOT” as a
reference to the Interconnection or the Region (including tables). 3. Regarding the Event Selection
Criteria in Attachment A: in item 2, consider whether certain events, such as DCS events, should be
required to be included in the FRM analysis. 4. Regarding the Event Selection Criteria in Attachment
A: item 7 provides that the selected frequency excursion events are to be selected so that they are
evenly distributed seasonally. Consider adding the seasonal distribution concept to item 2, particularly
if it becomes necessary to include events from the previous evaluation period. 5. In Attachment A,
page 1 says the ERO is to post the final list of frequency excursion events by December 15, but on
page 3 it suggests that the list will be posted by December 10. These references should be made
consistent. 6. Attachment A states, on page 3, “the ERO will use FRS Form 1 data to post the
following information for each Balancing Authority for the upcoming year: Frequency Bias Setting and
Frequency Response Obligation (FRO).” What is meant by “the upcoming year”? Is the BA supposed
to implement the new FBS immediately, or wait until the beginning of the next evaluation period on
December 1? Note that if the new FRO and FBS are implemented immediately (e.g. in March), then
the FRO will change in the middle of an evaluation period. This will complicate the comparison of FRM
and FRO as required by R1.
No
There is an inconsistency between the Background Document and Attachment A. Attachment A only
proposes event criteria based on “the largest category C (N-2) event identified,” but the Background
Document says: “Attachment A proposes the following Interconnection event criteria as a basis to
determine an Interconnection’s Frequency Response Obligation: - Largest category C loss-of-resource
(N-2) event; - Largest total generating plant with common voltage switchyard; - Largest loss of
generation in the interconnection in the last 10 years.”
No
1. In Attachment B, we suggest removing the paragraph beginning “The BA calculates . . .” because it
appears to be background information that conflicts with the methods provided in this version of the
standard for determining minimum bias settings. 2. Attachment B, Table 1, refers to “0.8% of peak
load or generation.” If a BA has both load and generation, will its minimum Frequency Bias Setting be
based on its load, its generation, or can it pick the value that it prefers to use?
Mark B Thompson
Alberta Electric System Operator
No
The FRO definition is specific to BAs. The Appendix 1, which is incorporated in the standard, uses this
definition in relation to requirements of the Interconnection. The SDT should consider a revision of
this definition that accounts for the requirements of the Interconnection versus the BA obligation to
the Interconnection.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002837
No
The language used in the requirements is superfluous. This could result in confusion and incorrect
assumptions being made. In R1, the comment within brackets “(as detailed in Attachment A and
calculated on FRS Form 1)”, is not necessary as it is already part of the FRM definition. We suggest
removing this bracketed text from the requirement. Also in R1, the phrase “to ensure that sufficient
Frequency Response is provided by each BA or RSG to maintain an adequate level of Frequency
response in the Interconnection” is a high level objective that does not add clarity to this
requirement. We suggest removing this from the requirement. R2, R3 and R5 use similar language
e.g. “to ensure effectively coordinated Tie Line Bias control”, “to ensure adequate control response”
etc. Although it provides background information, this does not add clarity to the requirement. We
suggest removing these from the requirements.
No
These documents not only provide additional clarity but also specify additional requirements, such as
FRS Form 1 annual reporting by January 10. All the enforceable requirements should be included in
the body of the standard. 1. Attachment A uses the terms "delta F (change in frequency)", "arresting
frequency (Point C)", "B Value", "A Value". These terms are not properly defined or described in this
document as drafted. The AESO suggests adding a description or definitions for clarity in this
document. 2. The standard gives 2 sets of values for Interconnection Frequency Response Obligation
in Table 2, (1) Base Obligation and (2) the obligation including 25% Safety Margin (which seems to
be implied by the "contingency protection criterion"). The Attachment A does not specifiy whether the
Base Obligation or the 25% Safety Margin value will be used to allocate the Interconnection FRO to
the BAs. Please clarify which value will be used to calculate the BA Frequency Response Obligation
(FRO) in the Interconnection FRO allocation formula in Attachment A. 3. The "initial FRO allocation"
formula in Attachment A uses Peak Load. The term Peak Load is not used in the standard nor is it a
defined term in the NERC Glossary. The standard uses Peak Demand, which is defined in the Glossary
Is "Peak Load" synonymous with "Peak Demand"? If so, Peak Demand should be used in the formula
instead. Otherwise Peak Load should be clearly defined in this document. 4. Is "Projected" in the FRO
allocation formula synonymous with "Forecasted"? If so, Forecasted should be used for consistency.
Otherwise "Projected" or the context in which it appears must be defined.
No
The Background Document uses BA Peak Generation in the BA FRO allocation formula. Attachment A
uses BA Installed Capacity. The AESO suggests making the two formulae consistent.
Besides the standard, the posting has two attachments, supporting material and two forms. It is not
clear how enforcement will be applied given the array of explicit and implicit requirements throughout
this package, and the use of undefined terminology, which will be subject to interpretations. In the
SDT response to our comments to the first draft of this standard it was stated that “The expectation is
events will be selected by the Balancing Authorities. The Balancing Authority may exclude events from
consideration for specific conditions such as data quality issues. “ Based on the SDT’s response, it is
our understanding that, for the purpose of the FRM calculation, BAs could exclude or include events
based on specific conditions consideration, such as data quality or event suitability (e.g. BA
separation from the Interconnection). However, the standard as currently drafted, does not have any
provisions to this effect. Please include such provisions in the body of the standard.
Anthony Jablonski
ReliabilityFirst
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002838
ReliabilityFirst thanks the SDT for their effort on this project. ReliabilityFirst has a number of
concerns/questions related to the draft BAL-003-1 VSLs which include the following: 1. General VSL
Comment – For consistency with other standards, each VSL should begin with the phrase “The
Responsible Entity…” or “The Balancing Authority”. This is consistent with the language of the
requirement and correctly pinpoints the appropriate responsible entity. 2. VSL R1 Comment – Based
on the FERC Guideline #3 “Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement”. ReliabilityFirst suggests the following modification: a. Lower VSL - The
Responsible Entity achieved an annual FRM within an Interconnection that was equal to or more
negative than the Interconnection’s FRO and the Responsible Entity’s FRM was less negative than its
FRO by more than 1% but by at most 30% or 15 MW/0.1 Hz, whichever one is the greater deviation
from its FRO b. Medium VSL - The Responsible Entity achieved an annual FRM within an
Interconnection that was equal to or more negative than the Interconnection’s FRO and the
Responsible Entity’s FRM was less negative than its FRO by more than 30% or by more than 15
MW/0.1 Hz, whichever one is the greater deviation from its FRO c. High VSL - The responsible entity
failed to achieve an annual FRM that is equal to or more negative than its FRO and the Responsible
Entity’s, FRM was less negative than its FRO by more than 1% but by at most 30% or 15 MW/0.1 Hz,
whichever one is the greater deviation from its FRO d. Severe VSL - The responsible entity failed to
achieve an annual FRM that is equal to or more negative than its FRO and the Responsible Entity’s
FRM was less negative than its FRO by more than 30% or by more than 15 MW/0.1 Hz, whichever
one is the greater deviation from its FRO 3. VSL R4 Comment – Based on the FERC Guideline #3
“Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification: a. Example for Lower VSL which should be carried
throughout all four VSLs - The Balancing Authority incorrectly modified the Frequency Bias Setting
value used in its ACE calculation when providing Overlap Regulation Services with combined footprint
setting-error less than 5% of the validated or calculated value 4. VSL R5 Comment – Based on the
FERC Guideline #3 “Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement”. ReliabilityFirst suggests the following modification: a. Example for Lower VSL which
should be carried throughout all four VSLs - The Balancing Authority used a monthly average
Frequency Bias Setting whose absolute value was less than or equal to 5% below the minimum
specified by the ERO.
ReliabilityFirst thanks the SDT for their effort on this project. ReliabilityFirst has a number of
concerns/questions related to the draft BAL-003-1 standard which include the following: 1. General
Comment – ReliabilityFirst is unsure how a Reserve Sharing Group (RSG) would be capable of
establishing a correct Frequency Response Measure (FRM) and Frequency Response Obligation (FRO)
as a RSG. Frequency Response and Frequency Bias are unique values established for each Balancing
Authority (BA), is the intent to require a RSG response to establish and maintain a certain frequency
response based upon the members and size of the RSG? From a monitoring perspective and without
more guidance it is unclear what or how these values will be determined. 2. General Comment –
ReliabilityFirst believes the proposed definitions for Frequency Response Measure (FRM) and
Frequency Response Obligation (FRO) are unclear. For example, ReliabilityFirst is unclear what is
meant by the term “observations” in the FRM definition. ReliabilityFirst also believes the terms
“reliable operation of an Interconnection” is ambiguous and seeks further clarification to its meaning.
3. General Comment – ReliabilityFirst recommends including Attachment A, Attachment B, FRS Form
1 and FRS Form 2 into the standard itself. These attachments and forms are referenced in the
requirements (and definitions) and therefore should be appropriately embodied within the standard.
4. General Comment – ReliabilityFirst believes the last fragment of words in Requirement R1 through
R4 (and first fragment of words in Requirement R5) is more of a justification for the requirement
rather than a requirement itself. ReliabilityFirst believes this justification should be moved to a
“Rationale Text Box”. For example, the first set of words in Requirement R5 states: “In order to
ensure adequate control response”. This language is really explaining why this requirement is needed.
ReliabilityFirst believes this should be removed, further expanded upon and placed in a “Rationale
Text Box”.
Florida Municipal Power Agency
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002839
Frank Gaffney
No
We thank the SDT for their hard work and diligence in moving this Project forward. However, we have
some concerns that cause us to not support the standard in its current form. In general, we believe
that there has not been sufficient prudency review for the standard, especially R1, to justify a
performance based standard around a Frequency Response Measure. We also believe that the
proposed standard does not meet all of the conditions of the Final SAR and Supplemental SAR. The
“Final SAR” was to develop methods by which a performance based standard would eventually be
developed. The Final SAR states: “The proposed standard’s intent is to collect data needed to
accurately model existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be modeled, and the reasons for the decline in Frequency
Response can be identified. Once the reasons for the decline in Frequency Response are confirmed,
requirements can be written to control Frequency Response to within defined reliability parameters.”
BAL-003-1 does not seem to complete the scope of this “Final SAR”. For instance, “the reasons for the
decline in Frequency Response” were not confirmed to our knowledge; and the field trial is not
completed to our knowledge. The Supplemental SAR adds to the scope of the Final SAR: “To provide a
minimum Frequency Response Obligation for the Balancing Authority to achieve, methods to obtain
Frequency Response and provide a consistent method for calculating the Frequency Bias Setting for a
Balancing Authority. In addition, the standard will specify the optimal periodicity of Frequency
Response surveys.” The Supplemental SAR does not eliminate the pre-requisite contained in the Final
SAR to determine the reasons for the decline in frequency response and confirm them before
establishing “defined reliability parameters”. In addition, the standard does not complete the
requirement of the Supplemental SAR to identify “methods to obtain Frequency Response”. For
instance, neither the BA nor the RSG have authority over governor and other generator settings.
There should be a requirement for GOPs to incorporate setting changes directed by the BA, otherwise
the standard establishes requirements that BAs and RSGs may not have the authority to achieve.
There is no consideration of "footprint" changes of the BA resulting in different allocation from the
ERO during a year. The standard and Attachments seem to specify an annual process with due dates
in December and January with no allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance? If the ERO does
not meet its obligations, can an entity still be found non-compliant, especially on a schedule basis?
Wasn’t there an issue of assigning standards to RROs, e.g., the fill-in-the-blank standards? Are there
similar issues with assigning requirements to the ERO? Is the ERO a “user, owner or operator” of the
BPS under Section 215, e.g., at (b)(1)”… All users, owners and operators of the bulk-power system
shall comply with the reliability standards that take effect under this section.” We question how this
would work from a compliance perspective.
No
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO can go back in
time to the previous year. This creates a double jeopardy to R1 of the standard. It also may include
irrelevant data if there have been changes from one year to the next in FRO or Bias settings assigned
by the ERO. On Frequency Response Obligation, first paragraph states that "Each Interconnection will
establish target contingency protection criteria"; however, the Interconnection is not a decisionmaking body. Does this really mean the ERO will establish FRO for each Interconnection? The single
asterisk note for the table on page 2 states: "It is extremely unlikely that an event elsewhere in the
Eastern Interconnection would cause the Florida UFLS special protection scheme to “false trip”.",
"Special protection scheme" should be stricken from this sentence, Florida has just a regional
difference in its UFLS program.
No
The document does not discuss how the new reliability parameter will affect BAs
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002840
On R5, the wording should be changed from “absolute value is at least equal to” to “absolute value is
greater than or equal to”
Brenda Powell
Constellation Energy Commodities Group
No
The Frequency Response Obligation has two components based on Attachment 1 - an Interconnection
FRO and a BA FRO. The proposed definition captures only the BA FRO.
No
R1 should accommodate agreements between multiple BAs and RSGs in achieving the annual
Frequency Response Measure. See proposed modification below: R1. Each Balancing Authority shall
achieve an annual Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on
FRS Form 1) that is equal to or more negative than its Frequency Response Obligations (FRO) to
ensure that sufficient Frequency Response is provided by each BA. Either the Balancing Authority
individual FRM, multiple Balancing Authority’s FRM per written agreement, or the FRM of the Reserve
Sharing Group must be equal to or more negative than the applicable Frequency Response
Obligations (FRO) for a single Balancing Authority or the aggregate of multiple Balancing Authorities
or RSGs. -In R2, “Each Balancing Authority not participating in Overlap Regulation Service” should
state “Each Balancing Authority, not receiving Overlap Regulation, shall implement the appropriate
Frequency Bias Setting (fixed or variable,) validated by the ERO, into its Area Control Error (ACE)
calculation beginning on the date specified by the ERO to ensure effectively coordinated Tie Line Bias
control”. -In R3, the explanatory language about why to operate in Tie Line Bias mode should be
deleted. See proposed modification below: R3. Each Balancing Authority not receiving Overlap
Regulation Service shall operate its Automatic Generation Control (AGC) in Tie Line Bias mode, unless
such operation would have an Adverse Reliability Impact on the Balancing Authority’s Area. -R5
should be modified to state only that the FBS is specified by the ERO in accordance with Attachment
B. As drafted the Requirement is in conflict with Attachment B because the Requirement mandates a
minimum and does not allow for a reduction to the minimum but it references Attachment B which is
titled “Process for Adjusting Minimum Frequency Bias Setting”. See proposed modification below: R5.
In order to ensure adequate control response, each Balancing Authority shall use a monthly average
Frequency Bias Setting whose absolute value is as specified by the ERO in accordance with
Attachment B. -There should be a Requirement specifically stating there is an obligation to complete
and submit FRS Form 1 by January 10th each year for clarity. -The requirements should be reordered to reflect the chronology of the process for frequency calculation, implementation and
performance measurement. The recommended order is as follows: R5 which defines the minimum
Frequency Bias Setting (FBS) for a Balancing Authority R4 which describes how the minimum FBS
may be altered through Overlap Regulation Service R2 which identifies the coordination required
around implementation R3 which requires operation in Tie Line Bias mode R1 which establishes the
performance obligation
Yes
No
Based on language modifications proposed to the Requirements, the measures should be revisited.
No
The language in the VSLs for R1 should be revisited based on the proposed language modifications
above and should also clearly look to the FRM of a BA, group of BAs or RSG against the BA FRO not
an Interconnection FRO.
Yes
Additional information relating to defining the FRO for the Interconnection would be helpful as would
an example for calculating the BA FRO.
Yes
Should be revisited based on the propposed modifications to the requirements.
No
Should be revisited based on the proposed modifications to the requirements.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002841
Yes
JEA Electric Compliance
Thomas McElhinney
No
We thank the SDT for their hard work and diligence in moving this Project forward. However, we have
some concerns that cause us to not support the standard in its current form. In general, we believe
that there has not been sufficient prudency review for the standard, especially R1, to justify a
performance based standard around a Frequency Response Measure. We also believe that the
proposed standard does not meet all of the conditions of the Final SAR and Supplemental SAR. The
“Final SAR” was to develop methods by which a performance based standard would eventually be
developed. The Final SAR states: “The proposed standard’s intent is to collect data needed to
accurately model existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be modeled, and the reasons for the decline in Frequency
Response can be identified. Once the reasons for the decline in Frequency Response are confirmed,
requirements can be written to control Frequency Response to within defined reliability parameters.”
BAL-003-1 does not seem to complete the scope of this “Final SAR”. For instance, “the reasons for the
decline in Frequency Response” were not confirmed to our knowledge; and the field trial is not
completed to our knowledge. The Supplemental SAR adds to the scope of the Final SAR: “To provide a
minimum Frequency Response Obligation for the Balancing Authority to achieve, methods to obtain
Frequency Response and provide a consistent method for calculating the Frequency Bias Setting for a
Balancing Authority. In addition, the standard will specify the optimal periodicity of Frequency
Response surveys.” The Supplemental SAR does not eliminate the pre-requisite contained in the Final
SAR to determine the reasons for the decline in frequency response and confirm them before
establishing “defined reliability parameters”. In addition, the standard does not complete the
requirement of the Supplemental SAR to identify “methods to obtain Frequency Response”. For
instance, neither the BA nor the RSG have authority over governor and other generator settings.
There should be a requirement for GOPs to incorporate setting changes directed by the BA, otherwise
the standard establishes requirements that BAs and RSGs may not have the authority to achieve.
There is no consideration of "footprint" changes of the BA resulting in different allocation from the
ERO during a year. The standard and Attachments seem to specify an annual process with due dates
in December and January with no allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance? If the ERO does
not meet its obligations, can an entity still be found non-compliant, especially on a schedule basis?
Wasn’t there an issue of assigning standards to RROs, e.g., the fill-in-the-blank standards? Are there
similar issues with assigning requirements to the ERO? Is the ERO a “user, owner or operator” of the
BPS under Section 215, e.g., at (b)(1)”… All users, owners and operators of the bulk-power system
shall comply with the reliability standards that take effect under this section.” We question how this
would work from a compliance perspective.
No
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO requirement differently
depending on whether or not the Interconnection met the FRO requirement. The obligation of the BA
to meet its allocated FRO should be consistent regardless of what the other entities within the
interconnection are doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
No
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO can go back in
time to the previous year. This creates a double jeopardy to R1 of the standard. It also may include
irrelevant data if there have been changes from one year to the next in FRO or Bias settings assigned
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002842
by the ERO. On Frequency Response Obligation, first paragraph states that "Each Interconnection will
establish target contingency protection criteria"; however, the Interconnection is not a decisionmaking body. Does this really mean the ERO will establish FRO for each Interconnection? The single
asterisk note for the table on page 2 states: "It is extremely unlikely that an event elsewhere in the
Eastern Interconnection would cause the Florida UFLS special protection scheme to “false trip”.",
"Special protection scheme" should be stricken from this sentence, Florida has just a regional
difference in its UFLS program.
No
The document does not discuss how the new reliability parameter will affect BAs
On R5, the wording should be changed from “absolute value is at least equal to” to “absolute value is
greater than or equal to”
Kirit Shah
Ameren
No
The Frequency Response Measure (FRM) definition should include which Entity(ies) it applies to,
similar to the definition of the FRO.
No
R1.While we agree with the concept of the entire requirement and the determination of the
Interconnection Frequency Response Obligation, we believe that the accurate measurement of
individual BA's FRM has not yet been demonstrated. This requirement should not be part of the
standard (even with the additional 12 months in the effective date) until the field trial demonstrates
that each BA's FRM can be consistently calculated to a level that will not create false non-compliance
to this requirement. While the calculation methodology in FRS Form 1 looks promising, with the Avalue and B-value average periods, we believe successful completion of the field trial is prudent. R5.
We were not sure if it was intended for this comment question to include Requirement R5, but have
decided to include our comments here. While we agree with the requirement of R5, it should not be at
the expense of changing the value of L10 in BAL-001, R2, which has been accepted by FERC in Order
693. An accommodation should be made so that any changes to the Frequency Bias Setting according
to BAL-003, R5, should not affect the value of L10 used in BAL-001, R2.
No
This is problematic since for a single BA interconnection these could be argued to be appropriate
VRFs, but is different for a multiple BA interconnection, where the risk that a single BA would pose to
the interconnection would be Lower.
Yes
With the understanding that any suggested changes to the proposed requirements would come with
corresponding changes to their measure.
No
It is not clear how the VSL for R1 uses the "Summation of the BA's FRM", when the requirement is BA
or RSG specific.
Yes
Yes
Yes
Considering the comments made regarding R5, in question 2, above, which are: R5. While we agree
with the requirement of R5, it should not be at the expense of changing the value of L10 in BAL-001,
R2, which has been accepted by FERC in Order 693. An accommodation should be made so that any
changes to the Frequency Bias Setting according to BAL-003, R5, should not affect the value of L10
used in BAL-001, R2.
Yes
We agree that the spreadsheet is meaningful, but still needs to be vetted through the field trial
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002843
process, with improvements made based on experience in its use.
While we are in general support of this standard and its requirements we have concerns regarding the
following: •The FRM methodology has not been fully vetted through the field trial process. •Adjusting
the minimum of the Frequency Bias Setting, while an appropriate adjustment for AGC control in the
ACE equation, should not be at the expense of L10 as used in BAL-001, R2. •The absence of any
resource specific frequency response requirement in NERC standards is an issue that must be
addressed somewhere. As the resource portfolio of our industry changes(expedited by recent EPA
rulemaking), the resources used for traditional primary frequency response are becoming a lower
percentage of the mix. New resources and existing resources that have not provided primary
frequency response need to be incorporated into the available frequency response discussion
Michael Brytowski
Great River Energy
Yes
No
R1: Including the Reserve Sharing Group (RSG) in the Frequency Response Obligation is outside of
the boundaries of a RSG. Where or how would a Frequency Bias be determined for an RSG to
determine their Frequency Response Obligation? Although it is apparent that frequency responds
during the implementation of reserves, the intention of a RSG is not to share frequency response, but
rather to share Reserves. Additionally, if the Frequency Response Obligation is not met by the RSG
how are penalties assessed? Should they be assessed to the group as a whole or strictly to the
generators that did not meet their individual obligation? R3: Needs to include verbiage for those
circumstances when it would be necessary to run AGC out of TLB such as during necessary testing.
The BA should have the option to operate out of TLB for a predetermined amount of time if needed
when notification and coordination with the RC has been established.
Yes
Yes
No
The VSLs on for Requirement R1 set a previously un-established precedent of relying on the
performance of other registered entities to establish the severity level of the violation. This is not
appropriate. The VSLs should be rewritten to provide further gradations of the violation severity based
on the BA’s own performance
No
Under item 3 of the Event Selection Criteria section, the delta F and Point C should be described
either in this attachment or the “Frequency Response Standard Background Document”. While many
in industry may understand what these terms mean, history has a way of getting lost with personnel
turnover. Furthermore, this would help ensure that the auditors and industry have a duplicate
understanding. In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency Protection
Criteria should be provided and which N-2 event was selected so that industry can help validate if the
correct MW value was selected. Furthermore, the document should clarify if the Contingency
Protection Criteria contains the “safety margin”. There is a statement in the paragraph before the
table that states it does but then the table lists out a separate 25% “Safety Margin”. Thus, it is not
clear if the “Safety Margin” is included in the Contingency Protection Criteria value listed in the table
or not. “Safety margin” should be changed to “reliability margin”. Safety has a specific meaning in the
electric industry and its use here is not appropriate. The Base Obligation should be explained. The
explanation should include its purpose and origin.
No
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002844
We can find no document titled “BAL-003-1 Background Document”. We assume this question is
referring to the “Frequency Response Standard Background Document” dated October 2011. We do
not believe the document provides sufficient clarity. No explanation is provided for why RSG was
added to Requirement R1. There are typos contained in the document. On page 6 in NIA, the A should
be in subscript. On page 7 in bullet 4 in the first sentence, “The” should be in lowercase
Yes
Yes
The Data Retention section requires the BA to retain data or evidence for up to four years. No data
that exceeds the audit cycle should be required to be retained. The audit cycle is three years.
Si Truc PHAN
Hydro-Quebec TransEnergie
No
The FRM and FRO definitions should precise that it is expressed in MW/0.1Hz. As for the Frequency
Bias Setting definition, as written, would apply only to a multiple BA Interconnection. In a single BA
Interconnection, the Frequency Bias translates the frequency error into a MW value that must be
dispatched to bring back Frequency to desired value. Since Tie Lines are not controlled through AGC,
there is no response withdrawal issue
No
The objective of R2 is that all BA’s implement their new Bias Setting at the same time, based on the
previous year’s data, so that control stays the most effective throughout the Interconnection (Tie-Line
Bias). In addition, the new Bias will be in effect all year long. The process is quite simple and
straightforward for a fixed Bias Setting. As for Variable Bias Setting, this process is not applicable
before the fact since the Bias equation can depend on real-time values that are not known in
advance. In addition, the simultaneous Bias implementation is not an issue for a single BA
Interconnection. Therefore, we suggest that Requirement 2 applies only to Fixed Bias Setting.
Yes
Yes
Yes
No
The Event Selection Criteria should be modified for the Quebec Interconnection. In Table 1, the
change in frequency (Delta f) used for Quebec’s Event Selection Criteria should be 0,3Hz (from point
“A” to point “C”) and must last for at least 7 seconds so that we don’t measure AGC action. In
addition, a criterion should be added by saying that events that recovered within the 20-52 second
average period for point “B” should be excluded from analysis.
Yes
No
The methodology proposed to compute the Minimum Frequency Bias Setting (in MW/0,1Hz) could be
adverse for the Quebec Interconnection. Hydro-Quebec uses a variable Bias that is calculated based
upon which generator is online and it’s droop setting. Under light load condition, we might have a Bias
setting that would be under (in absolute value) than the FRM which is the median value, even though
the Bias setting would reflect the grid’s frequency response. This method, as proposed, would
mandate us to have a larger Bias that what is really needed. Unlike Eastern Interconnection, we are
not over biased. By implementing this new methodology, it would make us over biased. Having a too
large Bias could lead to system instability, based on the results of studies from our control specialists.
The Minimum Frequency Bias Setting should take into account the wide load span that we can face.
For the variable bias, we could express the Minimum Frequency Bias Setting as a function of monthly
peak loads, and remove the Natural Frequency Response term. In addition, there is a gap between
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002845
Attachment B and the text in R5. See comment 10 for explanation.
Yes
There is a gap between R5, Attachment B and Form 1 next year’s Bias Setting equation. Requirement
5 states that the average Frequency Bias shall be at least equal to the minimum percentage of BA’s
peak load or generation. In Attachment B and Form 1, the required Frequency Bias is the maximum
(absolute value) between FRM, FRO and peak load+peak gen /2. As stated in comment 8, HydroQuebec is not in favor of adding the FRM into the minimum Frequency Bias requirement, at least for
Variable Bias Setting. Due to a good frequency response, this would lead us to have a too high AGC
Bias and causing potential reliability problems. In other words, this would lead us to be over-biased,
which would not be a good thing for a single BA Interconnection. For a Single BA Interconnection,
performance measure CPS1 tracks the performance of the variable Bias, which is enough to ensure
reliability through the Interconnection. Hydro-Quebec therefore recommends the drafting team that
Requirement 5 only applies to Multiple BA Interconnection. Another option is that Minimum Frequency
Bias Setting could be expressed as a function of monthly peak loads, and remove the Natural
Frequency Response term in the minimum Bias setting equation.
Greg Rowland
Duke Energy
No
Duke Energy would suggest removing “usually” from the Frequency Bias Setting definition, as the
value in the ACE equation must be in terms of MW/0.1Hz in order for ACE to be correctly calculated.
We apologize for missing this point in the last round of comments. Though some would argue that the
last phrase of the definition is more of an explanation of a function rather than a definition, we
support keeping the phrase inserted, as it should be recognized that the intent is to account for the
frequency response contribution AND keep the FBS slightly larger (in magnitude) than the average
estimated response, to better discourage withdrawal, which was also recognized by Nathan Cohn.
Should the definition for Frequency Response Measure (FRM) be specific to the BA, similar to the
definition for Frequency Response Obligation (FRO)?
No
Duke Energy supports the concept of a group of BAs forming a group to share in Frequency Response
however it should be clear that it is an option. We feel that the utilization of the term, “Reserve
Sharing Group”, is not consistent with the definition in the NERC Glossary of Terms which is specific to
sharing of contingency reserves, and should be replaced with a new term, such as “Frequency
Response Sharing Group”. R4 should clarify that a BA performing Overlap Regulation Service should
still be required to operate its AGC in “Tie Line Bias” mode. Though comments are provided below on
the Attachments, Duke Energy believes that all NERC Reliability Standards’ requirements must reside
within the standard itself (which is vetted by the Industry and subject to FERC approval), and not
within Attachments that may be revised without Industry review and approval. As noted below and in
prior comments, given the secondary control implications of changing the minimum Frequency Bias
Setting (FBS), Duke Energy believes that subsequent revisions to the minimum FBS should be vetted
through the Standards process. Duke Energy would suggest moving the details of the minimum FBS
for each Interconnection into the Standard, and having the implementation plan include annual
submittal of a revised minimum FBS based upon the methodology presented in Attachment B for
ballot approval by the Industry.
Yes
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing Group”.
No
On page 3 of the document it states “For a multiple Balancing Authority Interconnection, the
Interconnection Frequency Response Obligation is allocated based upon either the Balancing Authority
Peak Demand or peak generation”, however, the initial FRO allocation equation shows that the BA
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002846
allocation is based upon the sum of the Projected BA Peak Load plus installed capacity, times the
Interconnection FRO, and divided by the sum of the Projected Interconnection Peak Load plus
Interconnection installed capacity. Is the statement in quotes correct, or is the allocation equation
correct? In addition, the equation in Attachment A referencing “installed capacity” conflicts with the
equation in the BAL-003-1 Background Document entitled “Frequency Response Standard Background
Document” where “Peak Gen” is used. In summary, is the FRO allocation based upon an equation
which a) sums the Projected BA Peak Load plus peak generation, b) sums the Projected BA Peak Load
plus installed capacity, or c) uses either Projected BA Peak Load OR peak generation? All three
options are currently represented in the documentation. Calculation of the FRO for the Eastern
Interconnection: Duke Energy agrees with the criteria suggested for the event to be protected (4500
MW), and at this time also agrees with the “compromise” low limit of 59.6 Hz. However, knowing that
another Standard is under development which may require hourly assessment of available “frequency
responsive reserves”, we are trying to determine what impact the choice of this methodology will
have on the amount of frequency responsive reserves the industry will have to maintain – enough to
cover frequency swings that only occasionally reach down to perhaps 59.9 Hz as we see on the
Interconnection today (essentially the allocated FRO for a 0.1Hz deviation), enough to cover a 4500
MW loss, or whatever we deem appropriate as long as we are compliant to the FRM? We recognize
that the Standard Drafting Team cannot answer this question, as the Standard under development is
not within the scope of this team, however our comment is meant to illustrate the point that similar to
our response to question 8, it should be recognized that elements of this Standard are tightly coupled
to other current and potential Standards, and the impacts must be considered by the Industry.
No
Please see our comments to Question 6. In addition, Duke Energy disagrees with the statement on
page 9 that Attachment B will “ensure there is no negative impact on other Standards” – please see
our response to Question 8 for additional information.
No
Duke Energy suggests that the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1. Notwithstanding our suggestion that the
criteria/requirements of the minimum FBS in the Attachment be incorporated into the Standard, Duke
Energy has the following concerns with what is proposed: As cited in our comments to Question 8 in
the last posting (extensive, so not repeated here), the secondary control measures of CPS1, CPS2
and the draft Balancing Authority ACE Limit (BAAL) are tightly coupled to the Frequency Bias Setting
(FBS), and a reduction of the FBS will impact the secondary control requirements placed upon the BA.
Noted in our response to Question 7 above, the statement on page 9 in the “BAL-003-1 Background
Document”is not correct in stating that Attachment B will “ensure there is no negative impact on
other Standards”. The gradual reduction of the FBS will proportionally tighten the secondary control
limits for each Balancing Authority. Even if the “natural” Frequency Response in the Eastern
Interconnection remains unchanged for the next several years, under the process described allowing
the ERO to annually adjust the minimum FBS for the Interconnection, the FBS will eventually be
reduced to a value approximately 10% above the calculated response in magnitude, cutting the
current CPS1, CPS2 and BAAL limits in the Eastern Interconnection on average by more than half. The
current FBS for the Eastern Interconnection is approximately minus 6500 MW/0.1Hz, estimated
“natural” Frequency Response is perhaps around minus 2400 MW/0.1Hz. Unlike CPS1 and BAAL
where the measures are based upon the FBS of the BA only, CPS2 (dependent upon the FBS of the BA
and the Interconnection) will be significantly limiting to the degree that no change in a BA’s own
Frequency Response could significantly change its CPS2 limit if the Interconnection FBS drops over
time as indicated. At least under CPS1 and the draft BAAL, the BA would have an option of improving
its Frequency Response, allowing it to increase its FBS and proportionally the CPS1 and BAAL bounds
using the FBS. Conclusion from our last comments submitted: Duke Energy does not believe there is
a reliability need pushing the industry to tighten secondary control to the degree discussed above
simply as a result of reducing the Frequency Bias Setting. If the calculated Frequency Response of the
Interconnection stayed at its current level, what would be the justification for tightening the
secondary control requirements of CPS1, CPS2 and the proposed BAAL? Duke Energy supports taking
more of the error out of the ACE equation by having the FBS closer to the estimated Frequency
Response of the Balancing Authority, however, Duke Energy does not believe the result should be a
significant increase in secondary control costs to meet the CPS1, CPS2, or draft BAAL requirements.
Duke Energy understands the position placed upon this Standard Drafting Team- the secondary
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002847
control and reserve requirements are not under the scope of the team, however, proper consideration
has not been given in Attachment B to the impact lowering the FBS will have on the industry in terms
of the requirements placed upon the BA for secondary control and reserve requirements – especially
for meeting CPS2. The research discussed in our comments to the last posting support that reducing
the FBS while under CPS1 and the draft BAAL may be achievable, however a CPS2 bound cut
potentially in half or lower will place unreasonable bounds on a BA, requiring control actions even
when the BA may be operating in support of the Interconnection frequency. Given the significant
impacts discussed, Duke Energy believes that additional provisions must be in place for the Industry
to approve each subsequent revision to the calculation of the minimum Frequency Bias Setting, rather
than leave it as a decision made only by the ERO.
Yes
Duke Energy appreciates the significant work of the Standard Drafting Team in putting together the
draft Standard and extensive supporting documentation. Upon further consideration of the comments
above, Duke Energy has concluded that the work of this Standard Drafting Team and that of the
Balancing Authority Reliability-Based Control Standard Drafting Team under Project 2010-14
developing the Balancing Authority ACE Limit to replace CPS2, need to presented to the Industry as a
package – there is too much at stake to have one Standard impact other Standards to this degree.
Done in a vacuum the Industry is faced with the possibility of secondary control bounds being cut in
half or more, though there is no reliability need driving such performance requirements. Thank you.
ISO/RTO Council Standards Review Committee
Al DiCaprio
No
(1) In our previous comments, we suggested to drop the definitions for the terms FRM and FRO in
favor of providing the needed wording in the standard itself to take care of the specific details. The
SDT did not adopt our suggestion with the reason that these definitions will be used by other
standards in the future. That’s fair enough. However, the FRM definition: “The median of all the
Frequency Response observations reported annually on FRS Form 1” is problematic. It references an
FRS Form 1 which is not included in the definition itself but is in fact an Attachment to a standard. In
the current NERC Glossary of Terms, there is no such precedence that a definition must rely on the
requirements or details in a standard for completeness. Also, it is very cumbersome that when
changes are made to FRS Form 1, the definition must be posted for industry comment and balloting,
and vice versa. When other standards begin using the term, there will be cross references between
standards. This further complicates the update/approval process without any appreciable value. Once
again, we strongly urge the SDT to consider dropping these definitions, and have the details fully
specified in the standard body itself. This will eliminate that cross reference issue. After all, the
definition for FRM is a simple sentence and does not provide any clarity or specific details that cannot
be presented by using appropriate wording in a requirement. (2) The definition of Frequency Bias
Setting, if retained, should focus on what it is. Balancing Authorities do not supply energy. We
suggest to revise it to: Frequency Bias Setting A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s (BA’s) Area Control Error (ACE) equation to
approximate the expected natural response provided by the assets within the respective Balancing
Authority’s area.
No
General Comments The SRC offers the following general comment with regard to the SDT’s proposed
revisions: Gerry Cauley’s Results based initiative calls for requirements that focus on performance
(i.e. WHAT must be accomplished NOT on WHY it is required or HOW it should be accomplished). The
SRC has found that such explanatory statements as the SDT is proposing lead to ambiguities and
confusion in the compliance application. Compliance Enforcement agents must consider not just the
results but must decide if the action was taken for the given reason. To avoid such confusion, the
Results based approach uses reference documents to address such background material while leaving
the requirement as a direct mandate. The SRC notes: • All NERC Reliability Standards’ requirements
must reside within the standard itself (which is vetted by the Industry and subject to FERC approval).
• Data requirements are better handled through NERC’s Rules of Procedure Section 1600 than by
mandating that ad hoc Forms be submitted. • Definitions should be generic, and should be selfcontained (i.e. should not reference an external document). • The decisions regarding alternative
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002848
methodologies should be decided by the Industry not by the SDT. The SDT should make its case and
ask the Industry for its approval. Regarding Order 693 directives, the SRC notes that there are three
directives as follows: (1) To include Levels of Non-Compliance; (2) To determine the appropriate
periodicity of frequency response surveys necessary to ensure that Requirement R2 and other
requirements of the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) To define the necessary amount of Frequency Response needed for Reliable
Operation for each balancing authority with methods of obtaining and measuring that the frequency
response is achieved. The SRC suggests that Directive 2 be handled directly as a mandate that the
ERO conduct a fixed number of Frequency Response Surveys for randomly selected events. Discussion
of the number and the methodology can be explained in a reference document and leave the specifics
to the requirement. Directive 3 is critical to the Industry as it relates to who is the Applicable Entity.
The SDT addresses Directive 3 by mandating Balancing Authorities meet an objective. The directive is
to define that Objective, but there is no requirement associated with that Objective. There is an
attachment and there are discussions of what “may” be done, but there is no requirement in the
Standard itself. The reference to the BA as the provider of Frequency Response (i.e. Primary Control
response) runs counter to other FERC directives that mandate obligated entities be able to self-serve
or to interchange provision of services. In this case the BA per se has no assets and cannot selfserve, moreover the primary response service providers have no obligations to provide the service,
thus the BA potentially could face a situation where there is no physical service to be purchased but
there is a federally mandated standard to comply with. The idea of creating a Primary Response
Market as some have proposed does not work without an obligation on some entity to physically
provide that service. One final note, the SRC points out that the ACE is an error signal used to drive
secondary response; it is not a signal to drive primary response. Thus the use of the Frequency Bias
setting is not for control, it is for “adjusting” the error measure that is analyzed after the fact. This
standard needs: • a requirement on the ERO to compute the Obligation on each Interconnection • a
requirement on the ERO to conduct Frequency Response surveys (note the SRC does not support this
requirement but believes that it is needed to meet the FERC directive) • a requirement on energy
supply assets (both generation and load) to provide primary response (as a function of the
Interconnection obligation in the first bullet) The above will allow NERC to comply with the FERC
directives in a fashion consistent with the processes and procedures approved by FERC. Specific
recommendations: The SRC proposes that R1 be deleted based on the facts that: • It imposes an
obligation on an entity that has no capability to comply • There is an internal conflict with imposing
penalties on a deterministic basis (compliance with a fixed set of events) for a statistical service
(primary response is a function of the assets operating state and not a fixed service of the asset). In
any case, all of the words after FRO should be deleted. The words are not needed for the requirement
and if left in can become a source of contention between auditors and registered entities. R3 – delete
the added phrase “mode to effectively coordinate control”. The phrase “would have an Adverse
Impact on the BA’s area” needs further discussion. Who makes the decision that operating on AGC
will have adverse impact must be defined. R5 – delete the phrase “In order to ensure control
response”. Such phrases can be needless causes of debate. If a BA uses one of the bulleted methods
but does not get “adequate response” then is the BA non-compliant? What is “adequate response”?
Who decides if the response is adequate?
Yes
No
M1: The measure should not be tied to a specific Form. If a BA has the evidence but does not provide
it on a given Form, how is the reliability of the Power System impacted? The Form may be the format
of choice but it should not be an implied requirement. M4: This measure does not read quite right.
Something seems to be missing in the part that says: “…showing when Overlap Regulation Service is
provided including Frequency Bias Setting calculation to demonstrate compliance with Requirement
R4.” This part might have read something like: “…showing that when it performed Overlap Regulation
Service, it modified its Frequency Bias Setting in its ACE calculation or it calculated the Frequency
Bias Setting meeting the conditions specified in Requirement R4.”
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should have been
“…Reserve Sharing Group’s…”. Alternatively, the wording after “interconnection’s FRO” could be
revised to: “…and the Balancing Authority’s or the Reserve Sharing Group’s FRM was…”
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002849
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two separate documents
(Attachments A and B), the modified Attachment A is problematic. As many commenters indicated,
the previous Attachment A, other than the section providing guidance on event selection, appears to
be explanatory, contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment A should include
only the event selection process and calculations associated with the requirements, including an
explanation of what is necessary if variable Frequency Bias Settings are implemented. If other
"requirements" need to be specified, such as the reporting time frame stipulated on P. 3 of
Attachment A, they should be moved to the standard itself but not imbedded in an attachment. We
suggest that the SDT first determine if the materials in the revised Attachment A (and Attachment B)
are “Guideline” or Technical Background”, or are they “requirements”. If it is the former, then
Requirement R1 should not mention Attachment A at all. If it is the latter, then the as-written
Attachment A is a mix bag as it on the one hand describes the ERO’s process for supporting the
Frequency Response Standard (FRS), in other words, the method and criteria it uses to calculate the
frequency bias settings and the FRM, and on the other hand the BA’s obligations to support this
process. We strongly disagree that the latter requirements be imbedded in an attachment, especially
one that is supposed to provide the technical background and guideline for another entity which is not
held responsible for complying with the proposed method. Further, there are no measures provided
for the requirements stipulated/imbedded in Attachment A so how can the Responsible Entity (BA, in
this case) be assessed for compliance? We suggest the SDT move those requirements on the BA to
the main standard, and turn Attachment A into an appendix describing the calculation process. An
appendix is not regarded as a mandatory requirement. Similar comments apply to Attachment B.
Moreover, if the Attachments are to be integral to the standards, the terminology “may” must be
replaced with “shall”. Finally, the two Attachments are listed in Section F – Associated Documents.
This Section is generally used to list reference documents that are NOT standard requirements. We
suggest the SDT review and revise this listing depending on its final determination of the status of the
two Attachments (or their revisions, where appropriate).
We do not have an opinion on whether or not the Background Document provides sufficient clarity to
the development of the standard. We do, however, suggest that the SDT consider our comments in
Q6, above, and move some of the information from Attachments A and B to or combine with the
Background Document, to the Background Document to provide all the technical basis and
background behind the elements stipulated in the requirements.
No
Please see our comments under Q6. In brief, we do not agree with including a process description
type of document as part of the standard requirement. Process description should be regarded
guideline document and not a part of the standard requirement.
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet file. Apart from
that, however, there are other sheets added to the previous Form 1. But this Comment form makes
no mention of the changes, nor is there a question in the Comment Form asking whether the
additional information should be requested. We believe this is a significant change to the standard
and many commenters may have missed the opportunity to comment on it. Compared to the previous
version, Form 1 has been significantly expanded to include not only additional sheets but much more
comprehensive data requirements even on the Data Entry sheet itself. This makes data submission a
very time-consuming task but the justification for requiring detailed data entry has not been provided.
We question the need for such expansion on data entry requirements. We have yet to see the reason
for expanding Form 1 in assisting a BA to provide the data needed to comply with the standard, hence
we do not see how adding a Form 2 can help in that regard. We suggest the SDT to keep data
requirements to only what is minimally needed to support the FRS reporting process. Where the SDT
deems additional data entry sheets to be necessary, it should provide the rationale for expanding
from a 2 sheet form into a multiple sheet form for additional data collection. Where the SDT deems
the additional data sheet or information not necessary to support FRS reporting, then we suggest the
SDT to hide those pages not required for the standard so as to avoid confusion, and/or to remove
those analytical pages not directly used in the standard.
Finally, we ask the SDT to clarify what the primary purpose of this standard is. If it is to respond to
Order 693 then the standard misses the point of defining how often to run Frequency Response
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002850
Surveys; it does not crisply define the “Interconnection” obligations. If the SDT wants to focus on
AGC (which it seems to try to do) then the focus should be on the equations and variables and not on
the response performance. If the SDT does want to focus on performance then the issue of who is the
default provider must be addressed. As the SRC has noted previously, BAs do not own any generating
facilities or service providers. To create standards that apply to entities that are completely dependent
on other functional entities (facility owners or service providers) to comply with a requirement is
simply improper. The Industry structure has changed but these requirements have not and still
assume old industry relationships between BAs and GOs. This issue of who needs to be held
responsible for performing the required reliability tasks and services/products must be explicitly cited
in the standards and posted for the industry to debate and decide.
ACES Power Marketing Standards Collaborators
Jason L. Marshall
Yes
No
Requirement 1 should not apply to a Reserve Sharing Group. Reserve Sharing Groups (RSG) are
designed to share Contingency Reserves and/or Operating Reserves not Frequency Response. While
these reserves may be frequency responsive, they are not being shared for the purpose of expanding
frequency response. Furthermore, while reserve sharing groups may calculate a joint ACE by
summing its individual BA ACE values, RSGs do not have a Frequency Bias Setting which is necessary
to assess a Frequency Response Obligation.
Yes
Yes
No
The VSLs on for Requirement R1 set a previously un-established precedent of relying on the
performance of other registered entities to establish the severity level of the violation. This is not
appropriate. The VSLs should be rewritten to provide further gradations of the violation severity based
on the BA’s own performance.
No
Under item 3 of the Event Selection Criteria section, the delta F and Point C should be described
either in this attachment or the “Frequency Response Standard Background Document”. While many
in industry may understand what these terms mean, history has a way of getting lost with personnel
turnover. Furthermore, this would help ensure that the auditors and industry have a duplicate
understanding. In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency Protection
Criteria should be provided and which N-2 event was selected so that industry can help validate if the
correct MW value was selected. Furthermore, the document should clarify if the Contingency
Protection Criteria contains the “safety margin”. There is a statement in the paragraph before the
table that states it does but then the table lists out a separate 25% “Safety Margin”. Thus, it is not
clear if the “Safety Margin” is included in the Contingency Protection Criteria value listed in the table
or not. “Safety margin” should be changed to “reliability margin”. Safety has a specific meaning in the
electric industry and its use here is not appropriate. The Base Obligation should be explained. The
explanation should include its purpose and origin.
No
We can find no document titled “BAL-003-1 Background Document”. We assume this question is
referring to the “Frequency Response Standard Background Document” dated October 2011. We do
not believe the document provides sufficient clarity. No explanation is provided for why RSG was
added to Requirement R1. There are typos contained in the document. On page 6 in NIA, the A should
be in subscript. On page 7 in bullet 4 in the first sentence, “The” should be in lowercase.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002851
The Data Retention section requires the BA to retain data or evidence for up to four years. No data
that exceeds the audit cycle should be required to be retained. The audit cycle is three years.
Robert Blohm
Keen Resources Asia Ltd.
No
In the Standard, the definition of Frequency Response Measure (FRM) is statistically wrong. The
median is an improper statistical measure of Frequency Response because --it truncates large
excursions which are the specific subject of Frequency Response control, not normal operating
frequency errors which are self-correcting and are the subject of CPM control; --it is non-linear; and
therefore --it is non-summable over the interconnection; in other words, the individual BA medians
don't add up to the interconnection median, in complete incompatibility with CPM control which
requires summability of BA performances into the interconnection's performance. Moreover, it is
mathematically impossible to sum the medians of the BAs in a Reserve Sharing Group (RSG) into the
RSG's median: in other words, the RSG's median cannot represent the sum of the medians of its
members. The last paragraph on page 5 of the Background Document is patently wrong, invented,
and supported in no probability & statistics literature whatsoever. As a practicing statistician, I hereby
give testimony to the utter falsehood of the statement that "In general, statisticians use the median
as the best measure of central tendency when a population has outliers." (See
http://www.robertblohm.com/BestStatistic.doc for an explanation of "best statistic" which is a highly
technical and central topic in modern probability theory and statistics.) Also, "outliers" are falsely and
rhetorically claimed to be "noise" when in fact they are the "events" that are the specific subject of
Frequency Response. It is well known that they do not "fit" a normal distribution. They are distinct
from the normal operating errors that are the subject of CPM control. The paragraph does correctly
conclude that the linear regression more accurately incorporates outliers than the median does,
although the paragraph uses rhetoric by calling this improvement "skew" as if it is distortionary when,
in fact, the median distorts the reality.
Yes
Yes
Yes
Yes
No
The sample pre-selection described in Attachment A, Event Selection, Criteria 2 & 7, violates the
fundamental statistical procedure of unbiased sampling. A population is governed by a single
"process" which, when stationary, is represented by a fixed probability distribution. In this case the
population is several years of events (which are the subject of Frequency Response), not of normal
operating control errors which are the subject of CPM control. A sample is governed by a single
process that approximates the process governing the population as the sample gets larger, in this
case if it includes several years of data. Samples are measured "as they come", no triage/filtering
allowed, and they are called "stratified" when their distribution approximates the population
distribution. Unlike normal operating errors, samples of events are not evenly distributed over a year.
The attempt in criteria 2 & 7 to pre-select only certain events, and not others, in such a way that the
selected events occur evenly throughout the year, is papently wrong because it is trying to "fit"
events into a process (even distribution over time) that does not govern events, but that instead
governs normal operating errors that are the subject of CPM control, not of this Frequency Response
standard. In other words, criteria 2 & 7 confuse Frequency Response with CPM, and events with
normal operating errors. The result is a false, biased sample which destroys the integrity of this
standard. Paragraph 4 on page 5 of the Background Document, on the other hand, provides a
statistically correct description of event selection without sample pre-selection and should followed
instead of the erroneous criteria 2 & 7 in Attachment A.
Yes
Paragraph 4 on page 5 of the Background Document provides a statistically correct description of
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002852
event selection without sample pre-selection and should followed instead of the erroneous criteria 2 &
7 in Attachment A. The risk-based approach to determining FRM, that the Background Document
mentions in paragraph 4 of page 4 is being evaluated by the drafting team for application in this
standard, should be considered for deployment as soon as possible to replace the administered
method currently proposed in this standard, because the administered method lacks any technical
justification. No such justification was ever attempted in the development of this standard. The
administrative method of determining FRM is therefore but a highly dubious "quick fix" until the riskbased method is evaluated and implemented. The administrative method is in fact perverse because it
discourages BAs from reducing their contribution to frequency error by refusing to reduce the BA's
FRO accordingly, and because it encourages BAs to contribute to frequency error without increasing
their FRO.
Yes
Yes
As a qualified professional statistician I attest that this standard commits two violations of
fundamental statistical best practices: use of a median, and biased sample-preselection, as detailed in
my answers to questions 1 and 6.
Sacramento Municipal Utility District (SMUD)
Joe Tarantino
No
As drafted, requirement R1 requires Balancing Authorities or Reserve Sharing Groups (RSGs) to
achieve an annual Frequency Response Measure (FRM) that is equal to or more negative than its
Frequency Response Obligation (FRO). As RSGs exist today, FRM performance by an RSG is not
contemplated in the definition of FRM and appears to apply more towards 'secondary response'.
Recommend clarifying this concept and possibly including an example in the background document to
help explain how this would work. As drafted, in requirement R3, each Balancing Authority not
receiving Overlap Regulation Service to operate its AGC in Tie Line Bias mode… unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area. There may be occasions
in which an entity needs to perform testing or other instances where it is necessary or desirable to
operate in a mode other than Tie Line Bias that does not qualify as an Adverse Reliability Impact, but
never the less is necessary or desired. Recommend including language that would permit operation
other than Tie Line Bias mode provided the Reliability Coordinator was notified. We seek clarification
from the drafting team as to whether or not there will be any conflicts between proposed Requirement
R3 and the requirements of FERC-approved regional reliability standard BAL-004-WECC-1 – Automatic
Time Error Correction.
No
The standard is unclear as to if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard. Except for Table 2 in Attachment A, there is no
discussion of an amount of Frequency Response expected on a total basis. Balancing Authorities need
to know for how many tenths of a hertz they are to respond so they can determine how to plan to
meet this requirement. The documents do not appear to provide any boundary on the maximum
amount of Frequency Response that a BA will provide, i.e. it is not clear what will happen if an event
occurs in the Eastern Interconnection that causes the frequency to drop to less than 59.6 Hz or in the
Western Interconnection that causes the frequency to drop to less than 59.5 Hz, or if that event is
excluded from the list used to calculate the Balancing Authorities’ response or is it included with an
expectation that it counts the same as any other event. Without a clear statement of what is
expected, including whether there is a limit on that expectation or not, it is unclear what is expected
of the Balancing Authorities.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002853
No
In addition to the requirements, reducing frequency bias obligation results in generation tripping
closer to the set point. It seems that Lowering the Minimum Frequency Bias Setting from 1% to .8%
will result in a lower response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
As a final comment we believe there needs to have consideration for a coordinated response rather
than a setting threshold. Coordinated response thresholds values will provide for a desired and
anticipated frequency response.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002854
Consideration of Comments
Project 2007-12 Frequency Response
The Frequency Response Drafting Team thanks all commenters who submitted comments on the first
formal posting for Project 2007-12 Frequency Response. This standard was posted for a 45-day public
comment period from October 25, 2011 through December 9, 2011. Stakeholders were asked to
provide feedback on the standard and associated documents through a special electronic comment
form. There were 43 sets of comments, including comments from approximately 133 different people
from approximately 86 companies representing all 10 of the Industry Segments as shown in the table
on the following pages.
Based on the comments received and the drafting team’s discussion of those comments, the drafting
team made the following changes to the proposed Standard, definitions, and associated documents:
Modified the definition for Frequency Response Measure (FRM)
Modified the definition of Frequency Bias Setting
Removed the references to Reserve Sharing Groups (RSGs) and replaced them with Frequency
Response Sharing Group
Created a definition for Frequency Response Sharing Group (FRSG)
Modified Requirement R2 to provide clarity and incorporate Requirement R5
Created a new Requirement R3 for entities using variable Frequency Bias
Removed the requirement for operating in Tie Line Bias mode as duplicative of other
requirements in other standards
Removed Requirement R5 and combined it into revised Requirement R2 and new Requirement
R3
Modified Attachment A to provide additional clarity
Created a Procedure to provide instructions for the ERO to follow in supporting the standard
Made conforming changes to Measures, Evidence Retention, and VSLs to align with language in
the revised requirements
Re-wrote the Background Document to incorporate additional language for justification of
requirements and provide additional clarity
The SDT is now using the method detailed in the Frequency Response Initiative Report dated
September 30, 2012 to calculate the Interconnection Frequency Response Obligation.
There were some minority issues that the team was unable to resolve, including the following:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002855
A few stakeholders questioned a Requirement for the BA to provide Frequency Response when
they typically do not own generation. The SDT explained that the NERC Functional Model and
FERC cited the BA as the responsible party for providing Frequency Response and that this was
outside the scope of the industry approved SAR. The SDT also stated that there were several
different methods available to the BA to provide Frequency Response and that the SDT had
included these in the Background Document. The SDT further stated that any entity could
submit a SAR addressing this issue to the SC for consideration and that the SDT supported this
option.
A couple of the commenters felt that the median was not the proper method to use for the
calculation of the FRM and that the RSG was not fully explained. The SDT stated that the
statisticians note that the median is a more accurate measure of central tendency than the
mean when analyzing a sample that is small and or where scores vary widely. This is the case
when estimating a BA’s Frequency Response. The SDT also noted that while the median was
not perfect, the median approaches a BA’s typical performance after 15-20 observations and
that more observations give a higher confidence in the estimate of the BA’s performance.
Some commenters disagreed with proceeding through development of the standard before the
proposed measures have been thoroughly field tested. The SDT stated that it was responding to
FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months.
FERC later granted an extension to provide a standard addressing these issues by the end of
May 2012.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Frequency_Response.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments: Project 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
002856
Index to Questions, Comments, and Responses
1.
The SDT has made minor modifications to the proposed definitions to provide additional clarity.
Do you agree that these modifications provide sufficient clarity? If not, please explain in the
comment area. .................................................................................................................................. 10
2.
The SDT has made minor modifications to the Requirements R1 through R4 to provide additional
clarity. Do you agree that these modifications provide sufficient clarity to comply with the
standard? If not, please explain in the comment area. .................................................................... 28
3.
The SDT has developed VRFs for the proposed Requirements within this standard. Do you agree
that these VRFs are appropriately set? If not, please explain in the comment area. ...................... 82
4.
The SDT has developed Measures for the proposed Requirements within this standard. Do you
agree with the proposed Measures in this standard? If not, please explain in the comment area. 86
5.
The SDT has developed VSLs for the proposed Requirements within this standard. Do you agree
with these VSLs? If not, please explain in the comment area. ......................................................... 93
6.
The SDT divided the previously posted “Attachment A – Background Document” into two
documents to provide additional clarity. The first document “Attachment A- Supporting
Document” which details the methods used to develop the events to be analyzed, the FRO, FRM
and Frequency Bias Setting. Do you agree that the revised Attachment A – Supporting Document
provides sufficient clarity on the methodologies to be used? If not, please explain in the comment
area. ................................................................................................................................................. 113
8.
The SDT has developed a new document titled Attachment B – Process for Adjusting Bias Setting
Floor. This document is intended to provide the methodology the ERO will use to reduce the
minimum Frequency Bias Setting to become closer to natural Frequency Response. Do you agree
that this document provides clear and concise instructions for the ERO to follow? If not, please
explain in the comment area. ......................................................................................................... 161
9.
The SDT has provided an additional spreadsheet, FRS Form 2, to assist the Balancing Authority in
providing the data needed to comply with the proposed standard. Do you agree that this
spreadsheet is useful and the instructions are meaningful? If not, please explain in the comment
area. ................................................................................................................................................. 174
10.
Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1................................................. 184
Consideration of Comments: Project 2007-12 Frequency Response
3
002857
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Chris Higgins
Bonneville Power Administration
2
3
X
X
X
X
4
5
6
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. James Murphey
BPA
WECC 1
2. Bart McManus
BPA
WECC 1
3. David Kirsch
BPA
WECC 1
2.
Group
Jesus Sammy Alcaraz
Imperial Irrigation District
Additional Member Additional Organization Region Segment Selection
1. Tino Zaragoza
IID
WECC 1
2. Jesus Sammy Alcaraz IID
WECC 3
3. Diana Torres
IID
WECC 4
4. Marcela Caballero
IID
WECC 5
X
7
8
9
10
002858
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Cathy Bretz
IID
3.
Guy Zito
Group
Additional Member
4
5
6
7
Northeast Power Coordinating Council
Additional Organization
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Chantel Haswell
FPL Group, Inc.
NPCC 5
Nydro One Networks Inc.
NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
Neqw Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
Will Smith
OPPD
2.
CHUCK LAWRENCE ATC
10
X
MRO NSRF
X
Additional Member Additional Organization Region Segment Selection
MAHMOOD SAFI
9
NPCC 10
10. David Kiguel
1.
8
Region Segment Selection
2.
Group
3
WECC 6
1.
4.
2
MRO
1, 3, 5, 6
MRO
1
Consideration of Comments: Project 2007-12 Frequency Response
5
002859
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
NSP (XCEL)
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
1, 3, 5, 6
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 4, 5
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. RICHARD BURT
MPC
MRO
1, 3, 5, 6
5.
Gerald Beckerle
Group
SERC OC Standards Review Group
2
X
3
4
5
6
7
X
Additional Member Additional Organization Region Segment Selection
1.
Andy Burch
EEI
SERC
5
2.
Bob Dalrymple
TVA
SERC
1, 3, 5, 6
3.
Brad Gordon
PJM
SERC
2
4.
Vicky Budreau
SCPSA
SERC
1, 3, 5, 6
5.
Sam Holeman
Duke
SERC
6, 1, 3, 5
6.
Cindy Martin
Southern Co
SERC
1, 5
7.
Scott Brame
NCEMC
SERC
1, 3, 4, 5
8.
Wayne Van Liere
LGE-KU
SERC
3
9.
Larry Akens
TVA
SERC
1, 3, 5, 6
10. John Troha
SERC Reliability Corp.
SERC
10
6.
Robert Rhodes
Group
Additional Member
Additional Organization
SPP Standards Review Group
X
Region Segment Selection
1. John Allen
City Utilities of Springfield
SPP
2. David Dockery
Assocoated Electric Cooperative SERC
1, 3, 5
1, 3, 5
Consideration of Comments: Project 2007-12 Frequency Response
6
8
9
10
002860
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Lisa Duffey
Cleco Power
SPP
1, 3, 5
4. Jonathan Hayes
SPP
SPP
2
5. Steve Haun
Lincoln Electric System
MRO
1, 3, 5
6. Tony McMurtry
Lafayette Utilities System
SPP
NA
7. Dave Milliam
Kansas City Power & Light
SPP
1, 3, 5, 6
8. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
9. Katie Shea
Westar Energy
SPP
1, 3, 5, 6
7.
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
8.
Florida Municipal Power Agency
Group
Frank Gaffney
2
3
4
5
6
7
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
9.
Group
FRCC
Thomas McElhinney
JEA Electric Compliance
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. John Babik
JEA Electric Compliance FRCC
5
2. Ted Hobson
JEA Electric Compliance FRCC
1
3. Garry Baker
JEA System Operations
FRCC
10.
Group
3
ISO/RTO Council Standards Review
Committee
Al DiCaprio
X
Additional Member Additional Organization Region Segment Selection
1. Charles Yeung
SPP
2
2. Kathleen Goodman ISO-NE
SPP
NPCC
2
3. Gary DeShazo
CAISO
WECC 2
4. Greg Campoli
NYISO
NPCC
5. Steve Myers
ERCOT
ERCOT 2
2
Consideration of Comments: Project 2007-12 Frequency Response
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
8
7
002861
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6. Don Weaver
NBSO
NPCC
7. Mark Thompson
AESO
WECC 2
8. Ben Li
IESO
NPCC
11.
Group
Region
RFC
2. James Jones
WECC 1, 5, 6
3. Erin Woods
East Kentucky Power Cooperative
SERC
Joe Tarantino
Sacramento Municipal Utility District
(SMUD)
Additional Organization
X
X
X
X
X
Balancing Authority of Northern California (BANC) WECC 1
Southwest Power Pool Regional Entity
14.
Individual
Cindy Oder
Salt River Project
X
X
X
X
15.
Individual
Progress Energy
X
X
X
X
X
X
X
X
Individual
Jim Eckelkamp
Janet Smith, Regulatory
Affairs Supervisor
17.
Individual
Antonio Grayson
Southern Company
X
X
X
X
18.
Individual
Howard F. Illian
Energy Mark, Inc.
19.
Individual
Don McInnis
Florida Power & Light Company
X
X
X
20.
Individual
Carlos J. Macias
X
X
X
X
X
X
X
X
X
Arizona Public Service Company
X
Individual
Mauricio Guardado
FPL
Los Angeles Department of Water and
Power
Individual
Thomas Washburn
FMPP
Individual
24. Individual
Alice Ireland
Kathleen Goodman
Xcel Energy
ISO New England Inc
X
25.
John Tolo
Tucson Electric Power
X
21.
Individual
10
Region Segment Selection
Emily Pennel
23.
9
1, 3, 5, 6
Individual
22.
8
3, 5, 6
13.
16.
7
Segment
Selection
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative
12.
6
X
Old Dominion Electric Cooperative
1. Kevin Smith
5
2
1. Mark Ringhausen
Group
4
2
Additional Organization
Additional Member
3
ACES Power Marketing Standards
Collaborators
Jason L. Marshall
Additional
Member
2
Consideration of Comments: Project 2007-12 Frequency Response
X
X
X
X
X
8
002862
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
26.
Individual
Dennis Sismaet
Seattle City Light
27.
Individual
Michael Falvo
Independent Electricity System Operator
28.
Individual
John Bussman
Associated Electric Cooperative Inc
X
29.
Individual
Rich Salgo
NV Energy
30.
Individual
Thad Ness
31.
Individual
32.
2
X
4
X
5
6
X
X
X
X
X
American Electric Power
X
X
X
X
X
X
X
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
Individual
Louis C. Guidry
Cleco Corporation
X
X
X
X
33.
Individual
H. Steven Myers
ERCOT
34.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
35.
Individual
Curtis Crews
Texas Reliability Entity
36.
Individual
Mark B Thompson
Alberta Electric System Operator
37.
Individual
Anthony Jablonski
ReliabilityFirst
38.
Individual
Brenda Powell
Constellation Energy Commodities Group
39.
Individual
Kirit Shah
Ameren
X
X
X
X
40.
Individual
Michael Brytowski
Great River Energy
X
X
X
X
41.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
X
42.
Individual
Greg Rowland
Duke Energy
X
X
X
X
43.
Individual
Robert Blohm
Keen Resources Asia Ltd.
Consideration of Comments: Project 2007-12 Frequency Response
X
3
7
8
9
10
X
X
X
X
X
X
X
X
9
002863
1.
The SDT has made minor modifications to the proposed definitions to provide additional clarity. Do you agree that these
modifications provide sufficient clarity? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters felt that the SDT should use the term “prevent” instead of “discourage” in
the definition of FRM. The SDT explained that it did not want to use the word “prevent” since the SDT believes that the word would
imply that you could stop withdrawal. The SDT does not believe that you can totally stop the withdrawal but you can discourage it.
Many of the commenters did not agree with requiring the BA to provide Frequency Response. The NERC Functional Model and FERC
cite the BA as the responsible party for providing Frequency Response. There are several different methods available to the BA to
provide Frequency Response and these are included in the Background Document.
A couple of the commenters felt that the median was not the proper method to use for the calculation of the FRM and that the RSG
was not fully explained. Statisticians note that the median is a more accurate measure of central tendency than the mean when
analyzing a sample that is small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response. While
the median is not perfect, the median approaches a BA’s typical performance after 15-20 observations and more observations give a
higher confidence in the estimate of the BA’s performance.
Some commenters had concerns about the use of the RSG as a means to provide Frequency Response, and in response the SDT
modified the Background Document to further explain how an RSG (now FRSG) could be used to supply Frequency Response. The
SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term
“Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Organization
Yes or No
Question 1 Comment
Seattle City Light
Negative
Answer: No. Comments: LADWP and SCL recommend the following change
to the definition of Frequency Bias Setting. LADWP believes that this change
increases the clarity of the definition:
Original A number, either fixed or variable, usually expressed in MW/0.1 Hz,
included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s Frequency Response contribution to the
Consideration of Comments: Project 2007-12 Frequency Response
10
002864
Organization
Yes or No
Question 1 Comment
Interconnection, and discourage response withdrawal through secondary
control systems.
Proposed Change A number, either fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution
to the Interconnection, and prevent response withdrawal through
secondary control systems
Response: The SDT disagrees with your definition. The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does not
believe that you can totally stop the withdrawal but you can discourage withdrawal.
Alliant Energy Corp. Services, Inc.
Negative
The definition of Frequency Bias Setting should focus on what it is. balancing
Authorities do not supply energy. seggest rivising it to "A number, either
fixed or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority's Area Control Error equation to approximate the expected
natural response provided by the assets within the respective Balancing
Authority's area."
Response: The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model
Technical Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA
controls the amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar
to the relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the
TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
Consideration of Comments: Project 2007-12 Frequency Response
11
002865
Organization
Yes or No
Question 1 Comment
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
chosen to use.
Potomac Electric Power Co.
Negative
The proposed new Definitions do not stand alone and are also linked to
Attachments.
Response: The SDT has modified the definitions to no longer reference any other documents.
ISO/RTO Council Standards Review
Committee
No
(1) In our previous comments, we suggested to drop the definitions for the
terms FRM and FRO in favor of providing the needed wording in the
standard itself to take care of the specific details. The SDT did not adopt
our suggestion with the reason that these definitions will be used by
other standards in the future. That’s fair enough. However, the FRM
definition: “The median of all the Frequency Response observations
reported annually on FRS Form 1” is problematic.
It references an FRS Form 1 which is not included in the definition itself
but is in fact an Attachment to a standard. In the current NERC Glossary
of Terms, there is no such precedence that a definition must rely on the
requirements or details in a standard for completeness. Also, it is very
cumbersome that when changes are made to FRS Form 1, the definition
must be posted for industry comment and balloting, and vice versa.
When other standards begin using the term, there will be cross
references between standards. This further complicates the
update/approval process without any appreciable value.Once again, we
strongly urge the SDT to consider dropping these definitions, and have
the details fully specified in the standard body itself. This will eliminate
that cross reference issue. After all, the definition for FRM is a simple
Consideration of Comments: Project 2007-12 Frequency Response
12
002866
Organization
Yes or No
Question 1 Comment
sentence and does not provide any clarity or specific details that cannot
be presented by using appropriate wording in a requirement.
(2) The definition of Frequency Bias Setting, if retained, should focus on
what it is. Balancing Authorities do not supply energy. We suggest to
revise it to: Frequency Bias Setting A number, either fixed or variable,
usually expressed in MW/0.1 Hz, included in a Balancing Authority’s
(BA’s) Area Control Error (ACE) equation to approximate the expected
natural response provided by the assets within the respective Balancing
Authority’s area.
Response: The SDT believes that these terms will be used in later version of the BAL Standards. The term FRO is presently being
used in the development of a new standard (BAL-012-1 Planning Reserves). The SDT has modified the definitions to no longer
reference any other documents.
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
Consideration of Comments: Project 2007-12 Frequency Response
13
002867
Organization
Yes or No
Question 1 Comment
No
Duke Energy would suggest removing “usually” from the Frequency Bias
Setting definition, as the value in the ACE equation must be in terms of
MW/0.1Hz in order for ACE to be correctly calculated. We apologize for
missing this point in the last round of comments. Though some would argue
that the last phrase of the definition is more of an explanation of a function
rather than a definition, we support keeping the phrase inserted, as it
should be recognized that the intent is to account for the frequency
response contribution AND keep the FBS slightly larger (in magnitude) than
the average estimated response, to better discourage withdrawal, which
was also recognized by Nathan Cohn.
chosen to use.
Duke Energy
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: It is the understanding of the SDT that EMS systems could use different methods implementing the ACE calculation.
The SDT therefore believes that the term “usually” is more appropriate.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median of
all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO.
This will be calculated as MW/0.1Hz.”
Independent Electricity System
Operator
No
In our previous comments, we suggested to drop the definitions for the
terms FRM and FRO in favor of providing the needed wording in the
standard itself to take care of the specific details. The SDT did not adopt our
suggestion with the reason that these definitions will be used by other
standards in the future. That’s fair enough. However, the FRM definition:
“The median of all the Frequency Response observations reported annually
on FRS Form 1” is problematic. It references an FRS Form 1 which is not
included in the definition itself but is in fact an attachment to a standard. In
the current NERC Glossary of Terms, there is no such precedence that a
Consideration of Comments: Project 2007-12 Frequency Response
14
002868
Organization
Yes or No
Question 1 Comment
definition must rely on the requirements or details in a standard for
completeness. Also, it is very cumbersome that when changes are made to
FRS Form 1, the definition must be posted for industry comment and
balloting, and vice versa. When other standards begin using the term, there
will be cross references between standards. This further complicates the
update/maintenance problem without any appreciable value.
Once again, we strongly urge the SDT to consider dropping these definitions,
and have the details fully specified in the standard body. This will eliminate
the cross reference issues. After all, the definition for FRM is a simple
sentence and does not provide any clarity or specific details that cannot be
addressed by providing the appropriate wording in a requirement.
With this cross-reference issue, combined with the issues associated with
Attachments A and B (see our comments under Q6, below), we are unable
to support this standard at this time.
Response: The SDT believes that these terms will be used in later version of the BAL Standards. The term FRO is presently being
used in the development of a new standard (BAL-012-1 Planning Reserves). The SDT has modified the definitions to no longer
reference any other documents.
Keen Resources Asia Ltd.
No
In the Standard, the definition of Frequency Response Measure (FRM) is
statistically wrong. The median is an improper statistical measure of
Frequency Response because--it truncates large excursions which are the
specific subject of Frequency Response control, not normal operating
frequency errors which are self-correcting and are the subject of CPM
control;--it is non-linear; and therefore--it is non-summable over the
interconnection; in other words, the individual BA medians don't add up to
the interconnection median, in complete incompatibility with CPM control
which requires summability of BA performances into the interconnection's
performance. Moreover, it is mathematically impossible to sum the
medians of the BAs in a Reserve Sharing Group (RSG) into the RSG's median:
Consideration of Comments: Project 2007-12 Frequency Response
15
002869
Organization
Yes or No
Question 1 Comment
in other words, the RSG's median cannot represent the sum of the medians
of its members.The last paragraph on page 5 of the Background Document
is patently wrong, invented, and supported in no probability & statistics
literature whatsoever. As a practicing statistician, I hereby give testimony to
the utter falsehood of the statement that "In general, statisticians use the
median as the best measure of central tendency when a population has
outliers." (See http://www.robertblohm.com/BestStatistic.doc for an
explanation of "best statistic" which is a highly technical and central topic in
modern probability theory and statistics.) Also, "outliers" are falsely and
rhetorically claimed to be "noise" when in fact they are the "events" that
are the specific subject of Frequency Response. It is well known that they
do not "fit" a normal distribution. They are distinct from the normal
operating errors that are the subject of CPM control. The paragraph does
correctly conclude that the linear regression more accurately incorporates
outliers than the median does, although the paragraph uses rhetoric by
calling this improvement "skew" as if it is distortionary when, in fact, the
median distorts the reality.
Response: The word “average” is a generic term to represent central tendency. The term is often used synonymously with the
arithmetic “mean”.
The issue with measuring frequency response is that a BA’s calculated performance (as opposed to actual performance) is highly
variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the East typically is only called to
contribute about 10-15 MW for the loss of a large unit. Its minute to minute load changes can easily wash this contribution out.
An arithmetic mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Consideration of Comments: Project 2007-12 Frequency Response
16
002870
Organization
Yes or No
Question 1 Comment
interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
confidence in the estimate of the BA’s performance.
Manitoba Hydro
No
It is not clear why the term “Single Event Frequency Response Data (SEFRD)”
has been removed from the standard but is still used and defined in the
Background Document and Attachment A.
Response: The SDT removed the term because it was not being used within the standard itself. It was only being used in the
calculation of the FRM. There is no need to create a NERC Glossary defined term if it is not being used in the standard.
Seattle City Light
No
LADWP and SCL recommend the following change (in red) to the definition
of Frequency Bias Setting. LADWP believes that this change increases the
clarity of the definition:OriginalA number, either fixed or variable, usually
expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control
Error equation to account for the Balancing Authority’s Frequency Response
contribution to the Interconnection, and discourage response withdrawal
through secondary control systems.Proposed ChangeA number, either fixed
or variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing
Authority’s Frequency Response contribution to the Interconnection, and
discourage prevent response withdrawal through secondary control systems
Response: The SDT disagrees with your definition The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does not
believe that you can totally stop the withdrawal but you can discourage withdrawal.
Los Angeles Department of Water
and Power
No
LADWP recommends the following change to the definition of Frequency
Bias Setting (replace the word "discourage" with the word "prevent").
LADWP believes that this change increases the clarity of the
definition:OriginalA number, either fixed or variable, usually expressed in
Consideration of Comments: Project 2007-12 Frequency Response
17
002871
Organization
Yes or No
Question 1 Comment
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation
to account for the Balancing Authority’s Frequency Response contribution
to the Interconnection, and discourage response withdrawal through
secondary control systems.Proposed ChangeA number, either fixed or
variable, usually expressed in MW/0.1 Hz, included in a Balancing
Authority’s Area Control Error equation to account for the Balancing
Authority’s Frequency Response contribution to the Interconnection, and
prevent response withdrawal through secondary control systems
Response: The SDT disagrees with your definition. The SDT considered using the term “prevent” but decided to use the term
“discourage” instead. The SDT believes that the word “prevent” would imply that you could stop withdrawal. The SDT does
not believe that you can totally stop the withdrawal but you can discourage withdrawal.
Progress Energy
No
PGN supports the collective comments of SERC members.We feel that the
last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. While the SERC OC
Standards Review Group understands the statement, we do not feel it
belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that it is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
ERCOT
No
RE: Frequency Response Obligation (FRO) definition: ERCOT suggests
changing “Balancing Authority’s” to “Balancing Authority Area’s” as follows:
Consideration of Comments: Project 2007-12 Frequency Response
18
002872
Organization
Yes or No
Question 1 Comment
The Balancing Authority Area’s share of the required Frequency Response
needed for the reliable operation of an Interconnection.
A BA that does not own generation resources cannot provide Frequency
Response, it can only schedule and dispatch available resources capable of
such; . The BA should be responsible for taking action to schedule resources
that are capable of frequency response, and monitoring to assure frequency
response performance. The GOP (possibly the LSE when demand side
performance is involved) must be accountable for performing.However,
there is nothing in this requirement to encourage the owner of a resource
who chooses not to provide frequency response to come to the table.
There is nothing in this standard that uniformly requires all frequency
response providers to perform. This is likely to be detrimental to the
performance of a BAA and unfairly sanctions those willing to perform to to
assure reliability while others are not required to perform.
Response: The SDT believes that the BA is the responsible entity not the BA Area.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own
generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
Consideration of Comments: Project 2007-12 Frequency Response
19
002873
Organization
Yes or No
Question 1 Comment
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Ameren
No
The Frequency Response Measure (FRM) definition should include which
Entity(ies) it applies to, similar to the definition of the FRO.
Response: The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read
“The median of all the Frequency Response observations reported annually by Balancing Authorities for frequency events
specified by the ERO. This will be calculated as MW/0.1Hz.”
Constellation Energy Commodities
Group
No
The Frequency Response Obligation has two components based on
Attachment 1 - an Interconnection FRO and a BA FRO. The proposed
definition captures only the BA FRO.
Response: The definition is referencing the responsible entity, the BA. The interconnection’s FRO is only calculated as the
beginning point for the determination of the BA’s FRO.
Hydro-Quebec TransEnergie
No
The FRM and FRO definitions should precise that it is expressed in
MW/0.1Hz.
As for the Frequency Bias Setting definition, as written, would apply only to
a multiple BA Interconnection. In a single BA Interconnection, the
Frequency Bias translates the frequency error into a MW value that must be
dispatched to bring back Frequency to desired value. Since Tie Lines are not
controlled through AGC, there is no response withdrawal issue
Response: The FRM and FRO definitions have been modified to state MW/0.1Hz.
The SDT disagrees. There can be withdrawal on any interconnection that uses a Frequency Bias estimate if that estimate is
lower than Frequency Response and other factors are used to determine dispatch, i.e., future load estimate.
Northeast Power Coordinating
Council/ISO New England Inc.
No
The FRM definition should not refer to FORM 1.
Also, suggest the following wording for frequency bias setting: “A number,
Consideration of Comments: Project 2007-12 Frequency Response
20
002874
Organization
Yes or No
Question 1 Comment
either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to approximate the
frequency response provided by the assets within the respective Balancing
Authority’s area.”
Response: The SDT has modified the definitions to no longer reference any other documents.
The definition now read “The median of all the Frequency Response observations reported annually by Balancing Authorities for
frequency events specified by the ERO. This will be calculated as MW/0.1Hz.”
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
chosen to use.
MRO NSRF
No
The FRM definition: “The median of all the Frequency Response
observations reported annually on FRS Form 1” is problematic. It references
an FRS Form 1 which is not included in the definition itself but is in fact an
Consideration of Comments: Project 2007-12 Frequency Response
21
002875
Organization
Yes or No
Question 1 Comment
attachment to a standard. In the current NERC Glossary of Terms, there is
no such precedence that a definition must rely on the requirements or
details in a standard for completeness.
Additionally, the definition of Frequency Bias Setting should focus on what it
is. Balancing Authorities do not supply energy. Suggest revising it
to:Frequency Bias Setting A number, either fixed or variable, usually
expressed in MW/0.1 Hz, included in a Balancing Authority’s Area Control
Error equation to approximate the expected natural response provided by
the assets within the respective Balancing Authority’s area.
Response: The SDT has modified the definitions to no longer reference any other documents.
The definition now read “The median of all the Frequency Response observations reported annually by Balancing Authorities for
frequency events specified by the ERO. This will be calculated as MW/0.1Hz.”
The SDT agrees that the Balancing Authority does not directly supply energy. However, the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT also believes that the definition you have suggested is basically saying the same thing as the definition the SDT has
Consideration of Comments: Project 2007-12 Frequency Response
22
002876
Organization
Yes or No
Question 1 Comment
chosen to use.
Alberta Electric System Operator
No
The FRO definition is specific to BAs. The Appendix 1, which is incorporated
in the standard, uses this definition in relation to requirements of the
Interconnection. The SDT should consider a revision of this definition that
accounts for the requirements of the Interconnection versus the BA
obligation to the Interconnection.
Response: The definition is referencing the responsible entity, the BA. The Interconnection’s FRO is only calculated as the
beginning point for the determination of the BA’s FRO.
South Carolina Electric and Gas
No
The last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. Therefore, we do not feel
it belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
SERC OC Standards Review Group
No
We feel that the last phrase of the definition of Frequency Bias Setting is
more of an explanation of a function rather than a definition. While the
SERC OC Standards Review Group understands the statement, we do not
feel it belongs in the definition of the Frequency Bias Setting and a period
should be inserted after the word “Interconnection”. Should the definition
for Frequency Response Measure (FRM) be specific to the BA, similar to the
Consideration of Comments: Project 2007-12 Frequency Response
23
002877
Organization
Yes or No
Question 1 Comment
definition for Frequency Response Obligation (FRO)?
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
Southern Company
No
We suggest adding BA to the definition of Frequency Response Measure
(FRM), similar to the definition for Frequency Response Obligation (FRO).
Response: The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read
“The median of all the Frequency Response observations reported annually by Balancing Authorities for frequency events
specified by the ERO. This will be calculated as MW/0.1Hz.”
Associated Electric Cooperative Inc
Yes
The FRO definition incorrectly applies the historically narrow Balancing
Authority scope of responsibility, while the FRM definition does not address
applicability at all. But the BAL-003-1 Standard itself identifies RSGs (where
applicable) and BAs as the Responsible Entities within scope of this
standard. For consistency, AECI recommends using “Responsible Entities
(e.g. Reserve Sharing Groups - where applicable, and Balancing Authorities)”
in both the FRO and FRM definitions. Rationale: This change should help
future-proof the definition, should more specific “frequency response” or
“spinning reserve” sharing groups later surface within our industry.
AECI agrees with the Frequency Bias Setting definition’s inclusion of a bit
more functionality than typical. We however recommend replacing “to
account for the Balancing Authority’s Frequency Response contribution to
the Interconnection, and discourage response withdrawal through
secondary control systems”, with “to support their Frequency Response
contribution to the Interconnection”. Rationale: Readability, and clarity on
Consideration of Comments: Project 2007-12 Frequency Response
24
002878
Organization
Yes or No
Question 1 Comment
the “discouraging withdrawal...” phrase, which should reside in the
Background document.
Response: The SDT believes that using the term “Responsible Entities” would cause confusion since different standards could
define a Responsible Entity differently. However, the SDT has defined a new term “Frequency Response Sharing Group”
because it believes that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition
reads “A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of its members.” The SDT has decided not to
add the term FRSG to the definition for Frequency Response Obligation (FRO). The SDT believes that the FRO is assigned to a BA
not the FRSG. The FRSG FRO is a summation of the BA FRO’s.
The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has decided to not
further modify the definition based on your comments.
SCE&G
Affirmative
The last phrase of the definition of Frequency Bias Setting is more of an
explanation of a function rather than a definition. Therefore, we do not feel
it belongs in the definition of the Frequency Bias Setting and a period should
be inserted after the word “Interconnection”.
Should the definition for Frequency Response Measure (FRM) be specific to
the BA, similar to the definition for Frequency Response Obligation (FRO)?
o The utilization of the term, “Reserve Sharing Group”, is not consistent
with the definition in the NERC Glossary of Terms, and should be deleted,
applicability should be clarified or replaced with a new term, such as
“Frequency Response Sharing
Response: The SDT thanks you for your suggestion but feels that the statement referenced provides further clarity and has
decided to not further modify the definition based on your comments.
The SDT has modified the definition for FRM to state that is the responsibility of the BA. The definition now read “The median
of all the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.”
Consideration of Comments: Project 2007-12 Frequency Response
25
002879
Organization
Yes or No
Question 1 Comment
The SDT agrees that using the phrase Reserve Sharing Group could cause confusion. The SDT has defined a new term
“Frequency Response Sharing Group”. The definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.” The SDT has decided not to add the term FRSG to the definition for Frequency Response Obligation
(FRO). The SDT believes that the FRO is assigned to a BA not the FRSG. The FRSG FRO is a summation of the BA FRO’s.
Bonneville Power Administration
Yes
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
Western Electricity Coordinating
Council
Yes
ACES Power Marketing Standards
Collaborators
Yes
Southwest Power Pool Regional
Entity
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
Florida Power & Light Company
Yes
FPL
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
26
002880
Organization
Yes or No
Xcel Energy
Yes
Tucson Electric Power
Yes
NV Energy
Yes
Cleco Corporation
Yes
Great River Energy
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 1 Comment
27
002881
2.
The SDT has made minor modifications to the Requirements R1 through R4 to provide additional clarity. Do you agree that
these modifications provide sufficient clarity to comply with the standard? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters felt that the use of an RSG as a method for supplying Frequency Response
was not fully explained. The SDT modified the Background Document to further explain how an RSG (now FRSG) could be used to
supply Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that
using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Many of the commenters were concerned with the language in Requirement R3 stating that an entity had to be operating in Tie Line
Bias mode unless there were adverse affects on the BES. The SDT removed this requirement from the proposed standard since it is
duplicative of Requirement R6 and R7 in BAL-005-0.1b.
Many of the commenters did not agree with assigning the BA to provide Frequency Response. The NERC Functional Model and FERC
cited the BA as the responsible party for providing Frequency Response. There are several different methods available to the BA to
provide Frequency Response included in the Background Document.
A few of the commenters did not agree with lowering the minimum Frequency Bias Setting. Early research by Nathan Cohn on
interconnected power system operations found that control is optimum if a BA’s Bias Setting is equal to its natural Frequency
Response. If there were to be a difference between the two values, it is preferable to be slightly over-biased. The drafting team has
proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is outlined in a Procedure
developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to making this happen and
includes checks to confirm there are not unexpected influences injected into the CPS-related calculations. Based on concerns raised
by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting 0.9% of peak and has
included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The evaluation will look at
both frequency performance and impact on CPS-related compliance calculations.
A couple of commenters were concerned that the BA could be responsible to supply an infinite amount of Frequency Response. They
felt that a BA could not prepare for this in its planning process. The proposed standard was not clear on this subject and the SDT has
added language in the “Event Selection Criteria” section of Attachment A to limit the amount of Frequency Response a BA would be
required to provide to be compliant with the standard.
Consideration of Comments: Project 2007-12 Frequency Response
28
002882
Organization
Yes or No
Question 2 Comment
Seattle City Light
Negative
The language in Requirement 4 needs to be clarified and recommends the following
change:
R4. Each Balancing Authority that is performing Overlap Regulation Service shall
modify its Frequency Bias Setting in its ACE calculation to be equivalent to either
(i)
(ii)
the sum of the Frequency Bias Settings of the participating Balancing
Authorities as validated by the ERO, or
(ii) the Frequency Bias Setting as calculated based on the entire area being
combined and thereby represent the Frequency Response for the combined
area being controlled. [Risk Factor: Medium][Time Horizon: Operations
Planning]
Response: The SDT has modified Requirement R4 to use bullets in support of your suggestion.
Public Utility District No. 1 of
Douglas County
Negative
1. Recommend clarifying the language in R1 to include background information as to
how RSGs fit into the FRM performance.
2. Recommend R3 language be modified to permit operation in other than tie-line
bias mode with the requirement to notify the RC.
3. We have concern about the affect R3 will have on the WECC time error correction
standard (BAL-004-WECC-1).
4. Clarification is needed between Attachment A and the Background Document for
projected peak and historical peak.
5. We have a concern about the affect of lowering the minimum frequency bias
obligation from 1% to .8% and its probable affect on reliability.
6. We have a concern about he upper limit to the amount of frequency response
expected from BAs.
Response: Comment 1 – The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used
to supply Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes
Consideration of Comments: Project 2007-12 Frequency Response
29
002883
Organization
Yes or No
Question 2 Comment
that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
Comment 2 & 3– The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was
based on industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Comment 4 – The SDT has corrected the error between Attachment A and the Background Document.
Comment 5 – Early research by Nathan Cohn2 on interconnected power system operations found that control is optimum if a BA’s
Bias Setting is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to
be slightly over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Comment 6 – The SDT understands your concern and agrees that this could cause problems with compliance. The SDT has
modified Attachment A to include language which puts an upper limit on the amount of Frequency Response required from an
entity.
Potomac Electric Power Co.
Negative
1)The proposed Requirements do not meet all the FERC directives.
2)The proposed Requirements fail to recognize the fact that not all BAs can provide
primary frequency response.
3)The proposed Requirements are not all in the standard. Some are in the
Attachments.
2
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
30
002884
Organization
Yes or No
Question 2 Comment
Response: Comment 1 – The SDT disagrees with you about their meeting all of the FERC directives. Unfortunately your comment
does not provide specific information as to what you believe is not being addressed. The SDT has included a section within the
Background Document which details how this standard is meeting the FERC directives.
Comment 2 – The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Comment 3 – Unfortunately your comment does not provide enough information as to what parts of the attachments you believe
should be in the requirements. However, the SDT has made significant modifications to both Attachment A and Attachment B
now a Procedure for the ERO to follow in support of the proposed standard. The SDT believes that the requirements should be
succinct and the methodologies to be used should be part of an attachment.
Seattle City Light
No
o LADWP and SCL have a concern with Requirement 3. The requirement should
provide allowance for legitimate circumstances when an entity cannot run on Tie
Line Bias mode and not have an Adverse Reliability Impact on the Balancing
Authority’s Area. An entity should not be penalized when these legitimate
circumstances occur. LADWP believes that the Frequency Response Standard
Background Document, on Page 8, lists examples of legitimate circumstances:Telemetry problems that lead the operator to believe ACE is significantly in error.-
Consideration of Comments: Project 2007-12 Frequency Response
31
002885
Organization
Yes or No
Question 2 Comment
The frequency input to AGC is not reflective of the BA’s true frequency (such as if the
control center were operating a local generator and disconnected from the
Interconnection).- During restoration (where one BA might be controlling frequency
while another to which it is connected is managing interchange between them).- For
training purposes.- Many AGC systems will automatically switch to an alternate
mode if the EMS determines Tie Line Bias control could lead to problems.
o LADWP and SCL believe that the language in Requirement 4 needs to be clarified
and recommends the following change (in red):R4. Each Balancing Authority that is
performing Overlap Regulation Service shall modify its Frequency Bias Setting in its
ACE calculation to be equivalent to either (i) the sum of the Frequency Bias Settings
of the participating Balancing Authorities as validated by the ERO, or (ii) calculate the
Frequency Bias Setting as calculated based on the entire area being combined and
thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium][Time Horizon: Operations Planning]
o LADWP and SCL believes the language in Requirement 5 needs to be modified to be
consistent with that of the second paragraph of Attachment B. SCL recommends the
addition of “natural frequency response” as a third bullet item to Requirement 5 (in
red). The revised requirement would read:
R5. In order to ensure adequate control response, each Balancing Authority
shall use a monthly average Frequency Bias Setting whose absolute value is at
least equal to one of the following: [Risk Factor: Medium ][Time Horizon:
Operations Planning]
o The minimum percentage of the Balancing Authority Area’s estimated
yearly Peak Demand within its metered boundary per 0.1 Hz change as
specified by the ERO in accordance with Attachment B.
o The minimum percentage of the Balancing Authority Area’s estimated
yearly peak generation for a generation-only Balancing Authority, per
0.1 Hz change as specified by the ERO in accordance with Attachment
Consideration of Comments: Project 2007-12 Frequency Response
32
002886
Organization
Yes or No
Question 2 Comment
B.
o The natural frequency response
Response: The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow an entity to
circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into Requirement
R2 and a new Requirement R3.
FMPP
No
o R1. Each Balancing Authority (BA) or Reserve Sharing Group (RSG) shall achieve an
annual Frequency Response Measure (FRM) (as detailed in Attachment A and
calculated on FRS Form 1) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each BA or RSG to maintain an adequate level of Frequency Response in the
Interconnection. [Risk Factor: Medium ][Time Horizon: Operations Assessment] The
BA does not have control over the frequency responsive generation. There needs to
be a requirement that the GOP shall set frequency response for the generators as
directed by the BA.
o R5. In order to ensure adequate control response, each Balancing Authority shall
use a monthly average Frequency Bias Setting whose absolute value is {greater than
or (<= add these words)} {at least (<= delete these words)} equal to one of the
following: [Risk Factor: Medium ][Time Horizon: Operations Planning] o The
minimum percentage of the Balancing Authority Area’s estimated yearly Peak
Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B. o The minimum percentage of the Balancing
Authority Area’s estimated yearly peak generation for a generation-only Balancing
Authority, per 0.1 Hz change as specified by the ERO in accordance with Attachment
B.
Consideration of Comments: Project 2007-12 Frequency Response
33
002887
Organization
Yes or No
Question 2 Comment
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
With regards to your comment concerning Requirement R5, you have not provided enough information for the SDT to respond.
However, the SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Western Electricity
Coordinating Council
No
Agree with the changes made to this latest version of BAL-003-1. However,
additional clarity could be added by addressing the following:
R1- It is not clear what is intended by "Reserve Sharing Group". As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and
appears to apply more towards 'secondary response'. Recommend clarifiying this
concept and possibly include an example in the background document to help
explain how this would work.
R3 - There may be occasions in which an entity has a legitimate reason or a need to
operate in a mode other than Tie Line Bias but that does not qualify as an Adverse
Reliability Impact. Recommend including language that would permit limited
operation in a mode other than Tie Line Bias mode provided the Reliability
Coordinator was notified. R3 - Has the drafting team considered whether or not the
Consideration of Comments: Project 2007-12 Frequency Response
34
002888
Organization
Yes or No
Question 2 Comment
language of Requirement R3 will have any conflict or coordination issue with the
FERC-approved regional reliability standards BAL-004-WECC-1 - Automatic Time Error
Correction?
R5 - Suggest changing the language “at least equal to” to “greater than or equal to”
for clarity.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
Seattle City Light
Negative
Answer: No Comments: o LADWP and SCL have a concern with Requirement 3. The
requirement should provide allowance for legitimate circumstances when an entity
cannot run on Tie Line Bias mode and not have an Adverse Reliability Impact on the
Balancing Authority’s Area. An entity should not be penalized when these legitimate
circumstances occur. LADWP believes that the Frequency Response Standard
Background Document, on Page 8, lists examples of legitimate circumstances: Telemetry problems that lead the operator to believe ACE is significantly in error. The frequency input to AGC is not reflective of the BA’s true frequency (such as if the
control center were operating a local generator and disconnected from the
Interconnection). - During restoration (where one BA might be controlling frequency
while another to which it is connected is managing interchange between them). - For
training purposes. - Many AGC systems will automatically switch to an alternate
mode if the EMS determines Tie Line Bias control could lead to problems.
Consideration of Comments: Project 2007-12 Frequency Response
35
002889
Organization
Yes or No
Question 2 Comment
o LADWP and SCL believe that the language in Requirement 4 needs to be clarified
and recommends the following change: R4. Each Balancing Authority that is
performing Overlap Regulation Service shall modify its Frequency Bias Setting in its
ACE calculation to be equivalent to either (i) the sum of the Frequency Bias Settings
of the participating Balancing Authorities as validated by the ERO, or (ii) the
Frequency Bias Setting as calculated based on the entire area being combined and
thereby represent the Frequency Response for the combined area being controlled.
[Risk Factor: Medium][Time Horizon: Operations Planning]
o LADWP and SCL believes the language in Requirement 5 needs to be modified to
be consistent with that of the second paragraph of Attachment B. SCL recommends
the addition of “natural frequency response” as a third bullet item to Requirement 5.
The revised requirement would read:
R5. In order to ensure adequate control response, each Balancing Authority shall use
a monthly average Frequency Bias Setting whose absolute value is at least equal to
one of the following: [Risk Factor: Medium ][Time Horizon: Operations Planning]
o The minimum percentage of the Balancing Authority Area’s estimated yearly Peak
Demand within its metered boundary per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
o The minimum percentage of the Balancing Authority Area’s estimated yearly peak
generation for a generation-only Balancing Authority, per 0.1 Hz change as specified
by the ERO in accordance with Attachment B.
o The natural frequency response
Response: The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow an entity to
circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into Requirement
Consideration of Comments: Project 2007-12 Frequency Response
36
002890
Organization
Yes or No
Question 2 Comment
R2 and a new Requirement R3.
Avista Corp.
Negative
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly including an example in the background
document to help explain how this would work.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Early research by Nathan Cohn3 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
3
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
37
002891
Organization
Yes or No
Question 2 Comment
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
City of Redding, Oregon Public
Utility Commission,
BrightSource Energy, Inc.,
Clark Public Utilities, Avista,
Tri-State G & T Association,
Inc.; Deseret Power
Negative
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifying this concept and possibly including an example in the background
document to help explain how this would work.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Sacramento Municipal Utility
District (SMUD)
No
As drafted, requirement R1 requires Balancing Authorities or Reserve Sharing Groups
(RSGs) to achieve an annual Frequency Response Measure (FRM) that is equal to or
more negative than its Frequency Response Obligation (FRO). As RSGs exist today,
FRM performance by an RSG is not contemplated in the definition of FRM and
appears to apply more towards 'secondary response'. Recommend clarifying this
concept and possibly including an example in the background document to help
explain how this would work.
As drafted, in requirement R3, each Balancing Authority not receiving Overlap
Regulation Service to operate its AGC in Tie Line Bias mode... unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area. There
may be occasions in which an entity needs to perform testing or other instances
where it is necessary or desirable to operate in a mode other than Tie Line Bias that
does not qualify as an Adverse Reliability Impact, but never the less is necessary or
Consideration of Comments: Project 2007-12 Frequency Response
38
002892
Organization
Yes or No
Question 2 Comment
desired. Recommend including language that would permit operation other than Tie
Line Bias mode provided the Reliability Coordinator was notified.We seek
clarification from the drafting team as to whether or not there will be any conflicts
between proposed Requirement R3 and the requirements of FERC-approved regional
reliability standard BAL-004-WECC-1 - Automatic Time Error Correction.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Energy Mark, Inc.
No
Comment 1: The timing requirements for implementing the Frequency Bias Setting
are not specified for BAs participating in Overlap Regulation Service. The
requirements indicate the value that should be used for the Frequency Bias Setting,
but they do not indicate when those settings should be implemented.
Comment 2: The term "Tie Line Bias mode" in Requirement R3 is not sufficiently
defined to make this requirement enforceable. Any operating mode labeled as "Tie
Line Bias mode" on an EMS that uses interchange scheduled and frequency error as
inputs will meet the standard requirement as stated. This loop-hole exists because
the NERC definition of "Tie Line Bias" fails to define the term in enough detail to
actually limit AGC operation to the specified mode of operation. One way to
improve this requirement would be to redefine Tie Line Bias in the NERC Glossary as
a mode that uses the NERC ACE Equation as defined in BAL-001 as the basis for AGC
action when the EMS is in Tie Line Bias mode.
Comment 3: The standard is silent on how a BA receiving Overlap Regulation Service
should set its Frequency Bias Setting. Unless this is explicitly stated, it will be up to
Consideration of Comments: Project 2007-12 Frequency Response
39
002893
Organization
Yes or No
Question 2 Comment
the auditors to determine the value of the Frequency Bias Setting for BAs receiving
Overlap Regulation Service.
Comment 4: In general, the requirements indicate what the responsible BAs should
do and when. The requirements do not indicate what the BAs that are not
responsible should do and when, ie. how they are relieved from responsibility. This
may create problems when the auditors are required to interpret the standards for
BAs that have appropriately shifted responsibilites to others.
Response: Comment 1 – The SDT believes that Requirement R2 states the timing for implementation of the Frequency Bias
Setting. The Requirement R4 is simply to provide the BA with the method for combining the Frequency Bias Settings for providers
of Overlap Regulation Service. The Background Document and Attachment A have also been modified to provide further clarity.
Comment 2 – The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Comment 3 & 4 – The SDT does not believe that there is an issue for entities receiving Overlap Regulation Service. However, the
SDT has modified the Background document to further clarify this issue.
Duke Energy
No
Duke Energy supports the concept of a group of BAs forming a group to share in
Frequency Response however it should be clear that it is an option. We feel that the
utilization of the term, “Reserve Sharing Group”, is not consistent with the definition
in the NERC Glossary of Terms which is specific to sharing of contingency reserves,
and should be replaced with a new term, such as “Frequency Response Sharing
Group”.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Though comments are provided below on the Attachments, Duke Energy believes
that all NERC Reliability Standards’ requirements must reside within the standard
itself (which is vetted by the Industry and subject to FERC approval), and not within
Attachments that may be revised without Industry review and approval. As noted
below and in prior comments, given the secondary control implications of changing
Consideration of Comments: Project 2007-12 Frequency Response
40
002894
Organization
Yes or No
Question 2 Comment
the minimum Frequency Bias Setting (FBS), Duke Energy believes that subsequent
revisions to the minimum FBS should be vetted through the Standards process.
Duke Energy would suggest moving the details of the minimum FBS for each
Interconnection into the Standard, and having the implementation plan include
annual submittal of a revised minimum FBS based upon the methodology presented
in Attachment B for ballot approval by the Industry.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it also believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
The SDT has removed the Requirement R3 from this version of the proposed standard. This removal was based on industry
comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
Attachments that are referenced within a Requirement are mandatory and enforceable.
Early research by Nathan Cohn4 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
ISO/RTO Council Standards
Review Committee
4
No
General CommentsThe SRC offers the following general comment with regard to the
SDT’s proposed revisions: Gerry Cauley’s Results based initiative calls for
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
41
002895
Organization
Yes or No
Question 2 Comment
requirements that focus on performance (i.e. WHAT must be accomplished NOT on
WHY it is required or HOW it should be accomplished). The SRC has found that such
explanatory statements as the SDT is proposing lead to ambiguities and confusion in
the compliance application. Compliance Enforcement agents must consider not just
the results but must decide if the action was taken for the given reason. To avoid
such confusion, the Results based approach uses reference documents to address
such background material while leaving the requirement as a direct mandate.The
SRC notes:
o All NERC Reliability Standards’ requirements must reside within the standard itself
(which is vetted by the Industry and subject to FERC approval).
o Data requirements are better handled through NERC’s Rules of Procedure Section
1600 than by mandating that ad hoc Forms be submitted.
o Definitions should be generic, and should be self-contained (i.e. should not
reference an external document).
o The decisions regarding alternative methodologies should be decided by the
Industry not by the SDT. The SDT should make its case and ask the Industry for its
approval.
Regarding Order 693 directives, the SRC notes that there are three directives as
follows:
(1) To include Levels of Non-Compliance;
(2) To determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other requirements of the Reliability
Standard are being met, and to modify Measure M1 based on that determination
and
(3) To define the necessary amount of Frequency Response needed for Reliable
Operation for each balancing authority with methods of obtaining and measuring
that the frequency response is achieved.
Consideration of Comments: Project 2007-12 Frequency Response
42
002896
Organization
Yes or No
Question 2 Comment
The SRC suggests that Directive 2 be handled directly as a mandate that the ERO
conduct a fixed number of Frequency Response Surveys for randomly selected
events. Discussion of the number and the methodology can be explained in a
reference document and leave the specifics to the requirement.
Directive 3 is critical to the Industry as it relates to who is the Applicable Entity. The
SDT addresses Directive 3 by mandating Balancing Authorities meet an objective. The
directive is to define that Objective, but there is no requirement associated with that
Objective. There is an attachment and there are discussions of what “may” be done,
but there is no requirement in the Standard itself. The reference to the BA as the
provider of Frequency Response (i.e. Primary Control response) runs counter to
other FERC directives that mandate obligated entities be able to self-serve or to
interchange provision of services. In this case the BA per se has no assets and cannot
self-serve, moreover the primary response service providers have no obligations to
provide the service, thus the BA potentially could face a situation where there is no
physical service to be purchased but there is a federally mandated standard to
comply with. The idea of creating a Primary Response Market as some have
proposed does not work without an obligation on some entity to physically provide
that service.
One final note, the SRC points out that the ACE is an error signal used to drive
secondary response; it is not a signal to drive primary response. Thus the use of the
Frequency Bias setting is not for control, it is for “adjusting” the error measure that is
analyzed after the fact.This standard needs:
o a requirement on the ERO to compute the Obligation on each Interconnection
o a requirement on the ERO to conduct Frequency Response surveys (note the SRC
does not support this requirement but believes that it is needed to meet the FERC
directive)
o a requirement on energy supply assets (both generation and load) to provide
primary response (as a function of the Interconnection obligation in the first bullet)
Consideration of Comments: Project 2007-12 Frequency Response
43
002897
Organization
Yes or No
Question 2 Comment
The above will allow NERC to comply with the FERC directives in a fashion consistent
with the processes and procedures approved by FERC.
Specific recommendations: The SRC proposes that R1 be deleted based on the facts
that:
o It imposes an obligation on an entity that has no capability to comply
o There is an internal conflict with imposing penalties on a deterministic basis
(compliance with a fixed set of events) for a statistical service (primary
response is a function of the assets operating state and not a fixed service of
the asset).In any case, all of the words after FRO should be deleted. The words
are not needed for the requirement and if left in can become a source of
contention between auditors and registered entities.
R3 - delete the added phrase “mode to effectively coordinate control”.The
phrase “would have an Adverse Impact on the BA’s area” needs further
discussion. Who makes the decision that operating on AGC will have adverse
impact must be defined.
R5 - delete the phrase “In order to ensure control response”. Such phrases can
be needless causes of debate. If a BA uses one of the bulleted methods but
does not get “adequate response” then is the BA non-compliant? What is
“adequate response”? Who decides if the response is adequate?
Response: Unfortunately your comment does not provide enough information as to what parts of the attachments you believe
should be in the requirements. However, the SDT has made significant modifications to both Attachment A and Attachment B,
now a Procedure for the ERO to follow in supporting the standard. The SDT believes that the requirements should be succinct and
the methodologies to be used should be part of an attachment.
The SDT is using defined forms to ensure that everyone calculates their Frequency Bias Setting and Frequency Response Measure
in a consistent manner. The SDT also believes that this provides entities a relatively non-time consuming method to provide the
necessary information to evaluate compliance.
Consideration of Comments: Project 2007-12 Frequency Response
44
002898
Organization
Yes or No
Question 2 Comment
The SDT has modified the definitions to no longer reference any other documents.
The SDT is recommending a certain approach to calculating the FRM. The reference to other methods being evaluated is simply a
statement that the SDT believes that further analysis would be beneficial. Any modification to the calculation methodology would
require industry approval.
The SDT believes that it is meeting Directive #2 by requiring at least 20 events to be analyzed each year.
The SDT believes that it is meeting the directive to define the “objective” by creating the BA Frequency Response Obligation (FRO).
With regards to the BA being the responsible entity to provide Frequency Response the NERC Functional Model Technical
Document identifies the BA as the entity that manages and deploys Frequency Response. This is because a BA controls the
amount and distribution of spinning reserves and also has some control over interruptible resources. This is similar to the
relationship between the TOP and voltage control. Even though the TOP may not own generators or capacitor banks, the TOP is
still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
The ERO is not defined as an applicable entity in the industry approved SAR and therefore it would be inappropriate to include
them as an applicable entity.
Los Angeles Department of
Water and Power
No
LADWP has a concern with Requirement 3. The requirement should provide
allowance for legitimate circumstances when an entity cannot run on Tie Line Bias
Consideration of Comments: Project 2007-12 Frequency Response
45
002899
Organization
Yes or No
Question 2 Comment
mode and not have an Adverse Reliability Impact on the Balancing Authority’s Area.
An entity should not be penalized when these legitimate circumstances occur.
LADWP believes that the Frequency Response Standard Background Document, on
Page 8, lists examples of legitimate circumstances:- Telemetry problems that lead
the operator to believe ACE is significantly in error.- The frequency input to AGC is
not reflective of the BA’s true frequency (such as if the control center were operating
a local generator and disconnected from the Interconnection).- During restoration
(where one BA might be controlling frequency while another to which it is connected
is managing interchange between them).- For training purposes.- Many AGC systems
will automatically switch to an alternate mode if the EMS determines Tie Line Bias
control could lead to problems.
LADWP believes that the language in Requirement 4 needs to be clarified and
recommends the following change:- R4. Each Balancing Authority that is performing
Overlap Regulation Service shall modify its Frequency Bias Setting in its ACE
calculation to be equivalent to either (i) the sum of the Frequency Bias Settings of
the participating Balancing Authorities as validated by the ERO, or (ii) the Frequency
Bias Setting as calculated based on the entire area being combined and thereby
represent the Frequency Response for the combined area being controlled. [Risk
Factor: Medium][Time Horizon: Operations Planning]
LADWP believes the language in Requirement 5 needs to be modified to be
consistent with that of the second paragraph of Attachment B. LADWP recommends
the addition of “natural frequency response” as a third bullet item to Requirement 5.
The revised requirement would read:- R5. In order to ensure adequate control
response, each Balancing Authority shall use a monthly average Frequency Bias
Setting whose absolute value is at least equal to one of the following: [Risk Factor:
Medium ][Time Horizon: Operations Planning] o The minimum percentage of the
Balancing Authority Area’s estimated yearly Peak Demand within its metered
boundary per 0.1 Hz change as specified by the ERO in accordance with Attachment
B. o The minimum percentage of the Balancing Authority Area’s estimated yearly
peak generation for a generation-only Balancing Authority, per 0.1 Hz change as
Consideration of Comments: Project 2007-12 Frequency Response
46
002900
Organization
Yes or No
Question 2 Comment
specified by the ERO in accordance with Attachment B. o The natural frequency
response
Response: The SDT has removed the Requirement R3 from the next version of the proposed standard. This removal was based on
industry comments and the belief that it was duplicative with Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Requirement R4 which now uses bullets in support of your suggestion.
The SDT disagrees with your suggested modification. The SDT believes that your suggested modification could allow for an entity
to circumvent the minimum percentage process. However, the SDT has removed Requirement R5 and combined it into
Requirement R2 and a new Requirement R3.
MidAmerican Energy Co.
Negative
MidAmerican supports the comments provided by the NSRF.
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard.
It is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.5).
Without a statement that the BA is expected to keep its allocated portion of
generation reserves only up to the largest event identified in Table 2, a BA could be
expected to provide limitless amounts of frequency response. Balancing Authorities
cannot know what is expected of them and therefore cannot plan appropriately.
Response: The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency
Response that a BA will be required to provide.
East Kentucky Power Coop.;
ACES Power Marketing;
Hoosier Energy Rural Electric
Cooperative, Inc.; Southwest
Transmission Cooperative,
Inc.
Negative
Overall, [we] believes the drafting team has done an excellent job to address the
FERC directives from Order 693. However, we believe there is still room for
improving the standard and that there is a significant technical error. The technical
error was introduced by applying Requirement 1 to the RSG and is discussed below.
Requirement 1 should not apply to a Reserve Sharing Group. Reserve Sharing Groups
(RSG) are designed to share Contingency Reserves and/or Operating Reserves not
Consideration of Comments: Project 2007-12 Frequency Response
47
002901
Organization
Yes or No
Question 2 Comment
Frequency Response. While these reserves may be frequency responsive, they are
not being shared for the purpose of expanding frequency response. Furthermore,
while reserve sharing groups may calculate a joint ACE by summing its individual BA
ACE values, RSGs do not have a Frequency Bias Setting which is necessary to assess a
Frequency Response Obligation.
Under item 3 of the Event Selection Criteria section, the delta F and Point C should
be described either in this attachment or the “Frequency Response Standard
Background Document”. While many in industry may understand what these terms
mean, history has a way of getting lost with personnel turnover. Furthermore, this
would help ensure that the auditors and industry have a duplicate understanding.
In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency
Protection Criteria should be provided and which N-2 event was selected so that
industry can help validate if the correct MW value was selected.
Furthermore, the document should clarify if the Contingency Protection Criteria
contains the “safety margin”. There is a statement in the paragraph before the table
that states it does, but then the table lists out a separate 25% “Safety Margin”. Thus,
it is not clear if the “Safety Margin” is included in the Contingency Protection Criteria
value listed in the table or not. “Safety margin” should be changed to “reliability
margin”. Safety has a specific meaning in the electric industry and its use here is not
appropriate. The Base Obligation should be explained. The explanation should
include its purpose and origin.
The Data Retention section requires the BA to retain data or evidence for up to four
years. No data that exceeds the audit cycle should be required to be retained. The
audit cycle is three years for BAs.
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Consideration of Comments: Project 2007-12 Frequency Response
48
002902
Organization
Yes or No
Question 2 Comment
Response Obligations of its members.”
The SDT agrees with your comment concerning further clarification on certain terms and has made significant modifications to the
Background Document and Attachments A and B.
The Data Retention is stated as “the current year plus three calendar years” since it is highly unlikely that an entity will be audited
exactly three years after its previous audit. The SDT recognizes that most audits will occur within the year following the third
year.
PPL Electric Utilities Corp.;
PPL Generation LLC
Negative
The PPL Companies do not support proposed Reliability Standard BAL-003-1
(Frequency Response and Frequency Bias Setting) primarily because PPL believes it
inappropriately subjects Reserve Sharing Groups (RSGs) to the proposed
requirements. The proposed Applicability provision states that the mandatory
reliability requirements would be applicable to (1) Balancing Authorities and (2)
Reserve Sharing Groups (where applicable). However, it is unclear how the proposed
requirements would be applicable to an RSG. RSGs typically do not provide a
mechanism for sharing automatic Frequency Response. The BA Frequency Response
Obligation (FRO) is a formula based on BAs and the Interconnection and has nothing
to do with RSGs. Rather, RSGs collectively respond to requests for activation of
contingency reserves generally after the request is made by a member Balancing
Authority. The Standard Drafting Team should therefore remove RSGs from the
Applicability section and should remove all other references to RSGs in the proposed
standard.
Response: The SDT disagrees that an RSG is not an appropriate mechanism for providing Frequency Response. However the SDT
does believe that using the term “Reserve Sharing Group” could cause confusion and has defined a new term “Frequency
Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
Consideration of Comments: Project 2007-12 Frequency Response
49
002903
Organization
Yes or No
Question 2 Comment
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Progress Energy
No
PGN supports the collective comments of SERC members.We feel that the utilization
of the term, “Reserve Sharing Group”, is not consistent with the definition in the
NERC Glossary of Terms, and should be deleted, applicability should be clarified or
replaced with a new term, such as “Frequency Response Sharing”.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
MRO NSRF
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As
RSGs exist today, FRM performance by an RSG is not contemplated in the definition
of FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly include an example in the background document
to help explain how this would work.
R2 - Please add the word “range” in-between the words “date” and “specified”. The
background document specifies that there is a 72-hour period to implement the FBS
setting (See Background document Page 7). R2, as written, does not reflect the
Consideration of Comments: Project 2007-12 Frequency Response
50
002904
Organization
Yes or No
Question 2 Comment
period for which an entity may implement the ERO validated Bias into ACE. Also see
our comment on #7 as to the length of the comment period. Question 7 comment is
provided to assist the SDT; Note from question 7: (Page 7 (3rd paragraph) of the
Background document states “Given the fact that BA’s can encounter staffing or EMS
change issues coincident with the date the ERO sets for new Frequency Bias Setting
implementation, the standard provides a 24 hour window on each side of the target
date.
1. The Standard itself does not state this provision (24 hour window on each side of
target date) as indicated.
2. The SDT accurately addresses the fact that BA’s could have EMS or staffing issues
during implementation of the ERO validated FBS. The current stated 72-hour window
is not long enough for implementation of the FBS as there may be a host of issues
that could impact implementation. We suggest that a seven day window be used for
implementation of the FBS.)
R3 - Recommend the term “Adverse Reliability Impact” be removed from
Requirement
3. Based on the NERC definition of the term, a smaller entity could never operate its
AGC outside of TLB mode due to their impact on the BES not likely to result in
“instability or Cascading”. To ensure a more consistent and equitable approach when
applying this Requirement, recommend the drafting team incorporate the reliability
reasons listed within the Background Document into the actual Requirement.
Additionally, the phrase “effectively coordinated control” should be removed as this
is not essential to the Requirement and introduces ambiguity in its application. To
this end, the following revisions are proposed:
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate
its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively
coordinated control, unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area meets one or more of the following conditions.
Consideration of Comments: Project 2007-12 Frequency Response
51
002905
Organization
Yes or No
Question 2 Comment
o Telemetry problems that lead the operator to believe ACE is significantly in error.
o The frequency input to AGC is not reflective of the BA’s true frequency (such as if
the control center were operating a local generator and disconnected from the
Interconnection).
o During restoration (where one BA might be controlling frequency while another to
which it is connected is managing interchange between them).
o For training purposes.
o Many AGC systems will automatically switch to an alternative mode if the EMS
determines Tie Line Bias control could lead to problems.
o For single BA Interconnections, Flat Frequency and Tie Line Bias are equivalent.
o The Reliability Coordinator has been informed and the duration is [insert time
constraint language here].
R5 - Recommend to delete the phrase “In order to ensure control response”. Such
phrases can be needless causes of debate. If a BA uses one of the bulleted methods
but does not get “adequate response” then is the BA non-compliant? What is
“adequate response”? Who decides if the response is adequate? Please clarify.
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG). The new definition reads “A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response
Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Consideration of Comments: Project 2007-12 Frequency Response
52
002906
Organization
Yes or No
Question 2 Comment
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Xcel Energy
No
R1- It is not clear what is intended by "Reserve Sharing Group" in this context. As
RSGs exist today, FRM performance by an RSG is not contemplated in the definition
of FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly include an example in the background document
to help explain how this would work.
R3 - recommend modifying the language to permit AGC out of TLB mode if the RC is
notified; also remove the "to ensure coordinated control" as this is not essential for
the requirement. Our reasoning behind the suggested change to notification of the
RC is that there are occassions where an entity would need to perform testing, etc
and it could be argued that testing would not be sufficient justification for meeting
the Adverse Reliability Impact definition. Here is proposed revised language:Each
Balancing Authority not receiving Overlap Regulation Service shall operate its
Automatic Generation Control (AGC) in Tie Line Bias mode, unless the Balancing
Authority's Reliability Coordinator has been informed and the duration is [insert time
constraint language here].
Response: The SDT agrees that using the term “Reserve Sharing Group” could cause confusion and has defined a new term
“Frequency Response Sharing Group (FRSG)”. The new definition reads “A group whose members consist of two or more
Consideration of Comments: Project 2007-12 Frequency Response
53
002907
Organization
Yes or No
Question 2 Comment
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Constellation Energy
Commodities Group
No
R1 should accommodate agreements between multiple BAs and RSGs in achieving
the annual Frequency Response Measure. See proposed modification below:
R1. Each Balancing Authority shall achieve an annual Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or
more negative than its Frequency Response Obligations (FRO) to ensure that
sufficient Frequency Response is provided by each BA. Either the Balancing
Authority individual FRM, multiple Balancing Authority’s FRM per written agreement,
or the FRM of the Reserve Sharing Group must be equal to or more negative than the
applicable Frequency Response Obligations (FRO) for a single Balancing Authority or
the aggregate of multiple Balancing Authorities or RSGs.In R2, “Each Balancing Authority not participating in Overlap Regulation Service”
should state “Each Balancing Authority, not receiving Overlap Regulation, shall
implement the appropriate Frequency Bias Setting (fixed or variable,) validated by
the ERO, into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effectively coordinated Tie Line Bias control”. –
In R3, the explanatory language about why to operate in Tie Line Bias mode should
be deleted. See proposed modification below:
R3. Each Balancing Authority not receiving Overlap Regulation Service shall operate
its Automatic Generation Control (AGC) in Tie Line Bias mode, unless such operation
would have an Adverse Reliability Impact on the Balancing Authority’s Area.R5 should be modified to state only that the FBS is specified by the ERO in
accordance with Attachment B. As drafted the Requirement is in conflict with
Attachment B because the Requirement mandates a minimum and does not allow
for a reduction to the minimum but it references Attachment B which is titled
Consideration of Comments: Project 2007-12 Frequency Response
54
002908
Organization
Yes or No
Question 2 Comment
“Process for Adjusting Minimum Frequency Bias Setting”. See proposed modification
below:
R5. In order to ensure adequate control response, each Balancing Authority shall use
a monthly average Frequency Bias Setting whose absolute value is as specified by the
ERO in accordance with Attachment B.There should be a Requirement specifically stating there is an obligation to complete
and submit FRS Form 1 by January 10th each year for clarity.The requirements should be re-ordered to reflect the chronology of the process for
frequency calculation, implementation and performance measurement. The
recommended order is as follows:
R5 which defines the minimum Frequency Bias Setting (FBS) for a Balancing
Authority
R4 which describes how the minimum FBS may be altered through Overlap
Regulation Service
R2 which identifies the coordination required around implementationR3 which
requires operation in Tie Line Bias mode
R1 which establishes the performance obligation
Response: The SDT does not see anything within the Requirement that would restrict any agreements between multiple BAs and
RSGs. However, the SDT has modified the language in Requirement R1 to provide additional clarity. The requirement now reads
“Each Balancing Authority or Frequency Response Sharing Group (FRSG) shall achieve an annual Frequency Response Measure
(FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each Balancing Authority or FRSG to
maintain Interconnection Frequency Response equal to or more negative than the Interconnection Frequency Response
Obligation.” The SDT has also defined a new term “Frequency Response Sharing Group (FRSG)” because it also believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
Consideration of Comments: Project 2007-12 Frequency Response
55
002909
Organization
Yes or No
Question 2 Comment
jointly meet the Frequency Response Obligations of its members.”
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT also believes
that Attachment B, now a Procedure for the ERO to follow in supporting the standard, only details the process the ERO is to use
when evaluating and making modifications to the minimum Frequency Bias Setting.
The SDT disagrees with your comment concerning an additional requirement for timing of reporting. The SDT believes that this is
an administrative issue and is better handled within an attachment. The SDT would also like to note that an attachment when
referenced in a requirement becomes mandatory and enforceable.
The SDT thanks you for your suggested ordering for the requirements but believes that the revised proposed standard reflects the
proper order in that it sets the goal at beginning of year, calculates performance, reports performance and calculates bias at the
end of the year.
Constellation Energy
Negative
-R1 should accommodate agreements between multiple BAs and RSGs in achieving
the annual Frequency Response Measure. See proposed modification below: R1.
Each Balancing Authority shall achieve an annual Frequency Response Measure
(FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or
more negative than its Frequency Response Obligations (FRO) to ensure that
sufficient Frequency Response is provided by each BA. Either the Balancing Authority
individual FRM, multiple Balancing Authority’s FRM per written agreement, or the
FRM of the Reserve Sharing Group must be equal to or more negative than the
applicable Frequency Response Obligations (FRO) for a single Balancing Authority or
the aggregate of multiple Balancing Authorities or RSGs.
-In R2, “Each Balancing Authority not participating in Overlap Regulation Service”
Consideration of Comments: Project 2007-12 Frequency Response
56
002910
Organization
Yes or No
Question 2 Comment
should state “Each Balancing Authority, not receiving Overlap Regulation, shall
implement the appropriate Frequency Bias Setting (fixed or variable,) validated by
the ERO, into its Area Control Error (ACE) calculation beginning on the date specified
by the ERO to ensure effectively coordinated Tie Line Bias control”.
-In R3, the explanatory language about why to operate in Tie Line Bias mode should
be deleted. See proposed modification below: R3. Each Balancing Authority not
receiving Overlap Regulation Service shall operate its Automatic Generation Control
(AGC) in Tie Line Bias mode, unless such operation would have an Adverse Reliability
Impact on the Balancing Authority’s Area.
-R5 should be modified to state only that the FBS is specified by the ERO in
accordance with Attachment B. As drafted the Requirement is in conflict with
Attachment B because the Requirement mandates a minimum and does not allow
for a reduction to the minimum but it references Attachment B which is titled
“Process for Adjusting Minimum Frequency Bias Setting”. See proposed modification
below: R5. In order to ensure adequate control response, each Balancing Authority
shall use a monthly average Frequency Bias Setting whose absolute value is as
specified by the ERO in accordance with Attachment B.
-There should be a Requirement specifically stating there is an obligation to
complete and submit FRS Form 1 by January 10th each year for clarity. -The
requirements should be re-ordered to reflect the chronology of the process for
frequency calculation, implementation and performance measurement. The
recommended order is as follows: R5 which defines the minimum Frequency Bias
Setting (FBS) for a Balancing Authority R4 which describes how the minimum FBS
may be altered through Overlap Regulation Service R2 which identifies the
coordination required around implementation R3 which requires operation in Tie
Line Bias mode R1 which establishes the performance obligation
Response: The SDT does not see anything within the Requirement that would restrict any agreements between multiple BAs and
RSGs. However, the SDT has modified the language in Requirement R1 to provide additional clarity. The requirement now reads
Consideration of Comments: Project 2007-12 Frequency Response
57
002911
Organization
Yes or No
Question 2 Comment
“Each Balancing Authority or Frequency Response Sharing Group (FRSG) shall achieve an annual Frequency Response Measure
(FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more negative than its Frequency
Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each Balancing Authority or FRSG to
maintain Interconnection Frequency Response equal to or more negative than the Interconnection Frequency Response
Obligation.” The SDT has also defined a new term “Frequency Response Sharing Group (FRSG)” because they also believed that
using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
The SDT has modified Requirement R2 to provide better clarity. The requirement now reads “Each Balancing Authority that is a
member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the ERO to ensure effectively coordinated Tie Line Bias control.”.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT also believes
that Attachment A only details the process the ERO is to use when evaluating and making modifications to the minimum
Frequency Bias Setting.
The SDT disagrees with your comment concerning an additional requirement for timing of reporting. The SDT believes that this is
an administrative issue and is better handled within an attachment. The SDT would also like to note that an attachment when
referenced in a requirement becomes mandatory and enforceable.
The SDT thanks you for your suggested ordering for the requirements but believes that the revised proposed standard reflects the
proper order in that it sets the goal at beginning of year, calculates performance, reports performance and calculates bias at the
end of the year.
Ameren
No
R1.While we agree with the concept of the entire requirement and the
determination of the Interconnection Frequency Response Obligation, we believe
that the accurate measurement of individual BA's FRM has not yet been
demonstrated. This requirement should not be part of the standard (even with the
additional 12 months in the effective date) until the field trial demonstrates that
Consideration of Comments: Project 2007-12 Frequency Response
58
002912
Organization
Yes or No
Question 2 Comment
each BA's FRM can be consistently calculated to a level that will not create false noncompliance to this requirement. While the calculation methodology in FRS Form 1
looks promising, with the A-value and B-value average periods, we believe successful
completion of the field trial is prudent.
R5. We were not sure if it was intended for this comment question to include
Requirement R5, but have decided to include our comments here. While we agree
with the requirement of R5, it should not be at the expense of changing the value of
L10 in BAL-001, R2, which has been accepted by FERC in Order 693. An
accommodation should be made so that any changes to the Frequency Bias Setting
according to BAL-003, R5, should not affect the value of L10 used in BAL-001, R2.
Response: The SDT agrees that validation of the methodology needs to occur. However, the SDT is working under a FERC
approved deadline for completion of this project. The SDT is recommending that continued analysis should occur during the filing
period and implementation period of the standard. The STD has also added considerable language to the Background Document
on why it has chosen the methodology it is recommending for this standard.
The SDT understands your concern with the reduction of the minimum Frequency Bias Setting affecting other performance
standards. The process to do this is outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure
manages a “go slow” approach to making this happen and includes checks to confirm there are not unexpected influences injected
into the CPS-related calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to
make the initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a
change in minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
American Electric Power
No
R1: Clarification is needed regarding the responsibility of a BA that is a member of a
Reserve Sharing Group.
R2 and R3: What does “coordinated control” mean?
There no leverage for the BA to require the generator to carry their burden of
addressing governor settings or droop settings, yet the BA is obligated to meet some
performance measures.
Consideration of Comments: Project 2007-12 Frequency Response
59
002913
Organization
Yes or No
Question 2 Comment
This revision adds new performance measure responsibilities on the BA who likely
has no direct control over every resource affecting their performance within their
footprint. We are not necessarily challenging the performance measures themselves,
nor their underlying objectives, however AEP views this as a gap in responsibilities
which potentially effects reliability.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” to eliminate any confusion with the
present d3efined term “Reserve Sharing Group”. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has been instructed to include a “reliability outcome” within the requirements and therefore included the language
“…coordinated control…”. The SDT understands that this does not provide any additional clarity for complying with the
requirement and could be removed. The SDT will forward your concerns about the wording to the Standards Committee Quality
Review group for consideration.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
60
002914
Organization
Yes or No
Question 2 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Great River Energy
No
R1: Including the Reserve Sharing Group (RSG) in the Frequency Response Obligation
is outside of the boundaries of a RSG. Where or how would a Frequency Bias be
determined for an RSG to determine their Frequency Response Obligation? Although
it is apparent that frequency responds during the implementation of reserves, the
intention of a RSG is not to share frequency response, but rather to share Reserves.
Additionally, if the Frequency Response Obligation is not met by the RSG how are
penalties assessed? Should they be assessed to the group as a whole or strictly to
the generators that did not meet their individual obligation?
R3: Needs to include verbiage for those circumstances when it would be necessary to
run AGC out of TLB such as during necessary testing. The BA should have the option
to operate out of TLB for a predetermined amount of time if needed when
notification and coordination with the RC has been established.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
Consideration of Comments: Project 2007-12 Frequency Response
61
002915
Organization
Yes or No
Question 2 Comment
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Tucson Electric Power
No
R1: TEP feels that the FRO should be able to be calculated by the BA and that Form 1
changes should be treated via the Standard drafting process.
R2: TEP feels that use Form 1 should be required by the Standard. Further, BAs
should calculate its own frequency bias setting without ERO intervention.
R3: Operating outside Tie Line Bias mode should be allowed during a year to allow
for the testing of other modes.
R4: Agree with the concept, but without ERO intervention.
R5: Should read "greater than or equal to".
Response: The FRO can be estimated by the BA but the actual BA FRO for compliance is based on the BA’s footprint and is a
function of the Interconnection FRO. Modifications to the FRS Form 1 would go through the Standard Drafting Process.
R3 - The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
R2 and R4 - The Frequency Bias Setting is calculated on FRS Form 1. The ERO is only validating the data used in the calculation.
This is a practice that exists today. History has shown that there typically are errors in the data.
R5 - The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has
Consideration of Comments: Project 2007-12 Frequency Response
62
002916
Organization
Yes or No
Question 2 Comment
modified the requirement and believes we have implemented the intent of your suggestion.
SCE&G
Affirmative
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
o We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1 o
Response: The requirement to operate AGC in Tie Line Bias mode has been removed from the standard since it was duplicative of
Requirements R6 and R7 in BAL-005-0.1b.
The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to address your concern.
The new title is, “Frequency Bias Setting Minimums”.
Bonneville Power
Administration
No
Regarding R1, BPA believes that adding additional requirements in R1 by referencing
Attachment A does not add clarity. FRO should be a calculation that the BA’s can do
themselves and included within the standard.
Can Form 1 be changed outside of the standard drafting process? BPA doesn’t
believe that Form 1 should be allowed to be changed outside of the standard
drafting process. As drafted, Requirement R1 requires Balancing Authorities or
Reserve Sharing Groups (RSGs) to achieve an annual Frequency Response
Measure (FRM) that is equal to or more negative than its Frequency Response
Obligation (FRO).
As RSGs exist today, FRM performance by an RSG is not contemplated in the
definition of FRM and appears to apply more towards 'secondary response'.
BPA recommends clarifying this concept and possibly including an example in
the background document to help explain how this would work.
Regarding R2, BPA believes each BA should be able to calculate its own frequency
bias setting without ERO validation. The standard can require the BA to use Form 1,
if the BA doesn’t use Form 1 correctly, then the BA would be in violation of the
Consideration of Comments: Project 2007-12 Frequency Response
63
002917
Organization
Yes or No
Question 2 Comment
standard.
BPA believes that R3 should include a minimal amount of time (suggesting a couple
of hours per year) to allow for testing other modes. Requirement R3 requires each
Balancing Authority not receiving Overlap Regulation Service to operate its AGC in
Tie Line Bias mode... unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area. There may be occasions in which an entity needs
to perform testing or other instances where it is necessary or desirable to operate in
a mode other than Tie Line Bias that does not qualify as an Adverse Reliability
Impact, but never the less is necessary or desired. BPA recommends including
language that would permit operation other than Tie Line Bias mode provided the
Reliability Coordinator was notified.BPA seeks clarification from the drafting team as
to whether or not there will be any conflicts between proposed Requirement R3 and
the requirements of FERC-approved regional reliability standard BAL-004-WECC-1 Automatic Time Error Correction.
BPA agrees with the concept of R4, however, BPA again disagrees with the ERO
validation of the frequency bias setting.
BPA believes that reducing frequency bias obligation is detrimental to reliability. It
seems that lowering the Minimum Frequency Bias Setting from 1% to .8% will result
in a lower response, which in turn will lower the natural frequency response. BPA
believes that over time, it would seem that this pattern would lead to poorer
response.
BPA believes that R5 should read “greater than or equal to one of the following” not
“ at least equal to”. The requirement should be a part of Form 1 or included in R2.
For variable bias, the minimum percentage should be based on the forecasted month
peak.
Response: R1 – The FRO can be estimated by the BA but the actual BA FRO for compliance is based on the BA’s footprint and is a
function of the Interconnection FRO.
Consideration of Comments: Project 2007-12 Frequency Response
64
002918
Organization
Yes or No
Question 2 Comment
Modifications the FRS Form 1 would go through the Standard Drafting Process.
The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined
term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
R2 – The SDT is interested in the use of good data for the calculations but does not believe that a BA should be penalized for minor
data errors. This is why the SDT proposes that the ERO validate the data. In addition, this process is used today.
R3 - The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
R4 – Again, this is a process that is in use today. The SDT is not proposing that the ERO modify anything, just proposing that the
ERO validate the data being supplied.
R5 - The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. However, the SDT
understands your concern with the reduction of the minimum Frequency Bias Setting affecting other performance requirements.
The process to do this is outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a
“go slow” approach to making this happen and includes checks to confirm there are not unexpected influences injected into the
CPS-related calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to make the
initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change
Consideration of Comments: Project 2007-12 Frequency Response
65
002919
Organization
Yes or No
Question 2 Comment
in minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
Manitoba Hydro
No
Regarding R1:
1. Neither R1 nor the referenced Attachment A clarifies the FRM requirements for an
RSG to comply versus a BA. In particular
(i) At p.3, Attachment A states that the ERO is responsible for “annually
assigning an FRO and Frequency Bias Setting to each BA.” No mention is made
of RSGs.
(ii) Attachment A only references RSGs in the context of reporting obligations
for Form 1 (at p.4) and
(iii) Compared to BAL-002-0 R1.1, which clearly states that the BA may elect to
fulfill its obligation through an RSG and that in such cases the RSG has the
same responsibilities as each BA (that is a participant in the RSG).
2. It should be clarified that this requirement applies to a BA, where the BA doesn’t
belong to an RSG, OR to an RSG. As it is currently drafted, the standard applies to
each BA and each RSG. It is redundant in that each BA would need to comply,
whether or not they are a member of an RSG that would also be required to comply.
Further, the NERC Glossary definition of an RSG is a group of BAs that collectively
maintain, allocate and supply operating reserves. No mention is made of the
agreement including the sharing or delegation of responsibility related to FRM.
Accordingly, the standard should only reference a BA being able to delegate
responsibility to an RSG if the RSG Agreement allows for such delegation.
3. R1 does not specify where or how the FRO is determined. Presumably this would
be determined by the ERO pursuant to Attachment A.
4. The phrase “to ensure that sufficient Frequency Response ...” should be separated
from the requirement as it is
Consideration of Comments: Project 2007-12 Frequency Response
66
002920
Organization
Yes or No
Question 2 Comment
(i) not descriptive of the required actions;
(ii) redundant with the stated purpose at the beginning of the standard. In
general, such a drafting technique should be avoided as it may allow
Responsible Entities to argue that a violation has not occurred where the
specific action that is described has not been taken, but the purpose
referenced in the requirement has been met.
Regarding R2:
1. It is not clear from R2 who determines the Frequency Bias Setting for “validation”
by the ERO and how the FBS is determined. (Presumably done by the BA in
accordance with Attachment B). Based on Background document, should refer to
those “published” by ERO. The BA’s FBS may not be validated, and may be modified
before posting.
2. Attachment B does not refer to the ERO “validating” FBS.
3. Attachment B refers to an RSG calculating FBS, but the standard does not.
Response: R1 – Comment 1 & 2 – The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes
that using the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources
required to jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
Consideration of Comments: Project 2007-12 Frequency Response
67
002921
Organization
Yes or No
Question 2 Comment
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
Comment 3 – The process for determining the FRO is detailed in Attachment A.
Comment 4 – The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your
concerns about the wording to the Standards Committee Quality Review group for consideration.
R2 – Comment 1 – The Frequency Bias Setting is calculated on FRS Form 1. The ERO is only validating the data not calculating the
setting. The ERO will be working with the BA to correct any data errors discovered during the validation process. This is a process
that is in use today
Comment 2 & 3 – The SDT has made significant modifications to the Background Document and Attachment A to provide
additional clarity. The SDT has added language to Attachment A regarding validation of the BA data. The SDT has removed all
references to a FRSG for Frequency Bias Setting. Attachment B has been removed and the information from Attachment B has
been incorporated in a Procedure developed by the SDT for the ERO to follow to support this standard.
NV Energy
No
Requirement 1 seems to be the only one that has any applicability to an RSG;
however, it is unclear under what circumstances this requirement applies to an RSG.
Suggest changing the R1 to be addressed solely to BA's or alternatively, explain
under Applicability section 1.2 what "where applicable" means.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
Consideration of Comments: Project 2007-12 Frequency Response
68
002922
Organization
Yes or No
Question 2 Comment
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
ACES Power Marketing
Standards Collaborators
No
Requirement 1 should not apply to a Reserve Sharing Group. Reserve Sharing
Groups (RSG) are designed to share Contingency Reserves and/or Operating
Reserves not Frequency Response. While these reserves may be frequency
responsive, they are not being shared for the purpose of expanding frequency
response. Furthermore, while reserve sharing groups may calculate a joint ACE by
summing its individual BA ACE values, RSGs do not have a Frequency Bias Setting
which is necessary to assess a Frequency Response Obligation.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Consideration of Comments: Project 2007-12 Frequency Response
69
002923
Organization
Yes or No
Question 2 Comment
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
City of Redding, Oregon Public
Utility Commission,
BrightSource Energy, Inc.,
Clark Public Utilities, Avista,
Tri-State G & T Association,
Inc.; Deseret Power
Negative
Requirement R3 requires each Balancing Authority not receiving Overlap Regulation
Service to operate its AGC in Tie Line Bias mode... unless such operation would have
an Adverse Reliability Impact on the Balancing Authority’s Area. There may be
occasions in which an entity needs to perform testing or other instances where it is
necessary or desirable to operate in a mode other than Tie Line Bias that does not
qualify as an Adverse Reliability Impact, but never the less is necessary or desired.
Recommend including language that would permit operation other than Tie Line Bias
mode provided the Reliability Coordinator was notified.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
Alberta Electric System
Operator
No
The language used in the requirements is superfluous. This could result in confusion
and incorrect assumptions being made.
In R1, the comment within brackets “(as detailed in Attachment A and calculated on
FRS Form 1)”, is not necessary as it is already part of the FRM definition. We suggest
removing this bracketed text from the requirement.
Also in R1, the phrase “to ensure that sufficient Frequency Response is provided by
each BA or RSG to maintain an adequate level of Frequency response in the
Interconnection” is a high level objective that does not add clarity to this
requirement. We suggest removing this from the requirement.
R2, R3 and R5 use similar language e.g. “to ensure effectively coordinated Tie Line
Bias control”, “to ensure adequate control response” etc. Although it provides
background information, this does not add clarity to the requirement. We suggest
removing these from the requirements.
Response: Based on industry comments the SDT has modified the definition for FRM such that it no longer references any other
documents. Therefore, the SDT believes that leaving the reference to Attachment in the standard is prudent, based on advice
Consideration of Comments: Project 2007-12 Frequency Response
70
002924
Organization
Yes or No
Question 2 Comment
from the standards staff – without a reference to the specific Attachment, the responsible entity can’t be held to compliance with
the performance identified in that attachment.
The SDT has been instructed to include a “reliability outcome” within the requirements and therefore included the language you
are referencing. The SDT understands that this does not provide any additional clarity for complying with the requirement and
could be removed. The SDT will forward your concerns about the wording to the Standards Committee Quality Review group for
consideration.
Hydro-Quebec TransEnergie
No
The objective of R2 is that all BA’s implement their new Bias Setting at the same
time, based on the previous year’s data, so that control stays the most effective
throughout the Interconnection (Tie-Line Bias). In addition, the new Bias will be in
effect all year long. The process is quite simple and straightforward for a fixed Bias
Setting. As for Variable Bias Setting, this process is not applicable before the fact
since the Bias equation can depend on real-time values that are not known in
advance. In addition, the simultaneous Bias implementation is not an issue for a
single BA Interconnection. Therefore, we suggest that Requirement 2 applies only to
Fixed Bias Setting.
Response: The SDT agrees with your comment and has modified Requirement R2 to reflect your concern. The SDT has also added
an addition Requirement R3 to address entities using a variable Frequency Bias Setting.
Northeast Power Coordinating
Council
No
The requirements should not be directed at Balancing Authorities, as generators are
the main supplier of “discretionary” frequency response. Requirement R1 refers to
an attached form, which is not part of the standard and therefore not enforceable.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
Consideration of Comments: Project 2007-12 Frequency Response
71
002925
Organization
Yes or No
Question 2 Comment
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
If an attachment is referenced in a requirement that attachment becomes part of the requirement. The requirement has been
modified to no longer reference an attached form.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
The standard is silent on the “methods to obtain Frequency Response”. For instance,
the BA does not have authority over governor and other generator settings. There
should be a requirement for GOPs to incorporate setting changes directed by the BA,
otherwise the standard establishes requirements that BAs may not have the
authority to achieve. R1 includes the Reserve Sharing Group in its applicability, but
none of the other requirements do.
There is no consideration of "footprint" changes of the BA resulting in different
allocation from the ERO during a year. The standard and Attachments seem to
specify an annual process with due dates in December and January with no
allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance?
If the ERO does not meet its obligations, can an entity still be found non-compliant,
especially on a schedule basis? Wasn’t there an issue of assigning standards to RROs,
e.g., the fill-in-the-blank standards? Are there similar issues with assigning
requirements to the ERO? Is the ERO a “user, owner or operator” of the BPS under
Section 215, e.g., at (b)(1)”... All users, owners and operators of the bulk-power
system shall comply with the reliability standards that take effect under this section.”
I question how this would work from a compliance perspective.
On R5, the wording should be changed from “absolute value is at least equal to” to
Consideration of Comments: Project 2007-12 Frequency Response
72
002926
Organization
Yes or No
Question 2 Comment
“absolute value is greater than or equal to”
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has also included other methods that a BA can use to provide Frequency Response in the Background Document.
The SDT has added language to Attachment A to address changes in a BAs footprint.
The proposed standard is not putting a requirement on the ERO. There is language in the Attachments to provide additional time
for a BA to become compliant if the ERO is late in providing the necessary information. If the ERO does not provide the necessary
information then the BA would not be required to modify anything and therefore the last information provided would be that
which would be used for compliance purposes.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
South Carolina Electric and
Gas
No
The utilization of the term, “Reserve Sharing Group”, is not consistent with the
definition in the NERC Glossary of Terms, and should be deleted, applicability should
be clarified or replaced with a new term, such as “Frequency Response Sharing”.
Consideration of Comments: Project 2007-12 Frequency Response
73
002927
Organization
Yes or No
Question 2 Comment
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
Tri-State G & T Association,
Inc.; Tucson Electric Power
Co.; U.S. Army Corps of
Engineers; South California
Edison ; Platte River Power
Authority; Pacific Gas and
Electric Company; Colorado
Springs Utilities; Idaho Power
Negative
We believe that there are several modifications that, if implemented to the existing
requirements, would result in an improved, clarified standard.
As drafted, Requirement R1 requires Balancing Authorities or Reserve Sharing
Groups (RSGs) to achieve an annual Frequency Response Measure (FRM) that is
equal to or more negative than its Frequency Response Obligation (FRO). As RSGs
exist today, FRM performance by an RSG is not contemplated in the definition of
FRM and appears to apply more towards 'secondary response'. Recommend
clarifiying this concept and possibly including an example in the background
Consideration of Comments: Project 2007-12 Frequency Response
74
002928
Organization
Yes or No
Company; California Energy
Commission; California ISO;
Deseret Power
Question 2 Comment
document to help explain how this would work.
Requirement R3 requires each Balancing Authority not receiving Overlap Regulation
Service to operate its AGC in Tie Line Bias mode... unless such operation would have
an Adverse Reliability Impact on the Balancing Authority’s Area. There may be
occasions in which an entity needs to perform testing or other instances where it is
necessary or desirable to operate in a mode other than Tie Line Bias that does not
qualify as an Adverse Reliability Impact, but never the less is necessary or desired.
Recommend including language that would permit operation other than Tie Line Bias
mode provided the Reliability Coordinator was notified. We seek clarification from
the drafting team as to whether or not there will be any conflicts between proposed
Requirement R3 and the requirements of FERC-approved regional reliability standard
BAL-004-WECC-1 - Automatic Time Error Correction.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
Consideration of Comments: Project 2007-12 Frequency Response
75
002929
Organization
Yes or No
Question 2 Comment
The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
ISO New England Inc
No
We do not agree with placing a requirement on Balancing Authorities, as generators
are the main supplier of “discretionary” frequency response. Also, the requirement
refers to an attached form, which is not part of the standard and therefore not
enforceable.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
If an attachment is referenced in a requirement that attachment becomes part of the requirement. However the requirement has
been modified to no longer reference an attached form.
SERC OC Standards Review
Group
No
We feel that the utilization of the term, “Reserve Sharing Group”, is not consistent
with the definition in the NERC Glossary of Terms, and should be deleted,
applicability should be clarified or replaced with a new term, such as “Frequency
Response Sharing”.
R2 exempts BAs participating in Overlap Regulation Service from implementing the
Frequency Bias Setting on the date specified by the ERO, and R4 states how the BA
Consideration of Comments: Project 2007-12 Frequency Response
76
002930
Organization
Yes or No
Question 2 Comment
performing Overlap Regulation Service will modify its Frequency Bias Setting but
does not state when the setting will be implemented. The exemption for BAs
participating in Overlap Regulation Service should either be deleted from R2 or
language stating the implementation date of the frequency bias setting needs to be
included in R4.
R4 should clarify that a BA performing Overlap Regulation Service should still be
required to operate its AGC in “Tie Line Bias” mode.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine
how to allocate sanctions among its members. This standard does not mandate the formation of FRSGs, but allows them as a
means to meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply Frequency
Response.
The SDT has modified the language in Requirement R2. The term “not participating in” has be replace with “not receiving”. This
now encompasses entities that are providing Overlap Regulation Service.
The SDT has removed the requirement to operate AGC in Tie Line Bias mode as this requirement was duplicative of the
Requirements R6 and R7 in BAL-005-0.1b.
Consideration of Comments: Project 2007-12 Frequency Response
77
002931
Organization
Yes or No
Florida Municipal Power
Agency/JEA Electric
Compliance
No
Question 2 Comment
We thank the SDT for their hard work and diligence in moving this Project forward.
However, we have some concerns that cause us to not support the standard in its
current form.
In general, we believe that there has not been sufficient prudency review for the
standard, especially R1, to justify a performance based standard around a Frequency
Response Measure.
We also believe that the proposed standard does not meet all of the conditions of
the Final SAR and Supplemental SAR.The “Final SAR” was to develop methods by
which a performance based standard would eventually be developed. The Final SAR
states:”The proposed standard’s intent is to collect data needed to accurately model
existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed
reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be modeled,
and the reasons for the decline in Frequency Response can be identified. Once
thereasons for the decline in Frequency Response are confirmed, requirements can
be written to control Frequency Response to within defined reliability
parameters.”BAL-003-1 does not seem to complete the scope of this “Final SAR”. For
instance, “the reasons for the decline in Frequency Response” were not confirmed to
our knowledge; and the field trial is not completed to our knowledge.The
Supplemental SAR adds to the scope of the Final SAR:”To provide a minimum
Frequency Response Obligation for the Balancing Authority to achieve, methods to
obtain Frequency Response and provide a consistent method for calculating the
Frequency Bias Setting for a Balancing Authority. In addition, the standard will
specify the optimal periodicity of Frequency Response surveys.”The Supplemental
SAR does not eliminate the pre-requisite contained in the Final SAR to determine the
reasons for the decline in frequency response and confirm them before establishing
“defined reliability parameters”.
In addition, the standard does not complete the requirement of the Supplemental
Consideration of Comments: Project 2007-12 Frequency Response
78
002932
Organization
Yes or No
Question 2 Comment
SAR to identify “methods to obtain Frequency Response”. For instance, neither the
BA nor the RSG have authority over governor and other generator settings. There
should be a requirement for GOPs to incorporate setting changes directed by the BA,
otherwise the standard establishes requirements that BAs and RSGs may not have
the authority to achieve.
There is no consideration of "footprint" changes of the BA resulting in different
allocation from the ERO during a year. The standard and Attachments seem to
specify an annual process with due dates in December and January with no
allowance for mid-year changes and associated allocation changes.
If a standard has a requirement for the ERO, who will audit the ERO for compliance?
If the ERO does not meet its obligations, can an entity still be found non-compliant,
especially on a schedule basis? Wasn’t there an issue of assigning standards to RROs,
e.g., the fill-in-the-blank standards? Are there similar issues with assigning
requirements to the ERO? Is the ERO a “user, owner or operator” of the BPS under
Section 215, e.g., at (b)(1)”... All users, owners and operators of the bulk-power
system shall comply with the reliability standards that take effect under this section.”
We question how this would work from a compliance perspective.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
The SDT agrees that the original SAR was strictly for data collection. However, a supplemental SAR was developed to address the
FERC March 18, 2010 Order and was subsequently approved by the industry. The Standards Committee has determined that a
proposed standard must be within the scope of the approved SAR but the proposed standard is not required to address the full
scope of the SAR if stakeholders support a reduced scope.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
79
002933
Organization
Yes or No
Question 2 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
The SDT has also included other methods that a BA can use to provide Frequency Response in the Background Document.
The SDT has added language to Attachment A to address changes in a BA’s footprint.
The proposed standard is not putting a requirement on the ERO. There is language in the Attachments to provide additional time
for a BA to become compliant if the ERO is late in providing the necessary information. If the ERO does not provide the necessary
information then the BA would not be required to modify anything and therefore the last information provided would be that
which would be used for compliance purposes.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Florida Power & Light
Company
Yes
Independent Electricity
Yes
Consideration of Comments: Project 2007-12 Frequency Response
80
002934
Organization
Yes or No
Question 2 Comment
System Operator
Associated Electric
Cooperative Inc
Yes
Cleco Corporation
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
81
002935
3.
The SDT has developed VRFs for the proposed Requirements within this standard. Do you agree that these VRFs are
appropriately set? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters agreed with the VRFs that the SDT has proposed for the requirements within
the standard.
One commenter felt the VRFs were too high and that they should have a “lower” VRF. The SDT developed the VRFs using the NERC
Violation Risk Factor guidelines approved by FERC. A lower VRF is an administrative type of requirement that, if violated would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor and control
the bulk electric system; or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect
the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. Violation of any of the requirements in the proposed standard could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Another commenter stated that they could not fine the “Risk Severity Levels” in the standard. The SDT is not sure as to the meaning of
this comment. The SDT believes that the commenter may have been mixing two different terms, Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs). The question asked by the SDT was concerning the VRFs. These are located within the body of the
Requirement. The VSLs are located towards the end of the proposed standard.
Organization
Yes or No
Seattle City Light
Negative
Question 3 Comment
Answer: Yes. Comments: LADWP and SCL agree with the following VRFs: - R1 Medium - R2 - Medium - R3 - Medium - R4 - Medium - R5 - Medium
Response: The SDT thanks you for your clarifying comment.
Energy Mark, Inc.
No
Comment 5: See comments in the non-binding poll.
Response: Please see our response to your comments from the non-binding poll.
Florida Power & Light
Company
No
Could not find the Risk Severity Levels in the documents.
Consideration of Comments: Project 2007-12 Frequency Response
82
002936
Organization
Yes or No
Question 3 Comment
Response: The SDT is not sure as to the meaning of your comment. The SDT believes that you may be mixing two different terms,
Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs). The question asked by the SDT was concerning the VRFs. These
are located within the body of the Requirement. The VSLs are located towards the end of the proposed standard.
Cleco Corporation
No
Please note Cleco does not use the VRFs therefore we feel too much energy and time
is spent on the VRFs. The SDT needs to concentrate on the requirements and
measurements.
Response: The SDT thanks you for your clarifying comment.
Ameren
No
This is problematic since for a single BA interconnection these could be argued to be
appropriate VRFs, but is different for a multiple BA interconnection, where the risk
that a single BA would pose to the interconnection would be Lower.
Response: The SDT developed the VRFs using the NERC Violation Risk Factor guidelines approved by FERC. This document can be
found at http://www.nerc.com/files/Violation_Risk_Factors.pdf. IA lower VRF is an administrative type of requirement that, if
violated not be expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system; or, a requirement that is administrative in nature and a requirement in a planning time
frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control,
or restore the bulk electric system. Violation of any of the requirements in the proposed standard could directly affect the electrical
state or the capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Seattle City Light/Los Angeles
Department of Water and
Power
Yes
LADWP and SCL agree with the following VRFs:- R1 - Medium- R2 - Medium- R3 Medium- R4 - Medium- R5 - Medium
Response: The SDT thanks you for your affirmative response and clarifying comment.
NV Energy
Yes
Medium appears to be reasonable and appropriate.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Consideration of Comments: Project 2007-12 Frequency Response
83
002937
Organization
Yes or No
Bonneville Power
Administration
Yes
Imperial Irrigation District
Yes
Northeast Power Coordinating
Council
Yes
MRO NSRF
Yes
SERC OC Standards Review
Group
Yes
SPP Standards Review Group
Yes
ISO/RTO Council Standards
Review Committee
Yes
ACES Power Marketing
Standards Collaborators
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Southern Company
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 3 Comment
84
002938
Organization
Yes or No
ISO New England Inc
Yes
Tucson Electric Power
Yes
Independent Electricity
System Operator
Yes
Associated Electric
Cooperative Inc
Yes
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
Manitoba Hydro
Yes
Constellation Energy
Commodities Group
Yes
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Duke Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 3 Comment
85
002939
4.
The SDT has developed Measures for the proposed Requirements within this standard. Do you agree with the proposed
Measures in this standard? If not, please explain in the comment area.
Summary Consideration: Many of the commenters were concerned with the language in Requirement R3 stating that an entity had to
be operating in Tie Line Bias mode unless there were adverse affects on the BES and that if the requirement was modified that the
measure should be modified. The SDT explained that it had removed this requirement from the proposed standard since they felt it was
duplicative of Requirement R6 and R7 in BAL-005-0.1b.
Some commenters objected to the definition for FRM and the Measure referencing another document (FRS Form 1). The SDT explained
that it modified the definition for FRM to no longer reference another document. The revised definition reads “The median of all the
Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO. This will be
calculated as MW/0.1Hz.”
A couple of the commenters had concerns with Requirement R5 in that it should reference “natural Frequency Response” as a third
bullet. The SDT has explained that it removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The
SDT did not include the term “natural Frequency Response” within the standard itself but included it in the Background Document and
Attachment A. The SDT felt that this provided additional clarity within the requirement and allowed for further explanation of the term
in the Background Document and Attachment A.
Some commenters indicated that the use of an RSG as a method for supplying Frequency Response was not fully explained. The SDT
modified the Background Document to further explain how an RSG (now FRSG) could be used to supply Frequency Response. The SDT
has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve
Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities
that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response Obligations of its
members.”
A couple commenters wanted the sampling interval to be tuned on a per Interconnection basis to support HQTE’s characteristics. The
SDT agreed and explained that it adjusted the event selection criteria to address concerns related to response driving frequency back to
pre-event level during the B value measurement period and this adjustment should address their concern.
Organization
Yes or No
Consideration of Comments: Project 2007-12 Frequency Response
Question 4 Comment
86
002940
Organization
Yes or No
Seattle City Light
Negative
Question 4 Comment
Answer: No. Comments: LADWP and SCL recommend that the Measures for
Requirement 3 and Requirement 5 reflect their comments to Question 2.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Constellation Energy
Commodities Group
No
Based on language modifications proposed to the Requirements, the measures
should be revisited.
Response: The SDT has revised the Measures to align with modifications made to the Requirements.
Xcel Energy
No
Based on our suggested changes to R3 in response to Question 2, the drafting team
should modify M3 to be consistent with the proposed language.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
MRO NSRF
No
Based on suggested changes to R3 in response to Question 2, the drafting team
should modify M3 to be consistent with the proposed language.
Additionally, M1 should be revised to not reference a specific Form. The Form may
be the format of choice but it should not be an implied requirement.
Measures 3 and 4 identify the use of “operating logs” as evidence. Measure 2
identifies hard copy and electronic evidence, “or other evidence”. We suggest calling
out specifically “operator logs” for M2 also, in case there are system problems in
capturing hard copy or electronic evidence during the short time window for
implementation.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has modified Measure M1 which no longer references a form but does reference Attachment A to align with the
requirement.
Consideration of Comments: Project 2007-12 Frequency Response
87
002941
Organization
Yes or No
Question 4 Comment
The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be used as long
as it reflects compliance with the standard.
Bonneville Power
Administration
No
BPA believes that historian data should be able to be used for evidence.
Response: The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be
used as long as it reflects compliance with the standard. The SDT believes that the data from the software program “Historian”
could be used to demonstrate compliance..
Manitoba Hydro
No
It should be clarified that R1 requirement applies to a BA, where the BA doesn’t
belong to an RSG, or to an RSG. As it is currently drafted, the standard applies to
each BA and each RSG. It is redundant in that each BA would need to comply,
whether or not they are a member of an RSG that would also be required to comply.
Further, the NERC Glossary definition of an RSG is a group of BAs that collectively
maintain, allocate and supply operating reserves. No mention is made of the
agreement including the sharing or delegation of responsibility related to FRM.
Accordingly, the standard should only reference a BA being able to delegate
responsibility to an RSG if the RSG Agreement allows for such delegation.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has modified the Applicability Section to clarify when a BA or FRSG is accountable for compliance.
The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined
term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency
Response Obligations of its members.”
Tucson Electric Power
No
It should be clear that historical data may be used to show compliance.
Response: The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be
used as long as it reflects compliance with the standard. The SDT believes that the data used to reflect compliance would have to
Consideration of Comments: Project 2007-12 Frequency Response
88
002942
Organization
Yes or No
Question 4 Comment
be historical data.
Seattle City Light/ Los Angeles
Department of Water and
Power
No
LADWP and SCL recommend that the Measures for Requirement 3 and Requirement
5 reflect their comments to Question 2.
Response: The SDT has removed Requirement R3 as it is duplicative of Requirements R6 & R7 in BAL-005-0.1b.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
ISO/RTO Council Standards
Review Committee
No
M1: The measure should not be tied to a specific Form. If a BA has the evidence but
does not provide it on a given Form, how is the reliability of the Power System
impacted? The Form may be the format of choice but it should not be an implied
requirement.
M4: This measure does not read quite right. Something seems to be missing in the
part that says: “...showing when Overlap Regulation Service is provided including
Frequency Bias Setting calculation to demonstrate compliance with Requirement R4.”
This part might have read something like: “...showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation or it
calculated the Frequency Bias Setting meeting the conditions specified in
Requirement R4.”
Response: The SDT has modified Measure M1 which no longer references a form, however it does reference Attachment A to align
with the associated requirement.
The SDT is only providing examples (“…such as…”) of what could be used to reflect compliance. Other evidence can be used as
long as it reflects compliance with the standard.
The SDT has modified the Measure M4 to incorporate your suggested wording.
Independent Electricity
No
M4: This measure does not read quite right. Something seems to be missing in the
Consideration of Comments: Project 2007-12 Frequency Response
89
002943
Organization
Yes or No
System Operator
Question 4 Comment
part that says: “...showing when Overlap Regulation Service is provided including
Frequency Bias Setting calculation to demonstrate compliance with Requirement R4.”
This part might have read something like: “...showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation or it
calculated the Frequency Bias Setting meeting the conditions specified in
Requirement R4.”
Response: The SDT has modified the Measure M4 to incorporate your suggested wording.
ERCOT
No
Measure should be modified to align with revised Requirements per ERCOT’s
comments on #1.
Response: The SDT has modified the Measures to align with the modifications to the Requirements.
SERC OC Standards Review
Group/ Progress Energy/
South Carolina Electric and
Gas/ Duke Energy
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
Response: Please see our response to your comments on Question 2 regarding “Reserve Sharing Group”.
Northeast Power Coordinating
Council/ISO New England Inc.
No
The sampling interval needs to be tuned on a per Interconnection basis to support
HQTE’s characteristics.
Response: The SDT adjusted the event selection criteria to address concerns related to response driving frequency back to preevent level during the B value measurement period. We believe that this adjustment addresses your concern.
Florida Power & Light
Company
No
What is meant by documented formulae for M5? Is a one time snapshoot of the AGC
formual sufficien? The concept is ok but this needs clarification of proof.
Response: The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3.
Consideration of Comments: Project 2007-12 Frequency Response
90
002944
Organization
Yes or No
Southwest Power Pool
Regional Entity
Yes
Question 4 Comment
Measures are more specific and measurable than seen in the past. This is a positive
improvement.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Ameren
Yes
With the understanding that any suggested changes to the proposed requirements
would come with corresponding changes to their measure.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT agrees that any modification to a
Requirement would necessitate a re-evaluation of the corresponding Measure.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
Associated Electric
Cooperative Inc
Yes
NV Energy
Yes
Cleco Corporation
Yes
Consideration of Comments: Project 2007-12 Frequency Response
91
002945
Organization
Yes or No
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 4 Comment
92
002946
5.
The SDT has developed VSLs for the proposed Requirements within this standard. Do you agree with these VSLs? If not, please
explain in the comment area.
Summary Consideration: Most of the commenters indicated that VSLs for Requirement R1 should not include language tied to whether
or not a BA is in a single BA Interconnection or a multi-BA Interconnection. Frequency Response is an Interconnection-wide resource.
The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections. Consider a small BA
whose performance is 70% of its’ FRO. If all other BAs in the Interconnection are compliant, the small BA’s performance has negligible
impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not
rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would
treat multi-BA Interconnections tens of times more harshly than single BA Interconnections. However, the SDT has added language to
the requirement to reference the Interconnection Frequency Response Obligation.
Several commenters did not agree with the VSLs for Requirement R3. The SDT removed Requirement R3 from the revised standard
since the requirement was duplicative of Requirement R6 & R7 in BAL-005-0.1b.
With concerns about the use of the RSG as a means to provide Frequency Response, the SDT modified the Background Document to
further explain how an RSG (now FRSG) could be used to supply Frequency Response. The SDT has defined a new term “Frequency
Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve Sharing Group” could cause
confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities that collectively maintain,
allocate, and supply operating resources required to jointly meet the Frequency Response Obligations of its members.”
Organization
Yes or No
Seattle City Light
Negative
Question 5 Comment
Answer: No. Comments: LADWP and SCL recommend that either the VSL for
Requirement 3 reflects its comments to Question 2, or that these comments be
addressed as an exception in the Measure for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
Consideration of Comments: Project 2007-12 Frequency Response
93
002947
Organization
Yes or No
Question 5 Comment
with R6 and R7 in BAL-005-0.1b.
Public Utility District No. 1 of
Douglas County
Negative
1. The BA and interconnection meet the FRO differently. Suggest removing the
interconnection performance from the VSL and develop additional levels of BA
failure to meet its FRO.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
BrightSource Energy, Inc.
Negative
The negative vote from BrightSource is related to the proposed VSL only. The
proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO. Conforming changes
to the VSLs would need to be made for any changes to the Requirements as
suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
Consideration of Comments: Project 2007-12 Frequency Response
94
002948
Organization
Yes or No
Question 5 Comment
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of its FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
U.S. Army Corps of Engineers;
Platte River Power Authority;
Pacific Gas and Electric
Company; Idaho Power
Company; Colorado Springs
Utilities; California Energy
Commission; California ISO;
Clark Public Utilities; Tucson
Electric Power Co.; Tri-State G
& T Association, Inc.
Negative
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO. Conforming changes
to the VSLs would need to be made for any changes to the Requirements as
suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Consideration of Comments: Project 2007-12 Frequency Response
95
002949
Organization
Yes or No
Question 5 Comment
Negative
The VSL for Requirement 3 does not sufficiently reflect a thoughtful range of
violation severity of duration or number of instances by which AGC is not in Tie-Line
Bias mode.
Obligation.
Kansas City Power & Light Co.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 and R7 in BAL-005-0.1b.
ACES Power Marketing; East
Kentucky Power Coop.;
Hoosier Energy Rural Electric
Cooperative, Inc.
Negative
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
performance.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
Southwest Transmission
Cooperative, Inc.
Negative
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
Consideration of Comments: Project 2007-12 Frequency Response
96
002950
Organization
Yes or No
Question 5 Comment
performance. The proposed VSLs for Requirement R1 treats a BA that did not meet
the FRO requirement differently depending on whether or not the Interconnection
met the FRO requirement. The obligation of the BA to meet its allocated FRO
should be consistent regardless of what the other entities within the
interconnection are doing. Suggest removing the interconnection performance
from the VSLs and developing four increasing levels of BA failure to meet its FRO.
Conforming changes to the VSLs would need to be made for any changes to the
Requirements as suggested in the comments to the standard.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of its FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Western Area Power
Administration
Negative
Under compliance for R1, there is a difference between VSL levels whether the
interconnection met is FRO or not. If the interconnection meets it’s FRO but a single
BA doesn't’t meet its share of FRO the violation is considered low VSL, but, if the
interconnection dosen't’t meet it’s FRO the same BA will have a High VSL.
Obligation of the individual BA to meet its allocated FRO should always be
applicable regardless of what other BAs are doing in the interconnection. This
provision creates a disparity amongst BAs and creates a disparate treatment
between the BAs who perform compared to those who don’t.
Response: The drafting team does not agree, but believes an explanation would be helpful.
Consideration of Comments: Project 2007-12 Frequency Response
97
002951
Organization
Yes or No
Question 5 Comment
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Ameren Services; Ameren
Energy Marketing
Co./Ameren
Negative/No
It is not clear how the VSL for R1 uses the "Summation of the BA's FRM", when the
requirement is BA or RSG specific.
Response: Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing
Group (FRSG). FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Manitoba Hydro
Negative/No
The Violation Severity Levels for R1 penalize entities more severely depending on
how the interconnection as a whole has performed. MH believes that BAs should
only be held accountable for issues within their control and that the VSLs for R1
should be revised accordingly.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
98
002952
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small
BA’s performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for
its entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the SDT has added language to the requirement to reference the Interconnection Frequency Response
Obligation.
Constellation Energy
Commodities Group
No
The language in the VSLs for R1 should be revisited based on the proposed
language modifications above and should also clearly look to the FRM of a BA,
group of BAs or RSG against the BA FRO not an Interconnection FRO.
Response: The drafting team has made conforming changes to VSLs based on wording changes to the Requirements.
Regarding the evaluation of the Interconnection, the drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing Group (FRSG).
FRSG performance may be calculated on one of two ways:
Consideration of Comments: Project 2007-12 Frequency Response
99
002953
Organization
Yes or No
Question 5 Comment
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
Bonneville Power
Administration
No
BPA believes that R1 needs to be more clear and concise as to what is being
conveyed in the requirement. It is difficult to understand. The proposed VSLs for
Requirement R1 treats a BA that did not meet the FRO requirement differently
depending on whether or not the Interconnection met the FRO requirement. The
obligation of the BA to meet its allocated FRO should be consistent regardless of
what the other entities within the interconnection are doing. Suggest removing the
interconnection performance from the VSLs and developing four increasing levels
of BA failure to meet its FRO.BPA believes that conforming changes to the VSLs
would need to be made for any changes to the Requirements as suggested in the
comments to the standard.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. We would welcome suggested
wording changes that relay this concept more clearly.
With regard to removing a view of Interconnection performance, the drafting team does not agree, but believes an explanation
would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Consideration of Comments: Project 2007-12 Frequency Response
10
0
002954
Organization
Yes or No
Question 5 Comment
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
Florida Power & Light
Company
No
For R1 the low and high level descriptions appear to be identical and the high level
is less than the medium risk level.
For R3 there should be low, medium, and high levels. One BA not operating to TLB
does not jepordize the Interconnection. Additionally, computer failures, database
loads etc may require some period where TLB is not in service. Suggestion would
be Lower VSL operation off of TLB for more than 5 but < 8 continuous hours or
accumlative during the year of more than 8 < 16 hours. Medium VSL would be
operation off of TLB for more than 8 but <16 continuous hours or accumlative
during the year of more than 16 <24 hours. High VSL would be operation off of TLB
for more than 16 <24 continuous hours or accumlative during the year of more
than 36 <48 hours. Severe VLS would be >24 continuous hours off of TLB or
accumlative of > 48.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added
language to the requirement to reference the Interconnection Frequency Response Obligation.
Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative with R6 and
R7 in BAL-005-0.1b.
NV Energy
No
For R1, suggest that the VSL's not be dependent upon the aggregate performance
of the BA's within an interconnection.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
1
002955
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
American Electric Power
No
It is not clear for R1 what the exact delineations are among Lower, Medium, High,
and Severe VSL’s.
Response: The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are
deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and
assesses sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added
language to the requirement to reference the Interconnection Frequency Response Obligation.
Seattle City Light
No
LADWP and SCL recommend that either the VSL for Requirement 3 reflects its
comments to Question 2, or that these comments be addressed as an exception in
the Measure for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 andR7 in BAL-005-0.1b.
Los Angeles Department of
Water and Power
No
LADWP recommends that either the VSL for Requirement 3 reflects its comments to
Question 2, or that these comments be addressed as an exception in the Measure
for Requirement 3.
Response: Based on Industry comments and further review, the drafting team has deleted R3 as the requirement is duplicative
with R6 and R7 in BAL-005-0.1b.
ReliabilityFirst
No
ReliabilityFirst thanks the SDT for their effort on this project. ReliabilityFirst has a
number of concerns/questions related to the draft BAL-003-1 VSLs which include
Consideration of Comments: Project 2007-12 Frequency Response
10
2
002956
Organization
Yes or No
Question 5 Comment
the following:
1. General VSL Comment - For consistency with other standards, each VSL should
begin with the phrase “The Responsible Entity...” or “The Balancing Authority”. This
is consistent with the language of the requirement and correctly pinpoints the
appropriate responsible entity.
2. VSL R1 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:a. Lower VSL - The Responsible
Entity achieved an annual FRM within an Interconnection that was equal to or more
negative than the Interconnection’s FRO and the Responsible Entity’s FRM was less
negative than its FRO by more than 1% but by at most 30% or 15 MW/0.1 Hz,
whichever one is the greater deviation from its FROb. Medium VSL - The
Responsible Entity achieved an annual FRM within an Interconnection that was
equal to or more negative than the Interconnection’s FRO and the Responsible
Entity’s FRM was less negative than its FRO by more than 30% or by more than 15
MW/0.1 Hz, whichever one is the greater deviation from its FROc. High VSL - The
responsible entity failed to achieve an annual FRM that is equal to or more negative
than its FRO and the Responsible Entity’s, FRM was less negative than its FRO by
more than 1% but by at most 30% or 15 MW/0.1 Hz, whichever one is the greater
deviation from its FROd. Severe VSL - The responsible entity failed to achieve an
annual FRM that is equal to or more negative than its FRO and the Responsible
Entity’s FRM was less negative than its FRO by more than 30% or by more than 15
MW/0.1 Hz, whichever one is the greater deviation from its FRO3.
VSL R4 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:
a. Example for Lower VSL which should be carried throughout all four VSLs - The
Balancing Authority incorrectly modified the Frequency Bias Setting value used in
its ACE calculation when providing Overlap Regulation Services with combined
Consideration of Comments: Project 2007-12 Frequency Response
10
3
002957
Organization
Yes or No
Question 5 Comment
footprint setting-error less than 5% of the validated or calculated value4.
VSL R5 Comment - Based on the FERC Guideline #3 “Violation Severity Level
Assignment Should Be Consistent with the Corresponding Requirement”.
ReliabilityFirst suggests the following modification:
a. Example for Lower VSL which should be carried throughout all four VSLs - The
Balancing Authority used a monthly average Frequency Bias Setting whose absolute
value was less than or equal to 5% below the minimum specified by the ERO.
Response: While there may be a better way to lay out the VSL, the VSL for R1 is consistent with R1 in that performance can be
reported either as a single BA or as an RSG. The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and Severe VSLs say the Interconnection
does not meet the FRO and assesses sanctions based on whether the BA is deficient by a small or larger amount respectively.
However, the SDT has added language to the requirement to reference the Interconnection Frequency Response Obligation.
The drafting team has modified the VSLs for R4 based on your comments. The SDT removed Requirement R5 and combined it into
revised Requirement R2 and new Requirement R3.
Progress Energy / South
Carolina Electric and
Gas/Duke Energy
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
Response: Based on comments, the drafting team has created a new definition for an entity called a Frequency Response Sharing
Group (FRSG).
Similar to traditional Reserve Sharing Groups for Contingency Reserves, FRSGs as proposed in this standard , are voluntary
organizations whose members determine the terms and conditions of participation. The members of the FRSG would determine how
to allocate sanctions among its members. This standard does not mandate the formation of FRFSGs, but allows them as a means to
meet one of the FERC’s Order No. 693 directives.
FRSG performance may be calculated on one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting year on a single FRS Form 1, or
Consideration of Comments: Project 2007-12 Frequency Response
10
4
002958
Organization
Yes or No
Question 5 Comment
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each participant’s individual annual
performance.
SERC OC Standards Review
Group
No
See comments in Question 2 regarding utilization of the term “Reserve Sharing
Group”.
VSL for R1:The draft VSLs for R1 uses the summation of FRM for all BAs within an
Interconnection as a factor in determining the applicable VSL. This does not seem
consistent with R1. R1 is about a single BA and the individual BA’s frequency
response performance as measured by the FRM for that specific BA. Including the
FRM summation of the Interconnection expands R1. It appears that a BA that is
non-compliant with R1 could end up with either a Low/Medium or High/Severe VSL
based upon the FRO performance of the Interconnection. The FRM performance of
the Interconnection is beyond the knowledge and control of a single BA and should
not be a determinate of the applicable VSL.Is there a technical basis for selection of
the 1%, 30% and 15MW/.1 Hz VSL breakpoints? Does the Lower VSL give a 1% dead
band to a BA’s FRO? If so, will this be acceptable to NERC/FERC?
VSL for R2:The VSL should reflect the language used in the requirement. R2 says a
BA “not participating in Overlap Regulation service shall ....”, while the VSL says a
BA “not receiving Overlap Regulation Service.....” The VSL language is not
consistent with the requirement.
VSLs for R5:Since Frequency Bias Setting is expressed as a negative value, the terms
“absolute value” and “less than” must be used carefully. Wouldn’t the “absolute
value” of a BA’s Frequency Bias Setting always be positive and thus it could never
be less than the minimum specified by the ERO (a negative value)?
Response: With regard to R1, VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended
to measure a violation’s impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide
resource. The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
5
002959
Organization
Yes or No
Question 5 Comment
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Regarding the 1%, 30% and 15MW breakpoints, the 1% value accommodates rounding error. The 30% or 15MW/0.1Hz is intended to
comparably address both large and small BAs. The drafting team used its judgment in selecting these values and cannot predict what
the FERC might accept.
The SDT has modified the VSLs for Requirement R2 to correctly match the requirement.
The SDT has removed Requirement R5 from the proposed standard and combined it into Requirements R2 and R3. Requirement R2
no longer references “absolute value” and Requirement R3 references “absolute value” only as a comparison to another “absolute
value”.
Western Electricity
Coordinating Council
No
The proposed VSLs for Requirement R1 treat a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
Consideration of Comments: Project 2007-12 Frequency Response
10
6
002960
Organization
Yes or No
Question 5 Comment
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response.
To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
JEA Electric Compliance/ MRO
NSRF
No
The proposed VSLs for Requirement R1 treats a BA that did not meet the FRO
requirement differently depending on whether or not the Interconnection met the
FRO requirement. The obligation of the BA to meet its allocated FRO should be
consistent regardless of what the other entities within the interconnection are
doing. Suggest removing the interconnection performance from the VSLs and
developing four increasing levels of BA failure to meet its FRO.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consideration of Comments: Project 2007-12 Frequency Response
10
7
002961
Organization
Yes or No
Question 5 Comment
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response.
To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Northeast Power
Coordinating Council
No
The violation severity levels for R1 are reasonable. The technical writing needs to
be enhanced for clarity.
Response: Thank you for the comment. The drafting team will look at ways to clarify the wording or provide an explanation in
the Background Document.
ISO New England Inc
No
The violation severity levels for R1 seem to be reasonable. However, the technical
writing needs to be enhanced for clarity
Response: Thank you for the comment. The drafting team will look at ways to clarify the wording or provide an explanation in the
Background Document.
SPP Standards Review
Group/Cleco Corporation
No
The VSLs for R2 are based on 5, 15 and 25 days. What was the justification for these
values? Could we just as well use 10, 20 and 30 or some other set of values?
In R3, we understand that brief periods of operation outside of TLB control are
allowable providing 1) continued operation in TLB control would create ARI on the
Interconnection or 2) that justification is provided for the periods when TLB is not
used. For example, if something happens within our EMS that disables TLB control
Consideration of Comments: Project 2007-12 Frequency Response
10
8
002962
Organization
Yes or No
Question 5 Comment
are we compliant if we document the period as an EMS malfunction?
Response: Regarding R2, the time windows were based on judgment of the drafting team. Similar to the commenters’ question,
the team could have chosen 1, 7, 14 and 28 days or 1, 2, 3 or 4 days to frame the four levels of VSLs. The SDT has modified
Attachment A to allow an implementation window of 3 days for implementation of the Frequency Bias Setting.
With regard to R3, the drafting team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL-005-0.1b.
ACES Power Marketing
Standards
Collaborators/Great River
Energy
No
The VSLs on for Requirement R1 set a previously un-established precedent of
relying on the performance of other registered entities to establish the severity
level of the violation. This is not appropriate. The VSLs should be rewritten to
provide further gradations of the violation severity based on the BA’s own
performance.
Response: The drafting team does not agree, but believes an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed
VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections.
Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient Frequency
Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA Interconnections.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency Response but individual BAs are deficient by
small or larger amounts respectively. The High and Severe VSLs say the Interconnection does not meet the FRO and assesses
sanctions based on whether the BA is deficient by a small or larger amount respectively. However, the SDT has added language to the
requirement to reference the Interconnection Frequency Response Obligation.
Southern Company
No
VSL for R2:We suggest the language in the VSL be consistent with the language
Consideration of Comments: Project 2007-12 Frequency Response
10
9
002963
Organization
Yes or No
Question 5 Comment
used in the Requirement. The VSL for R2 says a BA ‘not receiving Overlap
Regulation Service.......’ R2 says a BA ‘not participating in Overlap Regulation service
shall .......’
VSLs for R5:Since Frequency Bias Setting is expressed as a negative value, the terms
“absolute value” and “less than” must be used carefully. This VSL uses “absolute
value” when referring to the BA’s Frequency Bias Setting, but does not use
“absolute value” when referring to the Frequency Response Obligation, or
minimum value specified by the ERO. Consider revising this VSL so that a true
comparison can be made.
Response: We agree with your suggested change for the VSL for R2 and corrected the mismatch between the requirement and
the VSLs.
The SDT has removed Requirement R5 from the proposed standard and combined it into Requirements R2 and R3. Requirement R2
no longer references “absolute value” and Requirement R3 references “absolute value” only as a comparison to another “absolute
value”.
Tucson Electric Power
No
VSL's could be clearer and simpler. Allowance for the testing of other AGC modes
should be considered.
Response: The drafting team has made changes to VSLs based on specific suggestions. Regarding AGC operation, the drafting
team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL-005-0.1b.
Southwest Power Pool
Regional Entity
Yes
Hard to follow the language for the VSL for R1. Suggest using formulas for ease of
interpretation or provide an example in the Supporting Documentation.
Response: The drafting team will provide an explanation in the Background Document.
Associated Electric
Cooperative Inc
Yes
The VSLs appear reasonable for the risk and particularly where they assess higher
severity when the BA or RSG Interconnection's performance was sub-standard as
well.
Consideration of Comments: Project 2007-12 Frequency Response
11
0
002964
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment.
ISO/RTO Council Standards
Review Committee
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should
have been “...Reserve Sharing Group’s...”. Alternatively, the wording after
“interconnection’s FRO” could be revised to: “...and the Balancing Authority’s or the
Reserve Sharing Group’s FRM was...”
Response: The drafting team agrees and has made this change.
Independent Electricity
System Operator
Yes
We do not have any issues with the VSLs, but wonder if the wording for R1 should
have been “...Reserve Sharing Group’s...”. Alternatively, the wording after
“interconnection’s FRO” could be revised to: “...and the Balancing Authority’s or the
Reserve Sharing Group’s FRM was...”
Response: The drafting team agrees and has made this change.
Texas Reliability Entity
Yes
We suggest that the Severe VSL for R3 is confusing and should be clarified as
follows: “A Balancing Authority not receiving Overlap Regulation service failed to
operate AGC in Tie Line Bias mode, when operation in Tie Line Bias mode would not
have had an Adverse Reliability Impact on the Balancing Authority’s Area.”
Response: Regarding AGC operation, the drafting team has deleted R3 as the requirement is duplicative with R6 and R7 in BAL005-0.1b.
Imperial Irrigation District
Yes
Salt River Project
Yes
Energy Mark, Inc.
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
11
1
002965
Organization
Yes or No
Xcel Energy
Yes
Hydro-Quebec TransEnergie
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 5 Comment
11
2
002966
6.
The SDT divided the previously posted “Attachment A – Background Document” into two documents to provide additional
clarity. The first document “Attachment A- Supporting Document” which details the methods used to develop the events to be
analyzed, the FRO, FRM and Frequency Bias Setting. Do you agree that the revised Attachment A – Supporting Document
provides sufficient clarity on the methodologies to be used? If not, please explain in the comment area.
Summary Consideration: The majority of the commenters pointed out that there was a discrepancy between Attachment A and
the Background Document concerning the methodology used to calculate FRO. The SDT addressed the discrepancy between the
two documents to ensure that historical data is used for the allocation of an Interconnection Frequency Response Obligation to
the BAs within that Interconnection.
Several of the commenters indicated that the proposed standard did not provide a limit on the amount of Frequency Response
that a BA was supposed to provide. The SDT added Paragraph #8 in Attachment A under the Event Selection Criteria to clarify
that events greater than the limit in the criteria would be capped at a certain limit. This translates to a maximum expectation of
Frequency Response equal to a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Some commenters were confused about the intent of Attachment A. They indicated that Attachment A was describing both a
methodology to select events and providing a background for the process (not a process/methodology). The intent of
Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain date and to have the
BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that provides at least the
response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the process. The
drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
As to the use of the term “may” in the attachment, at this time the drafting team is unable to further restrict the language due to
the issues surrounding an individual event. As an example, frequency is scheduled at 60 Hz most of the time. However, when
viewed on a graph or an EMS screen, it rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005.
The drafting team is unable to say at this time that an event that starts with frequency at 60.005 is materially different than an
event that starts at 59.995. Therefore, the drafting team has attempted to put guidance into the document as to what is pertinent
without attempting to be overly restrictive in the selection criteria since there is no support for a restriction at this time. As more
experience is gained, the process should be refined. If the refinement is significant enough to require a change to the Attachment
A language, the process required to do so would be open to participation of industry and not done without public exposure.
Consideration of Comments: Project 2007-12 Frequency Response
11
3
002967
A couple of commenters said that using older data for compliance could cause an entity to be in “double jeopardy”. The SDT
discussed the concern of double jeopardy several times. At this time, the drafting team believes the issue of noise in individual
events and the convergence of measurement of multiple events outweighs the double jeopardy concerns. The drafting team has,
however, reduced the minimum number of events in a 12 month period to 20 from 25 but is still recommending that events from
a previous year be used for the calculation if this number of events cannot be found in that period.
A few o commenters indicated that the allocation of the FRO to the BAs was a “top down” approach. The SDT agrees with some
of the comments made, but not in the conclusion drawn from the individual points. There is not currently an obligation to provide
any amount of frequency response to a sudden change in interconnection frequency. The proposed standard addresses this
shortcoming in the proposed standard.
The drafting team has also reduced the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction can
be studied closely to ensure no detrimental impact on the reliable operation of the Bulk Electric System.
Finally, there is ongoing disagreement in the industry as to whether it is desired to have a minimum Frequency Bias Setting that is
significantly greater than the Frequency Response Characteristic.
A couple of commenters questioned whether point B was 18 seconds after the start of the disturbance. The SDT revised the
language in the document to provide clarity on the 18 seconds. To the extent that the language is related to a specific definition
of steady frequency, this has been worded intentionally to allow the process being developed by the ERO (specifically the
Resources Subcommittee and the Frequency Working Group) to be adjusted based on experience that will only be gained through
evaluation of actual events over the course of the next few years. Until that experience is gained, there will need to be some
leeway in the process. The drafting team believes that the level of guidance provided in Attachment A is appropriate based on the
information currently available.
Organization
Yes or No
Question 6 Comment
Western Area Power
Administration, Western Area
Power Administration - UGP
Marketing
Negative
4. The allocation of FRO among BAs is a top-down approach instead of bottom up
approach currently used. Currently, BAs calculate their FRC and set their Bias based
on the greater of 1% peak load (1% generation for gen only BAs), or the average of
frequency response characteristic of their BA over a year (FRC). These calculated
individual biases get summed up and it becomes the Interconnection Bias value. The
proposed standard has identified a set MW (for Western Interconnection 685 MW for
Consideration of Comments: Project 2007-12 Frequency Response
11
4
002968
Organization
Yes or No
Question 6 Comment
0.1 of HZ) and is allocating it among all BAs. The individual BA’s allocated FRO is much
lower than what BAs obligations’ presently are since the proposed standard lowers
the bar for the BAs. The current approach is definitely superior to what is proposed
since it more closely matches with the characteristic of the system and it protect the
interconnection by requiring larger contribution than proposed standard.
5. The allocation of FRO among the BAs in the interconnection favors the BAs with
more load than more installed capacity
Response: 4. The drafting team agrees with some of the comments made here but not in the conclusion you draw from the
individual points. There is not currently an obligation to provide any amount of frequency response to a sudden change in the
interconnection frequency. The proposed standard addresses this shortcoming in the current standard. The drafting team has also
reduced the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction can be studied closely to ensure
no detrimental impact on the reliable operation of the Bulk Electric System. Finally, there is ongoing disagreement in the industry
as to whether it is desired to have a minimum Frequency Bias Setting that is significantly greater than the Frequency Response
Characteristic. Please refer to Order 693 P371 for further information on this issue.
5) After further discussion, the drafting team believes that the proposed allocation methodology does not favor any specific type
of entity. To the extent that the commenter believes that the allocation favors any specific type of entity, the commenter should
provide detailed reasoning of its position, not just an unsupported statement. The drafting team was unable to find any basis for
this position during our discussions of the proposed allocation methodology. The drafting team will also point out that installed
capacity is not a part of the calculation. The proposed allocation methodology, which has been clarified in the revised documents,
utilizes monthly average peak generation and average peak load.
Seattle City Light
Negative
Answer: No. Comments:
o LADWP and SCL consider the increase in number of events to analyze (now 25) to
be excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. SCL suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Consideration of Comments: Project 2007-12 Frequency Response
11
5
002969
Organization
Yes or No
Question 6 Comment
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not be used consistently across the industry.
Alliant Energy Corp. Services,
Inc.
Negative
Confusion exists around the "peak load" in that Attachment A states the allocastion is
based on Projected Peak Loads and Generation but the Background Document states
it will use historical Peak and Generation to make the allocation. - There appears to
be a difference in how FRO is calculated in Attachment A and what is described in the
Background Document. These differences should be reconciled such that both
documents address the same approach. If installed capacity is used in the equation in
Attachment A, how are variable/intermittent resources (e.g. wind, solar) accounted
for? At full capacity of something less - please clarify. –
It is not clear if there is an upper limit to the amount of frequcncy response expected
of the BA's under this standard. Except for Table 2 in Attachment A, there is no
discussion of an amount of FR expected on a total basis. BA's need to know for how
many tenths of a hertz they are to respond so they can determine how to plan to
meet the requirements.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
BrightSource Energy, Inc.;
Clark Public Utilities; Tri-State
Negative
Confusion exists between Attachment A and the Background Document. Attachment
A states peak load allocation is based on “Projected” Peak Loads and Generation, but
Consideration of Comments: Project 2007-12 Frequency Response
11
6
002970
Organization
Yes or No
G & T Association, Inc.; Tucson
Electric Power Co.; U.S. Army
Corps of Engineers; South
California Edison ; Platte River
Power Authority; Pacific Gas
and Electric Company;
Colorado Springs Utilities;
Idaho Power Company;
California Energy Commission;
California ISO; Deseret Power
Question 6 Comment
the Background Document states it will use “historical” Peak Load and Generation.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it seems
this pattern would lead to poorer response.
The standard is unclear as to if there is an upper limit to the amount of frequency
response expected of the Balancing Authorities under this standard. Except for Table
2 in Attachment A, there is no discussion of an amount of Frequency Response
expected on a total basis. Balancing Authorities need to know for how many tenths of
a hertz they are to respond so they can determine how to plan to meet this
requirement. The documents do not appear to provide any boundary on the
maximum amount of Frequency Response that a BA will provide, i.e. it is not clear
what will happen if an event occurs in the Eastern Interconnection that causes the
frequency to drop to less than 59.6 Hz or in the Western Interconnection that causes
the frequency to drop to less than 59.5 Hz, or if that event is excluded from the list
used to calculate the Balancing Authorities’ response or is it included with an
expectation that it counts the same as any other event. Without a clear statement of
what is expected, including whether there is a limit on that expectation or not, it is
unclear what is expected of the Balancing Authorities.
Finally, why are there no requirements on governor installation, settings, and
operation for a frequency response standard?
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
A reduction in the Frequency Bias Setting (FBS) may reduce the amount of AGC responses to a change in frequency. However, the
drafting team has ensured that the FBS does not dip below the actual frequency response to ensure that the Frequency Response
Consideration of Comments: Project 2007-12 Frequency Response
11
7
002971
Organization
Yes or No
Question 6 Comment
is not withdrawn due to AGC action. With that said, there is currently not an obligation to provide any amount of frequency
response to a sudden change in the interconnection’s frequency. The proposed standard addresses this shortcoming in the current
standard. The drafting team has modified the initial reduction in the minimum Frequency Bias Setting to ensure that the reduction
can be studied closely to ensure no detrimental impact on the reliable operation of the Bulk Electric System. Finally, there is
ongoing disagreement in the industry as to whether it is desired to have a minimum Frequency Bias Setting that is significantly
greater than the Frequency Response Characteristic. Please refer to Order 693 P371 for further information on this issue.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
The drafting team is operating under the Standard Authorization Requests (SARs) as approved. This drafting team believes that
proposing a generator requirement is beyond the scope of the SARs. To the extent that the commenter believes there is a need to
have a reliability standard related to generators, the drafting team would suggest that the commenter submit a SAR to begin the
development process.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO
can go back in time to the previous year. This creates a double jeopardy to R1 of the
standard. It also may include irrelevant data if there have been changes from one
year to the next in FRO or Bias settings assigned by the ERO.
On Frequency Response Obligation, first paragraph states that "Each Interconnection
will establish target contingency protection criteria"; however, the Interconnection is
not a decision-making body. Does this really mean the ERO will establish FRO for each
Interconnection?
The single asterisk note for the table on page 2 states: "It is extremely unlikely that an
event elsewhere in the Eastern Interconnection would cause the Florida UFLS special
protection scheme to “false trip”.", "Special protection scheme" should be stricken
from this sentence, Florida has just a regional difference in its UFLS program.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
Consideration of Comments: Project 2007-12 Frequency Response
11
8
002972
Organization
Yes or No
Question 6 Comment
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Salmon River Electric
Cooperative
Negative
We feel that the drafting team has done an excellent job of providing clarify and
reasonable reporting requirements to the right functional entity. We support the
modifications but would like to have two additional minor modification in order to
provide additional clarification to the Attachment I Event Table. We suggest the
following clarifications: For the Event: BES Emergency resulting in automatic firm load
shedding Modify the Entity with Reporting Responsibility to: Each DP or TOP that
experiences the automatic load shedding within their respective distribution serving
or Transmission Operating area. For the Event: Loss of Firm load for = 15 Minutes
Modify the Entity with Reporting Responsibility to: Each BA, TOP, DP that experiences
the loss of firm load within their respective balancing, Transmission operating, or
distribution serving area. With these modifications or similar modifications we fully
support the proposed Standard.
Response: The drafting team understands that this comment was submitted under the wrong project.
FMPP
No
o Item 2 should be changed as follows: The ERO will identify at least 25 frequency
excursion events in each Interconnection for calculating the Frequency Bias Setting
and the FRM. If the ERO cannot identify in a given evaluation period 25 frequency
excursion events satisfying the limits specified in criteria 3 below, then similar
acceptable events from the previous evaluation period also satisfying listed criteria
will be included with the data set by the ERO for determining FRS compliance. (as
written this item could cause double jeopardy for event from the previous period)
o Under FRO for the Interconnection the first sentence should be changed as follows:
“The ERO {Each Interconnection (delete these words)} will establish target
Consideration of Comments: Project 2007-12 Frequency Response
11
9
002973
Organization
Yes or No
Question 6 Comment
contingency protection criteria for each Interconnection.” (each Interconnection is
not a governing entity)
o The footnote under Table 2 of Attachment A should be changed as follows: The
Eastern Interconnection set point listed is a compromise value for the highest UFLS
step setting of 59.5Hz used in the east and the {special protection scheme’s (delete
these words)} highest UFLS step setting of 59.7Hz used in Florida. It is extremely
unlikely that an event elsewhere in the Eastern Interconnection would cause the
Florida UFLS {special protection scheme (delete these words)} to “false trip”. (this is
not a special protection system; it is just an UFLS)
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Seattle City Light
No
o LADWP and SCL consider the increase in number of events to analyze (now 25) to
be excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. SCL suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
Consideration of Comments: Project 2007-12 Frequency Response
12
0
002974
Organization
Yes or No
Question 6 Comment
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not used consistently across the industry.
Manitoba Hydro
No
1. p.2 refers to each “Interconnection” establishing target contingency protection
criteria. However, an “Interconnection” as defined in the NERC Glossary is an
electrical system, not a Responsible Entity. This should be revised to clarify which
Responsible Entities must establish the protection criteria.
2. Table 2, although entitled “Interconnection Frequency Response Obligations” does
not use the term FRO in the Table itself. This terminology should be consistent.
3. There is no clear statement in Attachment A identifying the significance of Table 2.
The previous paragraph identifies Table 2 as listing “default targets”, but how does
this relate to the FRO referenced in R1?
4. The “Note” on p.2 regarding the ERO being able to use additional events that don’t
satisfy the criteria is unreasonable as drafted. Since these events are used to
calculate the Frequency Bias Setting and FRM (as per p.1, s.2), the selection of events
should not be at the unfettered discretion of the ERO. As drafted, no grounds or
criteria must be satisfied.
Response:1. The drafting team modified the language to clarify that the ERO will set the IFRO.
2. The drafting team modified the table to ensure consistent terminology is used.
3. The drafting team modified Attachment A to clarify the importance and explain the calculations made to get to the
Interconnection FRO.
4. The drafting team revised the note to clarify that the ERO may use any event, regardless of size or other condition, in its
evaluation of Interconnection Frequency Response. However, these additional events will not be used for evaluation of BA
response compliance.
FPL
No
3. - How many seconds of observation for “Delta F”? Does “Point C” in a. refer to
“Figure 1 - Classic Frequency Excursion and Recovery” from NERC’s Survey
Consideration of Comments: Project 2007-12 Frequency Response
12
1
002975
Organization
Yes or No
Question 6 Comment
Instructions document dated September 1, 2010? If so it should be included in this
document along with the added 8 and 18 second time lines being shown. What is a
“narrow range” in item b.?
4. - Better define “relatively steady” (i.e. within a specific range and state it?) Also,
“near 60.000 Hz” is not precise enough (i.e. if the event begins below 60.000 Hz, what
range or time error correction is to be considered acceptable?) Is the “A” value also
part of the figure cited in 3?
5. - Is the “B” value also part of the figure cited in 3?
6. - Change “should be excluded” to “will be excluded”.
7. - Better explain “the cleanest 2 or 3 frequency excursion events” or remove the
word “cleanest”.
Page 2 paragraph 5: Provide specific dates for the “quarterly postings” and where
these will be posted (i.e. Internet address or other). Clarify the December 15 ERO
annual post date with the dates stated for same posting on Page 3 paragraph 5 and
the BA’s January 10 deadline. The BA posts 30 days from which date? This is
confusing.
Page 2 Table 2: What of starting event frequencies that are < 60 Hz? Why is the
“Highest UFLS” 59.6 when the Florida setting for its load is 59.7?
Page 3 FRO equation: Page 4 of the “Frequency Response Standard Background
Document, October 2011” also shows this equation but uses different terms. Make
the same on both documents. In the Background Document each component of the
numerator is explained and reference is made to FERC Form 714 to obtain these
values. There is no reference to this form for the denominator values. All of this
needs to be made clear with reference to FERC Form 714 on Attachment A.
Response: 3. The SDT has modified the titles of the columns in Table 1 of the Procedure document to clarify what was intended by
the table. The Point C value is defined in section 3a.
Consideration of Comments: Project 2007-12 Frequency Response
12
2
002976
Organization
Yes or No
Question 6 Comment
4 - Due to the complicated nature of event evaluation and selection, the drafting team has retained the words “relatively steady”
and “near 60” in the document without providing further clarification or definition. The drafting team believes that the process
being developed by NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some
leeway. As more experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
5 – No, the B value is a calculated value not shown in the chart referenced in number 3 above. Additional language has been
added in Attachment A to clarify both the A value and the B value. The A and B values are shown on Figure 2 of the Background
document as green and red lines, respectively.
6 – The drafting team modified this language.
7 – Due to the complicated nature of event evaluation and selection, the drafting team has retained the word “cleanest” in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
NERC is developing this part of the process and an area to post this information. The drafting team has put clear language in the
attachment requiring at least quarterly posting of events. It is currently the drafting team’s expectation that a list of potential
events would be posted shortly after they actually occur and a refined list will be made available quarterly.
Modifications to Table 2 have been made to clarify what is being used.
Attachment A and the Background Document have been modified so that the FRO Allocation equation is the same and the terms
are fully explained.
Tucson Electric Power
No
Attachment A creates additional requirements to the BAL-003-1 Standard. The
arrested value of frequency observed within 8 seconds may not be long enough in
some instances.
The delta F in the West should be greater than 0.05 Hz to ensure a measurable
frequency response.
West Under Frequency should be set at 59.95 Hz. There is no reliability concern for
Over Frequency.
Does 18 seconds after the start of the disturbance set point B?
Consideration of Comments: Project 2007-12 Frequency Response
12
3
002977
Organization
Yes or No
Question 6 Comment
Pre-disturbance frequency should be relatively steady and near 60.000 Hz is vague.
TEP feels that the ERO should not need to validate a BAs frequency bias setting.
Response: The drafting team has modified the standard to put the requirements there and use Attachment A to clarify the
process.
After further discussion and review of the events in the Western Interconnection Form 1 for 2011, the drafting team has modified
the Delta C and Under Frequency values in Table 1.
Based on language in Order 693 P355, the drafting team believes that frequency response is needed in both directions, not just
one.
The drafting team has revised the language in the document to provide clarity on the 18 seconds. To the extent that the language
related to a specific definition of steady frequency, this has been worded intentionally to allow the process being developed by
the ERO (specifically the Resources Subcommittee and the Frequency Working Group) to be adjusted based on experience that
will only be gained through evaluation of actual events over the course of the next few years. Until that experience is gained,
there will need to be some leeway in the process. The drafting team believes that the level of guidance provided in Attachment A
is appropriate based on the information currently available.
Due to level of detail being used to determine the FBS and FRM as well as the interactions between this standard and others, the
drafting team disagrees with the commenter and continues to recommend the ERO validate the FBS of each BA.
Bonneville Power
Administration
No
BPA believes that Attachment A adds additional requirements to the standard.
Confusion exists between Attachment A and the Background Document. Attachment
A states peak load allocation is based on “Projected” Peak Loads and Generation, but
the Background Document states it will use “historical” Peak Load and Generation.
3a: it may take longer than 8 seconds in some disturbances. This should be 10
seconds. .05 Hz Delta F is not low enough for the Western Interconnection, it should
be .075Hz to ensure there is measurable frequency response for the interconnection.
Also, under frequency should be set at 59.95 Hz. BPA does not believe there is a
reliability need to include over frequency events.
Consideration of Comments: Project 2007-12 Frequency Response
12
4
002978
Organization
Yes or No
Question 6 Comment
3b: It is unclear if the 18 seconds is setting the B point. If this is the B point, BPA
believes it should be changed to 25 seconds for the Western Interconnection.
4. Please define relatively steady and near 60 Hz.
6: For the Western Interconnection, BPA believes this needs to be 10 minutes at the
top of the hour. As mid hour scheduling becomes more prevalent, the ramping at the
bottom of the hour will have to be taken into account.
FRO for the interconnection: Starting frequency should be the FTL limit. With RBC in
place, the frequency is seldom at 60 Hz.
BPA understands the theory behind setting the base obligation to the values listed in
table 2. BPA would like to know if there were any studies performed to validate
setting the FRO for the interconnection to such a low level?
BA FRO and frequency bias setting: BPA does not agree with ERO assigning a
Frequency Bias setting to each BA. This calculation is indicated as the initial FRO
allocation, what is the process for changing it? BPA believes this should go through
the standard drafting process for any changes. The calculation should use Peak
online capacity, not the installed capacity. This would lead to the denominator being
2 X Peak projected load for the interconnection. BPA has approximately 35,000 MW
of installed generation, and has never seen the actual coincidental generation go over
21,000 MW.
Again, BPA doesn’t believe the ERO should be validating the frequency bias setting. It
is unclear to BPA how variable bias is being addressed in the standard.
Response: The drafting team has modified the requirements to address comments. The drafting team believes as modified the
requirements are stated in the standard and the process to be used is in the Attachment.
The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for the
allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection.
The drafting team has revised the language in the document to provide clarity on the 18 seconds. The drafting team has also
Consideration of Comments: Project 2007-12 Frequency Response
12
5
002979
Organization
Yes or No
Question 6 Comment
attempted to clarify that the B Value is the average of the scan rate data for the period from 20 to 52 seconds following the start
of the event. The event selection criteria will use the frequency approximately 18 seconds (prior to the start of the B Value period)
to as frequency level to determine if the change in frequency qualifies as an event for the purposes of this standard. Based on
event information for the 12 month period beginning December 2010, the drafting team has modified the frequency levels used
for event qualification but did not modify the 18 second frequency point.
To the extent that the language related to a specific definition of steady frequency, this has been worded intentionally to allow
the process being developed by the ERO (specifically the Resources Subcommittee and the Frequency Working Group) to be
adjusted based on experience that will only be gained through evaluation of actual events over the course of the next few years.
Until that experience is gained, there will need to be some leeway in the process. The drafting team believes that the level of
guidance provided in Attachment A is appropriate based on the information currently available.
Both the NERC Resources Subcommittee (RS) and the NERC Transmission Issues Subcommittee (TIS) evaluated the level of
response needed. The drafting team decided to use the limits determined by the RS over that determined by the TIS after
evaluation of both. The documents developed by both of these subcommittees are available on the NERC website under this
project (http://www.nerc.com/filez/standards/Frequency_Response-RF.html).
The drafting team clarifies that the ERO is not assigning the Frequency Bias Setting. The ERO will review the data to determine
that the Frequency Response Measure is correctly determined by the BA and that the Frequency Bias Setting is therefore correct.
The expected process is that a subcommittee under NERC will review the Form 1 and Form 2 for each entity to ensure that the BA
correctly filled out the form. Assuming the BA has correctly filled out these forms, there is no ERO interaction with the number
provided by the BA.
The FRO calculation is being included in the Attachment A to ensure that the process to modify the calculation would need to be
open to industry input. It is not appropriate to put it in a requirement since it would not make sense to make a requirement that
the FRO be allocated in a certain manner. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
The drafting team revised the requirements to separate the variable bias requirement from the fixed bias setting requirement and
provide clarity related to what is expected in a variable bias setting.
Energy Mark, Inc.
No
Comment 6: “If the ERO cannot identify in a given evaluation period 25 frequency
excursion events satisfying the limits specified in criteria 3 below, then similar
acceptable events from the previous evaluation period also satisfying listed criteria
Consideration of Comments: Project 2007-12 Frequency Response
12
6
002980
Organization
Yes or No
Question 6 Comment
will be included with the data set by the ERO for determining FRS compliance." I
believe that the better alternative in this case would be to use the lesser number of
events. This is partly based on the consideration that if there are fewer events, the
risk to the interconnection for that year was less that expected, and as a result,
evaluation of fewer events will not compromise interconnection reliability. If fewer
than 25 events are available in any year, the selection criteria should be adjusted to
select more events.
Comment 7: There are a number of problems with the use of "median" Frequency
Response of the measured events. These problems make a choice other than median
preferable. The following comments list some of those problems.
Comment 8: The current standard uses average Frequency Response of selected
events. This makes the current standard incompatible with the use of median.
Comment 9: If a BA reconfigures during a measurement year, that reconfiguration
will create a bi-modal distribution of the Frequency Response events. Median is
incapable of representing a bi-modal distribution. The use of median will result in a
standard that is incapable of measuring compliance effectively for an BA that is
reconfigured during a measurement year (Dec 1 thru Nov 30).
Comment 10: Any attempt to purchase additional Frequency Response from another
BA for a portion of a measurement year will also cause a bi-modal distribution
making the purchase of Frequency Response only effective for entire measurement
years.
Comment 11: Median is a non-linear measurement method. Because it is a nonlinear measurement method, there is no valid way to manage partial year
measurements.
Comment 12: I will offer an alternative to median to the SDT before the end of the
development of responses to these comments.
Comment 13: The Minimum Frequency Bias Setting and the Frequency Response
Obligation are both based on a method that assigns responsibility based on a Peak
Consideration of Comments: Project 2007-12 Frequency Response
12
7
002981
Organization
Yes or No
Question 6 Comment
Load / Peak Generation share of the interconnection. However, the method used to
set the Minimum Frequency Bias Setting is different than the method used to
determine the Frequency Response Obligation. Using these two different methods
could result in the Minimum Frequency Bias Setting being less that the FRO for a BA.
The best way to correct this problem is to use that same allocation methodology for
determining the FRO and the Minimum Frequency Bias Setting. This can be easily
accomplished by modifying R5 to use the FRO allocation method to determine the
Minimum Frequency Bias Setting. This calculation would divide the numerator from
the FRO allocation equation, divide it by two and multiply it by the percentage
specified in Attachment B. In fact, the current FRS Form 1 uses this equation with
projected rather than historic data. The best alternative would be to modify the R5 in
the standard to match the FRO allocation method and modify FRS Form 1 to use
historic data instead of projected data. This would result in only one set of Peak Load
and Peak Generation data throughout the standard, rather than three different sets
of data as currently written. When multiple sets of the same or similar data are used
within a single standard, it only creates confusion and errors in the result.
Response: Comment 6: The studies from the field trial show a convergence of the measurement after approximately 20 to 25
events. Based on the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to
fail inappropriately due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure
that the events picked are not weighted in such a way to cause the measurements to be increased over actual response. The
drafting team has attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate
the FRM. Finally, the calculation process is being used for more than the previous process, not to mention that the previous
process is not clearly defined and therefore not used consistently across the industry.
Comment 7-12: The drafting team is recommending use of the median for the purposes of determining a BA FRM over multiple
events. This decision is based on the determination that, while it may not be perfect, it is better than the other alternatives
available at this time. The drafting team recognizes that in the future a better methodology might be found; based on the data
available at this time the median allows us to move forward to implement a response requirement.
Comment 13: The drafting team understands your concern of using the historical numbers for the FRO allocation and the
projected number as the basis for the minimum Frequency Bias Setting. However, after discussions, the drafting team believes
Consideration of Comments: Project 2007-12 Frequency Response
12
8
002982
Organization
Yes or No
Question 6 Comment
that at this time, minimizing the changes to the current Frequency Bias Setting process provides better comparability for the
purpose of evaluating the impacts of reducing the minimum setting requirement. In the alternative, the drafting team feels that
allocating the FRM based on historical data provides less room to game the process since the numbers used for allocation can be
verified independently.
MRO NSRF
No
Confusion exists around the “peak load” in that Attachment A states the allocation is
based on Projected Peak Loads and Generation but the Background Document states
it will use a historical Peak and Generation to make the allocation. Also, for the BA
installed capacity, where is that value derived from and does NERC obtain that from
FERC form data or does the BA provide that information somewhere specific to this
effort? Additionally, there appears to be a difference in how FRO is calculated in
Attachment A and what is described in the Background Document. These differences
should be reconciled such that both documents address the same approach.If
installed capacity is used in the equation, how are variable/intermittent resources
(e.g. wind, solar) accounted for? At full capacity? Please clarify.We suggest the SDT
clarify if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or “Technical Background”, or “requirements
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
Xcel Energy
No
Confusion exists around the “peak load” in that the Attachment A states the
allocation is based on Projected Peak Loads and Generation but the Background
Document states it will use a historical Peak and Generation to make the allocation.
Also, for the BA installed capacity, where does that value come from and does NERC
obtain that from FERC form data or does the BA provide that information somewhere
specific to this effort? Additionally, there appears to be a difference in how FRO is
calculated in Attachment A and what is described in the Background Document.
These differences should be reconciled such that both documents address the same
Consideration of Comments: Project 2007-12 Frequency Response
12
9
002983
Organization
Yes or No
Question 6 Comment
approach.If installed capacity is used in the equation, how are variable/intermittent
resources (e.g. wind, solar) accounted for? At full capacity?
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and monthly peak generation (monthly peak) and does not use installed capacity.
ISO/RTO Council Standards
Review Committee
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two
separate documents (Attachments A and B), the modified Attachment A is
problematic. As many commenters indicated, the previous Attachment A, other than
the section providing guidance on event selection, appears to be explanatory,
contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment
A should include only the event selection process and calculations associated with
the requirements, including an explanation of what is necessary if variable Frequency
Bias Settings are implemented. If other "requirements" need to be specified, such as
the reporting time frame stipulated on P. 3 of Attachment A, they should be moved
to the standard itself but not imbedded in an attachment. We suggest that the SDT
first determine if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as-written Attachment A is a mix bag as it on the one hand describes the ERO’s
process for supporting the Frequency Response Standard (FRS), in other words, the
method and criteria it uses to calculate the frequency bias settings and the FRM, and
on the other hand the BA’s obligations to support this process. We strongly disagree
that the latter requirements be imbedded in an attachment, especially one that is
supposed to provide the technical background and guideline for another entity which
is not held responsible for complying with the proposed method. Further, there are
no measures provided for the requirements stipulated/imbedded in Attachment A so
how can the Responsible Entity (BA, in this case) be assessed for compliance?We
Consideration of Comments: Project 2007-12 Frequency Response
13
0
002984
Organization
Yes or No
Question 6 Comment
suggest the SDT move those requirements on the BA to the main standard, and turn
Attachment A into an appendix describing the calculation process. An appendix is not
regarded as a mandatory requirement. Similar comments apply to Attachment B.
Moreover, if the Attachments are to be integral to the standards, the terminology
“may” must be replaced with “shall”.
Finally, the two Attachments are listed in Section F - Associated Documents. This
Section is generally used to list reference documents that are NOT standard
requirements. We suggest the SDT review and revise this listing depending on its final
determination of the status of the two Attachments (or their revisions, where
appropriate).
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry. As to the use of the term “may” in the
attachment, at this time the drafting team is unable to further restrict the language due to the issues surrounding an individual
event. As an example, frequency is scheduled at 60 Hz most of the time. However, when viewed on a graph or an EMS screen, it
rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005. The drafting team is unable to say at this
time that an event that starts with frequency at 60.005 is materially different that an event that starts at 59.995. Therefore, the
drafting team has attempted to put guidance into the document as to what is pertinent without attempting to be overly
restrictive in the selection criteria since there is no support for a restriction at this time. As more experience is gained, the process
should be refined. It the refinement is significant enough to require a change to the Attachment A language, the process required
to do so would be open to participation of industry and not done without public exposure.
The SDT agrees with your comment about removing the documents from Section F of the proposed standard has made this
modification to the standard.
Independent Electricity
No
Despite the SDT’s good faith effort to convert the previous Attachment A into two
separate documents (Attachments A and B), the modified Attachment A is
Consideration of Comments: Project 2007-12 Frequency Response
13
1
002985
Organization
Yes or No
System Operator
Question 6 Comment
problematic. As many commenters indicated, the previous Attachment A, other than
the section providing guidance on event selection, appears to be explanatory,
contextual, and instructional in content. These aspects are important, but do not rise
up to the level of requirements to drive reliability performance/outcome. Attachment
A should include only the event selection process and calculations associated with
the requirements, including an explanation of what is necessary if variable Frequency
Bias Settings are implemented. If other "requirements" need to be specified, such as
the reporting time frame stipulated on page 3 of Attachment A, they should be
moved to the standard itself but not imbedded in an attachment. We suggest the SDT
to first determine if the materials in the revised Attachment A (and Attachment B) are
“Guideline” or “Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as-written Attachment A is a mix bag as it on the one hand describes the ERO’s
process for supporting the Frequency Response Standard (FRS) (in other words, the
method and criteria it uses to calculate the frequency bias settings and the FRM), and
on the other hand the BA’s obligations to support this process. We strongly disagree
that the latter requirements be imbedded in an attachment, especially one that is
supposed to provide the technical background and guideline for another entity
which, by the way, is not held responsible for complying with the proposed method.
Further, there are no measures developed for the requirements stipulated/imbedded
in Attachment A so how can the Responsible Entity (BA, in this case) be assessed for
compliance?
We suggest the SDT to move those requirements on the BA to the main standard,
and turn Attachment A into an appendix describing the calculation process. An
appendix is not regarded as a mandatory requirement. Similar comments apply to
Attachment B.
Finally, the two Attachments are listed in Section F - Associated Documents. This
Section is generally used to list reference documents that are NOT standard
requirements. We suggest the SDT review and revise this listing depending on its final
determination of the status of the two Attachments (or their revisions, where
Consideration of Comments: Project 2007-12 Frequency Response
13
2
002986
Organization
Yes or No
Question 6 Comment
appropriate).
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments and modified them to address the concerns raised by
the comments that requirements were in the Attachments. In order to explain the process, the drafting team believes the
information needs to be attached to the standard such that it cannot be changed without input from the industry. As to the use of
the term “may” in the attachment, at this time the drafting team is unable to further restrict the language due to the issues
surrounding an individual event. As an example, frequency is scheduled at 60 Hz most of the time. However, when viewed on a
graph or an EMS screen, it rarely sits at 60.000 for a long period of time, it fluctuates between 59.995 and 60.005. The drafting
team is unable to say at this time that an event that starts with frequency at 60.005 is materially different that an event that starts
at 59.995. Therefore, the drafting team has attempted to put guidance into the document as to what is pertinent without
attempting to be overly restrictive in the selection criteria since there is no support for a restriction at this time. As more
experience is gained, the process should be refined. It the refinement is significant enough to require a change to the Attachment
A language, the process required to do so would be open to participation of industry and not done without public exposure.
The SDT agrees with your comment about removing the documents from Section F of the proposed standard has made this
modification to the standard.
Florida Power & Light
Company
No
In the table on page2 the asterick references a statement that the 59.7Hz used in
Florida is a special protection scheme. This is incorrect. The special protection
scheme setting was 59.82Hz and was done away with in 2005 or earlier. The 59.7Hz
setting used within the FRCC is based on FRCC TWG studies that require this level of
setting to protect the state in the event of a separation and to protect nuclear
equipment. FPL supports the use of the C(N-2) critiera. Additionally, the reference to
the FERC714 report that is currently in the background data should be made part of
attachment A not separated. FPL fully agrees with Table 1The formula used to derive
the FRO is inconsistant with the definition used for requirement R5. R5 states that
the load is " within the BA's metered boundary". The load used in the formulae is
taken from FERC714. The yearly peak demand used in R5 should be the peak
Consideration of Comments: Project 2007-12 Frequency Response
13
3
002987
Organization
Yes or No
Question 6 Comment
monthly load from June, July or August as reported on FERC714 to be compatible
with the FRO formula.
Response: The drafting team has removed the reference to the special protection scheme. The drafting team has modified the FRO
allocation formula to better explain what is desired. However, the drafting team did not adjust the formula to what is suggested
by the commenter.
NV Energy
No
It is not clear whether the calculation of FRO is to utilize projections of BA load as in
Att A, or past data reported in FERC Form 1 as per the Background Document.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
Los Angeles Department of
Water and Power
No
LADWP considers the increase in number of events to analyze (now 25) to be
excessive. Previous years analyses typically involved 4-6 events; a permanent fivefold increase is not justified. LADWP suggests reducing the baseline number of events
from 25 to 12 per year. Analysis of a larger number of events could be requested on a
year-by-year basis if conditions warrant, but should not be mandatory for all regions
in all years.
Response: The studies from the field trial show a convergence of the measurement after approximately 20 to 25 events. Based on
the studies, the drafting team believes that a sample size as suggested would be very likely to cause entities to fail inappropriately
due to the large amount of noise in the data related to each event. Additionally, there is a desire to ensure that the events picked
are not weighted in such a way to cause the measurements to be increased over actual response. The drafting team has
attempted to minimize the effort required of the reporting entities by developing the forms needed to calculate the FRM. Finally,
the calculation process is being used for more than the previous process, not to mention that the previous process is not clearly
defined and therefore not used consistently across the industry.
JEA Electric
No
On Event Selection Criteria, bullet 2, if 25 events cannot be identified then the ERO
Consideration of Comments: Project 2007-12 Frequency Response
13
4
002988
Organization
Yes or No
Compliance/Florida Municipal
Power Agency
Question 6 Comment
can go back in time to the previous year. This creates a double jeopardy to R1 of the
standard. It also may include irrelevant data if there have been changes from one
year to the next in FRO or Bias settings assigned by the ERO.
On Frequency Response Obligation, first paragraph states that "Each Interconnection
will establish target contingency protection criteria"; however, the Interconnection is
not a decision-making body. Does this really mean the ERO will establish FRO for each
Interconnection?
The single asterisk note for the table on page 2 states: "It is extremely unlikely that an
event elsewhere in the Eastern Interconnection would cause the Florida UFLS special
protection scheme to “false trip”.", "Special protection scheme" should be stricken
from this sentence, Florida has just a regional difference in its UFLS program.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
The drafting team modified the language to clarify that the ERO will set the IFRO.
This modification was made.
Duke Energy
No
On page 3 of the document it states “For a multiple Balancing Authority
Interconnection, the Interconnection Frequency Response Obligation is allocated
based upon either the Balancing Authority Peak Demand or peak generation”,
however, the initial FRO allocation equation shows that the BA allocation is based
upon the sum of the Projected BA Peak Load plus installed capacity, times the
Interconnection FRO, and divided by the sum of the Projected Interconnection Peak
Load plus Interconnection installed capacity. Is the statement in quotes correct, or is
the allocation equation correct? In addition, the equation in Attachment A
referencing “installed capacity” conflicts with the equation in the BAL-003-1
Consideration of Comments: Project 2007-12 Frequency Response
13
5
002989
Organization
Yes or No
Question 6 Comment
Background Document entitled “Frequency Response Standard Background
Document” where “Peak Gen” is used. In summary, is the FRO allocation based upon
an equation which a) sums the Projected BA Peak Load plus peak generation, b) sums
the Projected BA Peak Load plus installed capacity, or c) uses either Projected BA
Peak Load OR peak generation? All three options are currently represented in the
documentation.
Calculation of the FRO for the Eastern Interconnection: Duke Energy agrees with the
criteria suggested for the event to be protected (4500 MW), and at this time also
agrees with the “compromise” low limit of 59.6 Hz. However, knowing that another
Standard is under development which may require hourly assessment of available
“frequency responsive reserves”, we are trying to determine what impact the choice
of this methodology will have on the amount of frequency responsive reserves the
industry will have to maintain - enough to cover frequency swings that only
occasionally reach down to perhaps 59.9 Hz as we see on the Interconnection today
(essentially the allocated FRO for a 0.1Hz deviation), enough to cover a 4500 MW
loss, or whatever we deem appropriate as long as we are compliant to the FRM? We
recognize that the Standard Drafting Team cannot answer this question, as the
Standard under development is not within the scope of this team, however our
comment is meant to illustrate the point that similar to our response to question 8, it
should be recognized that elements of this Standard are tightly coupled to other
current and potential Standards, and the impacts must be considered by the Industry.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency Response for
which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency Response equal to
a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Consideration of Comments: Project 2007-12 Frequency Response
13
6
002990
Organization
SERC OC Standards Review
Group
Yes or No
Question 6 Comment
No
The definition of Single Event Frequency Response Data (SEFRD) was struck from the
draft standard but still appears in Attachment A. Since R1 of the standard references
Attachment A, would the definition of SEFRD still be applicable? If the definition is to
be totally struck, we don’t think the term should be used in Attachment A.
Response: The SEFRD definition was moved to Attachment A. The SEFRD is used on individual events. The median of a BA’s SEFRDs
will be used to determine its FRM. Therefore, the drafting team believes it is appropriate to use the definition in the Attachment.
Since it is not likely to be used outside of the context of this standard, the drafting team is not proposing to place the definition in
the NERC Glossary.
Hydro-Quebec TransEnergie
No
The Event Selection Criteria should be modified for the Quebec Interconnection. In
Table 1, the change in frequency (Delta f) used for Quebec’s Event Selection Criteria
should be 0,3Hz (from point “A” to point “C”) and must last for at least 7 seconds so
that we don’t measure AGC action. In addition, a criterion should be added by saying
that events that recovered within the 20-52 second average period for point “B”
should be excluded from analysis.
Response: The drafting team has modified Attachment A to address these comments.
Keen Resources Asia Ltd.
No
The sample pre-selection described in Attachment A, Event Selection, Criteria 2 & 7,
violates the fundamental statistical procedure of unbiased sampling. A population is
governed by a single "process" which, when stationary, is represented by a fixed
probability distribution. In this case the population is several years of events (which
are the subject of Frequency Response), not of normal operating control errors which
are the subject of CPM control. A sample is governed by a single process that
approximates the process governing the population as the sample gets larger, in this
case if it includes several years of data. Samples are measured "as they come", no
triage/filtering allowed, and they are called "stratified" when their distribution
approximates the population distribution. Unlike normal operating errors, samples of
events are not evenly distributed over a year. The attempt in criteria 2 & 7 to preselect only certain events, and not others, in such a way that the selected events
Consideration of Comments: Project 2007-12 Frequency Response
13
7
002991
Organization
Yes or No
Question 6 Comment
occur evenly throughout the year, is papently wrong because it is trying to "fit"
events into a process (even distribution over time) that does not govern events, but
that instead governs normal operating errors that are the subject of CPM control, not
of this Frequency Response standard. In other words, criteria 2 & 7 confuse
Frequency Response with CPM, and events with normal operating errors. The result
is a false, biased sample which destroys the integrity of this standard. Paragraph 4 on
page 5 of the Background Document, on the other hand, provides a statistically
correct description of event selection without sample pre-selection and should
followed instead of the erroneous criteria 2 & 7 in Attachment A.
Response: The drafting team has discussed this issue several times and believes that issues related to measurement caused by
noise in individual events and the need to ensure adequate representation of events throughout the year outweigh the concern to
have a “pure” statistical sample. For these reasons the drafting team has not modified the event selection criteria.
Northeast Power Coordinating
Council
No
The SDT has to first determine if the materials in the revised Attachment A & B are
“Guideline” or Technical Background”, or are they “requirements”. If it is the former,
then Requirement R1 should not mention Attachment A at all. If it is the latter, then
the as written Attachment A is confusing as it describes the ERO’s process for
supporting the Frequency Response Standard (FRS) (the method and criteria it uses
to calculate the frequency bias settings and the FRM), and at the same time the BA’s
obligations to support this process. The latter requirements should not be imbedded
in an attachment, especially one that is supposed to provide the technical
background and guideline for another entity which is not held responsible for
complying with the proposed method. An appendix is not regarded as a mandatory
requirement.
Additionally, regarding BAL-003-1- Attachment A 1. Criterion 5 needs to be re-written
for clarity.
2. Criterion 7 refers to “cleanest events”. A statement of what constitutes a “clean
event” is needed to avoid possible controversy in the future.
Consideration of Comments: Project 2007-12 Frequency Response
13
8
002992
Organization
Yes or No
Question 6 Comment
3. The use of 59.6 Hz as the highest UFLS setting is flawed. It should either be 59.7 Hz
as a deliberate choice to protect Florida interests, or it should be 59.5 Hz without
concern for Florida’s unique settings.
4. In the last 2 sentences at the end of the section on Frequency Response Obligation,
it refers to an Interconnection being able to offer “alternate FRO protection criteria”.
The Interconnection should have been an integral part of establishing its obligation.
It is stated that the “ERO will confirm” the “alternate FRO protection criteria”. Does
this mean the ERO unconditionally approves it, or evaluates with a right of rejection?
Please clarify.
5. In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Does the industry have a clear and consistent definition for installed
capacity? Also, with greater wind energy development, the delivered capacity over
longer time horizons will be substantially less than nameplate machine ratings. The
background document refers to the use of peak generation instead of installed
capacity. Which shall be used? Please clarify.
6. Recent studies have shown that the 18-52 second sampling interval does not work
well for the Quebec Interconnection, in part due to the excellent and high level of
response found in that Interconnection. The standard needs to be modified such that
the sampling interval is that which works the best for each individual interconnection.
7. Attachment A needs to define the point A sampling interval.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The drafting team believes that Criterion 5 is clear as written. The comment does not provide any guidance as to what needs
Consideration of Comments: Project 2007-12 Frequency Response
13
9
002993
Organization
Yes or No
Question 6 Comment
clarification so no change was made.
2. Due to the complicated nature of event evaluation and selection, the drafting team has retained the word “cleanest” in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
3. The drafting team has revised the terminology used to explain the frequency levels proposed. There was not a change to the
Eastern Interconnection numbers.
4. An interconnection can recommend a change to the table. As the standards process currently works, that interconnection
would need to support its alternative level with data. If the interconnection has a single Regional Reliability Organization, the ERO
would typically agree to the alternative assuming it would be more restrictive (in this case a larger response requirement) than
the ERO has recommended.
5. The drafting team has addressed the concerns raised by clarifying that historical data is used for the allocation of an
Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is not used in the
allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak) and peak
generation (monthly peak) and does not use installed capacity.
6. The drafting team has modified Attachment A to address concerns with selection of an event where frequency returns to the A
Value level during the measurement period. These events will be excluded from the measurement process for all
interconnections.
7. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
Sacramento Municipal Utility
District (SMUD)
No
The standard is unclear as to if there is an upper limit to the amount of frequency
response expected of the Balancing Authorities under this standard. Except for Table
2 in Attachment A, there is no discussion of an amount of Frequency Response
expected on a total basis. Balancing Authorities need to know for how many tenths of
a hertz they are to respond so they can determine how to plan to meet this
requirement. The documents do not appear to provide any boundary on the
maximum amount of Frequency Response that a BA will provide, i.e. it is not clear
what will happen if an event occurs in the Eastern Interconnection that causes the
Consideration of Comments: Project 2007-12 Frequency Response
14
0
002994
Organization
Yes or No
Question 6 Comment
frequency to drop to less than 59.6 Hz or in the Western Interconnection that causes
the frequency to drop to less than 59.5 Hz, or if that event is excluded from the list
used to calculate the Balancing Authorities’ response or is it included with an
expectation that it counts the same as any other event. Without a clear statement of
what is expected, including whether there is a limit on that expectation or not, it is
unclear what is expected of the Balancing Authorities.
Response: The drafting team has added a paragraph in the FRM section of Attachment A limiting the amount of Frequency
Response for which a BA will be measured for compliance purposes. This translates to a maximum expectation of Frequency
Response equal to a Balancing Authority’s FRO times the number of .1 Hz shown in Table 2 in Attachment A.
Western Electricity
Coordinating Council
No
There is disagreement between Attachment A and the Background Document.
Attachment A states peak load allocation is based on “Projected” Peak Loads and
Generation, but the Background Document states it will use “historical” Peak Load
and Generation.
The allocation methodology of FRO among the BAs in the equation on page 3 of
Attachment A favors BAs with more load than more installed capacity. Peak load is
served but not all installed capacity is always dispatched.
Response: The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is
not used in the allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak)
and peak generation (monthly peak) and does not use installed capacity.
Alberta Electric System
Operator
No
These documents not only provide additional clarity but also specify additional
requirements, such as FRS Form 1 annual reporting by January 10. All the enforceable
requirements should be included in the body of the standard.
1. Attachment A uses the terms "delta F (change in frequency)", "arresting frequency
(Point C)", "B Value", "A Value". These terms are not properly defined or described in
this document as drafted. The AESO suggests adding a description or definitions for
Consideration of Comments: Project 2007-12 Frequency Response
14
1
002995
Organization
Yes or No
Question 6 Comment
clarity in this document.
2. The standard gives 2 sets of values for Interconnection Frequency Response
Obligation in Table 2, (1) Base Obligation and (2) the obligation including 25% Safety
Margin (which seems to be implied by the "contingency protection criterion"). The
Attachment A does not specifiy whether the Base Obligation or the 25% Safety
Margin value will be used to allocate the Interconnection FRO to the BAs. Please
clarify which value will be used to calculate the BA Frequency Response Obligation
(FRO) in the Interconnection FRO allocation formula in Attachment A.
3. The "initial FRO allocation" formula in Attachment A uses Peak Load. The term
Peak Load is not used in the standard nor is it a defined term in the NERC Glossary.
The standard uses Peak Demand, which is defined in the Glossary Is "Peak Load"
synonymous with "Peak Demand"? If so, Peak Demand should be used in the formula
instead. Otherwise Peak Load should be clearly defined in this document.
4. Is "Projected" in the FRO allocation formula synonymous with "Forecasted"? If so,
Forecasted should be used for consistency. Otherwise "Projected" or the context in
which it appears must be defined.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
2. The drafting team has modified Table 2 to clarify that the bottom number in each column is the Interconnection FRO. The
Interconnection FRO will be allocated to the BAs within that interconnection.
3 and 4. The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used for
the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
Consideration of Comments: Project 2007-12 Frequency Response
14
2
002996
Organization
Yes or No
Question 6 Comment
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
Great River Energy/ACES
Power Marketing Standards
Collaborators
No
Under item 3 of the Event Selection Criteria section, the delta F and Point C should be
described either in this attachment or the “Frequency Response Standard
Background Document”. While many in industry may understand what these terms
mean, history has a way of getting lost with personnel turnover. Furthermore, this
would help ensure that the auditors and industry have a duplicate understanding.
In the Frequency Response Obligation section on page 2, several items require more
description. Further description of why an N-2 event was chosen for the Contingency
Protection Criteria should be provided and which N-2 event was selected so that
industry can help validate if the correct MW value was selected.
Furthermore, the document should clarify if the Contingency Protection Criteria
contains the “safety margin”. There is a statement in the paragraph before the table
that states it does but then the table lists out a separate 25% “Safety Margin”. Thus,
it is not clear if the “Safety Margin” is included in the Contingency Protection Criteria
value listed in the table or not. “Safety margin” should be changed to “reliability
margin”. Safety has a specific meaning in the electric industry and its use here is not
appropriate. The Base Obligation should be explained. The explanation should
include its purpose and origin.
Response: 1. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
The drafting team has clarified Table 2 by modifying the titles for each line.
Texas Reliability Entity
No
We have a number of concerns regarding Attachment A which are set forth below:
1. Regarding the formula for “Initial FRO Allocation” on page 3 of Attachment A, the
terms for “BA installed capacity” and “Interconnection installed capacity” are
undefined and could be subject to manipulation and dispute. We suggest that this
formula be revised to mirror the calculation based on well-established FERC Form 714
data that is discussed in the Background document, which is based on actual
Consideration of Comments: Project 2007-12 Frequency Response
14
3
002997
Organization
Yes or No
Question 6 Comment
generation output.
2. In Attachment A, all references to “Texas” should be changed to “ERCOT” as a
reference to the Interconnection or the Region (including tables).
3. Regarding the Event Selection Criteria in Attachment A: in item 2, consider
whether certain events, such as DCS events, should be required to be included in the
FRM analysis.
4. Regarding the Event Selection Criteria in Attachment A: item 7 provides that the
selected frequency excursion events are to be selected so that they are evenly
distributed seasonally. Consider adding the seasonal distribution concept to item 2,
particularly if it becomes necessary to include events from the previous evaluation
period.
5. In Attachment A, page 1 says the ERO is to post the final list of frequency
excursion events by December 15, but on page 3 it suggests that the list will be
posted by December 10. These references should be made consistent.
6. Attachment A states, on page 3, “the ERO will use FRS Form 1 data to post the
following information for each Balancing Authority for the upcoming year: Frequency
Bias Setting and Frequency Response Obligation (FRO).” What is meant by “the
upcoming year”? Is the BA supposed to implement the new FBS immediately, or wait
until the beginning of the next evaluation period on December 1? Note that if the
new FRO and FBS are implemented immediately (e.g. in March), then the FRO will
change in the middle of an evaluation period. This will complicate the comparison of
FRM and FRO as required by R1.
Response: 1. The drafting team has addressed the discrepancy between the two documents to ensure that historical data is used
for the allocation of an Interconnection Frequency Response Obligation to the BAs within that interconnection. The proposed
methodology uses the average of the historical peak loads (monthly peak) and peak generation (monthly peak) and does not use
installed capacity.
2. This change was made.
Consideration of Comments: Project 2007-12 Frequency Response
14
4
002998
Organization
Yes or No
Question 6 Comment
3. The drafting team recommends all events with a frequency deviation that meets the selection criteria should be evaluated. For
the entity that lost generation (or load) to initiate the event, the calculation methodology proposed allows adjustments to be
made for that event.
4. This modification was made to the Attachment B (now a Procedure). The suggested modifications are shown in Criteria 2 and 7.
5. These two documents have been conformed.
6. The ERO will notify the BAs as to the date the Frequency Bias Setting is to be implemented if they are utilizing a fixed Frequency
Bias Setting.
Southern Company
No
We suggest increasing the delta f for the East to be the same value as the West or
larger. The reason for this is that the 0.04Hz suggested is too close to the governor
deadbands of .036Hz. This would potentially omit frequency response that some
units may provide for a larger excursion but not for those close to the deadband.
Response: The delta f values have been selected to balance the need to have a sufficient number of events for evaluation and the
need to have sufficient frequency movement to actually measure response. At this time the drafting team is not modifying the
eastern interconnection values based on the event selection process for the period December 2010 through November 2011.
ISO New England Inc
No
We suggest the SDT to first determine if the materials in the revised Attachment A &
B are “Guideline” or Technical Background”, or are they “requirements”. If it is the
former, then Requirement R1 should not mention Attachment A at all. If it is the
latter, then the as-written Attachment A is a mix bag as it on the one hand describes
the ERO’s process for supporting the Frequency Response Standard (FRS), in other
words, the method and criteria it uses to calculate the frequency bias settings and
the FRM, and on the other hand the BA’s obligations to support this process. We
strongly disagree that the latter requirements be imbedded in an attachment,
especially one that is supposed to provide the technical background and guideline for
another entity which, by the way, is not held responsible for complying with the
proposed method. An appendix is not regarded as a mandatory requirement.
Additionally, BAL-003-1- Attachment A
Consideration of Comments: Project 2007-12 Frequency Response
14
5
002999
Organization
Yes or No
Question 6 Comment
1. Criterion 5 needs to be re-written for clarity.
2. Criterion 7 refers to the “cleanest events”. Perhaps a statement of what
constitutes a “clean event” is needed to avoid possible controversy in the future.
3. The use of 59.6 Hz as the highest UFLS setting seems flawed. It should either be
59.7 Hz as a deliberate choice to protect Florida interests, or, it should be 59.5 Hz
without concern for Florida’s unique settings.
4. In the last 2 sentences at the end of the section on Frequency Response Obligation,
it refers to an Interconnection being able to offer “alternate FRO protection criteria”.
It seems that the Interconnection should have been an integral part of establishing its
obligation. Also, it states that the “ERO will confirm” the “alternate FRO protection
criteria”. Does this mean the ERO unconditionally approves it, or evaluates with a
right of rejection? Please clarify.
5. In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Does the industry have a clear and consistent definition for installed
capacity? Also, with greater wind energy development, the delivered capacity over
longer time horizons will be substantially less than nameplate machine ratings. Also,
the background document refers to the use of peak generation instead of installed
capacity. Which shall be used? Please clarify.
6. Very recent studies have shown that the 18-52 second sampling interval does not
work well for the Quebec Interconnection, in part due to the excellent and high level
of response found in that Interconnection. The standard needs to be modified such
that the sampling interval is that which works the best for each individual
interconnection.
7. Attachment A needs to define the point A sampling interval.
Response: The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain
date and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
Consideration of Comments: Project 2007-12 Frequency Response
14
6
003000
Organization
Yes or No
Question 6 Comment
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to be
attached to the standard such that it cannot be changed without input from the industry.
1. The drafting team believes that Criterion 5 is clear as written. The comment does not provide any guidance as to what needs
clarification so no change was made.
2. Due to the complicated nature of event evaluation and selection, the drafting team has retained the word cleanest in the
document without providing further clarification or definition. The drafting team believes that the process being developed by
NERC (specifically the NERC Resources Subcommittee and the Frequency Working Group) requires some leeway. As more
experience in gained, the NERC Resources Subcommittee will attempt to document the process further.
3. The drafting team has revised the terminology used to explain the frequency levels proposed. There was not a change to the
Eastern Interconnection numbers.
4. An interconnection can recommend a change to the table. As the standards process currently works, that interconnection
would need to support its alternative level with data. If the interconnection has a single Regional Reliability Organization, the ERO
would typically agree to the alternative assuming it would be more restrictive (in this case a larger response requirement) than
the ERO has recommended.
5. The drafting team has addressed the concerns raised by clarifying that historical data is used for the allocation of an
Interconnection Frequency Response Obligation to the BAs within that interconnection. Installed capacity is not used in the
allocation methodology. The proposed methodology uses the average of the historical peak loads (monthly peak) and peak
generation (monthly peak) and does not use installed capacity.
6. The drafting team has modified Attachment A to address concerns with selection of an event where frequency returns to the A
Value level during the measurement period. These events will be excluded from the measurement process for all
interconnections.
7. The definition of the terms are provided in the background document as well as the formulas in the spreadsheets.
Constellation Energy
Commodities Group
Yes
Additional information relating to defining the FRO for the Interconnection would be
helpful as would an example for calculating the BA FRO.
Response: The drafting team has revised Attachment A to provide better explanation and to clarify the allocation methodology to
Consideration of Comments: Project 2007-12 Frequency Response
14
7
003001
Organization
Yes or No
Question 6 Comment
the BA.
American Electric Power
Yes
A frequency response observation should not be used spanning multiple years, or if
there does, there should at least be a reset period.
Response: The drafting team has discussed the concern of double jeopardy several times. At this time, the drafting team believes
the issue of noise in individual events and the convergence of measurement of multiple events outweighs the double jeopardy
concerns. After further discussions, the drafting team has reduced the minimum number of events in a 12 month period to 20
from 25 but is still recommending that events from a previous year be used for the calculation if this number of events cannot be
found in that period.
Cleco Corporation/ SPP
Standards Review Group
Yes
We appreciate the effort of the SDT in developing Attachment A. It was very helpful
in weeding through BAL-003.
Response: Thank you for your comments.
Imperial Irrigation District
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Associated Electric
Cooperative Inc
Yes
South Carolina Electric and
Gas
Yes
Consideration of Comments: Project 2007-12 Frequency Response
14
8
003002
Organization
Ameren
Yes or No
Question 6 Comment
Yes
Consideration of Comments: Project 2007-12 Frequency Response
14
9
003003
7.
The second document “BAL-003-1 Background Document” provides information behind the development of the
standard. Do you agree that this new document provides sufficient clarity as to the development of the standard? If
not, please explain in the comment area.
Summary Consideration: The majority of the commenters referenced other questions in the comments. The SDT asked them to review
the response to those earlier questions.
Several of the commenters pointed out that there was a discrepancy between the Background Document and Attachment A regarding
the calculation of the BA FRO. The SDT has corrected the reference so both documents agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Some commenters indicated that Supplemental Regulation Service is not an appropriate method to provide Frequency Response. It is
inappropriate to expect supplementary regulation to transfer frequency response successfully. However the SDT does not want to
prevent any innovative solution that will transfer frequency response through the use of a pseudo-tie among Balancing Authorities.
Also, the SDT believes that Balancing Authorities exchanging supplementary regulation via a pseudo-tie have to be consistent in the
removal or inclusion of it in their actual net interchange measurement as well as in all events across the measurement period.
Organization
Yes or No
Seattle City Light
Negative
Question 7 Comment
Answer: Yes Comments: o LADWP and SCL note that the document “BAL-003-1
Background Document” seems to be reasonable.
Response: Thank you for your comment.
Energy Mark, Inc.
No
Comment 14: Some of the information in this document concerning the Frequency
Bias Setting for BAs participating in Overlap Regulation should be moved to the
Supporting Document. This change would help in addressing Comments 3 & 4 under
Question 2.
Response: The SDT has added language to Attachment A to address your concern.
Consideration of Comments: Project 2007-12 Frequency Response
15
0
003004
Organization
Yes or No
Duke Energy
No
Question 7 Comment
Please see our comments to Question 6. In addition, Duke Energy disagrees with the
statement on page 9 that Attachment B will “ensure there is no negative impact on
other Standards” - please see our response to Question 8 for additional information.
Response: Thank you for your comments. Please see the responses to Questions #6 and #8.
SERC OC Standards Review
Group
No
Portions of the Background Document do not appear to be complete or finished. The
Background Document should be edited to be consistent with changes made to the
standard or other related documents (eg. elimination of the definition of SEFRD and
any revisions to the draft BAL-003-1).
Response: The SDT has made significant modifications to the Background Document to support the proposed standard. The SDT is
proposing that this document be posted on the NERC web site in order for it to be easily obtained by stakeholders once the
standard is approved.
ERCOT
No
Refer to comments in #1.
Response: Refer to the response in Question #1.
Northeast Power Coordinating
Council
No
Refer to the first comment in Question 6.For the Frequency Response Standard
Background Document –
1. Cite Attachment B in addition to Attachment A in the discussion of requirement R1.
2. The Balancing Authority allocation method specified in this document does not
agree with that in Attachment A.
3. Drop the speculation on page 4 that most Balancing Authorities will be compliant.
While it may be a commonly held belief by many that there is adequate frequency
response right now, that assessment should be made after a targeted level of
reliability has been defined and approved. The same comment applies on page 12.
4. On page 6, drop the inappropriate recommendation of getting frequency response
Consideration of Comments: Project 2007-12 Frequency Response
15
1
003005
Organization
Yes or No
Question 7 Comment
through supplemental regulation. It is inappropriate to try to substitute a “minute
plus” product that is deployed centrally by the Balancing Authority for a “sub-minute”
product that is deployed automatically without any Balancing Authority action.
When a pseudo-tie is used, changes in the ACE values due to supplemental regulation
are unrelated to and not coordinated with the need to deploy frequency response.
Not only should this approach not be offered as an alternative, but the FRSDT should
actively conduct research to determine if supplemental regulation via a pseudo-tie
should be deliberately REMOVED from any actual net interchange calculation that
may include it. This comment also applies to the mentioning of supplemental
regulation on page 11 as well.
5. On page 7, the reference to a 24 hour window on each side of the frequency bias
setting implementation date is inconsistent with the wording of the standard. The
standard states that any time within the designated date is acceptable.
6. On page 8, the inclusion of “for training purposes” as a reason to not operate in tie
line bias control should be dropped. This training can be done in a training simulator.
If it is determined that it should be supported, then the requirement needs to be
reworded to allow it explicitly.
7. On page 14, the sentence: “This approach would only provide feedback for
performance during that specific event and would not provide insight into the depth
of response or other limitations” is difficult to understand. The paragraph would
read better by simply deleting the sentence.
Response: Please refer to our response to Question #6.
Comment 1 – The SDT has modified the Background Document to incorporate your suggested change.
Comment 2 – The SDT has corrected the reference so both documents agree. The drafting team is proposing to use historical
information rather than forecasted information for the allocation of the Frequency Response Obligation.
Comment 3 – The SDT has removed the speculative language and replaced it with more appropriate language.
Comment 4 - While the SDT agrees that it is inappropriate to expect supplementary regulation to transfer frequency response
Consideration of Comments: Project 2007-12 Frequency Response
15
2
003006
Organization
Yes or No
Question 7 Comment
successfully, we do not want to prevent any innovative solution that will transfer frequency response through the use of a
pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging supplementary regulation
via a pseudo-tie have to be consistent in the removal or inclusion of it in their actual net interchange measurement as well as all
events across the measurement period.
Comment 5 – The SDT has corrected the background document to accurately reflect the language proposed in the standard.
Comment 6 – The SDT has modified the background document to remove the training language.
Comment 7 – The SDT has revised the paragraph to provide additional clarity.
Xcel Energy
No
Same comment here as the one in question 6.
Response: Please refer to our response to Question #6.
ISO New England Inc
No
See first comment in 6 above. Also, Frequency Response Standard Background
Document –
1. Cite Attachment B in addition to Attachment A in the discussion of requirement 1.
2. The Balancing Authority allocation method specified in this document does not
agree with that in Attachment A.
3. Drop the speculation on page 4 that most Balancing Authorities will be compliant.
While it may be a commonly held belief by many that there is adequate frequency
response right now, that assessment should be made after a targeted level of
reliability has been defined and approved. The same comment applies on page 12.
4. On page 6, drop the inappropriate recommendation of getting frequency response
through supplemental regulation. It is inappropriate to try to substitute a “minute
plus” product that is deployed centrally by the Balancing Authority for a “sub-minute”
product that is deployed automatically without any Balancing Authority action.
When a pseudo-tie is used, changes in the ACE values due to supplemental regulation
are unrelated to and not coordinated with the need to deploy frequency response.
Not only should this approach not be offered as an alternative, but the FRSDT should
Consideration of Comments: Project 2007-12 Frequency Response
15
3
003007
Organization
Yes or No
Question 7 Comment
actively conduct research to determine if supplemental regulation via a pseudo-tie
should be deliberately REMOVED from any actual net interchange calculation that
may include it! This comment also applies to the mentioning of supplemental
regulation on page 11 as well.
5. On page 7, the reference to a 24 hour window on each side of the frequency bias
setting implementation date is inconsistent with the wording of the requirement.
The requirement says that any time within the designated date is acceptable.
6. On page 8, the inclusion of “for training purposes” as a reason to not operate in tie
line bias control should be dropped. This sort of training can be done in a training
simulator. Alternatively, if it is determined that it should be supported, then the
requirement needs to be reworded to allow it explicitly.
7. On page 14, the sentence: “This approach would only provide feedback for
performance during that specific event and would not provide insight into the depth
of response or other limitations” is difficult to understand. The paragraph would
read better by simply dropping it.
Response: Please refer to our response to Question #6.
Comment 1 – The SDT has modified the Background Document to incorporate your suggested change.
Comment 2 – The SDT has corrected the reference so both documents agree. The drafting team is proposing to use historical
information rather than forecasted information for the allocation of the Frequency Response Obligation.
Comment 3 – The SDT has removed the speculative language and replaced it with more appropriate language.
Comment 4 - While the SDT agrees that it is inappropriate to expect supplementary regulation to transfer frequency response
successfully, we do not want to prevent any innovative solution that will transfer frequency response through the use of a
pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging supplementary regulation
via a pseudo-tie have to be consistent in the removal or inclusion of it in their actual net interchange measurement as well as all
events across the measurement period.
Comment 5 – The SDT has corrected the background document to accurately reflect the language proposed in the standard.
Consideration of Comments: Project 2007-12 Frequency Response
15
4
003008
Organization
Yes or No
Question 7 Comment
Comment 6 – The SDT has modified the background document to remove the training language.
Comment 7 – The SDT has revised the paragraph to provide additional clarity.
Western Electricity
Coordinating Council
No
See response to question 6.
Response: Please refer to our response to Question #6.
Alberta Electric System
Operator
No
The Background Document uses BA Peak Generation in the BA FRO allocation
formula. Attachment A uses BA Installed Capacity. The AESO suggests making the two
formulae consistent.
Response: The drafting team has corrected the reference so both documents agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Florida Municipal Power
Agency
No
The document does not discuss how the new reliability parameter will affect BAs
Response: The new standard will require that Balancing Authorities meet a level of response to frequency events equal to or more
negative than their Frequency Response Obligation. The SDT has made significant modifications to the Background Document
which should address your concern.
JEA Electric Compliance
No
The document does not discuss how the new reliability parameter will affect BAs
Response: The new standard will require that Balancing Authorities meet a level of response to frequency events equal to or more
negative than their Frequency Response Obligation. The SDT has made significant modifications to the Background Document
which should address your concern.
MRO NSRF
No
The MRO NSRF has restated the same answer as in question 6 on purpose. Confusion
exists around the “peak load” in that Attachment A states the allocation is based on
Projected Peak Loads and Generation but the Background Document states it will use
Consideration of Comments: Project 2007-12 Frequency Response
15
5
003009
Organization
Yes or No
Question 7 Comment
a historical Peak and Generation to make the allocation. Also, for the BA installed
capacity, where is that value derived from and does NERC obtain that from FERC form
data or does the BA provide that information somewhere specific to this effort?
Additionally, there appears to be a difference in how FRO is calculated in Attachment
A and what is described in the Background Document. These differences should be
reconciled such that both documents address the same approach. If installed capacity
is used in the equation, how are variable/intermittent resources (e.g. wind, solar)
accounted for? At full capacity? Please clarify.
Page 7 (3rd paragraph) of the Background document states “Given the fact that BA’s
can encounter staffing or EMS change issues coincident with the date the ERO sets
for new Frequency Bias Setting implementation, the standard provides a 24 hour
window on each side of the target date.
1) The Standard itself does not state this provision (24 hour window on each side of
target date) as indicated.
2) The SDT accurately addresses the fact that BA’s could have EMS or staffing issues
during implementation of the ERO validated FBS. The current stated 72-hour window
is not long enough for implementation of the FBS as there may be a host of issues
that could impact implementation. We suggest that a seven day window be used for
implementation of the FBS.
Response: The drafting team has corrected the proposed standard to accurately reflect the language in the Background Document.
Texas Reliability Entity
No
There is an inconsistency between the Background Document and Attachment A.
Attachment A only proposes event criteria based on “the largest category C (N-2)
event identified,” but the Background Document says: “Attachment A proposes the
following Interconnection event criteria as a basis to determine an Interconnection’s
Frequency Response Obligation: - Largest category C loss-of-resource (N-2) event; Largest total generating plant with common voltage switchyard; - Largest loss of
generation in the interconnection in the last 10 years.”
Consideration of Comments: Project 2007-12 Frequency Response
15
6
003010
Organization
Yes or No
Question 7 Comment
Response: The drafting team has corrected the reference so both documents agree.
Great River Energy/ACES
Power Marketing Standards
Collaborators
No
We can find no document titled “BAL-003-1 Background Document”. We assume this
question is referring to the “Frequency Response Standard Background Document”
dated October 2011. We do not believe the document provides sufficient clarity. No
explanation is provided for why RSG was added to Requirement R1.There are typos
contained in the document. On page 6 in NIA, the A should be in subscript. On page
7 in bullet 4 in the first sentence, “The” should be in lowercase
Response: Your assumption was correct. The drafting team has corrected these typos.
Southern Company
No
We suggest the Background Document should be edited to be consistent with
changes made to the standard or other related documents (eg. Any revisions to draft
BAL-003-1 and removal of the definition of SEFRD).
Response: Thank you for your comments. The drafting team revised the background document based upon modifications to the
standard as well as modifications to other documents related to the standard.
Seattle City Light
Yes
o LADWP and SCL note that the document “BAL-003-1 Background Document”
seems to be reasonable.
Response: Thank you for your comments.
Constellation Energy
Commodities Group
Yes
Should be revisited based on the propposed modifications to the requirements.
Response: Thank you for your comments. The drafting team revised the background document based upon modifications to the
standard as well as modifications to other documents related to the standard.
Los Angeles Department of
Water and Power
Yes
LADWP notes that the document “BAL-003-1 Background Document” seems to be
reasonable.
Consideration of Comments: Project 2007-12 Frequency Response
15
7
003011
Organization
Yes or No
Question 7 Comment
Response: Thank you for your comments.
Keen Resources Asia Ltd.
Yes
Paragraph 4 on page 5 of the Background Document provides a statistically correct
description of event selection without sample pre-selection and should followed
instead of the erroneous criteria 2 & 7 in Attachment A. The risk-based approach to
determining FRM, that the Background Document mentions in paragraph 4 of page 4
is being evaluated by the drafting team for application in this standard, should be
considered for deployment as soon as possible to replace the administered method
currently proposed in this standard, because the administered method lacks any
technical justification. No such justification was ever attempted in the development
of this standard. The administrative method of determining FRM is therefore but a
highly dubious "quick fix" until the risk-based method is evaluated and implemented.
The administrative method is in fact perverse because it discourages BAs from
reducing their contribution to frequency error by refusing to reduce the BA's FRO
accordingly, and because it encourages BAs to contribute to frequency error without
increasing their FRO.
Response: The standard has to be written with what will be used day one. Due to the timeline that NERC has filed with FERC, there
is not enough time to adequately evaluate a second methodology.
Manitoba Hydro
Yes
Please see MH’s response to Question 1 regarding the term Single Event Frequency
Response Data.
Additionally, the discussion in this document is useful in clarifying the intent of the
drafting team, but some of this clarification would best be incorporated into the
Standard itself. Ex. RSG requirement on page 6. Also on page 7 Attachment A does
not specify what validation is and how it is done. Attachment A refers to BA providing
FBS data to ERO which then validates and publishes. This should be reflected in R2.
Response: Please refer to our response to Question 1.
The “validation” process is nothing new. The ERO presently validates the information sent in by BAs today. The ERO will not be
Consideration of Comments: Project 2007-12 Frequency Response
15
8
003012
Organization
Yes or No
Question 7 Comment
performing this process in a vacuum, but will be working with the BAs in the same manner as they presently do.
NV Energy
Yes
This is a good reference; however see response to Question 6 in that there appears to
be a discprepancy between Att A and the Background Document with regard to FRO
calculation.
Response: The drafting team has corrected the discrepancy so both documents now agree. The drafting team is proposing to use
historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Cleco Corporation/SPP
Standards Review Group
Yes
We appreciate the effort of the SDT in developing the Background Document. It
provided insight on how the SDT got the proposed standard to where it is with this
posting.
Response: Thank you for your comment.
Imperial Irrigation District
Yes
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Florida Power & Light
Company
Yes
FPL
Yes
FMPP
Yes
Consideration of Comments: Project 2007-12 Frequency Response
15
9
003013
Organization
Yes or No
Tucson Electric Power
Yes
Associated Electric
Cooperative Inc
Yes
South Carolina Electric and
Gas
Yes
Ameren
Yes
Hydro-Quebec TransEnergie
Yes
ISO/RTO Council Standards
Review Committee/
Independent Electricity
System Operator
Question 7 Comment
We do not have an opinion on whether or not the Background Document provides
sufficient clarity to the development of the standard. We do, however, suggest that
the SDT consider our comments in Q6, above, and move some of the information
from Attachments A and B to or combine with the Background Document, to the
Background Document to provide all the technical basis and background behind the
elements stipulated in the requirements.
Response: Please refer to our response to Question #6.
Consideration of Comments: Project 2007-12 Frequency Response
16
0
003014
8.
The SDT has developed a new document titled Attachment B – Process for Adjusting Bias Setting Floor. This document is
intended to provide the methodology the ERO will use to reduce the minimum Frequency Bias Setting to become closer to
natural Frequency Response. Do you agree that this document provides clear and concise instructions for the ERO to follow? If
not, please explain in the comment area.
Summary Consideration: The majority of commenters did not like the word “initially” that was used in the proposed standard. They
felt that it caused confusion. The SDT modified the attachment to remove the reference to the word “initially” and added
other clarifying language to the document.
Some commenters were concerned with how the calculation of FRO for BAs that have load and generation. The intent was that
generation-only BAs would base their settings on generation. Traditional BAs would use load. The SDT revised the table
to agree with the proposed standard.
One commenter indicated that the standard was measuring AGC. The SDT disagrees.. There may be some AGC influence in the
measurement however the SDT believes that this impact is minor. Based on the data received from the Field Trial, the
SDT did not see this phenomenon.
A couple of commenters indicated that the methodology used for calculation of the minimum Frequency Bias Setting could be adverse
for a single BA interconnection. The SDT explained that to ensure comparable treatment between BAs with fixed Bias
Settings, BAs with a variable Bias Setting report their monthly average Bias for the reporting year. This average will be
calculated when frequency is greater than 60.036 Hz or less than 59.964 Hz. The average of the 12 months’ Bias values
must be equal to or more negative than the Interconnection’s minimum Bias Setting.
Organization
Yes or No
Seattle City Light
Negative
Question 8 Comment
Answer: Yes Comments: o LADWP and SCL note that Attachment B seems to be
reasonable.
Response: Thank you for your comment.
Constellation Energy
Commodities Group
No
Should be revisited based on the proposed modifications to the requirements.
Consideration of Comments: Project 2007-12 Frequency Response
16
1
003015
Organization
Yes or No
Question 8 Comment
Response: The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to reflect
modifications to the requirements and suggested changes from the industry.
MRO NSRF
No
: There could be some confusion caused by the Attachment B due to the use of the
word “initially” when the reference is made to the current standard. The drafting
team should change the word “initially” to “currently” or strike it to avoid the
potential confusion.
The second paragraph of Attachment B (which contains the two bullets):The words
“initially 1%” in the second bullet contradict with the Table 1 on Attachment B, which
states “Initial” and “0.8%”. Suggest deleting the parenthetical in the second bullet as
when BAL-003-1 is effective it would be referencing an old Standard version. If the
initial minimum is intended to be 1% say so in the Table 1.
Response: The SDT has modified Attachment B, now a Procedure for the ERO to follow in supporting the standard, to reflect your
suggested changes.
Texas Reliability Entity
No
1. In Attachment B, we suggest removing the paragraph beginning “The BA
calculates . . .” because it appears to be background information that conflicts
with the methods provided in this version of the standard for determining
minimum bias settings.2.
2. Attachment B, Table 1, refers to “0.8% of peak load or generation.” If a BA has
both load and generation, will its minimum Frequency Bias Setting be based on its
load, its generation, or can it pick the value that it prefers to use?
Response: The SDT agrees and has removed it from the Attachment B, now a Procedure.
The SDT intended that generation-only BAs would base their settings on generation. Traditional BAs would use load. We have
revised the table to agree with the proposed standard.
Bonneville Power
No
BPA understands the concept and we disagree with it. As the ERO continues to lower
the required minimum frequency bias setting for an interconnection, the BA’s that
Consideration of Comments: Project 2007-12 Frequency Response
16
2
003016
Organization
Yes or No
Administration
Question 8 Comment
have frequency response higher than the 1% will have a higher percentage of the
frequency response of the interconnection.
Also, this standard is primarily measuring AGC response, not natural frequency
response; therefore not lowering the limit is appropriate.
Response: The SDT believes that you may be mixing the Frequency Bias Setting and Frequency Response Measure. As proposed
the FRO will be assigned based upon load and generation as defined in Attachment A. Therefore actual Frequency Response will
be required to come from the interconnection on that basis. To the extent an entity has a FRM greater than its Interconnection’s
minimum Frequency Bias Setting, its Frequency Bias Setting may grow as a percent of the Interconnections total Frequency Bias
Setting. However, that is not Frequency Response.
The SDT disagrees with your comment concerning AGC. There may be some AGC influence in the measurement however the SDT
believes that this impact is minor. Based on the data received from the Field Trial, the SDT did not see this phenomenon.
Duke Energy
No
Duke Energy suggests that the SDT consider a term other than “Initial’ in the title for
Table 1. We suggest “Proposed Frequency Bias Setting” for Table 1. Notwithstanding
our suggestion that the criteria/requirements of the minimum FBS in the Attachment
be incorporated into the Standard, Duke Energy has the following concerns with what
is proposed:
As cited in our comments to Question 8 in the last posting (extensive, so not repeated
here), the secondary control measures of CPS1, CPS2 and the draft Balancing
Authority ACE Limit (BAAL) are tightly coupled to the Frequency Bias Setting (FBS),
and a reduction of the FBS will impact the secondary control requirements placed
upon the BA. Noted in our response to Question 7 above, the statement on page 9 in
the “BAL-003-1 Background Document”is not correct in stating that Attachment B will
“ensure there is no negative impact on other Standards”.The gradual reduction of the
FBS will proportionally tighten the secondary control limits for each Balancing
Authority. Even if the “natural” Frequency Response in the Eastern Interconnection
remains unchanged for the next several years, under the process described allowing
the ERO to annually adjust the minimum FBS for the Interconnection, the FBS will
Consideration of Comments: Project 2007-12 Frequency Response
16
3
003017
Organization
Yes or No
Question 8 Comment
eventually be reduced to a value approximately 10% above the calculated response in
magnitude, cutting the current CPS1, CPS2 and BAAL limits in the Eastern
Interconnection on average by more than half. The current FBS for the Eastern
Interconnection is approximately minus 6500 MW/0.1Hz, estimated “natural”
Frequency Response is perhaps around minus 2400 MW/0.1Hz. Unlike CPS1 and
BAAL where the measures are based upon the FBS of the BA only, CPS2 (dependent
upon the FBS of the BA and the Interconnection) will be significantly limiting to the
degree that no change in a BA’s own Frequency Response could significantly change
its CPS2 limit if the Interconnection FBS drops over time as indicated. At least under
CPS1 and the draft BAAL, the BA would have an option of improving its Frequency
Response, allowing it to increase its FBS and proportionally the CPS1 and BAAL
bounds using the FBS.
Conclusion from our last comments submitted: Duke Energy does not believe there is
a reliability need pushing the industry to tighten secondary control to the degree
discussed above simply as a result of reducing the Frequency Bias Setting. If the
calculated Frequency Response of the Interconnection stayed at its current level,
what would be the justification for tightening the secondary control requirements of
CPS1, CPS2 and the proposed BAAL? Duke Energy supports taking more of the error
out of the ACE equation by having the FBS closer to the estimated Frequency
Response of the Balancing Authority, however, Duke Energy does not believe the
result should be a significant increase in secondary control costs to meet the CPS1,
CPS2, or draft BAAL requirements. Duke Energy understands the position placed
upon this Standard Drafting Team- the secondary control and reserve requirements
are not under the scope of the team, however, proper consideration has not been
given in Attachment B to the impact lowering the FBS will have on the industry in
terms of the requirements placed upon the BA for secondary control and reserve
requirements - especially for meeting CPS2. The research discussed in our comments
to the last posting support that reducing the FBS while under CPS1 and the draft
BAAL may be achievable, however a CPS2 bound cut potentially in half or lower will
place unreasonable bounds on a BA, requiring control actions even when the BA may
Consideration of Comments: Project 2007-12 Frequency Response
16
4
003018
Organization
Yes or No
Question 8 Comment
be operating in support of the Interconnection frequency. Given the significant
impacts discussed, Duke Energy believes that additional provisions must be in place
for the Industry to approve each subsequent revision to the calculation of the
minimum Frequency Bias Setting, rather than leave it as a decision made only by the
ERO.
Response: We agree with your comment about the word "initial" in Attachment B, now a Procedure for the ERO to follow in
supporting the standard, and have removed the word “initial” from the title to remove the confusion.
We believe that your assessments about the effects on CPS2, BAAL and CPS1 are uncertain because there are complex interactions
between the Frequency Bias Setting and the ACE values in these measures that use a Frequency Bias Setting.
We agree that the words in Attachment B, now a Procedure for the ERO to follow in supporting the standard, stating "ensure there is
no negative impact on other standards" is an overstatement at this point. We have added language to allow for analysis prior to
implementing changes to the minimum Frequency Bias Setting. This is also why we have chosen to go slow with the concept of
allowing the frequency bias setting to be reduced below 1% of Peak Load.
We agree with your support of taking more of the error out of the ACE equation by making the FBS closer to the estimated Frequency
Response of the Balancing Authority; however, we do not agree that the effects of secondary control can be ignored when we make
these changes. Therefore we are proposing a “go slow approach” to making this happen and included checks to confirm there are
not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Attachment B, now a Procedure for the ERO to follow
in supporting the standard, to make the initial minimum Bias Setting 0.9% of peak and has included a provision that the ERO will
evaluate the impact caused by a change in minimum Bias Setting. The evaluation will look at both frequency performance and
impact on CPS-related compliance calculations.
We support your comment related to the ERO working with the Industry to approve each subsequent revision to the minimum FBS.
However, it is this drafting team’s understanding that the language in the standard is limited to referencing the ERO and the ERO will
develop a process to address the needs of the standard. Therefore, no modification has been made to require any specific
coordination between the ERO and the Industry.
Consideration of Comments: Project 2007-12 Frequency Response
16
5
003019
Organization
Yes or No
Sacramento Municipal Utility
District (SMUD)
No
Question 8 Comment
In addition to the requirements, reducing frequency bias obligation results in
generation tripping closer to the set point.
It seems that Lowering the Minimum Frequency Bias Setting from 1% to .8% will
result in a lower response, which in turn will lower the natural frequency response.
Over time it seems this pattern would lead to poorer response.
Response: The SDT is unsure of what your first comment is attempting to say. Therefore the SDT cannot provide a response to
your comment without further clarification.
The SDT believes that you may be mixing the Frequency Bias Setting and Frequency Response Measure. As proposed the FRO will
be assigned based upon load and generation as defined in Attachment A. Therefore actual Frequency Response will be required
to come from the Interconnection on that basis. To the extent an entity has an FRM greater than its Interconnection’s minimum
Frequency Bias Setting, its Frequency Bias Setting may grow as a percent of the Interconnection’s total Frequency Bias Setting.
However, that is not Frequency Response.
NV Energy
No
In Attachment B, it seems unclear whether the initial FB setting is supposed to be 1%
of BA peak load or 0.8% as shown in the table. In general, I was extremely confused
about what the required FB setting should be. R5 indicates a percentage of load
found in Att B, but Att B indicates the greater of Natural Frequency Response or 1%
of peak, and then the table that follows indicates 0.8%. At this point, I have no idea
what is being stated for the requirement.
Response: The SDT agrees and has modified the attachment.
The SDT intended that generation-only BAs would base their settings on generation. Traditional BAs would use load. We have
revised the table to agree with the proposed standard.
Progress Energy
No
PGN supports the collective comments of SERC members. We suggest the SDT
consider a term other than “Initial’ in the title for Table 1. We suggest “Proposed
Frequency Bias Setting” for Table 1
Consideration of Comments: Project 2007-12 Frequency Response
16
6
003020
Organization
Yes or No
Question 8 Comment
Response: The SDT agrees with your comments and has made corresponding modifications to the attachment by removing the
word, “initial”.
Independent Electricity
System Operator
No
Please see our comments under Q6. In brief, we do not agree with including a
process description type of document as part of the standard requirement.
Response: Please refer to our response to Question #6.
ISO/RTO Council Standards
Review Committee
No
Please see our comments under Q6. In brief, we do not agree with including a
process description type of document as part of the standard requirement. Process
description should be regarded guideline document and not a part of the standard
requirement.
Response: Please refer to our response to Question #6.
Tucson Electric Power
No
Reducing a BAs frequency bias setting may have an adverse impact on recovering
from a frequency event once you get past the first 8-10 seconds. A larger bias will
allow for actual and sustained AGC generator responses. Industry focus should be on
generator governor response within the first 8-10 seconds.
Response: The Standard Drafting Team disagrees with your comment. Full recovery is dependent upon the contingent BA
recovering from its loss. However, we do agree that secondary frequency support from the non-contingent BAs may not be as
robust.
Northeast Power Coordinating
Council
No
Refer to the first comment in Question 6.
Response: Please refer to our response to Question #6.
Hydro-Quebec TransEnergie
No
The methodology proposed to compute the Minimum Frequency Bias Setting (in
MW/0,1Hz) could be adverse for the Quebec Interconnection. Hydro-Quebec uses a
Consideration of Comments: Project 2007-12 Frequency Response
16
7
003021
Organization
Yes or No
Question 8 Comment
variable Bias that is calculated based upon which generator is online and it’s droop
setting. Under light load condition, we might have a Bias setting that would be under
(in absolute value) than the FRM which is the median value, even though the Bias
setting would reflect the grid’s frequency response. This method, as proposed, would
mandate us to have a larger Bias that what is really needed. Unlike Eastern
Interconnection, we are not over biased. By implementing this new methodology, it
would make us over biased. Having a too large Bias could lead to system instability,
based on the results of studies from our control specialists. The Minimum Frequency
Bias Setting should take into account the wide load span that we can face.
For the variable bias, we could express the Minimum Frequency Bias Setting as a
function of monthly peak loads, and remove the Natural Frequency Response term.
In addition, there is a gap between Attachment B and the text in R5. See comment
10 for explanation.
Response: To ensure comparable treatment between BAs with fixed Bias Settings, BAs with a variable Bias Setting report their
monthly average Bias for the reporting year. This average will be calculated when frequency is greater than 60.036 Hz or less than
59.964 Hz. The average of the 12 months’ Bias values must be equal to or more negative than the Interconnection’s minimum Bias
Setting.
Xcel Energy
No
There could be some confusion caused by the Attachment B due to the use of the
word “initially” when the reference is made to the current standard. The drafting
team should change the word “initially” to “currently” or strike it to avoid the
potential confusion.
Response: The SDT agrees with your comment and has modified the attachment to remove the word, “initially”.
Florida Power & Light
Company
No
There is no technical justification provided either in the attachment or background
data for the initial starting value of 0.8%. This is acceptable but is arbitary.
Additionally, the last sentense on page 1 of Attachment B should be changed to read
" the ERO must reduce ( in absolute value) the minimum Frequency Bias Settings for
BA's within that Interconnection, by 0.1 percentage point from its previous annual
Consideration of Comments: Project 2007-12 Frequency Response
16
8
003022
Organization
Yes or No
Question 8 Comment
value, to better match the Frequency Bias Setting to the natural Frequency Response
or provide technical justification for not implementing the reduction
Response: You are correct, the starting value is arbitrary. The SDT did not want to make a one step change to immediately reduce
the minimum Frequency Bias Setting to natural Frequency Response. The SDT believes that a multi-year multi-step process would
be better and allows for monitoring the effects on other performance standards.
The SDT believes that the end result would be the same. The present wording allows for collaboration between the ERO and
other entities/groups. The SDT is also concerned with putting a requirement on the ERO within an Attachment when there is not
a reliability problem if it were not to happen.
SERC OC Standards Review
Group
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
South Carolina Electric and
Gas
No
We suggest the SDT consider a term other than “Initial’ in the title for Table 1. We
suggest “Proposed Frequency Bias Setting” for Table 1
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
ISO New England Inc
No
We suggest the SDT to first determine if the materials in the revised Attachment A &
B are “Guideline” or Technical Background”, or are they “requirements”. If it is the
former, then Requirement R1 should not mention Attachment A at all. If it is the
latter, then the as-written Attachment A is a mix bag as it on the one hand describes
the ERO’s process for supporting the Frequency Response Standard (FRS), in other
words, the method and criteria it uses to calculate the frequency bias settings and
the FRM, and on the other hand the BA’s obligations to support this process. We
strongly disagree that the latter requirements be imbedded in an attachment,
especially one that is supposed to provide the technical background and guideline for
another entity which, by the way, is not held responsible for complying with the
Consideration of Comments: Project 2007-12 Frequency Response
16
9
003023
Organization
Yes or No
Question 8 Comment
proposed method. An appendix is not regarded as a mandatory requirement.
Response: The process is still being developed at NERC but an Attachment would document processes to be utilized without a
measurement saying that you failed the standard.
Southern Company
No
We suggest using the words, ‘Proposed Frequency Bias Setting’ in the Title of Table 1
instead of the word, ‘Initial’.
Response: The SDT agrees with your comment and has modified the attachment by removing the word, “initial”.
ERCOT
No
While there is no problem with the calculation involved, it is unclear why the SDT
elected to assign a grid performance element in this standard to the ERO, who has no
functional (registered) role in grid performance. Since this is a cook-book calculation
and transfer of data on frequency performance, why not assign it to the BA?
Response: The Attachment B, now a Procedure for the ERO to follow in supporting the standard, only outlines a process that the
ERO is to use when adjusting the minimum Frequency Bias Setting. The Procedure does not place any grid performance
requirement on the ERO. The SDT also believes that some authority should have oversight over the minimum setting to prevent
abuses and assure fairness.
Seattle City Light
Yes
o LADWP and SCL note that Attachment B seems to be reasonable.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Energy Mark, Inc.
Yes
Comment 15: This Yes answer assumes that the SDT addresses Comment 13 under
Question 6 in these comments.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT addressed your Comment #13
under Question #6.
Ameren
Yes
Considering the comments made regarding R5, in question 2, above, which are:
Consideration of Comments: Project 2007-12 Frequency Response
17
0
003024
Organization
Yes or No
Question 8 Comment
R5. While we agree with the requirement of R5, it should not be at the expense of
changing the value of L10 in BAL-001, R2, which has been accepted by FERC in Order
693. An accommodation should be made so that any changes to the Frequency Bias
Setting according to BAL-003, R5, should not affect the value of L10 used in BAL-001,
R2.
Response: The SDT thanks you for your affirmative response and clarifying comment. However, the SDT disagrees with your
comment. Since L10 is the function of individual Frequency Bias Settings to the sum of all BA Frequency Bias Settings within an
Interconnection and establishes operating boundaries, it would be inappropriate to leave L10 as is when a Frequency Bias Setting
changes.
Los Angeles Department of
Water and Power
Yes
LADWP notes that Attachment B seems to be reasonable
Response: The SDT thanks you for your affirmative response and clarifying comment.
FPL
Yes
Last paragraph: As stated, would that make the Minimum Frequency Bias Setting
0.7% of peak load or generation? A numerical example shown would help clarify this
paragraph.
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT has added an example to the
Background Document.
Southwest Power Pool
Regional Entity
Yes
Need to clarify that 2012 Bias setting will be based on 1% of peak load or generation
until approval of BAL-003-1 by FERC establishing the .08% of peak load or generation
minimum threshold.
Response: We agree and we have endeavored to do so. The SDT does point out that the proposed minimum for the first year
once approved by FERC is 0.9% not 0.08%.
Associated Electric
Yes
This is a very important document, providing bounds and rationale for and future
Consideration of Comments: Project 2007-12 Frequency Response
17
1
003025
Organization
Yes or No
Cooperative Inc
Question 8 Comment
changes, as well as initial settings going into ballot. As such, it is AECI's understanding
that, upon going into effect, this BAL-003-1 will utilize these initial settings.
Response: The SDT thanks you for your affirmative response and clarifying comment.
Imperial Irrigation District
Yes
SPP Standards Review Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
Salt River Project
Yes
FMPP
Yes
American Electric Power
Yes
Cleco Corporation
Yes
Manitoba Hydro
Yes
Great River Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
17
2
003026
Consideration of Comments: Project 2007-12 Frequency Response
17
3
003027
9.
The SDT has provided an additional spreadsheet, FRS Form 2, to assist the Balancing Authority in providing the data needed to
comply with the proposed standard. Do you agree that this spreadsheet is useful and the instructions are meaningful? If not,
please explain in the comment area.
Summary Consideration: Many of the commenters expressed concern with the fact that the Excel Spreadsheets that were required to
be used were in a newer version of Excel than their company was presently using. In response, the SDT developed Excel Spreadsheets
that are compatible with earlier versions of Excel.
A couple of commenters expressed concern that the Excel Spreadsheets did not contain all of the information necessary to comply with
the analysis required (timing of the event (hour, minute, second). Form 1 contains the time of the event including the hour, minute and
second for t(0) and a graph of frequency data for each event in the list. The time for each BA’s t(0) may vary from this time due to
different sample rates of data and physical proximity to the contingency. Since this standard does not identify an “A Point” or “B Point”
but calculates an “A Value” and “B Value”, providing an exact time for these provides little value. T(0) is the focus of the measurement
process and is the first observed change in frequency of the event. Also added to Form 1, the BA can enter the time zone of its data and
the time of t(0) will be converted to the correct time in that zone. We agree that the proper selection of t(0) is important. This can be
viewed on the “Graph 20 to 52s” worksheet. When set correctly, the first change in frequency of the event will be exactly in the center
of the graph on the vertical grid line.
Some commenters felt that it would be useful if the SDT could develop a completed form as an example to help entities better
understand the methodologies used in the form. Form 2 contains actual data for frequency and NAI of an event. Sample data was
added for each of the adjustments to demonstrate their use and impact on the analysis.
A couple of commenters question the meaning of “master event list” in FRS Form 2. The “Master event list” refers to the event list
contained in each Interconnection’s Form 1.
Organization
Yes or No
Question 9 Comment
Seattle City Light
Negative
Answer: No Comments: o LADWP and SCL note that Form 2 is not compatible with
prior versions of Excel-it won’t even open in Excel 2003 (which is still widely used)and requests that all spreadsheets and calculation tools developed under 2007-12 be
revised to support common software of the past 10 years.
Consideration of Comments: Project 2007-12 Frequency Response
17
4
003028
Organization
Yes or No
Question 9 Comment
Response: Excel 2003 versions of all forms have been developed.
Seattle City Light
No
o LADWP and SCL note that Form 2 is not compatible with prior versions of Excel-it
won’t even open in Excel 2003 (which is still widely used)-and requests that all
spreadsheets and calculation tools developed under 2007-12 be revised to support
common software of the past 10 years.
Response: Excel 2003 versions of all forms have been developed.
Associated Electric
Cooperative Inc
No
AECI believes the SDT could spare our industry both confusion and inconsistency, by
specifying that identified Interconnection Disturbances include both Point A and
Point B to the hour, minute, and second. While this introduces some risk of Entities
over-automating their data-reports, the benefits for Eastern Interconnection
respondents would be tremendous. Cautions and disclaimers should be placed on
both Form 1 and Form 2, to assure respondents manually inspect their frequency
data and pinpoint the specific inflection-point samples.
Response: Form 1 contains the time of the event including the hour, minute and second for t(0) and a graph of frequency data for
each event in the list. The time for each BA’s t(0) may vary from this time due to different sample rates of data and physical
proximity to the contingency. Since this standard does not identify an “A Point” or “B Point” but calculates an “A Value” and “B
Value”, providing an exact time for these provides little value. T(0) is the focus of the measurement process and is the first
observed change in frequency of the event. Also added to Form 1, the BA can enter the time zone of its data and the time of t(0)
will be converted to the correct time in that zone. We agree that the proper selection of t(0) is important. This can be viewed on
the “Graph 20 to 52s” worksheet. When set correctly, the first change in frequency of the event will be exactly in the center of the
graph on the vertical grid line.
Bonneville Power
Administration
No
BPA believes the form is not easily understood and is overly complicated for what it is
trying to accomplish. BPA believes the form might work for an internal evaluation,
just not for an external audit. Compliance is based on this form. BPA believes the
standard needs to be simplified and possibly returned to a data gathering standard.
Consideration of Comments: Project 2007-12 Frequency Response
17
5
003029
Organization
Yes or No
Question 9 Comment
Response: The addition of “Adjustments” to the analysis did add complexity to the Form. These were added based on comments
received from the industry on previous postings. Some of these “Adjustments” may be removed as the field trial progresses if
they are not utilized. In the latest Form 2, version 6, the multiple time period averages were removed since the final average
period was selected based on the results of the first round of the field trial evaluated last fall. However, Form 2 is important to
the standard in that it achieves the requirement of measuring frequency response in the same manner for all Interconnections.
Returning Form 2 with Form 1 allows validation of the selection of t(0) which is critical for this requirement.
The SDT does not believe that it can revert back to a “data gathering” standard. The SDT is responding to FERC Directives from
Order 693 as well as the FERC Order dated March 18, 2010 which mandated development of a standard addressing the Order 693
directives within six months. FERC later granted an extension to provide a standard addressing these issues by the end of May
2012.
FPL
No
FRS Form 2 - Two-second Sample DataInstructions tab/worksheet: What is referred
to as or meant by the ‘master event list’?
4. - Regarding 2 second sample rate for 25 minutes starting 2 minutes before event
begins and 15 minutes after it begins, does this add up to 25 minutes or are
additional minutes being required for collection? Also, FPL can report frequency at
this rate, but can only report load in MW every four seconds. Move to 4 second
sample rate.6-8. - Possible to add button to auto-populate cells C8 and C11 in ‘Entry
Data’ tab from the new column C and cell identifying the desired frequency change
time and simplify these steps?
10. - Clarify where the “Copy” button is. Is it the one in the ‘Data’ tab or worksheet?
Entry Data tab/worksheet:Step 6 should also be or be moved to the “Instructions”
worksheet.Are the values in column C in the “Data” worksheet labeled “Total Lost
Generation” the same as those in column AQ in the “Evaluation” worksheet? If so,
why are they not both labeled “Net Actual Interchange”?
What is the definition of “Non Conforming Load” in column E?
Response: “Master event list” refers to the event list contained in each Interconnection’s Form 1.
Consideration of Comments: Project 2007-12 Frequency Response
17
6
003030
Organization
Yes or No
Question 9 Comment
The inconsistency in the data sample totals has been corrected. The absolute minimum amount of data required for the full
analysis is two minutes before the beginning of the event to 15 minutes after the beginning of the event. The calculation rate of
“Load” can be at a different rate than the AGC scan rate. The Load data is not used in measuring performance. The variability of
Load can impact measured performance and can be observed on the “BA Load Dampening” worksheet graph. On some
Interconnections, load dampening can be observed in the data. Using the historian “data sample” collection option, it will fill the
spreadsheet with the same value of Load, changing at the calculation rate.
The “auto populate” of cells C8 and C11 is a good idea. A couple BAs did this during the first phase of the field trail. The problem
is that the event time of t(0) in column C was set using 2 second scan data in one part of the Interconnection and the beginning of
the event may be shifted one or two scans when frequency is scanned less often. This would make this automation difficult for
the value in C8. It is critical for the measure for t(0) be set correctly. The value of C11 is less critical and is not used in the initial
primary Frequency Response Measure. It is only used to demonstrate delivery of primary frequency response during the
frequency recovery period.
The location of the “Copy” button has been clarified.
Step 6 on the “Data Entry” worksheet was added to the “Instructions” worksheet. The value in column C in the “Data” worksheet
labeled “Total Lost Generation” is for single BA Interconnections only. It takes the place of “Net Actual Interchange” for multiple
BA Interconnections. Column “AO” on the “Evaluation” worksheet is not the same as the “Contingent BA Lost Generation” data
on the “Evaluation” worksheet. The “Contingent BA Lost Generation” data is only used by multiple BA Interconnection BAs not
Single BA Interconnections. The “Data” worksheet for the “Single BA Interconnection” Forms has an n/a in columns G, H and I and
should not be used by BAs in these Interconnections. This is noted on their “Instructions” worksheet. This should explain why
they are not labeled the same.
Non-conforming Load is Load that changes abnormally different than the conventional diurnal load pattern of a Balancing
Authority Area. Non-conforming Load becomes significant when the net change within a few minutes is greater than a BA’s L 10
limit. The importance here is that this Load change can be ten times larger than some BAs’ FRO and makes measuring the SEFRD
inaccurate. An example of non-conforming load would be an arc furnace of a significant size.
Thank you for your comments and the effort to find each of these items.
ISO/RTO Council Standards
Review Committee
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet
file. Apart from that, however, there are other sheets added to the previous Form 1.
But this Comment form makes no mention of the changes, nor is there a question in
Consideration of Comments: Project 2007-12 Frequency Response
17
7
003031
Organization
Yes or No
Question 9 Comment
the Comment Form asking whether the additional information should be requested.
We believe this is a significant change to the standard and many commenters may
have missed the opportunity to comment on it. Compared to the previous version,
Form 1 has been significantly expanded to include not only additional sheets but
much more comprehensive data requirements even on the Data Entry sheet itself.
This makes data submission a very time-consuming task but the justification for
requiring detailed data entry has not been provided.
We question the need for such expansion on data entry requirements. We have yet
to see the reason for expanding Form 1 in assisting a BA to provide the data needed
to comply with the standard, hence we do not see how adding a Form 2 can help in
that regard. We suggest the SDT to keep data requirements to only what is minimally
needed to support the FRS reporting process. Where the SDT deems additional data
entry sheets to be necessary, it should provide the rationale for expanding from a 2
sheet form into a multiple sheet form for additional data collection. Where the SDT
deems the additional data sheet or information not necessary to support FRS
reporting, then we suggest the SDT to hide those pages not required for the standard
so as to avoid confusion, and/or to remove those analytical pages not directly used in
the standard.
Response: The SDT points out that there are no additional data requirements. It is possible that you are seeing more
spreadsheets due to them being unhidden.
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the ability of the BA to enter the time zone of its data and the
spreadsheet will calculate the local time of the event from the UTC time. This was added for the convenience of the BA in
collecting the correct data for each event and does not require additional data from the BA. The second worksheet added was a
worksheet that displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data
collection and the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This
graph worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this
worksheet will greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous
Consideration of Comments: Project 2007-12 Frequency Response
17
8
003032
Organization
Yes or No
Question 9 Comment
versions. The absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the
“Data” worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in
the ACE equation and is important to BAs that utilize variable Bias. Column K, BA Load, was added by the drafting team in the
beginning to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I
of the “Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
Independent Electricity
System Operator
No
If we are not mistaken, Form 2 is added as the last sheet in the Form 1 spreadsheet
file. Apart from that, however, there are other sheets added to the previous Form 1.
But this Comment form makes no mention of the changes, nor is there a question on
the additional information requested. We have a concern over this omission of
attention or oversight. Compared to the previous version, Form 1 has been
significantly expanded to include not only additional sheets but much more
comprehensive data requirements even on the Data Entry sheet itself. This makes
data submission a very time-consuming task but the justification for requiring
detailed data entry has not been provided. We question the need for such expansion
on data entry requirements. We have yet to see the reason for expanding Form 1 in
assisting a BA to provide the data needed to comply with the standard, hence we do
not see how adding a Form 2 can help in that regard. We suggest the SDT to look at
the basic need for data submission that would suffice to support the FRS reporting
process. Where the SDT deems additional data entry sheets to be necessary, it should
provide the rationale for expanding from a 2 sheet form into a multiple sheet form
for additional data collection.
Response: The SDT points out that there are no additional data requirements. It is possible that you are seeing more
spreadsheets due to them being unhidden.
Consideration of Comments: Project 2007-12 Frequency Response
17
9
003033
Organization
Yes or No
Question 9 Comment
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the ability of the BA to enter the time zone of its data and the
spreadsheet will calculate the local time of the event from the UTC time. This was added for the convenience of the BA in
collecting the correct data for each event and does not require additional data from the BA. The second worksheet added was a
worksheet that displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data
collection and the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This
graph worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this
worksheet will greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous
versions. The absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the
“Data” worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in
the ACE equation and is important to BA’s that utilize variable Bias. Column K, BA Load, was added by the drafting team in the
beginning to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I
of the “Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
Los Angeles Department of
Water and Power
No
LADWP notes that Form 2 is not compatible with prior versions of Excel-it won’t even
open in Excel 2003 (which is still widely used)-and requests that all spreadsheets and
calculation tools developed under 2007-12 be revised to support common software
of the past 10 years.
Response: Excel 2003 versions of all forms have been developed.
Tucson Electric Power
No
TEP feels that Form 2 is a useful tool for internal BA use and should not be used for
compliance purposes.
Response: Form 2 is not intended to be used to reflect compliance but rather for consistency in reporting.
Consideration of Comments: Project 2007-12 Frequency Response
18
0
003034
Organization
Yes or No
Question 9 Comment
Form 2 was developed so consistent analysis of each event could be validated. During the first round of the field trial, many BAs
selected the incorrect t(0), some provided data that was filtered or utilized data compression techniques that caused the analysis
to be incorrect. With Form 2, the selection of t(0) can be quickly evaluated and data quality reviewed. The proper selection of t(0)
can be made and Form 1 corrected providing validated consistent results.
MRO NSRF
Yes
: It would be useful if the drafting team could develop a completed form as an
example to help entities better understand the methodologies used in the form
Response: All versions of Form 2 contain actual data for frequency and NAI of an event. Sample data was added for each of the
adjustments to demonstrate their use and impact on the analysis.
Xcel Energy
Yes
It would be useful if the drafting team could develop a completed form as an example
to help entities better understand the methodologies used in the form.
Response: All versions of Form 2 contain actual data for frequency and NAI of an event. Sample data was added for each of the
adjustments to demonstrate their use and impact on the analysis.
Ameren
Yes
We agree that the spreadsheet is meaningful, but still needs to be vetted through the
field trial process, with improvements made based on experience in its use.
Response: We completely agree.
Imperial Irrigation District
Yes
Northeast Power Coordinating
Council
Yes
SERC OC Standards Review
Group
Yes
SPP Standards Review Group
Yes
Consideration of Comments: Project 2007-12 Frequency Response
18
1
003035
Organization
Yes or No
Southwest Power Pool
Regional Entity
Yes
Salt River Project
Yes
Progress Energy
Yes
Southern Company
Yes
Energy Mark, Inc.
Yes
Florida Power & Light
Company
Yes
FMPP
Yes
ISO New England Inc
Yes
NV Energy
Yes
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
Cleco Corporation
Yes
Manitoba Hydro
Yes
Constellation Energy
Commodities Group
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 9 Comment
18
2
003036
Organization
Yes or No
Great River Energy
Yes
Hydro-Quebec TransEnergie
Yes
Duke Energy
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12 Frequency Response
Question 9 Comment
18
3
003037
10.
Please provide any other comments (that you have not already provided in response to the questions above) that you have on
the draft standard BAL-003-1.
Summary Consideration: Many of the commenters referenced other questions in the comments. The SDT asked them to review
the response to those earlier questions rather than repeating the responses here.
Several commenters pointed out that there was a discrepancy between the Background Document and Attachment A regarding
the calculation of the BA FRO. The SDT has corrected the reference so both documents agree. The drafting team is proposing to
use historical information rather than forecasted information for the allocation of the Frequency Response Obligation.
Several other commenters indicated that Supplemental Regulation Service was not an appropriate method to provide Frequency
Response. The SDT agrees that it is inappropriate to expect supplementary regulation to transfer Frequency Response
successfully, however the SDT did not want to prevent any innovative solution that will transfer Frequency Response through the
use of a pseudo-tie among Balancing Authorities. Also, the SDT believes that Balancing Authorities exchanging Supplementary
Regulation via a pseudo-tie have to be consistent in the removal or inclusion of Supplementary Regulation in their actual net
interchange measurement as well as in all events across the measurement period.
Many commenters were concerned that the BA could be responsible for supplying an infinite amount of Frequency Response.
They indicated that a BA could not prepare for this in its planning process. The SDT agrees that the proposed standard was not
clear on this subject and added language in the “Criteria for Selection of Events” section of the revised Attachment A to limit the
amount of Frequency Response a BA would be required to provide in order to be compliant with the standard.
Some commenters were concerned with the wording in Requirement R5. They indicated that the wording needed to say “greater
than or” instead of “at least”. The SDT removed the requirement and combined it with the revised Requirement R2 and the new
Requirement R3. The SDT has modified the requirement and believes we have implemented the intent of your suggestion.
Many commenters did not agree with requiring the BA to provide Frequency Response. The NERC Functional Model and FERC
both cited the BA as the responsible entity for providing Frequency Response. T There are several different methods available to
the BA to provide Frequency Response and the SDT has included these in the Background Document.
Some commenters were concerned with the threshold that the SDT recommended for the Eastern Interconnection. Florida sees a
greater change in frequency for a given contingency than for a comparable event elsewhere in the East. This is the reason for
the higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry extra frequency responsive
reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a contingency inside
Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW of frequency
Consideration of Comments: Project 2007-12 Frequency Response
18
4
003038
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
A few commented did not agree with lowering the minimum Frequency Bias Setting. Early research by Nathan Cohn on
interconnected power system operations found that control is optimum if a BA’s Bias Setting is equal to its natural Frequency
Response. If there were to be a difference between the two values, it is preferable to be slightly over-biased. The drafting team
has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is outlined in a
Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to making this
happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations. Based on
concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting 0.9% of
peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Some commenters had concerns about the use of the RSG as a means to provide Frequency Response, and the SDT modified the
Background Document to further explain how an RSG (now FRSG) could supply Frequency Response. The SDT has defined a new
term “Frequency Response Sharing Group (FRSG)” because it believes that using the presently defined term “Reserve Sharing
Group” could cause confusion. The new definition reads “A group whose members consist of two or more Balancing Authorities
that collectively maintain, allocate, and supply operating resources required to jointly meet the Frequency Response Obligations
of its members.”
A couple of commenters indicated that the median was not the proper method to use for the calculation of the FRM. Statisticians
note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is small and
or where scores vary widely. This is the case when estimating a BA’s Frequency Response. While the median is not perfect, the
median approaches a BA’s typical performance after 15-20 observations and more observations give a higher confidence in the
estimate of the BA’s performance.
Organization
Yes or No
Question 10 Comment
MRO NSRF
Negative
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard. Except for Table 2 in Attachment A,
there is no discussion of an amount of FR expected on a total basis. Balancing
Authorities need to know for how many tenths of a hertz they are to respond so they
Consideration of Comments: Project 2007-12 Frequency Response
18
5
003039
Organization
Yes or No
Question 10 Comment
can determine how to plan to meet this requirement. The documents do not appear
to provide any boundary on the maximum amount of FR that a BA will provide, i.e. it
is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is
the BA expected to provide a limitless amount of frequency response?).
Also, is that event excluded from the list used to calculate the Balancing Authorities’
response or is it included with an expectation that it counts the same as any other
event. Without a clear statement of what is expected, including whether there is a
limit on that expectation or not, the Balancing Authorities cannot know what is
expected of them and therefore cannot plan appropriately.
In the first paragraph of R5 delete “at least” and replace with “greater than or”. This
phrase would now read “…absolute value is greater than or equal to one of the
following:” “Equal to or greater than” accurately identifies the expectation, the
current phrasing will lead to confusion and mis-interpretation.
Bullet #1 of R5: The minimum % is based upon the “estimated yearly Peak Demand”.
During the NERC webinar it was mentioned that this minimum would move to being
based on historical reporting of Peak Demand. Where does the SDT stand on this
item? Please provide clarification.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Consideration of Comments: Project 2007-12 Frequency Response
18
6
003040
Organization
Yes or No
Muscatine Power & Water
Negative
Question 10 Comment
"MPW agrees with the comments submitted by the MRO-NSRF."
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
JDRJC Associates
Negative
Support Midwest ISO Comments
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Lincoln Electric System
Negative
Please see comments submitted by the MRO NSRF. (See comments for Question 5
submitted by the MRO NSRF.)
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
Consideration of Comments: Project 2007-12 Frequency Response
18
7
003041
Organization
Yes or No
Question 10 Comment
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Madison Gas and Electric Co.
Negative
Please see the MRO NSRF comments
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Midwest Reliability
Organization
Negative
Please see the comments submitted by MRO NSRF. As MRO Sector 10 we agree with
MRO NSRF position and recommendation to vote negative for this ballot.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Muscatine Power & Water
Negative
"MPW agrees with the comments submitted by the MRO-NSRF."
Consideration of Comments: Project 2007-12 Frequency Response
18
8
003042
Organization
Yes or No
Question 10 Comment
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Nebraska Public Power
District
Negative
NPPD joins it’s comments with comments submitted by the Midwest Reliability
Organization - NERC Standards Review Forum (MRO NSRF) submitted on December
8, 2011.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
Omaha Public Power District
Negative
Please see MRO's comments submitted via Comment Form.
Response: The SDT agrees with you that there was not a clear statement as to the maximum amount of Frequency Response that
a BA would have to provide. The SDT has added language in Attachment A that caps the amount of Frequency Response that a BA
will be required to provide.
The SDT has removed Requirement R5 and combined it into Requirement R2 and a new Requirement R3. The SDT has modified
Consideration of Comments: Project 2007-12 Frequency Response
18
9
003043
Organization
Yes or No
Question 10 Comment
the requirement and believes we have implemented the intent of your suggestion.
The SDT has corrected the reference so that both Attachment A and the Background Document agree. The drafting team is
proposing to use historical information rather than forecasted information for the allocation of the Frequency Response
Obligation.
FirstEnergy Corp.; FirstEnergy
Energy Delivery; FirstEnergy
Solutions;Ohio Edison
Company
Abstain
FirstEnergy appreciates the hard work of the drafting team but needs more time to
review the standard with internal business units and with our RTO. Therefore at this
time we must abstain.
Response: The SDT thanks you for your clarifying comment.
Abstain
As a qualified professional statistician I abstain from voting "affirmative" or
"negative" on this standard because it violates two fundamental statistical best
practices.
1. In the Standard, the definition of Frequency Response Measure (FRM) is
statistically wrong. The median is an improper statistical measure of Frequency
Response because --it truncates large excursions which are the specific subject of
Frequency Response control, not normal operating frequency errors which are selfcorrecting and are the subject of CPM control; --it is non-linear; --it is non-summable
over the interconnection; in other words, the individual BA medians don't add up to
the interconnection median, in complete incompatibility with CPM control which
requires summability of BA performances into the interconnection's performance.
Moreover, it is mathematically impossible to sum the medians of the BAs in a
Reserve Sharing Group (RSG) into the RSG's median: in other words, the RSG's
median cannot represent the sum of the medians of its members. The last paragraph
on page 5 of the Background Document is patently wrong, invented, and supported
in no probability & statistics literature whatsoever. As a practicing statistician, I
hereby give testimony to the utter falsehood of the statement that "In general,
statisticisns use the median as the best measure of central tendency when a
Consideration of Comments: Project 2007-12 Frequency Response
19
0
003044
Organization
Yes or No
Question 10 Comment
population has outliers." (See http://www.robertblohm.com/BestStatistic.doc for an
explanation of "best statistic" which is a highly technical and central topic in modern
probability theory and statistics.) Also, "outliers" are falsely and rhetorically claimed
to be "noise" when in fact they are the "events" that are the specific subject of
Frequency Response. It is well known that they do not "fit" a normal distribution.
They are distinct from the normal operating errors that are the subject of CPM
control. The paragraph does correctly conclude that the linear regression more
accurately incorporates outliers than the median does, although the paragraph uses
rhetoric by calling this improvement "skew" as if it is distortionary when, in fact, the
median distorts the reality.
2. The sample pre-selection described in Attachment A, Event Selection, Criteria 2 &
7, violates the fundamental statistical procedure of unbiased sampling. A population
is governed by a single "process" which, when stationary, is represented by a fixed
probability distribution. In this case the population is several years of events (which
are the subject of Frequency Response), not of normal operating control errors
which are the subject of CPM control. A sample is governed by a single process that
approximates the process governing the population as the sample gets larger, in this
case if it includes several years of data. Samples are measured "as they come", no
triage/filtering allowed, and they are called "stratified" when their distribution
approximates the population distribution. Unlike normal operating errors, samples of
events are not evenly distributed over a year. The attempt in criteria 2 & 7 to preselect only certain events, and not others, in such a way that the selected events
occur evenly throughout the year, is papently wrong because it is trying to "fit"
events into a process (even distribution over time) that does not govern events, but
that instead governs normal operating errors that are the subject of CPM control,
not of this Frequency Response standard. In other words, criteria 2 & 7 confuse
Frequency Response with CPM, and events with normal operating errors. The result
is a false, biased sample which destroys the integrity of this standard. Paragraph 4 on
page 5 of the Background Document, on the other hand, provides a statistically
correct description of event selection without sample pre-selection and should
Consideration of Comments: Project 2007-12 Frequency Response
19
1
003045
Organization
Yes or No
Question 10 Comment
followed instead of the erroneous criteria 2 & 7 in Attachment A. The reason I do not
vote "negative": the risk-based approach to determining FRM, that the Background
Document mentions in paragraph 4 of page 4 is being evaluated by the drafting team
for application in this standard, should be considered for deployment as soon as
possible to replace the administered method currently proposed in this standard,
because the administered method lacks any technical justification. No such
justification was ever attempted in the development of this standard. The
administrative method of determining FRM is therefore but a highly dubious "quick
fix" until the risk-based method is evaluated and implemented. The administrative
method is in fact perverse because it discourages BAs from reducing their
contribution to frequency error by refusing to reduce the BA's FRO accordingly, and
because it encourages BAs to contribute to frequency error without increasing their
FRO.
Response: The word “average” is a generic term to represent central tendency. The term is often used synonymously with the
arithmetic “mean”.
The issue with measuring Frequency Response is that a BA’s calculated performance (as opposed to actual performance) is highly
variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the East typically is only called to contribute
about 10-15 MW for the loss of a large unit. Its minute to minute Load changes can easily wash this contribution out. An arithmetic
mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
Consideration of Comments: Project 2007-12 Frequency Response
19
2
003046
Organization
Yes or No
Question 10 Comment
confidence in the estimate of the BA’s performance.
Associated Electric
Cooperative, Inc.
Affirmative
Please see comments submitted by John Bussman of AECI. Thanks, Chris Bolick
Response: Please refer to our earlier question responses to Mr. Bussman’s comments.
Southwest Power Pool, Inc.
Negative
Please refer to the IRC Standards Review Committee comments which SPP is a party
to for our concerns and recommendations for this standard.
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
City Utilities of Springfield,
Missouri
Affirmative
SPRM supports the comments from SPP.
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
Oklahoma Gas and Electric Co.
Affirmative
See comments submitted by the Southwest Power Pool
Response: The SDT cannot find any comments submitted by the IRC Standards Review Committee.
Electric Reliability Council of
Texas, Inc.
Affirmative The Applicability of BAL-003-1 should be clarified. Specifically, Section 1.2 should be
changed from “Reserve Sharing Groups (where applicable)” to “Reserve Sharing Group
whose intent includes meeting Frequency Response Obligations”.
Regarding Data Retention:
1. As the standard is currently drafted, both the BA and the RSG would be
required to retain data or evidence to show compliance with requirements R1
and M1. It is unclear whether this is the intention, or whether it would be
acceptable that just one or the other would maintain such records.
2. In the first and second paragraph, the reference to ‘three calendar years’
should be specified to be the ‘previous three calendar years’.
3. In the third paragraph, it should be clarified who is required to keep
Consideration of Comments: Project 2007-12 Frequency Response
19
3
003047
Organization
Yes or No
Question 10 Comment
information related to non compliance if the BA belongs to an RSG – the BA or
the RSG or both.
4. In the fourth paragraph, it should be clarified for what length of time the last
audit records must be retained.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.” The SDT has modified the Background Document to further
explain how an RSG (now FRSG) can be used to supply Frequency Response.
1 & 3 - The SDT believes that the reporting entity would be the responsible entity to maintain records. The SDT also believes that
once a BA has declared itself as part of an FRSG then the FRSG would be the responsible entity with the obligation to maintain
records.
2 - The SDT agrees with your second comment and has made this modification.
4 – The last audit record should be kept until the next audit.
Midwest ISO, Inc.
Affirmative
We would like to thank the drafting team for developing a standard responsive to
the FERC Orders.
Response: The SDT thanks you for your affirmative response and clarifying comment.
SCE&G
Affirmative
We feel that frequency response is a function of a contingency event and the
Purpose Statement should recognize this relationship. We suggest the following
insertion in the Purpose Statement. Purpose: To require sufficient Frequency
Response from the Balancing Authority to maintain Interconnection Frequency
within predefined bounds by arresting frequency deviations (due to a contingency
event) and supporting frequency until the frequency is restored. To provide
consistent methods for measuring Frequency Response and determining the
Frequency Bias Setting.
Consideration of Comments: Project 2007-12 Frequency Response
19
4
003048
Organization
Yes or No
Question 10 Comment
Response: The SDT thanks you for your affirmative response and clarifying comment. The SDT believes that the Purpose
Statement you are recommending is basically the same as what the SDT is proposing. For this reason the SDT has decided to
propose their Purpose Statement for use in the proposed standard.
SERC Reliability Corporation
Affirmative
Please see comments submitted by the SERC Operating Committee standards
subgroup for technical suggestions to improve the standard.
Response: Please refer to the earlier question for the SDTs responses.
Tennessee Valley Authority
Affirmative
Comments submitted by SERC OC Standards Review Group. TVA votes affirmative
with comments previously submitted by SERC.
Response: Please refer to the earlier questions for the SDTs responses.
Louisville Gas and Electric Co.
Negative
We support the comments in the SERC OC Standards Review Group Comments.
Response: Please refer to the earlier questions for the SDTs responses.
AEP, AEP Marketing, AEP
Service Corp.
Negative
AEP's negative ballot is primarily due to our concerns regarding R1. Comments are
being submitted via electronic form by Thad Ness on behalf of American Electric
Power.
Response: Please refer to our response for Question #1.
Alberta Electric System
Operator
Negative
Besides the standard, the posting has two attachments, supporting material and two
forms. It is not clear how enforcement will be applied given the array of explicit and
implicit requirements throughout this package, and the use of undefined
terminology, which will be subject to interpretations.
In the SDT response to our comments to the first draft of this standard it was stated
that “The expectation is events will be selected by the Balancing Authorities. The
Balancing Authority may exclude events from consideration for specific conditions
Consideration of Comments: Project 2007-12 Frequency Response
19
5
003049
Organization
Yes or No
Question 10 Comment
such as data quality issues. “ Based on the SDT’s response, it is our understanding
that, for the purpose of the FRM calculation, BAs could exclude or include events
based on specific conditions consideration, such as data quality or event suitability
(e.g. BA separation from the Interconnection). However, the standard as currently
drafted, does not have any provisions to this effect. Please include such provisions in
the body of the standard.
Response: The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments
that requirements were in the Attachments. In order to explain the process, the drafting team believes the information needs to
be attached to the standard such that it cannot be changed without input from the industry.
The SDT recognizes that data may not be available for specific events and therefore has provided in FRS Form 1 a means to
exclude an event. Additionally if an entity has separated from an Interconnection this could be reason for excluding that event
from its FRM calculation since the frequency it would be responding to would not be the Interconnection wide frequency. The risk
caused by excluding events is that the measurement process has shown that a limited number of events does not provide suitable
calculation.
Ameren Energy Marketing
Co.; Ameren Services
Negative
We believe that this is good start to a worthwhile standard, but the following issues
need to be addressed in this standard:
(1) The FRM methodology has not been fully vetted through the field trial process.
(2)Adjusting the minimum of the Frequency Bias Setting, while an appropriate
adjustment for AGC control in the ACE equation, should not be at the expense of L10
as used in BAL-001, R2.
(3) The absence of any resource specific frequency response requirement in NERC
standards is an issue that must be address somewhere. As the resource portfolio of
our industry changes(expedited by recent EPA rulemaking), the resources used for
traditional primary frequency response are becoming a lower percentage of the mix.
New resources and existing resources that have not provided primary frequency
response need to be incorporated into the available frequency response discussion.
(4) BAL-003 is only applicable for an interconnected system, conditions that are
Consideration of Comments: Project 2007-12 Frequency Response
19
6
003050
Organization
Yes or No
Question 10 Comment
created by islanding and other emergences are not address here(nor should they),
but need to be address within the EOP family of standards, so that adequate primary
frequency response is available during emergency situations.
Response: (1) – The issue with measuring Frequency Response is that a BA’s calculated performance (as opposed to actual
performance) is highly variable event to event. This is particularly true for a single BA in a multi-BA Interconnection.
Calculated Frequency Response has a very large noise to signal ratio. A 5,000 MW BA in the Eastern Interconnection typically is only
called to contribute about 10-15 MW for the loss of a large unit. Its minute to minute Load changes can easily wash this contribution
out. An arithmetic mean or regression analysis will be influenced by noise-induced outliers.
Statisticians note that the median is a more accurate measure of central tendency than the mean when analyzing a sample that is
small and or where scores vary widely. This is the case when estimating a BA’s Frequency Response.
A regression would be appropriate if you were trying to forecast “calculated” frequency response for a BA in a multi-BA
Interconnection.
While not perfect, the median approaches a BA’s typical performance after 15-20 observations. More observations give a higher
confidence in the estimate of the BA’s performance.
- The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related
calculations. Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial
minimum Bias Setting 0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in
minimum Bias Setting. The evaluation will look at both frequency performance and impact on CPS-related compliance
calculations.
(2) - The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
19
7
003051
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
Frequency Response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
(3) – The SDT agrees that the issue you cite should not be covered in this standard. The SDT will forward this comment on to the
appropriate entity at NERC.
PJM Interconnection, L.L.C.
Negative
PJM does not believe that the BA should be the entity responsible for the frequency
response obligation, moreover the SDT has not sufficiently vetted the issue of
applying the response requirements on an entity that cannot provide that service.
PJM is concerned that the proposed draft does not explicitly cover the FERC Order
693 directives in the proposed requirements and rather addresses the directives
indirectly in the attachments. This matter of mandatory vs. informational
attachments must be formally clarified before approval can be given for this
approach.
PJM does not agree with the additional clarifying phrases being incorporated into the
requirements. Explanatory phases should be included as text boxes as proposed in
NERC’s Risk Based Methodology.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
19
8
003052
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Potomac Electric Power Co.
Negative
The proposed standard is not reliability centered and will not improve reliability. 5)
Potomac Electric Power Company supports the comments provided by PJM.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
Consideration of Comments: Project 2007-12 Frequency Response
19
9
003053
Organization
Yes or No
Question 10 Comment
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Atlantic City Electric Company
Negative
See comments submitted by David Thorne in Segment 1, Potomac Electric Power
Company
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient
frequency response in all Interconnections, the value of implementing a performance obligation on generators at this time
would not outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a
need for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Attachments that are referenced within a Requirement are mandatory and enforceable.
The SDT has been instructed to include a “reliability outcome” within the requirements. The SDT will forward your concerns about
the wording to the Standards Committee Quality Review group for consideration.
Avista Corp.
Negative
This standard should be designed for each interconnection explicitly rather than one
size fits all. Frequency is an interconnection issue and response is driven by the
interconnection's topology. One size does not fit all for interconnections. This
Consideration of Comments: Project 2007-12 Frequency Response
20
0
003054
Organization
Yes or No
Question 10 Comment
standard should be designed around the explicit needs of each interconnection.
Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
Response: The SDT believes that an Interconnection has the capability to request a variance (especially one that is more restrictive),
however the SDT has tried to prevent the need for variances by respecting the individuality of each of the Interconnections in
setting Interconnection Frequency Excursion Threshold Values, Interconnection Frequency Response Obligations and the Frequency
Bias Setting Minimums as noted in Attachment A.
Early research by Nathan Cohn5 on interconnected power system operations found that control is optimum if a BA’s Bias Setting is
equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
Beaches Energy Services; City
of Bartow, Florida; Tampa
Electric Co.
Negative
We thank the SDT for their hard work and diligence in moving this Project forward.
However, I have some concerns that cause me to not support the standard in its
current form. In general, I believe that there has not been sufficient prudency review
for the standard, especially R1, to justify a performance based standard around a
Frequency Response Measure.
I also believe that the proposed standard does not meet the intent of the Final SAR
5
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
20
1
003055
Organization
Yes or No
Question 10 Comment
or Supplemental SAR. The “Final SAR” was to develop methods by which a
performance based standard would eventually be developed. The Final SAR states:
“The proposed standard’s intent is to collect data needed to accurately model
existing Frequency Response. There is evidence of continuing decline in Frequency
Response in the three Interconnections over the past 10 years, but no confirmed
reason for the apparent decline. The proposed standard requires entities to provide
data so that Frequency Response in each of the Interconnections can be modeled,
and the reasons for the decline in Frequency Response can be identified. Once the
reasons for the decline in Frequency Response are confirmed, requirements can be
written to control Frequency Response to within defined reliability parameters.”
BAL-003-1 is beyond the scope of this “Final SAR”. For instance, “the reasons for the
decline in Frequency Response” were not confirmed to our knowledge; and the field
trial is not completed to our knowledge. The Supplemental SAR adds to the scope of
the Final SAR: “To provide a minimum Frequency Response Obligation for the
Balancing Authority to achieve, methods to obtain Frequency Response and provide
a consistent method for calculating the Frequency Bias Setting for a Balancing
Authority. In addition, the standard will specify the optimal periodicity of Frequency
Response surveys.” Please note that the Standards Development Roadmap does not
confirm whether this Supplemental SAR was ever approved; hence, I question
whether this is actually part of the scope of the SDT. Be that as it may, the
Supplemental SAR does not eliminate the pre-requisite contained in the Final SAR to
determine the reasons for the decline in frequency response and confirm them
before establishing “defined reliability parameters”. In addition, the standard does
not meet the scope requirements of the Supplemental SAR.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
The SDT agrees that the original SAR was strictly for data collection. However, a supplemental SAR was developed to address the
FERC March 18, 2010 Order and was subsequently approved by the industry.
Consideration of Comments: Project 2007-12 Frequency Response
20
2
003056
Organization
Yes or No
Constellation Energy
Commodities Group
Negative
Question 10 Comment
Please see submitted comments for additional detail behind the negative vote.
Response: Please see the SDT responses to your comments to the earlier questions.
Energy Mark, Inc.
Negative
The issue of Median, Mean, Regression needs to be resolved using Field Trial data.
This should be able to be completed before the end of January 2012.
The FRO and Minimum Bias Setting allocations should be determined using a single
allocation method and a single data set.
Wording changes are needed in the Requirements to indicate compliance in all cases
for all BAs.
In general, although this standard has many weaknesses, its implementation with
small modifications will be better than failure to implement it.
Response: The drafting team is recommending use of the median for the purposes of determining a BA FRM over multiple events.
This decision is based on the determination that, while it may not be perfect, it is better than the other alternatives available at
this time. The drafting team recognizes that in the future a better methodology might be found; based on the data available at
this time the median allows us to move forward to implement a response requirement.
The drafting team understands your concern of using the historical numbers for the FRO allocation and the projected number as
the basis for the minimum Frequency Bias Setting. However, after discussions, the drafting team believes that at this time,
minimizing the changes to the current Frequency Bias Setting process provides better comparability for the purpose of evaluating
the impacts of reducing the minimum setting requirement. In the alternative, the drafting team feels that allocating the FRM
based on historical data provides less room to game the process since the numbers used for allocation can be verified
independently.
The SDT has modified the requirements and believes that your concern has now been addressed.
The SDT thanks you for your comment.
Energy Mark, Inc.
Negative
The Time Horizon for R1 is Operations Assesment. It should be Real Time. Frequency
Consideration of Comments: Project 2007-12 Frequency Response
20
3
003057
Organization
Yes or No
Question 10 Comment
Response is a service that is automatic. It does not require operator action to
activate the service. It requires that the operator set-up the system to provide the
automatic response before an event requiring Frequency Response occurs. Unlike
other Real Time services, if the operator fails to set-up the system to provide this
service before Real Time, there is no action that the operator can take to provide the
service in response to an event. Many other actions in the standards required by the
system operator are considered to be Real Time because the operator can take
action after an event occurs. It does not make sense to consider an action that must
be taken before Real Time as Operations Assessment.
Response: The requirement does not fall into a single category. The operator is constantly taking actions some of which were set
in a “longer term” horizon, some in a “real-time” horizon and this is an after-the-fact measure.
Fort Pierce Utilities Authority
Negative
FPUA supports the comments submitted by Florida Municpal Power Agency (FMPA)
through the formal comment process.
Response: Please refer to the SDT response to the comments received from FMPA in the earlier questions.
Hydro One Networks, Inc.
Negative
Hydro One is casting a negative vote for this project. We support and subscribe to
the comments submitted by NPCC on behalf of its members.
In summary, the comments are:
1 o Use of 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz.
2 o Use of installed capacity in determining the Frequency Response Obligation.
3 o The sampling interval should be tuned on a per Interconnection basis to support
HQTE’s characteristics.
4 o NPCC does not advocate the use of supplemental regulation as a method of
procuring frequency response.
5 o BAL-003-1 is applicable only to Balancing Authorities and Reserve Sharing
Consideration of Comments: Project 2007-12 Frequency Response
20
4
003058
Organization
Yes or No
Question 10 Comment
Groups. A common concern that has been expressed in the industry is that the
burden of compliance is being placed solely on Balancing Authorities while the main
sources of discretional frequency response are generators.
6 o Balancing Authorities must be able to provide sufficient frequency response and
be able to and the proper frequency bias settings applied in their AGC systems are
necessary.
7 o In the formula for determining the Balancing Authority’s FRO allocation, installed
capacity is used. Is there a clear and consistent definition for installed capacity?
Considering the growth of wind energy development, the delivered energy from
wind generation over longer time horizons will be substantially less than the machine
nameplate ratings.
8 o The background document refers to the use of peak generation instead of
installed capacity. Which shall be used?
o Additional minor issues for the SDT consideration that should be addressed:
? A link should be provided in the standard to FRS Form 1, or instructions
provided for how entities may find the form.
? In the definitions, FRS should be spelled out before using the acronym.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for its higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2, 7 & 8 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses
“historical data” to circumvent the problem you have described.
Consideration of Comments: Project 2007-12 Frequency Response
20
5
003059
Organization
Yes or No
Question 10 Comment
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
5 – The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
Consideration of Comments: Project 2007-12 Frequency Response
20
6
003060
Organization
Yes or No
Question 10 Comment
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
6 – The SDT agrees with you comment.
Additional minor issues
The Forms will be put on a NERC website and announced once the standard is approved.
The definition no longer reference FRS Form 1.
Independent Electricity
System Operator
Negative
The complete IESO’s comments on the revised standard are provided through the
electronic comment form. The summary below highlights IESO's major concerns with
the revised standard:
1)The definition for Frequency Response Measure (FRM): The proposed FRM
definition: “The median of all the Frequency Response observations reported
annually on FRS Form 1” is problematic. It references an FRS Form 1 which is not
included in the definition itself but is in fact an attachment to the standard. In the
current NERC Glossary of Terms, there is no such precedence that a definition must
rely on the requirements or details in a standard for completeness. Also, it is very
cumbersome that when changes are made to FRS Form 1, the definition must be
posted for industry comment and balloting, and vice versa. When other standards
begin using the term, there will be cross references between standards. This further
complicates the update/maintenance problem without any appreciable value. (See
complete comment in Section Q1 in the electronic comment form)
2)Attachment A: Attachment A should include only the event selection process and
calculations associated with the requirements, including an explanation of what is
necessary if variable Frequency Bias Settings are implemented. If other
"requirements" need to be specified, such as the reporting time frame stipulated on
page 3 of Attachment A, they should be moved to the standard itself but not
imbedded in an attachment. (See complete comment in Section Q6 in the electronic
Consideration of Comments: Project 2007-12 Frequency Response
20
7
003061
Organization
Yes or No
Question 10 Comment
comment form)
3)The expanded FRS Form 1 and the addition of a Form 2 ask for data entry that is
excessive and whose value has not been demonstrated. (See complete comment in
Section Q9 in the electronic comment form)
Response: 1) The SDT has modified the definition to no longer reference FRS Form 1. The definition now reads “The median of all
the Frequency Response observations reported annually by Balancing Authorities for frequency events specified by the ERO. This
will be calculated as MW/0.1Hz.”
2) The intent of Attachment A is to describe the process that will be used. There is no intent to require a filing on a certain date
and to have the BA prove to the auditor that a filing was made on that date. Rather the requirement is to have an FRM that
provides at least the response required of a BA based on it’s FRO and provide a high-level overview of the mechanical parts of the
process. The drafting team has modified the Requirements and Attachments to address the concerns raised by the comments that
indicated requirements were in the Attachments. In order to explain the process, the drafting team believes the information
needs to be attached to the standard such that it cannot be changed without input from the industry.
3) The SDT points out that there are no additional data requirements. It is possible that you are seeing more spreadsheets due to
them being unhidden.
Form 2 is a separate stand-alone workbook. Form 1 does have a worksheet labeled “BA Form 2 Event Data” that will contain the
single event data from each of the BA’s Form 2s. Two additional worksheets were added to Form 1 and several worksheets were
deleted. The “Time Zone Ref” worksheet was added to allow the BA to enter the time zone of its data and have the spreadsheet
calculate the local time of the event from the UTC time. This was added for the convenience of the BA in collecting the correct
data for each event and does not require additional data from the BA. The second worksheet added was a worksheet that
displays graphs of frequency for each event and the t(0) selected correctly. This was added to aid the BA with data collection and
the selection of t(0) since this seemed to be one of the biggest problems during the first phase of the field trial. This graph
worksheet does not require the BA to do anything. It is not used in the analysis and can be deleted. Deleting this worksheet will
greatly reduce the size of Form 1. None of the data requirements on Form 1 or Form 2 have changed from previous versions. The
absolute minimum data needed for this standard is the date/time, frequency and NAI in columns A, B and C of the “Data”
worksheet in Form 2. Columns D through I have been totally optional and can be left blank. Column J is the Bias setting in the ACE
equation and is important to BA’s that utilize Variable Bias. Column K, BA Load, was added by the drafting team in the beginning
to see if Load Dampening could be measured as this has been done for several years on one Interconnection. Column I of the
Consideration of Comments: Project 2007-12 Frequency Response
20
8
003062
Organization
Yes or No
Question 10 Comment
“Data” worksheet is the only optional data that the BA should use when it is the contingent BA during any of the events
evaluated. Utilizing this data will allow the BA’s SEFRD to be calculated correctly and give the BA a full sample set for the annual
median calculation. Form 2 is necessary to standardize the measurement process on all Interconnections. You are free to hide
any analytical worksheets on Form 1 and Form 2. You can do this on your “master” Form 2 and then build each Form 2 for each
event using this master. These additional worksheets are available for BAs to utilize if they find that their performance is below
the FRO and will aid the analysis of the contributing causes.
ISO New England, Inc.
Negative
ISO New England will not vote to approve the standard because it fails to place
requirements on generators to provide frequency response. There are four
substantive problems:
1 • Using 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz
2 • Using installed capacity in determining the Frequency Response Obligation
3 • The sampling interval needs to be tuned on a per Interconnection basis to
support HQTE’s characteristics
4 • Do not advocate the use of supplemental regulation as a method of procuring
frequency response
Additionally, the SDT must decide on what the purpose of this standard is. If it is to
respond to Order 693 then the standard misses the point of defining how often to
run Frequency Response Surveys; it does not crisply define the “Interconnection”
obligations. If the SDT does want to focus on performance then the issue of who is
the default provider must be addressed. As the IRC has noted previously, all BAs do
not own the service providers. To create standards that apply to entities that are
dependent on other function entities to comply with a standard requirement is of
great concern.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
Consideration of Comments: Project 2007-12 Frequency Response
20
9
003063
Organization
Yes or No
Question 10 Comment
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
Consideration of Comments: Project 2007-12 Frequency Response
21
0
003064
Organization
Yes or No
Question 10 Comment
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
6 – The SDT agrees with you comment.
Additional minor issues
The Forms will be put on a NERC website and announced once the standard is approved.
The definition no longer reference FRS Form 1.
JEA
Negative
JEA is not comfortable with a performance based standard as written without more
field testing to ensure that net interchange is not skewed by load and generation
changes that are not a function of frequency. Since frequency response has
components from load and generation resources, and load is not controllable for the
most part, seems this standard should be directed at specific generator response
methods from the GO/GOP's.
This is a wide reaching standard. And, this is a performance standard (if it doesn't
perform as designed, it is a violation). Because of this, more testing needs to be
completed so we know the model is correct. We are not sure we know how to
ensure compliance.
Don't agree the standard needs to be performance based.
Response: Based on the studies performed by the SDT, the drafting team believes that a calculation of the median of multiple
Consideration of Comments: Project 2007-12 Frequency Response
21
1
003065
Organization
Yes or No
Question 10 Comment
events addresses the concerns raised by the noise being inside a single event. The studies from the field trial show a convergence
of the measurement after approximately 20 to 25 events.
The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which mandated
development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to provide a
standard addressing these issues by the end of May 2012.
Kansas City Power & Light Co.
Negative
The proposed Standard BAL-003-1 does not consider the real time operating
conditions under which this standard should apply. There are no considerations for
the complexities introduced by capacity energy agreements between BA's nor
consideration of the differing level of Interconnection Frequency Response needed
at times of minimum interconnection load conditions and interconnection peak load
conditions.
Response: The method for determining the FRO is based upon the determination of the largest contingency that could occur at any
time and does not vary based upon time of day or system conditions. Since the largest contingency could occur at any time, the
minimum Frequency Response Obligation necessary to manage the contingency will not be dependent upon the differing conditions
that can occur during different times of the day like those referred to in the question.
Lakeland Electric
Negative
In general; here has not been sufficient prudency review for the standard, especially
R1, to justify a performance based standard around a Frequency Response Measure.
Refer to comments submitted by FMPA on LAK behalf.
Response: The SDT is responding to FERC Directives from Order 693 as well as the FERC Order dated March 18, 2010 which
mandated development of a standard addressing the Order 693 directives within six months. FERC later granted an extension to
provide a standard addressing these issues by the end of May 2012.
Please refer to the SDT response to the comments received from FMPA in the earlier questions.
Liberty Electric Power LLC
Negative
Voting no due to SDT addressing FERC directives with attachments instead of in the
standard requirements.
Response: The SDT disagrees with your concern about addressing FERC directives within an attachment. If a requirement
Consideration of Comments: Project 2007-12 Frequency Response
21
2
003066
Organization
Yes or No
Question 10 Comment
references specific performance in an Attachment, then the performance described in the Attachment is mandatory and
enforceable.
Manitoba Hydro
Negative
The Applicability of BAL-003-1 should be clarified. Specifically, Section 1.2 should be
changed from “Reserve Sharing Groups (where applicable)” to “Reserve Sharing Group
whose intent includes meeting Frequency Response Obligations”.
Regarding Data Retention:
1. As the standard is currently drafted, both the BA and the RSG would be
required to retain data or evidence to show compliance with requirements R1
and M1. It is unclear whether this is the intention, or whether it would be
acceptable that just one or the other would maintain such records.
2. In the first and second paragraph, the reference to ‘three calendar years’
should be specified to be the ‘previous three calendar years’.
3. In the third paragraph, it should be clarified who is required to keep
information related to non compliance if the BA belongs to an RSG – the BA or
the RSG or both.
4. In the fourth paragraph, it should be clarified for what length of time the last
audit records must be retained.
Response: The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using the
presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.” The SDT has modified the Background Document to further
explain how an RSG (now FRSG) can be used to supply Frequency Response.
1 & 3 - The SDT believes that the reporting entity would be the responsible entity to maintain records. The SDT also believes that
once a BA has declared themselves as part of a FRSG then the FRSG would be the responsible entity to maintain records.
2 - The SDT agrees with your second comment and has made this modification.
4 – The last audit record should be kept until the next audit.
Consideration of Comments: Project 2007-12 Frequency Response
21
3
003067
Organization
Yes or No
Question 10 Comment
New Brunswick Power
Transmission Corporation
Negative
The compliance burden should not fall on the BA as the provider of Frequency
Response (i.e. Primary Control response). In this case the BA per se has no assets,
moreover the primary response service providers have no obligations to provide the
service, thus the BA potentially could face a situation where there is no physical
service to be purchased but there is a mandated standard to comply with. The idea
of creating a Primary Response Market as some have proposed does not work
without an obligation on some entity to physically provide that service.
Response: The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency
Response. This is because a BA controls the amount and distribution of spinning reserves and also has some control over
interruptible resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not
own generators or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
New York State Department
of Public Service, National
Association of Regulatory
Utility Commissioners
Negative
After review of the standard and draft comments to be submitted by industry
participants, it appears that there are many areas of the proposed standard that
require clarification.
Response: The SDT thanks you for your participation. Please be more specific about what needs clarification so the SDT can
address your specific concerns.
Consideration of Comments: Project 2007-12 Frequency Response
21
4
003068
Organization
Yes or No
Northeast Power Coordinating
Council
Negative
Question 10 Comment
This standard as written does not place requirements on generators to provide
frequency response. There are four substantive problems:
1 • Using 59.6 Hz as an Eastern Interconnection UFLS instead of an actual value of
either 59.5 Hz or 59.7 Hz.
2 • Using installed capacity in determining the Frequency Response Obligation.
3 • The sampling interval needs to be tuned on a per Interconnection basis to
support HQTE’s characteristics.
4 • Do not advocate the use of supplemental regulation as a method of procuring
frequency response.
It must be decided as to what the purpose of this standard is. If it is to respond to
Order 693 then the standard misses the target of defining how often to run
Frequency Response Surveys; it does not crisply define the “Interconnection”
obligations. If performance is the focus, then the issue of who is the default provider
must be addressed. All BAs do not own the service providers. To create standards
that apply to entities that are dependent on other functional entities to comply with
a standard requirement is of great concern.
FRS Form 1 is listed as being an Associated Document. Will it be attached to the
standard?
The acronym FRS is used in the standard. FRS should be spelled out before its
acronym is used.
If FRS Form 1 will not be an appendix or an attachment to the document, then a link
should be provided to it, or instructions given on how to find it.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4000 MW
Consideration of Comments: Project 2007-12 Frequency Response
21
5
003069
Organization
Yes or No
Question 10 Comment
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
Consideration of Comments: Project 2007-12 Frequency Response
21
6
003070
Organization
Yes or No
Question 10 Comment
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
New Brunswick System
Operator
Negative
Please see comments submitted by the NPCC Reliability Standards Committee and
the IRC Standards Review Committee
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
Consideration of Comments: Project 2007-12 Frequency Response
21
7
003071
Organization
Yes or No
Question 10 Comment
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
Consideration of Comments: Project 2007-12 Frequency Response
21
8
003072
Organization
Yes or No
Question 10 Comment
approved.
The definition no longer reference FRS Form 1.
New York Independent
System Operator
Negative
The NYISO's comments are included with both the Joint IRC/SRC and Joint NPCC RSC
comments.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the Eastern Interconnection to continuously carry about 4,000 MW
of frequency responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a
contingency on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an
obligation based on 59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Consideration of Comments: Project 2007-12 Frequency Response
21
9
003073
Organization
Yes or No
Question 10 Comment
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
Rochester Gas and Electric
Corp.
Negative
RG&E supports comments to be submitted to NPCC.
Response: 1 - Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the
East. This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry
extra frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
Consideration of Comments: Project 2007-12 Frequency Response
22
0
003074
Organization
Yes or No
Question 10 Comment
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
2 – The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3 – The SDT adjusted the event selection Criteria to address concerns related to response driving frequency back to the pre-event
level during the B value measurement period. We believe that this adjustment addresses your concern.
4 – The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
Consideration of Comments: Project 2007-12 Frequency Response
22
1
003075
Organization
Yes or No
Question 10 Comment
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
FRS Forms 1 and 2 will be Attached to the standard. The Forms will be put on a NERC website and announced once the standard is
approved.
The definition no longer reference FRS Form 1.
Orlando Utilities Commission
Negative
Per LPPC comments
Response: The SDT is not sure of the entity you are referencing (LPPC). Therefore, the SDT cannot respond to your comment
without further clarification.
Portland General Electric Co.
Negative
PGE agrees with the WECC whitepaper including the comments and concerns.
Negative
The PPL Companies do not support proposed Reliability Standard BAL-003-1
(Frequency Response and Frequency Bias Setting) primarily because PPL believes it
inappropriately subjects Reserve Sharing Groups (RSGs) to the proposed
requirements. The proposed Applicability provision states that the mandatory
reliability requirements would be applicable to (1) Balancing Authorities and (2)
Reserve Sharing Groups (where applicable). However, it is unclear how the proposed
requirements would be applicable to an RSG. RSGs typically do not provide a
mechanism for sharing automatic Frequency Response. The BA Frequency Response
Response: see WECC comments.
PPL Electric Utilities Corp.; PPL
Generation LLC
Consideration of Comments: Project 2007-12 Frequency Response
22
2
003076
Organization
Yes or No
Question 10 Comment
Obligation (FRO) is a formula based on BAs and the Interconnection and has nothing
to do with RSGs. Rather, RSGs collectively respond to requests for activation of
contingency reserves generally after the request is made by a member Balancing
Authority. The Standard Drafting Team should therefore remove RSGs from the
Applicability section and should remove all other references to RSGs in the proposed
standard.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
PPL EnergyPlus LLC
Negative
Please refer to PPL's corporate comments.
Response: The SDT has modified the Background Document to further explain how an RSG (now FRSG) can be used to supply
Frequency Response. The SDT has defined a new term “Frequency Response Sharing Group (FRSG)” because it believes that using
the presently defined term “Reserve Sharing Group” could cause confusion. The new definition reads “A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members.”
Seattle City Light
Negative
LADWP and SCL support project 2007-12’s general approach to frequency response,
and is prepared to support the ballot once several problematic details are corrected.
o LADWP and SCL note that the time allowed to analyze the final “official” set of 25
events for each year, from Dec 15 to Jan 10, is relatively short and coincides with the
holiday vacation season
Response: The ERO will be posting preliminary events throughout the year. The criteria contained in Attachment A should allow
an entity to evaluate events as they occur. This coupled with the Forms 1 & 2 should allow an entity to be looking forward
throughout the year. In addition the standard allows 30-days for providing information.
Consideration of Comments: Project 2007-12 Frequency Response
22
3
003077
Organization
Yes or No
Question 10 Comment
Seattle City Light
Negative
SCL would like to see addressed in the Standard how the case is to be addressed
where a BA simply has no frequency response information to provide, as could
happen for a small 1-2 generator BA which has its generators out of service for an
extended period for maintenance or upgrades. Assuming the BA purchases
frequency response services from another entity during this period, is the BA out of
compliance with the proposed Standard simply because it has no data report? And
how is its next-year obligation to be computed? These issues should be addressed in
the Measures or Additional Compliance information. If these are issues for “lawyers”
as the Standards Drafting Team indicated during the November 14, 2011, webinar
then the team should engage a NERC lawyer to resolve them prior to releasing the
Standard for ballot.
o Finally, SCL points out that the proposed Standard introduces a new obligation on
applicable entities to maintain frequency responsive reserves. Although this
obligation does not appear to be unreasonable or problematic in general,
compliance may prove difficult for some entities and in some localized areas.
Response: The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Consideration of Comments: Project 2007-12 Frequency Response
22
4
003078
Organization
Yes or No
Question 10 Comment
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
Public Utility District No. 1 of
Snohomish
County/Snohomish County
PUD No. 1
Negative
Public Utility District No. 1 of Snohomish County supports the comments filed by
Seattle City Light.
Response: The ERO will be posting preliminary events throughout the year. The criteria contained in attachment A should allow
an entity to evaluate events as they occur. This coupled with the Forms 1 & 2 should allow an entity to be looking forward
throughout the year. In addition the standard allows 30-days for providing information.
The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
South California Edison
Negative
SCE's "No" vote, like the WECC position, regarding Project 2007-12 is based on the
Consideration of Comments: Project 2007-12 Frequency Response
22
5
003079
Organization
Yes or No
Company
Question 10 Comment
following five points:
1) Clarification is needed whether there will/ will not be conflicts between proposed
Requirement R3 and the requirements of FERC-approved regional reliability standard
BAL-004-WECC-1 - Automatic Time Error Correction
2) Confusion exists between Attachment A and the Background Document:
2a) Attachment A states peak load allocation is based on “Projected” Peak
Loads and Generation, versus
2b) The Background Document which states it will use “historical” Peak Load
and Generation.
3) Reducing frequency bias obligation is detrimental to reliability. It seems that
Lowering the Minimum Frequency Bias Setting from 1% to .8% will result in a lower
response, which in turn will lower the natural frequency response. Over time it
seems this pattern would lead to poorer response.
4) There is no clear statement of what is expected from the Balancing Authorities
and whether or not there is a limit on that expectation.
5) Why are there no requirements on governor installation, settings, and operation
for a frequency response standard?
Response: 1) The SDT has removed Requirement R3. The SDT believes that this requirement is duplicative of BAL-005-0.1b
Requirements R6 & R7.
2) The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical
data” to circumvent the problem you have described.
3) Early research by Nathan Cohn6 on interconnected power system operations found that control is optimum if a BA’s Bias Setting
is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to be slightly
over-biased.
6
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
22
6
003080
Organization
Yes or No
Question 10 Comment
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
4) The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency Response that
a BA will be required to provide
5) The NERC Functional Model Technical Document identifies the BA as the entity that manages and deploys Frequency Response.
This is because a BA controls the amount and distribution of spinning reserves and also has some control over interruptible
resources. This is similar to the relationship between the TOP and voltage control. Even though the TOP may not own generators
or capacitor banks, the TOP is still responsible for controlling voltage within limits.
The industry-approved Standards Authorization Request (SAR) for BAL-003 did not include a performance obligation for
generators. The drafting team is obliged to stay within the bounds of its SAR.
There are two primary reasons the SAR did not apply a performance obligation on generators. First, there are thousands of
generators in North America. It would be many times more costly and difficult to implement a standard that measures all
generators and verifies performance is properly calculated. Secondly, given the fact that there presently is sufficient frequency
response in all Interconnections, the value of implementing a performance obligation on generators at this time would not
outweigh the effort and cost.
Again, the drafting team cannot include requirements beyond the bounds of its SAR. If the commenter(s) believes there is a need
for a generator performance obligation, they are encouraged to submit a SAR to that effect.
Western Area Power
Administration
Negative
1. Reducing frequency bias obligation is a detriment to reliability of interconnection
and the proposed standard aims to reduce the bias obligation from the current
minimum level of 1% load to 0.8% and subsequently to a lower percentage.
2. The proposed standard is very confusing and complex in regard to data collection
Consideration of Comments: Project 2007-12 Frequency Response
22
7
003081
Organization
Yes or No
Question 10 Comment
and compliance.
3. The proposed standard is encompassing reserve sharing group (where applicable),
why? What reserve sharing group operates AGC?
It is not clear whether the compliance period is monthly or yearly for R1 & R5.
The issue of non-binding standard and whether it serves a purpose to go through
complicated data submission and found in compliance or out of compliance without
any consequences.
Response: 1. Early research by Nathan Cohn7 on interconnected power system operations found that control is optimum if a BA’s
Bias Setting is equal to its natural Frequency Response. If there were to be a difference between the two values, it is preferable to
be slightly over-biased.
The drafting team has proposed to bring Bias Setting and natural Frequency Response more in line. The process to do this is
outlined in a Procedure developed by the SDT which replaces Attachment B. The Procedure manages a “go slow” approach to
making this happen and includes checks to confirm there are not unexpected influences injected into the CPS-related calculations.
Based on concerns raised by the industry, the drafting team has modified the Procedure to make the initial minimum Bias Setting
0.9% of peak and has included a provision that the ERO will evaluate the impact caused by a change in minimum Bias Setting. The
evaluation will look at both frequency performance and impact on CPS-related compliance calculations.
3. The SDT has modified the Background Document to provide additional information and clarity.
4. The SDT modified R1 so that it no longer applies to an RSG _ the SDT defined new term, “Frequency Response Sharing Group”
to address stakeholder concerns that the RSG is not the correct entity. The definition of Frequency Response Sharing Group is:
A group whose members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of its members.
3. Requirement R1 is calculated on an annual basis. The SDT has removed Requirement R5 and combined it into Requirement R2
7
Control of Generation and Power Flow on Interconnected Systems, John Wiley & Sons, 1967
Consideration of Comments: Project 2007-12 Frequency Response
22
8
003082
Organization
Yes or No
Question 10 Comment
and new Requirement R3.
The SDT made modifications to Attachment A to try to distinguish mandatory performance assigned to the BA from process steps
performed by the ERO.
Xcel Energy, Inc.
Negative
It is not clear if there is an upper limit to the amount of frequency response expected
of the Balancing Authorities under this standard. Except for Table 2 in Attachment A,
there is no discussion of an amount of FR expected on a total basis. Balancing
Authorities need to know for how many tenths of a hertz they are to respond so they
can determine how to plan to meet this requirement. The documents do not appear
to provide any boundary on the maximum amount of FR that a BA will provide, i.e. it
is not clear what will happen if an event occurs in the Eastern Interconnection that
causes the frequency to drop to less than 59.6 Hz (e.g. what if freq dips to 59.0? Is
the BA expected to provide a limitless amount of frequency response?). Also, is that
event excluded from the list used to calculate the Balancing Authorities’ response or
is it included with an expectation that it counts the same as any other event. Without
a clear statement of what is expected, including whether there is a limit on that
expectation or not, the Balancing Authorities cannot know what is expected of them
and therefore cannot plan appropriately.
Response: The SDT understands your concern and has added language in Attachment A that caps the amount of Frequency
Response that a BA will be required to provide.
Negative
59.6 Hz should be used as the Eastern Interconnection URLS.
Installed capacity should always be used determining an area's frequency response
obligation.
I question the use of supplemnetal regulation as a method of procuring frequency
response. Is this an acceptable practice throughout all NERC Regions?
Each Balancing Authority must be able to provide the required or calculated
frequency response and be able to incorporate the proper frequency bias settings in
Consideration of Comments: Project 2007-12 Frequency Response
22
9
003083
Organization
Yes or No
Question 10 Comment
the Balancing Authority's AGC system.
A link should be provided in the proposed standard to FRS Form 1.
Response: Florida sees a greater change in frequency for a given contingency than for a comparable event elsewhere in the East.
This is the reason for their higher first step of UFLS in Florida. Having all Eastern Interconnection Balancing Authorities carry extra
frequency responsive reserves to protect against a target minimum frequency of 59.7 Hz would not protect Florida against a
contingency inside Florida, but would require the other BAs in the East to continuously carry about 4,000 MW of frequency
responsive reserves to protect against a false trip in Florida if frequency fell below 59.7 Hz but over 59.5 Hz. This is a contingency
on the order of 7,000 MW or more. The drafting team compromised and gave the entire Interconnection an obligation based on
59.96Hz.
The SDT has modified both the Background Document and Attachment A to be consistent. The calculation uses “historical data”
to circumvent the problem you have described.
The SDT has a section in the Background Document addressing methods of obtaining Frequency Response.
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a contractual share of Frequency Response from
Adjacent Balancing Authorities. See FRS Form 1. While the final rules with regard to contractual services are being defined,
the current expectation is that the ERO and the associated Region(s) should be notified beforehand and that the service be at
least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or Loads (The drafting team encourages the development of a NAESB business practice for
Frequency Response service for linear (droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service, BAs and FRSGs may use whatever is
most appropriate for their situation.
Consideration of Comments: Project 2007-12 Frequency Response
23
0
003084
Organization
Yes or No
Question 10 Comment
The SDT agrees with you comment.
The Forms will be put on a NERC website and announced once the standard is approved.
END OF REPORT
Consideration of Comments: Project 2007-12 Frequency Response
23
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003085
Unofficial Comment Form
Frequency Response Technical Conferences
Please use the electronic comment form to submit comments on the Frequency Response Technical
Conferences held on May 22, 2012 and May 24, 2012. These comments will be posted on the project
webpage as part of the development record and considered by the FRSDT as it continues to develop
BAL-003. Comments must be submitted by June 15, 2012. If you have questions please contact Darrel
Richardson (email) or by telephone at (609) 613-1848.
Background Information:
NERC recently held two technical conferences on Frequency Response. The first conference was held
on May 22, 2012 in Arlington, VA and the second was held in Denver, Colorado on May 24, 2012. The
purpose of these conferences was to obtain industry input on the development of a Frequency
Response standard. The information provided in the conferences primarily dealt with the following
three areas.
1. The work that has been done on the standard to date
2. Which Functional Entity should be responsible for Frequency Response.
3. How to measure Frequency Response
A complete set of presentations from the conferences can be found at the following link.
http://www.nerc.com/filez/standards/Frequency_Response-RF.html
NERC is requesting industry comments pertaining to the information provided in the conferences or
suggestions for further consideration in the development of a Frequency Response standard. Please
share your thoughts on the Technical Conference and the associated subject matter below.
Enter All Comments in Simple Text Format.
1. Please provide any comments on the Technical Conference and associated subject matter in the
comment area below.
Comments:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003086
Standards Announcement
Frequency Response Technical Conferences
Comment Period: May 30 – June 15, 2012
Now Available
NERC recently held two technical conferences on Frequency Response. The first conference
was held on May 22, 2012 in Arlington, VA and the second was held in Denver, Colorado on
May 24, 2012. The purpose of these conferences was to obtain industry input on the
development of a Frequency Response standard. The information provided in the conferences
primarily dealt with the following three areas.
1. The work that has been done on the standard to date
2. Which Functional Entity should be responsible for Frequency Response.
3. How to measure Frequency Response
A complete set of presentations from the conferences can be found at the following link.
http://www.nerc.com/filez/standards/Frequency_Response-RF.html
NERC is requesting industry comments pertaining to the information provided in the
conferences or suggestions for further consideration in the development of a Frequency
Response standard. Please share your thoughts on the Technical Conference and the
associated subject matter by providing your comments using the electronic comment form.
The deadline to submit comments is 8 p.m. ET Friday, June 15, 2012. An off-line, unofficial copy
of the comment form for administrative use is available on the project page.
For more information or assistance, please contact Monica Benson at [email protected].
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003087
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003088
Name (9 Responses)
Organization (9 Responses)
Group Name (6 Responses)
Lead Contact (6 Responses)
Contact Organization (6 Responses)
Question 1 (0 Responses)
Question 1 Comments (15 Responses)
Individual
Don Tench on Behalf of ENBALA
ENBALA Power Networks
I. INTRODUCTION ENBALA Power Networks (ENBALA) respectfully submits these comments in
response to the North American Electric Reliability Corporation (NERC) Technical Conference on
Frequency Response held in Arlington VA on May 22, 2012 and Denver CO on May 24, 2012. ENBALA
rewards large electricity users for participation in the Smart Grid. The ENBALA Power Network enables
industrial, commercial and municipal partners to be financially rewarded for the inherent flexibility of
their electrical equipment. Resource partners incur no cost in connecting to this platform and receive
payments for helping to bring continuous balance to the electricity system. The purpose of these
conferences was to provide background on the development, and implementation of BAL-003-1 Frequency Response Standard (FRS) and to explain the rationale and considerations for the
Requirements and their associated compliance information as well as to solicit feedback from industry
participants on the standard. ENBALA provides these comments in support of draft standard BAL-0031 II. BACKGROUND The requirement to continuously balance load and generation to maintain stable
frequency is a critically important aspect of interconnected power system operation. Frequency
Response is the characteristic of load and generation within Balancing Authorities and
Interconnections that reacts or responds to changes in load-resource balance and resulting changes in
system frequency. Primary Frequency Control is defined by NERC as those actions provided by the
Interconnection to arrest and stabilize frequency in response to frequency deviations, typically caused
by a significant system loss. Primary Control comes from mechanical inertia, followed by automatic
generator governor response, load response (typically from motors), and other devices that provide
an immediate response based on local (device-level) control systems. Primary Frequency Response
(PFR) is the first stage of overall frequency control and is the response, which begins immediately, of
resources and load to a locally sensed change in frequency to arrest that change in frequency. This is
distinct from Secondary Frequency Control, defined to be those actions provided by an individual BA
or its Reserve Sharing Group to correct the resource – load unbalance that created the original
frequency deviation, which will restore both Scheduled Frequency and Primary Frequency Response.
Secondary Control comes from automated dispatch from a centralized control system. The original
Standards Authorization Request (SAR) to establish mandatory standards with respect to this critical
requirement were established in BAL-003-0, finalized on June 30, 2007. In Order No. 693, the Federal
Energy Regulatory Commission (FERC) directed additional changes to this standard . We interpret the
objective of the FERC direction to be to establish concrete measures and allocation of Interconnection
Frequency Response to ensure continued reliable operation III. COMMENTS Presentations and
discussion at the conference provided the following understanding; - The system currently has
enough PFR to operate reliably. The concern is that continuing decline could result in unreliability at a
future date. The immediate concern is to ensure that the decline on the Eastern Interconnection is
halted. - Approximately 30% of generators provide governor response and hence primary frequency
control at any time in the Eastern and Western Interconnections. - Primary Frequency Response (PFR)
should not be viewed as event driven but rather as continuous control. - The draft standard has been
written to give the Balancing Authority (BA) responsibility to meet the standard. The main issue with
this is a concern that BA's are being given responsibility but do not have the requisite authority to
impose requirements on participants (eg. generators) to provide the PFR. The discussion at the
conference focused almost exclusively on the ability of generators to supply PFR through governor
action. This is not surprising given the fact that the interconnected power system is based on rotating
machines (for the most part) and that speed governors are a necessary part of generator control
systems and have been providing PFR for many years. However, there is growing evidence that some
generation operators prefer not to provide this service as only a fraction of generators actually
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003089
provide PFR to the interconnection at any time. Many reasons were discussed that generators do not
provide response, ranging from regulatory restrictions, environmental restrictions, and operation at
full output, economic choices to make the plant more efficient, and physical constraints, among
others. But in our opinion, all of these reasons come down to a fundamental consideration – the
generators must sacrifice some efficiency to provide PFR. This is not a surprising outcome. Prior to
electricity deregulation many ‘ancillary services ’ provided by generators were considered to be
delivered at low or no cost. However, organized electricity markets have shown that these services
have considerable value. Primary Frequency Response is another example. This is not to say that
generators may not be the most effective way to provide the majority of PFR. However, generation
resources may not be the least cost supplier of PFR. It is important to recognize that this service has
a cost and different technologies are able to provide the service at different costs. These costs vary
even amongst generation technologies. In addition, there are alternatives to providing all PFR from
generation. ENBALA’s experience in providing Secondary Frequency Control (SFC) to organized
markets has shown that aggregated mid-sized commercial and industrial facilities can provide very
high quality SFC, demonstrably better performance than the majority of generation. This technology
can be extended to provide localized PFR as well. It is our opinion that PFR from load can be of higher
‘quality’ than that provided by generation. The ability of individual aggregated loads to increase or
decrease nearly instantaneously in response to frequency provides an immediate stabilizing influence
on frequency that works together with generator inertia to arrest frequency deviations more quickly
than generation alone. Recent studies by California ISO identify that this response can be several
times more valuable than slower generation response. Given the facts that; PFR is a valuable
reliability service, the cost of providing PFR varies with technology, decisions must be made with
respect to who will provide PFR, and alternatives exist to continuing with the provision of generator
only PFR, we respectfully make the following suggestions; - The standard should continue as drafted
and not limit the technology to provide PFR (eg. generators only) - PFR should be recognized as a
reliability service in the same manner as other ancillary services. - The standard should apply to an
entity like the BA, as drafted, that has defined responsibility for balancing load and generation Mechanisms should be developed to procure PFR sufficient to meet NERC standards, on an economic
basis either through market or tariff provisions IV. CONCLUSION It is ENBALA’s belief that unless the
value of Primary Frequency Response can be made transparent to the marketplace, efficient
alternatives will not be implemented and inefficient decisions with respect to existing technologies will
be made leading to higher costs for consumers. Treatment of PFR as a market priced reliability
service will allow the industry to determine the most efficient and effective way to provide necessary
Frequency Response, independent of changes taking place in the supply mix of generation.
Respectfully Submitted,
Individual
Robert Blohm
Keen Resources Asia Ltd.
17-year NERC veteran's, long-standing active FRS drafting team contributor's, ex NERC Standards
Committee member's, and Columbia-University-postgraduated statistician's expert comments on
"Avoiding a Trifecta of Statistics Errors in the NERC Frequency Response Standard". Please review my
6-slide powerpoint presentation downloadable at http://www.robertblohm.com/3FRSissues.pptx or
http://www.robertblohm.com/3FRSissues.ppt and submitted but never posted for inclusion in the
technical conference. The last 3 slides highlight the following 3 fundamental statistics errors in the
FRS as drafted so far: (1) confusion of (the correct probabilistic measure of "largest contingency"
consisting of) "largest event to occur at least as often as once in 10 years" with (the incorrect
probabilistic measure of "largest contingency" consisting of) "largest event in the last 10 years" which
may be the "largest event to occur at least as often as once in MUCH MORE THAN 10 years"; (2)
sampling of frequency responses to events that is not true "random", "unbiased" or "stratified"
sampling which requires samples that are distributed unevenly over time just like the population of
responses to events is: every month or season of the year cannot be forced to have the same number
of samples; otherwise what is being measured is not the population of responses to events, but
something else (like responses to regular small operating errors that are the domain of CPS, not the
FRS) with a probability density over time in the shape of a flat-top box; (3) use of a median measure
of frequency-response performance, which is impossible for 3 reasons: because there is a practical
infinity of possible Frequency Responsive Reserve Sharing Groups or overlap regulation
arrangements, because use of the median incents the formation of those whose actual provision of
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003090
frequency response is over-represented by the median and would in that case deteriorate below the
actual minimum amount required for system reliability, and because use of the median disincents the
formation of those whose actual provision of of frequency response is under-represented by the
median. The first 3 slides clarify the following 3 technical points: (1) the resistance of load to adjust
to sudden change in generation output prompts frequency (but not generator output) to change and
to thereby involuntarily change the load whose resistance to that adjustment prompts frequency to
change even more and only until the sudden generation output change is reversed enough in order
first to stop the frequency change and then begin to reverse the frequency change; [The involuntary
load response/adjustment provides the energy used by generation inertia to immediately slow down
frequency change until frequency response is deployed to stop and begin to reverse the frequency
change as illustrated in this 4-slide powerpoint presentation of 4 errors in the Cummings
presentation's slide of frequency response
http://www.robertblohm.com/CummingsVsIllianLoadResponse.pptx or
http://www.robertblohm.com/CummingsVsIllianLoadResponse.ppt . The 2 graphs depicted therein
show that load response and inertia are inseparable and provide the entirety of frequency response
during more than the initial half of the 5 or 6 second pre-arresting period, and this supports the next
slide.] (2) the FRS is a standard for "system" frequency response (the 1st of NERC's 2 glossary
definitions of "frequency response"), not for "equipment" frequency response (the 2nd of NERC's 2
glossary definitions of "frequency response"); the FRS is a BA-Response System Operation and
Measurement Standard, not a Connection and Maintenance Standard for Individual Pieces of
Equipment; in other words, all sharp large-enough tie-line and frequency changes of whatever kind
for whatever reason are counted (“summed”) and managed (and included in the probability density
curve of frequency events and responses thereto), not just measurements of a construed pure
machine response to one single imagined un-overlapped change (shorn of supposed "contaminants"
of an idealized "equipment" reality non-existent at actual "system" level); (3) the probability density
function of frequency events that are un-uniformly distributed over time governs the FRS and is
different from the standard normal distribution of operating errors (that governs CPS) that are evenly
distributed over time in a uniform distribution.
Group
Dominion
Connie Lowe
Dominion
Dominion agrees that resources other than generators could supply some limited frequency response,
but believe that all resources providing reliability-related services should be subject to applicable
NERC reliability standards. We also agree that relationships can exist between reliability and
compensation, especially in organized markets. In order for generators to be able to respond to a low
frequency event, they would need to operate slightly below their maximum output. The Balancing
Authority is the entity best suited to make the determination of how to balance efficiency and
reliability. There may be financial consequences for resources that do not meet their assigned
schedule and we encourage further discussion of this with NAESB to determine whether this issue
might be ripe for discussions and possible solutions from NERC (reliability) and NAESB
(commercial/financial). As noted in the Duke presentation, alignment is also needed in the new NERC
standards and Glossary of terms (clarification is needed on specific terms used by engineering vs. the
Generator Operator) as it pertains to frequency response.
Individual
Terry Bilke
MISO
The standard sets a rational backstop for reliability without forcing undue costs for undefined
improvements in reliability. My primary concern is the reliability gap created for variable bias BAs.
There is no discernible reason why a variable bias BA should ever have a bias less negative than say
30% of its FRO. The variable bias BA should also have an average annual bias at least 90% of its
FRO. This can be managed through the year and still will be well less than the current obligation
under BAL-003-0. Since there is no firm technical guidance on how variable bias is to be set, to leave
this gap will cause a mass movement of BAs to report as variable bias entities. It will also leave the
door open to gaming to artificially improve CPS and DCS and BAAL performance.
Group
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003091
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
Requirement 3 of the standard covers the use of variable bias. However, the requirement does not
establish a minimum limit for variable bias. In order to prevent what could be perceived as a way to
‘game’ the requirement, we would suggest incorporating a minimum limit on variable bias that does
not allow the value to be positive.
Individual
John Seelke
Public Service Enterprise Group
PSEG Comments on Project 2007-12 – Frequency Response A. SUMMARY OF COMMENTS 1. The
standard drafting team (SDT) for Project 2007-12 has not explained how compliance with draft
standard BAL-003-1 is achievable; therefore, a key goal of Order 693 has not been met. a. BAL-0031’s objectives (from the project’s web page) states “There is evidence of continuing decline in
Frequency Response in the three Interconnections over the past 10 years, but no confirmed reason
for the apparent decline.” If one does not know why Frequency Response is declining, how can a BA
ensure itself that it has sufficient Frequency Response in its area to meet its obligation? b. BAL-003-1
assigns Balancing Authorities (BAs) the requirement to meet a Frequency Response Obligation for
their respective areas. However, BAs have no the authority to set requirements for suppliers of
Frequency Response service: Generator Owners (GOs) as well as demand response resources. 2. Two
existing standards (BAL-001-0.1a and BAL-002-0) also address Frequency Response. However, the
pro forma Open Access Transmission Tariff (OATT) contained ancillary services associated with these
standards prior to the standards being approved. a. The SDT needs to explain the relationship
between BAL-001-0.1a, BAL-002-0, and draft standard BAL-003-1 since they all address an aspect of
Frequency Response. b. BAL-003-1’s objectives (from the project’s web page) do not include a
statement that having sufficient Frequency Response is necessary to arrest the frequency decline
within the first seconds of a disturbance so that underfrequency load shedding (UFLS) is minimized. 3.
There is no OATT ancillary service for the service in draft standard BAL-003-1. Unless commercial
terms are established which define the relationship between BAs and Frequency Response providers,
BAL-003-1 will not be implementable. Because commercial terms need to be defined in the OATT, we
encourage NERC to work with FERC’s Office of Energy Market Regulation and/or its Office of Energy
Policy and Innovation to initiate proceeding with the goal of developing a new ancillary service –
Primary Frequency Response Service. 4. A plot of frequency versus time after the sudden loss of
generation is only contained in presentations for the technical conferences, but a plot is not in any of
BAL-003-1’s documents. Such a plot is needed in the standard (or in an attachment to it) so that the
familiar reference points – A, B, and C – can be used in the standard’s documents. 5. With regard to
setting the Frequency Response Obligation by Interconnections in BAL-003-1: a. How can two
Interconnections (Eastern and Quebec), which are not Registered Entities, comply with the
requirement in Attachment A to set a Frequency Response Obligation? b. The SDT should explain its
rationale for choosing “the largest category C (N-2) event identified” as the basis for setting an
Interconnection’s Frequency Response Obligation. 6. Project 2010-14-1 is related to Project 2007-10,
and the two project teams should coordinate on these items: a. Both SDTs should put themselves in
the position of a BA that must comply with R3 and all its subparts in draft standard BAL-012-1 and
develop a hypothetical implementation plan for a BA to meet its Frequency Response Obligation. b.
Both SDTs should work together to explain the relationship between Regulating Reserve, Contingency
Reserve, and Frequency Response Reserve contained in BAL-012-1. B. REGULATORY BACKGROUND
When FERC approved BAL-003-0 – Frequency Response and Bias – in Order 693, it issued NERC a
directive in P. 375: …the Commission directs the ERO to develop a modification to BAL-003-0 through
the Reliability Standards development process that: … (3) defines the necessary amount of Frequency
Response needed for Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.” The standard drafting team for Project 2007-12
is currently addressing all but one of the items in the Order 693 directive. See below: Order 693, P.
375 (3) Directive Addressed by SDT? 1. Define the necessary amount of Frequency Response for each
BA Yes 2. Define methods of obtaining Frequency Response No 3. Define methods of measuring that
Frequency Response is achieved Yes This second item is critical. “Methods” can describe technical
options, but it can also describe process options. While the project’s “Frequency Response
Background Document” dated October 2011 has a section on “methods of obtaining Frequency
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003092
Response” on p. 11, that section has six bullet points on the topic. The points are not integrated into
a coherent approach that explains how compliance is achievable. Draft standard BAL-003-1 assigns
BAs the requirement to meet a Frequency Response Obligation for their respective areas. However,
BAs have no the authority to set requirements for suppliers of Frequency Response service: GOs as
well as demand response resources. In addition, there are no OATT provisions that will compensate
suppliers for the service BAs will ask them to provide. C. TECHNICAL COMMENTS 1. BAL-001-0.1a
and BAL-002-0 NERC’s Glossary defines of Frequency Response and Frequency Bias as follows:
Frequency Response: (Equipment) The ability of a system or elements of the system to react or
respond to a change in system frequency. (System) The sum of the change in demand, plus the
change in generation, divided by the change in frequency, expressed in megawatts per 0.1 Hertz
(MW/0.1 Hz). Frequency Bias: A value, usually expressed in MW/0.1 Hz, set into a Balancing
Authority [Area Control Area] ACE algorithm that allows the Balancing Authority to contribute its
frequency response to the Interconnection. Two existing standards are related to draft standard BAL003-1. a. BAL-001-0.1a – Real Power Control Performance – addresses maintenance of frequency,
within limits, by a BA in a steady-state (no disturbance) environment by measuring ACE. This requires
BAs to have sufficient Regulating Reserve. The ACE equation includes a component for Frequency
Bias. This component adjusts ACE when frequency deviates from 60 Hz, allowing a BA to contribute
its Frequency Response to the Interconnection. In the OATT, this service is Schedule 3 – Regulation
and Frequency Response. b. BAL-002-1– Disturbance Control Performance – requires BAs to provide
sufficient Contingency Reserve so that ACE can be returned to its pre-disturbance level within 15
minutes. In the OATT, this service is incorporated into two schedules: Schedule 5 – Operating
Reserve – Spinning Reserve Service and Schedule 6 – Operating Reserve – Supplemental Reserve
Service. In both standards, the needed ancillary services were in the OATT PRIOR to the standards
being approved. The reliability standards set performance requirements while the OATT sets the
commercial structure for compensating providers. To meet the requirements of BAL-001-0.1a and
BAL-002-1, BAs need Frequency Response (equipment) so that they have the “ability… to react or
respond to a change in system frequency.” Maintaining ACE is a Frequency Response service, but it is
different from the type of service in draft standard BAL-003-1 and as described in the technical
conference. The SDT should explain the relationship of all three standards since they all address an
aspect of Frequency Response. 2. Draft BAL-003-1 Objectives The objectives of Project 2007-12 are
excerpted below from its web page: Frequency Response, a measure of an Interconnection’s ability to
stabilize frequency immediately following the sudden loss of generation or load, is a critical
component to the reliable operation of the bulk power system, particularly during disturbances and
restoration. Failure to maintain frequency can disrupt the operation of equipment and initiate
disconnection of power plant equipment to prevent them from being damaged, which could lead to
wide-spread blackouts. THERE IS EVIDENCE OF CONTINUING DECLINE IN FREQUENCY RESPONSE IN
THE THREE INTERCONNECTIONS OVER THE PAST 10 YEARS, BUT NO CONFIRMED REASON FOR THE
APPARENT DECLINE (emphasis added). The proposed standard would set a minimum Frequency
Response obligation for each Balancing Authority, provide a uniform calculation of Frequency
Response and Frequency Bias Settings that transition to values closer to natural Frequency Response,
and encourage coordinated AGC operation. This statement has two shortcomings. First, the
emphasized sentence above is discouraging because if one does not know why Frequency Response is
declining, how can a BA ensure itself that it has sufficient Frequency Response in its area to meet its
obligation? The standard should describe how a BA might comply with its Frequency Response
Obligation in an appendix. (See the comments in Section D below.) Second, it makes no mention that
having sufficient Frequency Response is necessary TO ARREST FREQUENCY DECLINE WITHING THE
FIRST SECONDS OF A DISTURBANCE SO THAT UNDERFREQUENCY LOAD SHEDDING (UFLS) IS
MINIMIZED. 3. Graphics A plot of frequency versus time after the sudden loss of generation is only
contained in the presentations for the technical conferences, not in any of BAL-003-1’s documents.
Such a plot is needed in the standard (or in an attachment to it) so that the familiar reference points
– A, B, and C – can be used in the standard’s documents. 4. Physical response to loss of generation
The workshop did a good job in explaining what occurs physically within an Interconnection after
generation is lost. Those are summarized below for the SDT to review for any misunderstanding. a. At
point A (pre-disturbance), an unspecified amount of generation is lost. b. Between point A and point C
(the frequency nadir), several changes occur: i. Due to the loss of generation, load is greater than
generation, and in response to this imbalance, generators “slow down” and frequency drops. Each
generator’s loss of speed releases power to serve the load, albeit at a reduced frequency. Generators
with greater mass are preferred since they have more stored rotating power to release. Frequency
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003093
Bias setting in each BA’s ACE equation allows this power to flow into the Interconnection. ii. Load is
also reduced when frequency is reduced because loads such as motors slow down also and consume
less power. Load reduction aids in arresting frequency decline. However, unless the frequency decline
triggers the first UFLS step, no connected is lost. iii. Generator governors begin to respond. A
generator’s governor that can increase output when frequency declines provided certain
characteristics are met. 1) The generator must be operating below its maximum capacity that can be
achieved under automatic (i.e. non-operator intervention) operation. A generator with a 100 MW
capacity and operating at 80 MW has “head room” to respond while the same generator operating at
100 MW cannot. 2) The governor’s “dead band,” which defines a range (+/-) of frequency changes
that do not activate the governor, must not be so wide so as to effectively disable the governor from
responding to frequency changes during a disturbance. 3) The governor cannot be overridden by
“outer loop controls” on the generator. These controls countermand the governor’s response, keeping
the generator’s output level unchanged. Governor response is the last to occur – it begins within
seconds after the disturbance and continues until the generators with active governors reach their
maximum capacity or until frequency is restored. In addition, properly devised demand response
resources can substitute for governor-responsive generators. c. At point B, frequency is stabilized. All
of items above occur automatically, without operator intervention. Collectively, these actions are
referred to the “primary response” of the Interconnection to loss of generation. Subsequent responses
involve operator actions that eventually return system frequency and ACE to a pre-disturbance ACE
target. These subsequent responses are not the objective of draft BAL-003-1, but they are the
objective of BAL-002-1. 5. Frequency Response Obligation Determination Regarding the Frequency
Response Obligation for an Interconnection, Attachment A in draft BAL-003-1 states “Each
Interconnection will establish target contingency protection criteria,” with the default target “based on
the largest category C (N-2) event identified.” We have several questions: a. How can two
Interconnections (Eastern and Quebec), which are not Registered Entities, comply with the
requirement in Attachment A to set a Frequency Response Obligation? In fact, no Interconnection is
listed in the Applicability section of BAL-003-1. b. We assume that “category C” in the Attachment A
language above references Table 1 in the current TPL standards, but that should be clarified by the
SDT. Does the SDT intend to restrict the category C events to those that only result in the loss of two
Elements? This question is asked because category C in Table 1 is described as “Event(s) resulting in
the loss of two or more (multiple) elements.” c. The default target contingency in Attachment A is
greater than minimum Contingency Reserve requirement in BAL-002-1 (R3.1), which is based on “the
most severe single contingency." Why was the minimum requirement in BAL-002-1 not used? The
SDT should explain its rationale for choosing “the largest category C (N-2) event identified” as the
basis for setting an Interconnection’s Frequency Response Obligation. 6. Frequency Response
Obligation Measurement We summarized Frequency Response Obligation measurement below for the
SDT to review for any misunderstanding. a. Frequency Response will be measured at point B due to
technical limitations in measuring each BA’s point C. However, point C can be measured for an
Interconnection. Because the C to B ratio is highly consistent within an Interconnection, measuring
the response at B also measures the decline at C is achieved. b. For compliance purposes, each BA’s
performance in meeting its Frequency Response Obligation will be based upon its median Frequency
Response of at least 25 events, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz). D. FREQUENCY
RESPONSE OPTIONS The discussion below is not inclusive, and the SDT is encouraged to provide
guidance on compliance as recommended in Section C.2 above. 1. Value high inertia generators.
Generators that are on line and spinning, even if loaded to their maximum capacity, provide MW by
slowing down, and generators with greater mass are preferred. In engineering parlance, this is
termed the inertia constant, H, which, for a given generator is: H = (Stored kinetic energy in
megajoules at synchronous speed)/(Generator rating in MVA) Generators with a greater H constant
have more value in arresting frequency decline than similarly rated generators with a lower H
constant. 2. Value interruptible load on underfrequency relays. Many utilities have interruptible loads,
and some of these could be configured to be shed load based upon frequency steps that are above
the first UFLS step. As an example, direct load control programs for cycling residential air conditioners
and water heaters could be configured to interrupt all appliances on the program for several minutes
after a disturbance, with the appliances gradually restored after the frequency decline is arrested. 3.
For generators that provide primary Frequency Response through governor action, value rapid
response. The rate of increase in generator output due to governor response is both governor and
prime-mover specific. The governor’s droop determines how much it will increase signal generator
power to increase when frequency declines. Also, generators with rapid power increase capability,
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003094
such as simple cycle gas turbines, can deliver the governor’s signal to increase power more quickly.
The more rapid a generator’s response capability, the more it should be valued. a. Generators
providing primary Frequency Response through governor action or automatically curtailed
interruptible load also provide “Operating Reserve – Spinning,” which is a component of Operating
Reserve. It is defined in the NERC Glossary as follows: Operating Reserve – Spinning The portion of
Operating Reserve consisting of: i. Generation synchronized to the system and fully available to serve
load within the Disturbance Recovery Period following the contingency event; or ii. Load fully
removable from the system within the Disturbance Recovery Period following the contingency event.
The term “Disturbance Recovery Period” is used in BAL-002-1, and its default value is 15 minutes. To
minimize UFLS activation, which can occur within seconds after a disturbance, primary Frequency
Response is the key requirement, and the 15 minute time frame in Operating Reserve – Spinning is
not relevant. However, a GO that provides primary Frequency Response via an active governor or a
demand response provider that provides automatically curtailed interruptible load is also providing
Operating Reserves – Spinning. E. OATT PROVISIONS Unless commercial terms are established which
define the relationship between BAs and Frequency Response providers (GOs and demand response
resources), BAL-003-1 will not be implementable. Because commercial terms need to be defined in
the OATT, we encourage NERC to work with FERC’s Office of Energy Market Regulation and/or its
Office of Energy Policy and Innovation to initiate proceeding with the goal of developing a new
ancillary service – Primary Frequency Response Service. This service would address automatic
Frequency Response within a short time frame (up to about 30 seconds) after a disturbance. Overlap
between Spinning Reserve Service and Primary Frequency Response Service would need to be
addressed. F. COORDINATION WITH PROJECT 2010-14.1 After preparing the majority of our
comments, a first-time request for comments on a related project, Project 2010-14.1 – Phase 1 of
Balancing Authority Reliability-based Controls Reserves – was posted on June 4. This project includes
a new draft standard BAL-012-1 that has a proposed definition for Frequency Response Reserve – “An
amount of reserve automatically responsive to locally sensed frequency deviation during the primary
control time frame.” That definition is similar to the ancillary service proposed above. Both SDTs
should put themselves in the position of a BA that must comply with R3 and all its subparts in draft
standard BAL-012-1 and develop a hypothetical implementation plan for a BA to meet its Frequency
Response Obligation. If they did, they would understand why BAs have little understanding of what
they must do to comply with draft BAL-003-1. Both SDTs work together to explain the relationship
between Regulating Reserve, Contingency Reserve, and Frequency Response Reserve contained in
BAL-012-1.
Group
Bonneville Power Administration
Chris Higgins
Transmission Reliability Program
Chris Higgins Bonneville Power Administration Transmission Reliability Program [email protected]
360-418-2132 Submitting on behalf of the BPA's AGC team. BPA continues to fundamentally disagree
with the approach that BAL-003-1 is developing into. Please reference BPA’s extensive comments
submitted on 12/8/11 for Project 2007-12 Frequency Response found here:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf. BPA also
believes that having a special interest group present their perspective on the standard and a
consultant provide a sales pitch in relation to load response was inappropriate and ill-served.
Individual
Don McInnis
Florida Power & Light
The conference was very informative. Of particular interest was who should be responsible for
providing frequency response. The assignment to the BA was well supported and logically presented.
The details presented in the conference were different than those in the original version of the
standard i.e. the frequency selected to protect for was modified from 59.7 to " prevailing". The
prevailing frequency if prevailing is interpreted as dominant is 59.3Hz yet the standards team choose
59.5Hz without explanation or justification. There was also a lack of technical justification in
increasing the frequency bias minimum from the original 0.8% to 0.9%. While a minimum should be
established there should be no link to frequency response as the two are no longer related.
Individual
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003095
Bob Frost
Portland General Electric
1. BAL-003-1, Attachment A, states that the ERO will provide quarterly posting of candidate frequency
events. It then states it will post the final list of frequency excursion events used for standard
compliance by December 15 each year. Because the quarterly postings are only candidates and the
median frequency response is the measure, Balancing Authorities cannot always be certain they will
be compliant with the Standard until December 15. 2. FRS Form 1, sheet “Data Entry”, requests entry
by the Balancing Authority of next year’s FRO (cell O31). However, per Attachment A, this information
is provided by the ERO only after Form 1 is submitted by the Balancing Authority. A Balancing
Authority is only able to estimate their FRO. 3. FRS Form 2, sheet “Entry Data”, has the Balancing
Authority modify formulas for cells C8 and C11 in order to identify the beginning and recovery from
the event. This is tedious as Form 2 must be completed a minimum of 25 times each year. The
spreadsheet should be authored so that the user does not need to modify formulas. The sheet “Data”
on Form 2 could have cells adjacent to the data that are marked to identify these points.
Group
MISO Standards Collaborators
Marie Knox
MISO
We have a strong concern related to the handling of variable bias. The drafting team is fully removing
the floor for the minimum amount of bias for these BAs and only asks bias to be equal to natural
frequency response when frequency is off normal. There should always be some bias (perhaps 40% of
FRO) provided to the Interconnection and there should be some minimum annual average. This can
be managed through the year and still will be well less than the current obligation under BAL-003-0.
Since there is no firm technical guidance on how variable bias is to be set, to leave this gap will cause
a mass movement of BAs to report as variable bias entities. It will also leave the door open to gaming
to artificially improve CPS, DCS and BAAL performance. For example, an algorithm that takes bias to
a small positive number once each 15 minutes would assure the BA will never fail DCS or BAAL.
Group
LG&E and KU Services
Brent Ingebrigtson
LG&E and KU Services
LG&E and KU Services have two comments/questions related to the material presented at the FR
Technical Conference: 1. Data was presented that illustrates a decline in the Frequency Response of
the Eastern Interconnect for the period 1994 through 2010. Since FR is partially related to the
amount of on-line generation available at the time of the contingency, has the SDT investigated the
amount of spinning reserves typically available on the Eastern Interconnect during the same 1994 to
2010 period? If so, was there a correlation between the decline of Frequency Response and available
spinning reserve? 2. During the conference, mention was made that there is a cost for obtaining
Frequency Response – mainly the cost of unused spinning generator capacity. However, no data,
analysis or estimates were presented as to what these costs might be. Cost estimates for attaining
the desired amount of Frequency Response would be useful to the industry and FERC in evaluating
the proposed Frequency Response standard.
Individual
Michael Goggin
American Wind Energy Association
AWEA appreciates the opportunity to comment on NERC’s ongoing work on frequency response
standards. Based on the presentations at NERC’s May 2012 technical conferences on frequency
response issues, it appears that consensus exists around three important points, which we would like
to highlight in our comments. We are pleased that these points appear to be embodied in the ongoing
work of the standards drafting team on frequency response (BAL-003-1). 1. The balancing authority
(BA) should be the entity responsible for meeting a frequency response standard. This responsibility
would fit in well with a BA’s existing responsibilities for maintaining system frequency within
acceptable bounds, such as CPS 1&2 and DCS requirements. Just as a BA currently obtains the
reserves and other services required to meet these frequency standards and operates according to
these standards, the BA is the logical entity for taking on those responsibilities for frequency
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003096
response. The BA is the only entity that has a real-time awareness of overall power system needs and
capabilities, and is thus ideally suited for meeting a frequency response standard. 2. A BA’s selection
of resources to provide frequency response service should be market-based. As was explained at the
technical conferences, different resources have widely divergent costs for providing frequency
response. Many resources are likely to be able to provide significant frequency response at very low
cost, while other resources are likely to face significantly higher costs for providing this service. For
example, maintaining the capability to provide sustained frequency response from a wind plant would
require holding the wind plant below its operating capability at all times, foregoing significant
production of near-zero-marginal cost, zero emissions wind energy. As a result, under normal
operating conditions, the wind plant’s opportunity cost for providing frequency response capability is
likely to be significantly higher than the cost for many other generating resources, which would be
able to save on fuel costs by operating below their maximum output. Innovative technologies,
including some forms of demand response and energy storage, are also likely to be able to provide
frequency response at relatively low cost. The BA is well-positioned to use a market-based
mechanism to select the least-cost frequency response resources from the available resources, as
conditions change in real-time. This market-based incentive should also provide sufficient incentive
for most potential resources to install any equipment necessary to provide frequency response. The
market mechanism should be designed to pay for performance, so that frequency response resources
are incentivized to provide services with the maximum value for the power system. 3. The decline in
frequency response on the Eastern U.S. power system pre-dates the introduction of wind energy and
appears to have been caused by changes in how conventional power plants are operated, and not in
any way tied to the increased use of wind energy. As NERC noted in comments submitted to FERC on
October 14, 2010: “Frequency response of the interconnected North American electric systems has
shown a significant decline for several years. The reasons for the decline are numerous, including: • A
trend toward larger governor deadband settings, exceeding the historical typical setting of ±36
millihertz (mHz); • Use of steam turbine sliding pressure controls; • Loading units to 100 percent of
capacity leaving no “headroom” for response to losses of generation; • Blocked governor response; •
Once-through boilers; • Gas Turbine inverse response; • Withdrawal of primary frequency response of
generators by MW setpoints, resulting in limited time of response; and • Changes in the frequency
response characteristics of the load. These changes have been evolving for some time and are not the
direct result of the emergence of renewable resources such as wind and solar.” Data presented at the
technical conference indicated that only around 30% of generators are currently providing frequency
response. Much of the decline in frequency response provision appears to result from generator
owners maximizing efficiency and minimizing costs under current market structures. Implementing a
market-based mechanism to select the least-cost frequency response resources from the available
resource pool would allow conventional generators to be appropriately compensated for any costs
they incur for providing frequency response while simultaneously selecting the least-cost resources
for the power system. The technical conference also discussed the fact that only 1/3 of the 30% of
generators that are providing frequency response (so 10% of the total generation fleet) sustain that
frequency response for more than a short period of time. Part of the problem appears to be that some
current energy imbalance tariff provisions may penalize generators that increase their output beyond
the scheduled amount, and therefore generators are limiting the duration of frequency response
following a system disturbance to avoid imbalance penalties. At the technical conference, there
appeared to be widespread support for reforming those energy imbalance tariff provisions to remove
that perverse incentive, which is commendable.
Group
ISO/RTO Standards Review Committee
Albert DiCaprio
PJM
Introduction The undersigned members of the ISO/RTO Standards Review Committee (SRC)
appreciate that NERC provided the opportunity to comment upon NERC’s Frequency Response
Technical Conference. The Conference addressed an important topic in which the SRC is deeply
interested – primary control. The SRC notes that the Conference’s presentation of the various and
diverse perspectives of this topic highlighted the continued need to resolve and address several
issues: • The need for a common language for discussion • The need for an objective analysis of a
reliability need • Given the proof of such an objective reliability need, there is a need to define the
quantitative parameters involved in measuring the objective • The need to justify the creation of a
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003097
mandatory standard that is relevant to the current and future BES. That includes: o Reviewing
relevancy of old standards o Clarifying discussions o Objectively assigning responsibilities Discussion
Terminology/Common Language The SRC noted that the presenters did not share a common set of
terms. The term Frequency Response was used to address issues that are separated by time frames
and that deserve separate discussions. Frequency Response was used generically to mean any
activity related to controlling frequency. Frequency Response was also used to mean undirected
control (such as the change in generator output caused by a governor). Frequency Response was
used to mean directed control (aka secondary control). It was also used to mean the Area Control
Error equation. Rather than relying on the broad and ill-defined term Frequency Response, the SRC
suggests that either newly minted terms be created or that more traditional terms such as Primary
Control Response and Secondary Control Response be used. All too often the presenters crossed the
traditional boundaries thereby decreasing the clarity (and the value) of the discussion. There was also
a tendency to use the term “Service” for both the traditional Ancillary Services (Load Following (aka
Economic Dispatch); Spinning reserves; Supplemental reserves; Regulation service (aka AGC);
Reactive and voltage control service; Black start) and for conditions that exist (i.e. the reaction from
generators to changes in frequency). There is a tendency to equate Frequency Control through tie-line
bias (typically this is AGC or secondary control) with Primary control (Dave Lemmons); Bias vs. Beta
(is also a secondary control issue but it is linked because the parameters themselves are related to
the primary response experienced; but they drive secondary control problems and solutions). In short
the Bias is a 1st order approximation of what the magnitude of primary response that goes into the
ACE equation to drive secondary control. Unless care is taken with the terms, it is easy to envision
differences in discussions. Good resolutions of problems caused on the secondary control system were
presented (Terry Bilke) but that need is relatively independent of this SDT. For our comments the
SRC will focus on Primary Control response and use the terms primary, primary response, or primary
frequency response rather than Frequency Response. Need The SRC notes that the presenters offered
a variety of reasons for a “Frequency Response” standard: • Because the governor response in the
Eastern Interconnection changed (or appears to be changing) • To avoid Under-Frequency Load
Shedding relay operation • To avoid problems for Secondary control (valid need but not a valid
justification for Primary Frequency control standard) (Howard Illian) • FERC Order 693 o Determine
the appropriate periodicity of frequency response surveys o Define necessary amount of Frequency
Response for reliable operations with methods of obtaining response and measuring that the
frequency response is achieved • FERC Technical Conference The SRC observes that the presenters
are attempting to address the goal of operating at a reasonable margin away from both UFLS (underfrequency) and OFR (over-frequency) settings, and to avoid any single event (contingency) causing
those relays to activate. The SRC fully supports that objective. Several presenters mentioned the
above objective and addressed the amount of post-event governor response, i.e. response that was
activated after the frequency was arrested. Presenters recognized that not all suppliers are
generators, and not all generators have governors, and not all of those generators respond in the
same way. They also note that BAs do not all own generators. One presenter documented that the
Eastern Interconnection has the worst post event response but also has the highest frequency arrest
level (i.e. are farthest from a relay trip point) Most presenters expressed preference to impose
Frequency response production requirements on BAs. Most presenters want to focus on the Eastern
Interconnection. The SRC believes the requirement addressing primary frequency response must: •
Relate to the frequency nadir point not the post event response • Apply to and be assigned to “ALL”
Functional Entities registered for that applicable group • Reflect the capabilities of the functional
entity to provide the mandated service. • Address both supply capabilities as well as appropriateness
of relay settings If the objective is to avoid tripping relays and to minimize the risk of tripping those
relays then the requirement must focus on that objective. Some presenters stated that it is traditional
and simply easier to focus a Frequency Response requirement on BAs. Others stated that there were
too many suppliers to impose a frequency response mandate on the suppliers. The SRC as well as
NERC have stated the intention to have performance based standards and to move away from
procedural requirements. The majority of the Technical Conference presenters focused on procedural
solutions (i.e. governor response) and tried to indicate that both generation and demand response
could serve as response providers. Bob Cummings of NERC showed that the typical worst response of
the EI was equal to or higher than the best responses in ERCOT or WECC. In effect the concern about
lack of post event response does not reflect the margin of reliability experienced even with the
“hockey stick” response. Given the fact that none of the presenters proposed increasing the ERCOT
and WECC responses to be as effective as the EI response, the observed decrease in the Eastern
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003098
interconnection could be seen as a type of “right-sizing” of response – i.e. the east is now coming
closer to the rest of North America. Supply The SRC does recognize the change in frequency response
in the EI, but is concerned that mandating ill-advised requirements on the wrong applicable entities
will foster the loss of the provision of primary response service and not help it. If the “supply”
requirement is placed on a coordinator, then the energy producing assets have no incentive to
provide a service that takes away from other more lucrative products. If the requirement is placed on
a subset of suppliers then those suppliers will likely mimic the suppliers in the other subset and not
offer any service at all. The idea of focusing on one given solution – governor response – creates
disincentives for new technologies. The Industry is now adopting those innovations without a mandate
and should be allowed to continue that expansion without the threat of a standard that would impede
such expansion. Suggestions The SRC believes there is a need for more open presentations including
people not as focused on governors. The majority of presenters were experts in a given area. Their
expertise seemed to preclude exploration of other options than the current option/approach. It should
be noted that a Governor-centric requirement violates Order 693’s mandate to be resource neutral. It
is time to have a discussion of the role of coordinators (like RCs, TOPs and BAs) who can and do use a
palette of tools and services to address a given system condition without being obligated to answer
for non-production. An alternative could be that such entities are required to provide assessment and
analysis but not production; or they are required to arrange for, purchase, or otherwise provide
capacity (not energy) capable of providing the primary frequency response. Many of the presenters
seemed to be in a vertically integrated industry where the coordinator is the owner and operator. That
is no longer universally true. A primary frequency response service for an interconnection may be
calculated as discussed by the presenters, but the mandate must be developed so that the default
entity will be obligated to provide or purchase the obligation (thus opening the opportunity to all new
innovations). Should that be the LSEs who use the service; the suppliers who provide the service; the
coordinators who integrate all of the services; or to allow a combination without specifying “how” it
must be done? Other SRC Considerations raised by presenters’ comments It is invalid to avoid
imposing a requirement on the appropriate applicable entity simply because there are many of them;
if other standards apply to the same applicable entities then this one can also. Speed should not be a
driver contrary to what one presenter stated. As presenters said we are fine today without any
mandatory standard for primary control. This prompts the question “why the need for speed?”
Because we can correct problems with the requirements later, via SARs, is NOT a justification for
creating an inaccurate standard. Why should TOPs be permitted to set relays anywhere, but GOPs be
obligated to set governors to avoid those relays? Focusing on improving details of what we have
today does not make today’s paradigm better!!!! A standard should not serve as a field test for an
idea!!!!
Individual
Laura Lee
Duke Energy
Duke Energy appreciates having the opportunity to participate in the Frequency Response Technical
Conference. It was a very helpful for our team to hear the issues that were brought by others to the
discussion, along with the opinions of NERC staff, the Frequency Response Standard Drafting Team
(FRRSDT), and FERC staff. Duke Energy provides the following comments and proposed resolutions to
some of the issues we believe should be addressed. Frequency Response Obligation (FRO) As the
FRRSDT reviews all of the issues discussed and subsequent comments provided, we ask that
consideration be given to drilling down to the “root cause” of the issues, to see what is driving them.
We have found one of the root causes of a few issues to be the allocation of the FRO. In the current
proposal, a BA’s FRO is the Interconnection Frequency Response Obligation applied to the ratio of the
BA’s generation and load at peak divided by the Interconnection BA totals of generation and load at
peak. Including generation in the allocation helps accommodate treatment of generation-only BAs
(representing perhaps one percent of the total generation in the Interconnection), but in the process
creates issues for both individual generating resources and all other BAs. Duke Energy believes that
the FRO allocation should be based upon load only, based upon the numerous issues and inequities
that an FRO allocation based upon load and generation would otherwise create, including but not
limited to: a) An FRO allocation based upon generation at peak treats resources on a non-comparable
basis within a “traditional” (load and generation) BA, biased against resources dedicated to peaking
operation (CTs as an example), and in favor of resources which may not operate at peak capacity
during such times (wind resources as an example). b) A third party resource added to a BA footprint
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003099
would add to the BA’s response requirement, but the third party resource would have no requirement
to provide frequency response. If such resources are only providing peaking energy to off-system
loads, the generation would add to the response requirement for the BA for the year, though the
resources may run a small fraction of that time. Even if the resources were capable of providing
frequency response when online, they may do little to compensate the BA for the increased yearround requirement. The allocation methodology creates the issue that the BA must now address –
compensation for the increased response requirement or some other tariff provision to make it whole.
c) The allocation methodology creates a gaming opportunity – a strategy to purchase external energy
across the peak would be a small premium to pay to achieve a reduced Frequency Response
Obligation for the year – but a large price to pay for the BA with the resources selling off-system
outside its control. d) Discussed further below, the inclusion of generation in the FRO allocation
creates a significant discrepancy between the methodology used to determine the FRO and the
methodology used to determine the minimum Frequency Bias Setting. In our opinion, these are
among the issues that neither the BAs nor the resources need to face. An allocation based upon the
load within the BA rather than load plus generation would resolve them. An additional modification to
enhance equitable treatment and eliminate gaming is the use of total energy for the period rather
than peak loads in the FRO allocation. There is uncertainty that the use of 12 monthly peaks
accurately represents the load benefiting from the continuous provision of Frequency Response.
Similar to the gaming discussed above for generation, BAs capable of “peak shaving” are able to
reduce a year-round requirement based upon a few hours of operation. Duke Energy proposes that
the determination of a BA’s FRO be the Interconnection FRO applied to the ratio of the BA’s NEL (for
those submitting EIA-714 reports, this would be the annual total in column e of Part II, Schedule 3;
for others, this would be the sum of LSE NELs in the BA as reported for determination of NERC and
Regional fees) divided by the Interconnection BA totals of these NELs. Basing the FRO allocation upon
annual energies rather than peak loads eliminates the potential for a year-round FRO to be pushed to
others by peak shaving if a peak value is used. The FRO for generation-only BAs (representing
approximately 1% of the total generation within an Interconnection) can be set to a fixed percentage
of total capacity, similar to current requirements for calculating the Frequency Bias Setting. Frequency
Bias Setting (FBS) Notwithstanding our concern raised in the past that the secondary control
measures are too tightly bound to the FBS and believing that in some cases the FBS is used as a
convenient measure of BA size, Duke Energy agrees with the proposal to gradually reduce the
magnitude of the FBS to some margin above the natural Frequency Response of the Interconnection.
However, as proposed in the “Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard” dated February 21, 2012, the allocation of the FBS reduction would be a margin
based upon peak load or peak generation, rather than a margin based upon a methodology similar to
that used for the allocation of the Frequency Response Obligation. As an example, based upon the
proposed FRO allocation using load plus generation at peak, two BAs with the same peak load, but
with differing levels of generation at peak due to off-system transactions, would have a different FRO
allocation; however, these two BAs would be given the same minimum Frequency Bias Setting based
upon a percentage of peak load only. A generation-only BA with the same amount of generation as a
traditional BA serving a similar amount of load, would have an FRO allocation approximately half that
of the traditional BA, however these two BAs would be given the same minimum FBS. Under the
proposed procedure for reducing the magnitude of the FBS, the generation-only BA would always
have a minimum FBS set almost twice what it would need to have compared to the traditional BA. We
believe that the incremental reduction in the FBS will not achieve an equitable allocation in its final
state. Duke Energy believes that the minimum FBS for each BA should be reduced in magnitude to a
fixed percentage above each BA’s FRO (but no lower individually than its FRM), while assuring that
the Interconnection FBS remains at some margin above the Interconnection FRM. The current
procedure posted for the FBS reduction will not achieve that equitable allocation, as the minimum FBS
will always be based upon a different methodology than the FRO allocation in its current form. Upon
request, Duke Energy can provide a procedure which could be used for determining the minimum FBS
which would allow the minimum FBS for each BA to be incrementally reduced in magnitude over time
based upon the FRO allocation, and ensure that the Interconnection FBS remains at some margin
above the Interconnection FRM. However, given the timeline for moving this standard forward, Duke
Energy would propose that consideration be given to basing the FRO allocation on load only as
discussed above, setting a value for the generation-only BAs, and returning to the issue of aligning
the methodologies used for the FRO allocation and minimum FBS calculation at a later time. Variable
Frequency Bias Setting Duke Energy disagrees with the FRRSDT’s proposal not to require a minimum
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003100
FBS for BAs using a Variable FBS in multiple BA Interconnections. There are no defined requirements
on how a Variable FBS SHALL be calculated, yet its use changes not only the ACE measured against
the BAL-001 secondary control requirements, but also the bounds of those secondary control
requirements. Overall, Duke Energy questions whether the proposed standard should continue to
allow the use of a Variable FBS in calculating ACE or secondary control performance. Duke Energy
does not question the value of a BA implementing the logic of a variable FBS in its generation control
algorithm, along with other factors to more efficiently control resources, however its operation should
be measured in a manner consistent with all other BAs. Nathan Cohn was of the opinion that the
secondary control assistance provided by the FBS should be a shared obligation. In the publication
“IEEE Transactions on Power Systems, Vol. 3, No. 3, August 1988”, Cohn noted the following in the
article VARIABLE, NON-LINEAR TIE-LINE FREQUENCY BIAS FOR INTERCONNECTED SYSTEMS
CONTROL: “The very conditions that create a variable frequency response to which an area bias is
linked as in the subject paper would create a variable level of bias assistance by the area in fulfilling
system needs.” Nathan Cohn goes on to state, “It is of course recognized that the extent of bias
assistance to be scheduled by individual areas is, as are all operating practices, a matter for system
operating personnel to determine. This discusser suggests, however, that there are potential
advantages in bias assistance based on a common percentage-of-peak for all areas. It would provide
an equitable, cooperative, and democratic systems approach.” As supported by the statements of
Cohn, Duke Energy believes that the assistance provided by the FBS should be a shared obligation
equally applied to all BAs by using a fixed FBS in the calculation of ACE and secondary control
performance. BAL-003-1 Documents The document, “Procedure for ERO Support of Frequency
Response and Frequency Bias Setting Standard” dated February 21, 2012, no longer has a reference
to being “Attachment B” to the draft BAL-003-1 standard. Duke Energy would appreciate clarification
of whether this document is within the scope of what will be eventually be included in the ballot of
Project 2007-12 ― Frequency Response, and what process would be required to make any
subsequent revisions to the procedure.
Individual
Rebecca Moore Darrah
MISO
The Midwest Independent Transmission System Operator, Inc. (“MISO”) appreciates the opportunity
to comment on the technical conferences that NERC recently held on Frequency Response issues,
and, in particular, the proposed changes to BAL-003. MISO adds only two brief comments here. MISO
agrees with the proposed change in BAL-003-1 with respect to the calculation of minimum amount of
frequency response to be provided by a Balancing Authority (this is the Frequency Response
Obligation under Requirement R1 of BAL-003-1). The allocation of Frequency Response Obligation
among Balancing Authorities in an Interconnection is to be based on peak load data, which is a
reasonable approach to determining what proportion of frequency response should be contributed to
each Balancing Authority. MISO also agrees with the manner of calculating each Balancing Authority’s
Frequency Response Obligation under Requirement R1; the proposal by the Standards Drafting Team
will ensure that adequate frequency response is provided by each Balancing Authority. At the same
time, the Standards Drafting Team should reconsider its approach to variable bias. Balancing
Authorities with variable bias are not subject to some of the requirements. Variable bias
methodologies are not identified, and that lack of an identified methodology opens the opportunity for
individual Balancing Authorities to engage in gaming (such as having bias go to zero or a small
positive number every 15 minutes to ensure DCS and BAAL is never failed).
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003101
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
8. The draft standard was posted for a 45-day formal comment period and a 10 day initial
ballot from October 25, 2011 through December 8, 2011.
Proposed Action Plan and Description of Current Draft:
This is the third posting of the proposed standard and its associated documents for a 30 day
formal comment period and a successive 10 day ballot, from October 5, 2012 through November
5, 2012.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments submitted within the comment period
and with the successive ballot.
January, 2013
2. Conduct a recirculation ballot for ten days.
January, 2013
3. BOT adoption.
February, 2013
BAL-003-1
October 1, 2012
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003102
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Definitions of Terms used in the Standard
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s inverse Frequency Response contribution to the Interconnection, and
discourage response withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG)
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to jointly
meet the sum of the Frequency Response Obligations of its members.
BAL-003-1
October 1, 2012
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003103
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to its scheduled
value. To provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.1.1
The Balancing Authority is the responsible entity unless the Balancing
Authority is a member of a Frequency Response Sharing Group, in which
case, the Frequency Response Sharing Group becomes the responsible
entity.
1.2. Frequency Response Sharing Group
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, R3 and
R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as
calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a FRSG
to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time
Horizon: Real-time Operations]
BAL-003-1
October 1, 2012
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003104
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency Bias Setting determined subject
to Attachment A, as validated by the ERO, into its Area Control Error (ACE)
calculation during the implementation period specified by the ERO and shall use this
Frequency Bias Setting until directed to change by the ERO. [Risk Factor: Medium
][Time Horizon: Operations Planning]
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/- 0.036 Hz.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation, in order to represent the Frequency
Bias Setting for the combined Balancing Authority Area, to be equivalent to either:
[Risk Factor: Medium ][Time Horizon: Operations Planning]
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS
Form 2 for the participating Balancing Authorities as validated by the ERO, or
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
C. Measures
M1. Each Frequency Response Sharing Group or Balancing Authority that is not a member
of a Frequency Response Sharing Group shall have evidence such as dated data plus
documented formula in either hardcopy or electronic format that it achieved an annual
FRM )in accordance with the methods specified by the ERO in Attachment A with data
from FRS Form 1 reported to the ERO as specified in Attachment A) that is equal to or
more negative than its FRO to demonstrate compliance with Requirement R1.
M2. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service shall have evidence
such as a dated document in hard copy or electronic format showing the ERO validated
Frequency Bias Setting was implemented into its ACE calculation within the
implementation period specified or other evidence to demonstrate compliance with
Requirement R2.
M3. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and is utilizing variable
Frequency Bias shall have evidence such as a dated report in hard copy or electronic
format showing the average clock-minute average Frequency Bias Setting was less
than zero and during periods when the clock-minute average frequency is outside of the
BAL-003-1
October 1, 2012
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003105
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
range 59.964 Hz to 60.036 Hz was equal to or more negative than its Frequency
Response Obligation to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation as
specified in Requirement R4 to demonstrate compliance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3 and R4, Measures M1, M2, M3 and M4 for the current
year plus the previous three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Frequency Response Sharing Group shall retain data or evidence to show
compliance with Requirement R1 and Measure M1 for the current year plus the
previous three calendar years unless directed by its Compliance Enforcement
BAL-003-1
October 1, 2012
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003106
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority or Frequency Response Sharing Group is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and flat frequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
BAL-003-1
October 1, 2012
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
R3
R4
003107
Service and uses a
fixed Frequency
Bias Setting failed to
implement the
validated Frequency
Bias Setting value
into its ACE
calculation within
the implementation
period specified but
did so within 5
calendar days from
the implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting did not
implement the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 25 calendar
days from the
implementation
period specified by
the ERO.
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
is not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 1% but by at
most 10%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 10% but by at
most 20%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 20% but by at
most 30%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
obligation by more
than 30%..
BAL-003-1
October 1, 2012
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Overlap Regulation
Services with
combined footprint
setting-error less
than or equal to 10%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 10% but less
than or equal to 20%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 20% but less
than or equal to 30%
of the validated or
calculated value.
003108
Overlap Regulation
Services with
combined footprint
setting-error more
than 30% of the
validated or
calculated value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
E. Regional Variance
None
F. Associated Documents
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
0
1
BAL-003-1
October 1, 2012
Date
April 1, 2005
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003109
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
8. The draft standard was posted for a 45-day formal comment period and a 10 day initial
ballot from October 25, 2011 through December 8, 2011.
Proposed Action Plan and Description of Current Draft:
This is the third posting of the proposed standard and its associated documents for a 30 day
formal comment period and a successive 10 day ballot, from October 5, 2012 through November
5, 2012.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments submitted within the comment period
and with the successive ballot.
January, 2013
2. Conduct a recirculation ballot for ten days.
January, 2013
3. BOT adoption.
February, 2013
BAL-003-1
October 1, 2012
Page 1 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003110
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
Definitions of Terms used in the Standard
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
EROon FRS Form 1. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A numbervalue, (either a fixed or variable Frequency Bias), usually expressed in MW/0.1
Hz, included inset into a Balancing Authority’s Area Control Error equation to account
forthat allows the Balancing Authority’s inverse Frequency Response contribution to
contribute its Frequency Response to the Interconnection, and discourage response
withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG)
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to jointly
meet the sum of the Frequency Response Obligations of its members.
BAL-003-1
October 1, 2012
Page 2 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003111
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to its scheduled
value. To provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.1.1.1.1
The Balancing Authority is the responsible entity unless the
Balancing Authority is a member of a Frequency Response Sharing
Group, in which case, the Frequency Response Sharing Group becomes
the responsible entity.
1.1.11.2.
Frequency Responseeserve Sharing Group (where applicable)
Effective Date:
In those jurisdictions where regulatory approval is required, Requirements
R2, R3 and R4 and R5 of this standard shall become effective the first calendar
day of the first calendar quarter 12 months after applicable regulatory approval.
In those jurisdictions where no regulatory approval is required, Requirements R2,
R3 and, R4 and R5 of this standard shall become effective the first calendar day
of the first calendar quarter 12 months after Board of Trustees adoption.
1.2.1.3.
In those jurisdictions where regulatory approval is required, Requirements
R1 of this standard shall become effective the first calendar day of the first
calendar quarter 24 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter
24 months after Board of Trustees adoption.
1.3.1.4.
B. Requirements
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG(BA) or Reserve Sharing Group (RSG) shall achieve an annual
Frequency Response Measure (FRM) (as calculated and reported detailed in
accordance with Attachment A and calculated on FRS Form 1) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a
FRSGor RSG to maintain an adequate level of Frequency Response in the
Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time
Horizon: Real-time OperationsOperations Assessment]
BAL-003-1
October 1, 2012
Page 3 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003112
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receivingparticipating in Overlap Regulation Service and
uses a fixed Frequency Bias Setting shall implement the Frequency Bias Setting
determined subject to Attachment A, as (fixed or variable) validated by the ERO, into
its Area Control Error (ACE) calculation during the implementation periodbeginning
on the date specified by the ERO and shall use this Frequency Bias Setting until
directed to change by the EROto ensure effectively coordinated Tie Line Bias control.
[Risk Factor: Medium ][Time Horizon: Operations Planning]
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is:operate
its Automatic Generation Control (AGC) in Tie Line Bias mode to ensure effectively
coordinated control, unless such operation would have an Adverse Reliability Impact
on the Balancing Authority’s Area. [Risk Factor: Medium ][Time Horizon: Operations
PlanningReal-time Operations]
3.1 Less than zero at all times, and
3.13.2
Equal to or more negative than its Frequency Response Obligation
when Frequency varies from 60 Hz by more than +/- 0.036 Hz.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation, in order to represent the Frequency
Bias Setting for the combined Balancing Authority Area, to be equivalent to eitherthe
sum of the Frequency Bias Settings of the participating Balancing Authorities as
validated by the ERO or calculate the Frequency Bias Setting based on the entire area
being combined and thereby represent the Frequency Response for the combined area
being controlled.: [Risk Factor: Medium ][Time Horizon: Operations Planning]
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS
Form 2 for the participating Balancing Authorities as validated by the ERO, or
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
In order to ensure adequate control response, each Balancing
Authority shall use a monthly average Frequency Bias Setting whose absolute value is at
least equal to one of the following: [Risk Factor: Medium ][Time Horizon: Operations
Planning]
R3.
The minimum percentage of the Balancing Authority Area’s
estimated yearly Peak Demand within its metered boundary per 0.1 Hz change as specified
by the ERO in accordance with Attachment B.
The minimum percentage of the Balancing Authority Area’s estimated yearly peak
generation for a generation-only Balancing Authority, per 0.1 Hz change as specified by the
ERO in accordance with Attachment B.
BAL-003-1
October 1, 2012
Page 4 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003113
C. Measures
M1. Each The Frequency Response Sharing Group or Balancing Authority that is not a
member of a Frequency Response Sharing Group or Reserve Sharing Group shall have
evidence such as dated data plus documented formula in either hardcopy or electronic
format that it achieved an annual FRM )in accordance with the methods specified by
the ERO in Attachment A with data from FRS Form 1 reported to the ERO as specified
in Attachment A) thatwith data to show that its FRM is equal to or more negative than
its FRO to demonstrate compliance with Requirement R1.
M2. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service shall have evidence
such as a dated document in hard copy or electronic format showing the ERO validated
Frequency Bias Setting was implementedentered into its ACE calculation within the
implementation periodon the date specified or other evidence to demonstrate
compliance with Requirement R2.
M3. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and is utilizing variable
Frequency Bias shall have evidence such as a dated reportoperating log, database or list
in hard copy or electronic format showing the average clock-minute average Frequency
Bias Setting was less than zero and during periods when the clock-minute average
frequency is outside of the range 59.964 Hz to 60.036 Hz was equal to or more
negative than its Frequency Response Obligation or operator interviews supported by
other evidence showing the AGC operating mode including explanation when
operating in other than Tie Line Bias mode to demonstrate compliance with
Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation as
specified in Requirement R4when Overlap Regulation Service is provided including
Frequency Bias Setting calculation to to demonstrate compliance with Requirement
R4.
The Balancing Authority shall have evidence such as dated data plus documented
formula to support the calculation retained in either hardcopy or electronic format
showing the monthly average Frequency Bias Setting or other evidence to demonstrate
compliance with Requirement R5.
M5.M4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
BAL-003-1
October 1, 2012
Page 5 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003114
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3 and, R4 and R5, Measures M1, M2, M3 and, M4, and
M5 for the current year plus the previous three calendar years unless directed by
its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The Frequency Responseeserve Sharing Group shall retain data or evidence to
show compliance with Requirement R1 and Measure M1 for the current year plus
the previous three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority or Frequency Responseeserve Sharing Group is found
non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and fFlat Ffrequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
BAL-003-1
October 1, 2012
Page 6 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
003115
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO, and the
Balancing
Authority’s, or
Frequency
Responseeserve
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
FRO, and the
Balancing
Authority’s, or
Frequency
Responseeserve
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO,
and the Balancing
Authority’s, or
Frequency
Responseeserve
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its FRO,
and the Balancing
Authority’s, or
Frequency
Responseeserve
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
fixed Frequency
Bias Setting failed to
implement the
validated Frequency
Bias Setting value
into its ACE
calculation within
the implementation
periodon the date
specified but did so
within 5 calendar
days from the
implementation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days from the
implementation
periodollowing the
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days from the
implementation
periodollowing the
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
fixed Frequency
Bias Setting did not
implement the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 25 calendar
days from the
implementation
periodollowing the
date specified by the
ERO.
BAL-003-1
October 1, 2012
Page 7 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
R3
R4
periodollowing the
date specified by the
ERO.
N/AThe Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
is not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 1% but by at
most 10%.
date specified by the
ERO.
date specified by the
ERO.
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 10% but by at
most 20%.N/A
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 20% but by at
most 30%.N/A
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services with
BAL-003-1
October 1, 2012
003116
The Balancing
Authority that is a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
obligation by more
than 30%..The
Balancing Authority
not receiving
Overlap Regulation
service failed to
operate AGC in Tie
Line Bias mode and
such operation
would not have had
an Adverse
Reliability Impact
on the Balancing
Authority’s Area.
The Balancing
The Balancing
Authority
Authority
incorrectly changed incorrectly changed
the Frequency Bias
the Frequency Bias
Setting value used in Setting value used in
its ACE calculation
its ACE calculation
when providing
when providing
Overlap Regulation Overlap Regulation
Services with
Services with
Page 8 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003117
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
R5
combined footprint
setting-error less
than or equal to
105% of the
validated or
calculatedcorrect
value.
combined footprint
setting-error more
than 105% but less
than or equal to
2015% of the
validated or
calculatedcorrect
value.
combined footprint
setting-error more
than 2015% but less
than or equal to
3025% of the correct
validated or
calculated value.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was less
than or equal to 5%
below the minimum
specified by the
ERO.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 5% but
less than or equal to
15% below the
minimum specified
by the ERO.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 15% but
less than or equal to
25% below the
minimum specified
by the ERO.
combined footprint
setting-error more
than 3025% of the
correct validated or
calculated value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
The absolute value
of the Balancing
Authorities’
calculated monthly
average Frequency
Bias Setting was
more than 25%
below the minimum
specified by the
ERO.
E. Regional Variance
None
F. Associated Documents
Attachment A - Frequency Response Standard Supporting Document
Attachment B – Process for Adjusting Bias Setting FloorProcedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
BAL-003-1
October 1, 2012
Date
Action
Change Tracking
Page 9 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Standard BAL-003-1 — Frequency Response and Frequency Bias Setting
0
1
BAL-003-1
October 1, 2012
April 1, 2005
Effective Date
New
Complete Revision under
Project 2007-12
Revision
003118
Page 10 of 10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003119
Attachment A
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Supporting Document
Frequency Response Obligation (FRO) for the Interconnection
The ERO, in consultation with regional representatives, has established a target contingency protection
criterion for each Interconnection. The default target listed in Table 1 is based on the largest category C
(N-2) event identified except for the Eastern Interconnection, which uses the largest event in the last 10
years. Additionally, this contingency protection criterion includes uncertainty adjustments at a 95 %
confidence level to prevent Point C from encroaching on the interconnection’s highest Under Frequency
Load Shed (UFLS) step for credible contingencies. The Obligation for each Interconnection in Table 1 is
calculated by dividing the Target Protection Criteria MWs by 10 times the difference between the
starting frequency and the Prevailing UFLS First Step. This number is then multiplied by the C to B Ratio
to arrive at a MW/0.1 Hz number. In the Eastern Interconnection there is an additional adjustment for
the event nadir being below the Value B due to primary frequency response withdrawal. This
Interconnection Frequency Response Obligation (FRO) includes uncertainty adjustments at a 95 %
confidence level. Detailed descriptions of the calculations used in Table 1 below are defined in the
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard.
Interconnection
Eastern
Western
ERCOT
HQ
Starting Frequency
59.974
59.976
59.963
59.972
Prevailing UFLS First Step
59.5
59.5
59.3
58.5
Base Delta Frequency
0.474
0.476
0.663
1.472
CCADJ
0.007
0.004
0.012
N/A
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
CBR
1.000
1.625
1.377
1.550
Delta Frequency (DFCBR)
0.467
0.291
0.473
0.949
BC’ADJ
0.018
N/A
N/A
N/A
Max. Delta Frequency
0.449
0.291
0.473
0.949
Resource Contingency Criteria
4,500
2,740
2,750
1,700
Credit for LR
300
1,400
IFRO
-1,002
-840
-286
-179
Table 1: Interconnection Frequency Response Obligations
October 1, 2012
Units
Hz
Hz
Hz
Hz
Hz
Hz
Hz
MW
MW
MW/0.1 Hz
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003120
*The Eastern Interconnection UFLS set point listed is a compromise value set midway between
the stable frequency minimum established in PRC-006-1 (59.3 Hz) and the local protection UFLS
setting of 59.7 Hz used in Florida and Manitoba.
**In the Base Obligation measure for ERCOT, 1400 MW (Load Resources triggered by Under Frequency
Relays at 59.70 Hz) was reduced from its Contingency Protection Criteria level of 2750 MW to get 239
MW/0.1 Hz. This was reduced to accurately account for designed response from Load Resources within 30
cycles.
An Interconnection may propose alternate FRO protection criteria to the ERO by submitting a SAR with
supporting technical documentation.
Balancing Authority Frequency Response Obligation (FRO) and
Frequency Bias Setting
The ERO will manage the administrative procedure for annually assigning an FRO and implementation of
the Frequency Bias Setting for each Balancing Authority. The annual timeline for all activities described
in this section are shown below.
For a multiple Balancing Authority interconnection, the Interconnection Frequency Response Obligation
shown in Table 1 is allocated based on the Balancing Authority annual load and annual generation. The
FRO allocation will be based on the following method:
FRO FRO
Annual Gen Annual Load
Annual Gen Annual Load
Where:
• Annual GenBA is the total annual “Output of Generating Plants” within the Balancing Authority
Area (BAA), on FERC Form 714, column c of Part II - Schedule 3.
• Annual LoadBA is total annual Load within the BAA, on FERC Form 714, column e of Part II Schedule 3.
• Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
• Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
The data used for this calculation is from the most recently filed Form 714. As an example, a report to
NERC in January 2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to assemble
and submit equivalent data to the ERO for use in the FRO Allocation process.
Balancing Authorities that elect to form a FRSG will calculate a FRSG FRO by adding together the
individual BA FRO’s.
October 1, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003121
Balancing Authorities that elect to form a FRSG as a means to jointly meet the FRO will calculate their
FRM performance one of two ways:
•
•
Calculate a group NIA and measure the group response to all events in the reporting year on a
single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that that contains the
sum of each participant’s individual event performance.
Balancing Authorities that merge or that transfer load or generation are encouraged to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation to the
Interconnection remains the same and so that CPS limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM), Frequency
Bias Setting and Frequency Bias type (fixed or variable) to the ERO each year to allow the ERO to validate
the revised Frequency Bias Settings on FRS Form 1. If the ERO posts the official list of events after the
date specified in the timeline below, Balancing Authorities will be given 30 days from the date the ERO
posts the official list of events to submit their FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing Authorities,
the ERO will use FRS Form 1 data to post the following information for each Balancing Authority for the
upcoming year:
•
•
Frequency Bias Setting
Frequency Response Obligation (FRO)
Once the data listed above is fully posted, the ERO will announce the three-day implementation period
for changing the Frequency Bias Setting if it differs from that shown in the timeline below.
A BA using a fixed Frequency Bias Setting sets its Frequency Bias Setting to the greater of (in absolute
value):
•
•
Any number the BA chooses between 100% and 125% of its Frequency Response Measure as
calculated on FRS Form 1
Interconnection Minimum as determined by the ERO
For purposes of calculating the minimum Frequency Bias Setting, a Balancing Authority participating in a
Frequency Response Sharing Group will need to calculate its stand-alone Frequency Response Measure
using FRS Form 1 and FRS Form 2 to determine its minimum Frequency Bias Setting.
A Balancing Authority providing Overlap Regulation will report the historic peak demand and generation
of its combined BAs’ areas on FRS Form 1 as described in Requirement R4.
There are occasions when changes are needed to Bias Settings outside of the normal schedule.
Examples are footprint changes between Balancing Authorities and major changes in load or generation
or the formation of new Balancing Authorities. In such cases the changing Balancing Authorities will
October 1, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003122
work with their Regions, NERC and the Resources Subcommittee to confirm appropriate changes to Bias
Settings, FRO, CPS limits and Inadvertent Interchange balances.
If there is no net change to the Interconnection total Bias, the Balancing Authorities involved will agree
on a date to implement their respective change in Bias Settings. The Balancing Authorities and ERO will
also agree to the allocation of FRO such that the sum remains the same.
If there is a net change to the Interconnection total Bias, this will cause a change in CPS2 limits and FRO
for other Balancing Authorities in the Interconnection. In this case, the ERO will notify the impacted
Balancing Authorities of their respective changes and provide an implementation window for making
the Bias Setting changes.
Frequency Response Measure (FRM)
The Balancing Authority will calculate its FRM from Single Event Frequency Response Data (SEFRD),
defined as: “the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz” as calculated on FRS Form 2 for each event shown on FRS
Form 1. The events in FRS Form 1 are selected by the ERO using the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change in its Net Actual
Interchange on its tie lines with its adjacent Balancing Authorities divided by the change in
Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to their Net
Actual Interchange (NAI) values to account for factors such as nonconforming loads. FRS Form 1 and 2
shows the types of adjustments that are allowed. Note that with the exception of the Contingent BA
column, any adjustments made must be made for all events in an evaluation year. As an example, if an
entity has non-conforming loads and makes an adjustment for one event, all events must show the nonconforming load, even if the non-conforming load does not impact the calculation. This ensures that the
reports are not utilizing the adjustments only when they are favorable to the BA.) The ERO will use a
standardized sampling interval of approximately 16 seconds before the event up to the time of the
event for the pre-event NAI, and frequency (A values) and approximately 20 to 52 seconds after the
event for the post-event NAI (B values) in the computation of SEFRD values, dependent on the data scan
rate of the Balancing Authority’s Energy Management System (EMS).
All events listed on FRS Form 1 need to be included in the annual submission of FRS Forms 1 and 2. The
only time a Balancing Authority should exclude an event is if its tie-line data or its Frequency data is
corrupt or its EMS was unavailable. FRS Form 2 has instructions on how to correct the BA’s data if the
given event is internal to the BA or if other authorized adjustments are used.
Assuming data entry is correct FRS Form 1 will automatically calculate the Balancing Authority’s FRM for
the past 12 months as the median of the SEFRD values. A Balancing Authority electing to report as an
FRSG or a provider of Overlap Regulation Service will provide an FRS Form 1 for the aggregate of its
participants.
October 1, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003123
To allow Balancing authorities to plan its operations, events with a “Point C” that cause the
Interconnection Frequency to be lower than that shown in Table 1 above (for example, an event in the
Eastern Interconnection that causes the Interconnection Frequency to go to 59.4 Hz) or higher than an
equal change in frequency going above 60 Hz may be included in the list of events for that
interconnection. However, the calculation of the BA response to such an event will be adjusted to show
a frequency change only to the Target Minimum Frequency shown in Table 1 above (in the previous
example this adjustment would cause Frequency to be shown as 59.5 Hz rather than 59.4 HZ) or a high
frequency amount of an equal quantity. Should such an event happen, the ERO will provide additional
guidance.
October 1, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003124
Timeline for Balancing Authority Frequency Response and Frequency
Bias Setting Activities
Described below is the timeline for the exchange of information between the ERO and Balancing
Authorities (BA) to:
•
•
•
Facilitate the assignment of BA Frequency Response Obligations (FRO)
Calculate BA Frequency Response Measures (FRM)
Determine BA Frequency Bias Settings (FBS)
Target Date
Activity
April 30
The ERO reviews candidate frequency events and selects frequency events for the
first quarter (December to February).
May 10
Form1 is posted with selected events from the first quarter for BA usage by the
ERO.
May 15
The BAs receive a request to provide load and generation data as described in
Attachment A to support FRO assignments and determining minimum FBS for
BAs.
July 15
The BAs provide load and generation data as described in Attachment A to the
ERO.
July 30
The ERO reviews candidate frequency events and selects frequency events for the
second quarter (March to May).
August 10
Form1 is posted with selected events from the first and second quarters for BA
usage by the ERO.
October 30
The ERO reviews candidate frequency events and selects frequency events for the
third quarter (June to August)
November 10
Form1 is posted with selected events from the first, second, and third quarters for
BA usage by the ERO.
November 20
If necessary, the ERO provides any updates to the necessary Frequency Response.
November 20
The ERO provides the fractional responsibility of each BA for the Interconnection’s
FRO and Minimum FBS to the BAs.
January 30
The ERO reviews candidate frequency events and selects frequency events for the
fourth quarter (September to November).
October 1, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003125
2nd business day in
February
Form1 is posted with all selected events for the year for BA usage by the ERO.
February 10
The ERO assigns FRO values to the BAs for the upcoming year.
March 7
BAs complete their frequency response sampling for all four quarters and their
FBS calculation, returning the results to the ERO.
March 24
The ERO validates FBS values, computes the sum of all FBS values for each
Interconnection, and determines L10 values for the CPS 2 criterion for each BA as
applicable.
Any time during
first 3 business
days of April
(unless specified
otherwise by the
ERO)
The BA implements any changes to their FBS and L10 value.
October 1, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003126
Implementation Plan for BAL-003-1 – Frequency
Response & Frequency Bias Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b should be retired at midnight of the day immediately prior to the Effective Date of BAL003-1 in the Jurisdiction in which the new standard is becoming effective.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4 and R5
become effective:
Frequency Response Measure (FRM): The median of all the Frequency Response observations
reported annually on FRS Form 1.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the required
Frequency Response needed for the reliable operation of an Interconnection.
Frequency Bias Setting: A numbervalue, either fixed or variable, usually expressed in MW/0.1
Hz, included inset into a Balancing Authority’s Area Control Error equation to account for
algorithm that allows the Balancing Authority’s Frequency Response contributionto contribute
its frequency response to the Interconnection and discourage withdrawal through secondary
control systems.
The existing definition of Frequency Bias Setting should be retired at midnight of the day immediately
prior to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming
effective.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following NERC
approved standards:
•
•
•
•
BAL-001-0.1a Real Power Balancing Control Performance
BAL-004-0 Time Error Correction
BAL-004-1 Time Error Correction
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003127
Once this standard becomes effective, the responsible entities identified in the applicability section of
the standard must comply with the requirements. These include:
• Balancing Authorities
• Reserve Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R2, R3, R4 and
R5 of this standard shall become effective the first calendar day of the first calendar quarter
12 months after applicable regulatory approval. In those jurisdictions where no regulatory
approval is required, Requirements R2, R3, R4 and R5 of this standard shall become
effective the first calendar day of the first calendar quarter 12 months after Board of
Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter 24
months after applicable regulatory approval. In those jurisdictions where no regulatory
approval is required, Requirements R1 of this standard shall become effective the first
calendar day of the first calendar quarter 24 months after Board of Trustees adoption.
BAL-003-1 – Frequency Response and Frequency Bias | Implementation Plan | October 24, 2011
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003128
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b Requirements R1, R2, R3, R4 and R6 should be retired midnight of the day immediately
prior to the Effective Date ofwhen BAL-003-1 in the Jurisdiction in which the new standard is becoming
becomes effective.
BAL-003-0 Re1quirement R5 should be retired as outlined in the following table.
For those Balancing Authorities that serve native load:
•
•
•
•
•
May 2011 through December 2011
January 2012 through December 2012
January 2013 through December 2013
January 2014 through December 2014
January 2015 through
-0.8% of peak/0.1 Hz
-0.6% of peak/0.1 Hz
-0.4% of peak/0.1 Hz
-0.2% of peak/0.1 Hz
-0.0% of peak/0.1 Hz
For those Balancing Authorities that do not serve native load:
•
•
•
•
•
May 2011 through December 2011
generation/0.1 Hz
January 2012 through December 2012
generation/0.1 Hz
January 2013 through December 2013
generation/0.1 Hz
January 2014 through December 2014
generation/0.1 Hz
January 2015 through
generation/0.1 Hz
-0.8% of upcoming years maximum
-0.6% of upcoming years maximum
-0.4% of upcoming years maximum
-0.2% of upcoming years maximum
-0.0% of upcoming years maximum
The FRR drafting team, NERC and the NERC Resources Subcommittee will observe the impact
on frequency and will implement a reversion plan should frequency performance decline.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4
and R5 become effective:
July 12, 2011
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003129
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually on FRS Form 1.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
Frequency Bias Setting: A number, either a fixed or variable, usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s Frequency Response contribution to the Interconnection,
and discourage response withdrawal through secondary control systems.
The existing definition of Frequency Bias Setting should be retired midnight of the day immediately prior
to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming effective.
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved standards:
•
BAL-001-0.1a Real Power Balancing Control Performance
•
BAL-004-0 Time Error Correction
•
BAL-004-1 Time Error Correction
•
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
•
Reserve Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R21, R3, R4 and R54 of
this standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R21, R3, R4 and R54 of this standard shall become effective the first calendar day of
the first calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R12 of this
standard shall become effective the first calendar day of the first calendar quarter 24 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, Requirements R12 of this standard shall become effective the first calendar day of
the first calendar quarter 24 months after Board of Trustees adoption.
July 12, 2011
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003130
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Event Selection Process
This procedure outlines the ERO process for supporting the Frequency Response Standard (FRS). A
Procedure revision request may be submitted to the ERO for consideration. The revision request must
provide a technical justification for the suggested modification. The ERO shall post the suggested
modification for a 45-day comment period and discuss the revision request in a public meeting. The
ERO will make a recommendation to the NERC BOT, which may adopt the revision request, reject it, or
adopt it with modifications. Any approved revision to this Procedure shall be filed with FERC for
informational purposes.
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of
frequency events to be used by Balancing Authorities (BA) to calculate their Frequency Response to
determine:
•
•
Whether the BA met its Frequency Response Obligation, and
An appropriate fixed Bias Setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for analysis. The
events that best fit the criteria will be used to support the FRS. The evaluation period for
performing the annual Frequency Bias Setting and the Frequency Response Measure (FRM)
calculation is December 1 of the prior year through November 30 of the current year.
2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating
the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion
events in a 12 month evaluation period satisfying the criteria below, then similar acceptable
events from the subsequent year’s evaluation period will be included with the data set by the
ERO for determining FRS compliance. This is described later.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the
FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C and
the arrested frequency Point C exceeds the excursion threshold values specified for the
Interconnection in Table 1 below.
i. The A Value is computed as an average over the period from -16 seconds to 0
seconds before the frequency transient begins to decline.
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
October 1, 2012
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003131
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection
East
West
ERCOT
HQ
A Value
to Pt C
0.04Hz
0.07Hz
0.15Hz
0.30Hz
Point C (Low)
< 59.96
< 59.95
< 59.90
< 59.85
Point C (High)
> 60.04
> 60.05
> 60.10
> 60.15
Table 1: Interconnection Frequency Excursion Threshold Values
b. The time from the start of the rapid change in frequency until the point at which
Frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not be
included.
4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The
A Value is computed as an average over the period from -16 seconds to 0 seconds before the
frequency transient begins to decline. For example, given the choice of the two events below,
the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60
Hz.
5. Excursions that include 2 or more events that do not stabilize within 18 seconds will not be
considered.
6. Frequency excursion events occurring during periods when large interchange schedule ramping
or load change is happening, and frequency excursion events occurring within 5 minutes of the
top of the hour, will be excluded from consideration if other acceptable frequency excursion
events from the same quarter are available.
7. The ERO will select the largest (A Value to Point C) 2 or 3 frequency excursion events occurring
each month. If there are not 2 frequency excursion events satisfying the selection criteria in a
month, then other frequency excursion events should be picked in the following sequence:
a. From the same event quarter of the year.
October 1, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003132
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
b. From an adjacent month.
c. From a similar load season in the year (shoulder vs. summer/winter)
d. The largest unused event.
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable
events from the next year’s evaluation period will be included with the data set by the ERO for
determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be
reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a
24 month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation. The
ERO will post the final list of frequency excursion events used for standard compliance as specified in
Attachment A of BAL-003-1. The following is a general description of the process that the ERO will use
to ensure that BAs can evaluate events during the year in order to monitor their performance
throughout the year.
Monthly
Candidate events will be initially screened by the "Frequency Event Detection Methodology" shown on
the following link located on the NERC Resources Subcommittee area of the NERC website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oct_2011.p
df. Each month's list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under "Candidate Frequency Events".
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
•
•
•
•
December through February
March through May
June through August
September through November
Based on criteria established in the "Procedure for ERO Support of Frequency Response and Frequency
Bias Setting Standard", events will be selected to populate the FRS Form 1 for each Interconnection.
The Form 1's will be posted on the NERC website, in the Resources Subcommittee area under the title
"Frequency Response Standard Resources". Updated Form 1's will be posted at the end of each quarter
listed above after a review by the NERC RS' Frequency Working Group. While the events on this list are
expected to be final, as outlined in the selection criteria, additional events may be considered, if the
October 1, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003133
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
number of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the
year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters
listed above, will be posted as specified in Attachment A. Each Balancing Authority reports its previous
year’s Frequency Response Measure (FRM), Frequency Bias Setting and Frequency Bias type (fixed or
variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for
errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in
Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility in when
each BA implements its settings.
October 1, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003134
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Process for Adjusting Interconnection Minimum Frequency Bias Setting
This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to
better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance
with this procedure.
The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other
balancing standard limits.
Under BAL-003-1, the minimum Frequency Bias Settings will be moved toward the natural Frequency
Response in each interconnection. In the first year, the minimum Frequency Bias Setting for each
interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is
based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714
Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table
1 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum
Frequency Bias Setting is allocated among the BAs on an interconnection using the same allocation
method as is used for the allocation of the Frequency Response Obligation (FRO).
Interconnection
Eastern
Western
ERCOT*
HQ*
Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)
0.9% of non-coincident peak load
0.9% of non-coincident peak load
N/A
N/A
Table 2. Frequency Bias Setting Minimums
*The minimum Frequency Bias Setting requirement does not apply to a Balancing Authority that
is the only Balancing Authority in its Interconnection. These Balancing Authorities are solely
responsible for providing reliable frequency control of their Interconnection. These Balancing
Authorities are responsible for converting frequency error into a megawatt error to provide
reliable frequency control, and the imposition of a minimum bias setting greater than the
magnitude the Frequency Response Obligation may have the potential to cause control system
hunting, and instability in the extreme.
The ERO, in coordination with the regions of each interconnection, will annually review Frequency Bias
Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds
(in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value)
than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting
for BAs within that Interconnection may be reduced (in absolute value) based on the technical
evaluation and consultation with the regions affected by 0.1 percentage point of peak load (expressed in
MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency Response.
The ERO, in coordination with the regions of each Interconnection, will monitor the impact of the
reduction of minimum frequency bias settings, if any, on frequency performance, control performance,
October 1, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003135
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish postcontingency restoration of frequency to schedule or control performance problems occur, then the prior
reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction
based on the criterion stated above may not be implemented.
October 1, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003136
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection Frequency Response Obligation Methodology
This procedure outlines the process the ERO is to use for determining the Interconnection Frequency
Response Obligation (IFRO).
The following are the formulae that comprise the calculation of the IFROs.
Where:
•
•
•
•
•
•
•
•
•
•
•
•
•
DFBase is the base delta frequency.
FStart is the starting frequency determined by the statistical analysis.
UFLS is the highest UFLS trip setpoint for the interconnection.
CCAdj is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data.
DFCC is the delta frequency adjusted for the differences between 1-second and sub-second Point
C observations for frequency events.
CBR is the statistically determined ratio of the Point C to Value B.
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
BC’ADJ is the statistically determined adjustment for the event nadir being below the Value B
(Eastern Interconnection only) during primary frequency response withdrawal.
MDF is the maximum allowable delta frequency.
RLPC is the resource loss protection criteria.
CLR is the credit for load resources.
ARLPC is the adjusted resource loss protection criteria adjusted for the credit for load resources.
IFRO is the interconnection frequency response obligation.
October 1, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003137
Frequency Response
Standard Background
Document
October, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003138
Table of Contents
Table of Contents ............................................................................................................................ 1
Introduction .................................................................................................................................... 2
Background ..................................................................................................................................... 2
Rationale by Requirement .......................................................................................................... 224
Requirement 1 .................................................................................................................... 224
Background and Rationale .................................................................................................. 224
Requirement 2 .................................................................................................................... 328
Background and Rationale .................................................................................................. 329
Requirement 3 .................................................................................................................... 349
Requirement 4 .................................................................................................................. 3410
Background and Rationale ................................................................................................ 3510
Requirement 5 .................................................................................................................. 3510
Background and Rationale ................................................... Error! Bookmark not defined.10
How this Standard Meets the FERC Order 693 Directives ........................................................ 3611
FERC Directive ....................................................................................................................... 3611
1. Levels of Non-Compliance ............................................................................................. 3611
2. Determine the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other Requirements of the Reliability Standard are met 3612
3. Define the necessary amount of Frequency Response needed for Reliable Operation for
each Balancing Authority with methods of obtaining and measuring that the frequency
response is achieved ............................................................................................................. 3612
Necessary Amount of Frequency Response ..................................................................... 3612
Methods of Obtaining Frequency Response .................................................................... 3713
Measuring that the Frequency Response is Achieved ...................................................... 3713
Going Beyond the Directive .................................................................................................. 3813
Future Work ............................................................................. Error! Bookmark not defined.13
Good Practices and Tools .......................................................................................................... 3914
Background ........................................................................................................................... 3914
Identifying and Estimating Frequency Responsive Reserves ............................................... 3914
Using FRS Form 1 Data .......................................................................................................... 4015
Tools ...................................................................................................................................... 4015
Field Trial ...................................................................................... Error! Bookmark not defined.16
1
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003139
Introduction
This document provides background on the development, testing and implementation of BAL003-1 - Frequency Response Standard (FRS).1 The intent is to explain the rationale and
considerations for the Requirements of this standard and their associated compliance
information. The document also provides good practices and tips for Balancing Authorities
(“BAs”) with regard to Frequency Response.
In Order No. 693, the Federal Energy Regulatory Commission (“FERC” or the “Commission”)
directed additional changes to BAL-003.2 This document explains how compliance with those
directives is met by BAL-003-1.
The original Standards Authorization Request (“SAR”), finalized on June 30, 2007, assumed
there was adequate Frequency Response in all the North American Interconnections. The goal
of the SAR was to update the Standard to make the measurement process of frequency
response more objective and to provide this objective data to Planners and Operators for
improved modeling. The updated models will improve understanding of the trends in
Frequency Response to determine if reliability limits are being approached. The Standard
would also lay the process groundwork for a transition to a performance-based Standard if
reliability limits are approached.
This document will be periodically updated by the FRS Drafting Team (FRSDT) until the Standard
is approved. Once approved, this document will then be maintained and updated by the ERO
and the NERC Resources Subcommittee to be used as a reference and training resource.
Background
This section discusses the different components of frequency control and the individual
components of Primary Frequency Control also known as Frequency Response.
Frequency Control
Most system operators generally have a good understanding of frequency control and Bias
Setting as outlined in the balancing standards and the references to them in the NERC
Operating Manual. Frequency control can be divided into four overlapping windows of time as
outlined below.
Primary Frequency Control (Frequency Response) – Actions provided by the
Interconnection to arrest and stabilize frequency in response to frequency deviations.
Primary Control comes from automatic generator governor response (also known as speed
1
2
2
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of Terms Used in NERC Reliability
Standards, available here: http://www.nerc.com/files/Glossary_of_Terms.pdf.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 368-375, order on reh’g, Order
No. 693-A, 120 FERC ¶ 61,053 (2007).
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003140
regulation), load response (typically from motors), and other devices that provide an
immediate response based on local (device-level) control systems.
Secondary Frequency Control – Actions provided by an individual BA or its Reserve Sharing
Group to correct the resource – load unbalance that created the original frequency
deviation, which will restore both Scheduled Frequency and Primary Frequency Response.
Secondary Control comes from either manual or automated dispatch from a centralized
control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced basis
that are coordinated so there is a net zero effect on Area Control Error (ACE). Examples of
Tertiary Control include dispatching generation to serve native load; economic dispatch;
dispatching generation to affect Interchange; and re-dispatching generation. Tertiary
Control actions are intended to replace Secondary Control Response by reconfiguring
reserves.
Time Control includes small offsets to scheduled frequency to keep long term average
frequency at 60 Hz.
Primary Frequency Control – Frequency Response
Primary Frequency Control, also known generally as Frequency Response, is the first stage of
overall frequency control and is the response of resources and load to a locally sensed change
in frequency in order to arrest that change in frequency. Frequency Response is automatic, not
driven by any centralized system, and begins within seconds rather than minutes. Different
resources, loads, and systems provide Frequency Response with different response times,
based on current system conditions such as total resource/load and their respective mix.
The proposed NERC Glossary of Terms defines Frequency Response as:
(Equipment) The immediate and automatic reaction or response of power from a
system or power from elements of the system to a change in locally sensed system
frequency.
(System) The sum of the change in demand, and the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).
As noted above, Frequency Response is the characteristic of load and generation within
Balancing Authorities and Interconnections. It reacts or responds with changes in power to
attempt changes in load-resource balance that result in changes to system frequency. Because
the loss of a large generator is much more likely than a sudden loss of an equivalent amount of
load, Frequency Response is typically discussed in the context of a loss of a large generator.
Included within Frequency Response are many components of that response. Understanding
Frequency Response and the FRS requires an understanding of each of these components and
how they relate to each other.
Frequency Response Illustration
The following simple example is presented to illustrate the components of Frequency Response
in graphical form. It includes a series of seven graphs that illustrate the various components of
3
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003141
Frequency Response and a brief discussion of each describing how these components react to
attempted changes in the load-resource balance and resulting changes in system frequency.
The illustration is based on an assumed Disturbance event of the sudden loss of 1000 MW of
generation. Although a large event is used to illustrate the response components, even small
frequently occurring events will result in similar reactions or responses. The magnitude of the
event only affects the shape of the curves on the graph; it does not obviate the need for
Frequency Response.
Primary Frequency Control - Frequency Response - Graph 1
3000
60.100
Power Deficit
2500
60.000
2000
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Change in Power (MW)
Frequency
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The first graph, Primary Frequency Control – Frequency Response – Graph 1, presents a sudden
loss of generation of 1000 MW. The components are presented relative to time as shown on
the horizontal Time axis in seconds. This simplified example assumes a Disturbance event of
the sudden loss of generation resulting from a breaker trip that instantaneously removes 1000
MW of generation from the interconnection. This sudden loss is illustrated by the power deficit
line shown in black using the MW scale on the left. Interconnection frequency is illustrated by
the frequency line shown in red using the Hertz scale on the right. Since the Scheduled
Frequency is normally 60 Hz, it is assumed that this is the frequency when the Disturbance
event occurs.
Even though the generation has tripped and power injected by the generator has been
removed from the interconnection, the loads continue to use the same amount of power. The
4
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003142
“Law of Conservation of Energy”3 requires that the 1000 MW must be supplied to the
interconnection if energy balance is to be “conserved”. This additional 1000 MW of power is
produced by extracting kinetic energy that was stored in the rotating mass of all of the
synchronized generators and motors on the interconnection when they were increased from
zero to synchronous speed – essentially using this equipment as a giant flywheel. The extracted
energy supplies the “balancing inertia”4 power required to maintain the power and energy
balance on the interconnection. This balancing inertia power is produced by the generators’
spinning inertial mass’ resistance to the slowdown in speed of the rotating equipment on the
interconnection that both provides the stored kinetic energy and reduces the frequency of the
interconnection. This is illustrated in the second graph, Primary Frequency Control – Frequency
Response – Graph 2, by the orange dots representing the balancing inertia power that exactly
overlay and offset the power deficit.
Primary Frequency Control - Frequency Response - Graph 2
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
As the frequency decreases, synchronized motors slow, as does the work they are providing,
resulting in a decrease in load called “load damping.” This load damping is the reason that the
power deficit initially declines. Synchronously operated motors will contribute to load
damping. Variable speed drives that are decoupled from the interconnection frequency do not
3
4
5
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power which is the first
derivative of energy with respect to time, must also be conserved.
The term “balancing Inertia” is coined here from the terms “inertial frequency response” and “balancing energy”. Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003143
contribute to load damping. In general, any load that does not change with interconnection
frequency including resistive load will not contribute to load damping or Frequency Response.
It is important to note that the power deficit equals exactly the balancing inertia, indicating that
there is no power or energy imbalance at any time during this process. What is normally
considered as “balancing power or energy” is actually power or energy required to correct the
frequency error from scheduled frequency. Any apparent power or energy imbalance is
corrected instantaneously by the balancing inertia power and energy extracted from the
interconnection. Thus the balancing function is really a frequency control function described as
a balancing function because ACE is calculated in MWs instead of Hertz, frequency error.
During the initial seconds of the Disturbance event, the governors have yet to respond to the
frequency decline. This is illustrated with the Blue line on the third graph, Primary Frequency
Control – Frequency Response – Graph 3, showing Governor Response. This time delay results
from the time that it takes the controller to adjust the equipment and the time it takes the
mass to flow from the source of the energy (main steam control valve for steam turbines, the
combustor for gas turbines, or the gate valve for hydro turbines) to the turbine-generator
blades where the power is converted to electrical energy.
Primary Frequency Control - Frequency Response - Graph 3
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Note that the frequency continues to decline due to the ongoing extraction by balancing inertia
power of energy from the rotating turbine-generators and synchronous motors on the
interconnection. The reduction in load also continues as the effect of load damping continues
6
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003144
to reduce the load while frequency declines. During this time delay (before the governor
response begins) the balancing inertia limits the rate of change of frequency.
After a short time delay, the governor response begins to increase rapidly in response to the
initial rapid decline in frequency, as illustrated on the fourth graph, Primary Frequency Control
– Frequency Response – Graph 4. Governor response exactly offsets the power deficit at the
point in time that the frequency decline is arrested. At this point in time, the balancing inertia
has provided its contribution to reliability and its power contribution is reduced to zero as it is
replaced by the governor response. If the time delay associated with the delivery of governor
response is reduced, the amount of balancing inertia required to limit the change in frequency
by the Disturbance event can also be reduced. This supports the conclusion that balancing
inertia is required to manage the time delays associated with the delivery of Frequency
Response. Not only is the rapid delivery of Frequency Response important, but the shortening
of the time delay associated with its delivery is also important. Therefore, two important
components of Frequency Response are 1) how long the time delay is before the initial delivery
of response begins; and 2) how much of the response is delivered before the frequency change
is arrested.
Primary Frequency Control - Frequency Response - Graph 4
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
This point, at which the frequency is first arrested, is defined as “Point C” and Frequency
Response calculated at this point is called the “arrested frequency response.” The arrested
frequency is normally the minimum (maximum for load loss events) frequency that will be
7
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003145
experienced during a Disturbance event. From a reliability perspective, this minimum
frequency is the frequency that is of concern. Adequate reliability requires that frequency at
the time frequency is arrested remain above the under-frequency relay settings so as not to trip
these relays and the firm load interrupted by them. Frequency Response delivered after
frequency is arrested at this minimum level provides less reliability value than Frequency
Response delivered before Point C, but greater value than Secondary Frequency Control power
and energy which is delivered minutes later.
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with their Governor Response. This results in the frequency partially
recovering from the minimum arrested value and results in an oscillating transient that follows
the minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period that ends roughly 20 seconds after the Disturbance event. This postdisturbance transient period is included on the fifth illustrative graph, Primary Frequency
Control – Frequency Response – Graph 5.
Primary Frequency Control - Frequency Response - Graph 5
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The total Disturbance event illustration is presented on the sixth graph, Primary Frequency
Control – Frequency Response – Graph 6. Frequency and power contributions stabilize at the
end of the transient period. Frequency Response calculated from data measured during this
settled period is called the “Settled Frequency Response.” The Settled Frequency Response is
the best measure to use as an estimator for the “Frequency Bias Setting” discussed later.
8
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003146
Primary Frequency Control - Frequency Response - Graph 6
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The final Disturbance event illustration is presented on the seventh graph, Primary Frequency
Control – Frequency Response – Graph 7. This graph shows the averaging periods used to
estimate the pre-disturbance A-Value averaging period and the post-disturbance B-Value
averaging period used to calculate the settled frequency response. A discussion of the
measurement of Frequency Response immediately follows these graphs. That discussion
includes consideration of the factors that affect the methods chosen to measure Frequency
Response for implementation in a reliability standard.
9
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003147
Primary Frequency Control - Frequency Response - Graph 7
3000
60.100
Power Deficit
Balancing Inertia
Load Damping
Governor Response
A-value
B-value
2500
60.000
Frequency
59.900
1500
59.800
B-Value Averaging Period
A-Value Averaging Period
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
2000
59.400
-20
-15
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Frequency Response Measurement (FRM)
The classic Frequency Response points A, C, and B, shown below in Fig. 1 Frequency Response
Characteristic, are used for measurement as found in the Frequency Response Characteristic
Survey Training Document within the NERC operating manual, found at
http://www.nerc.com/files/opman_7-1-11.pdf. This traditional Frequency Response Measure
has recently been more specifically termed “settled frequency response.” This term has been
used because it provides the best Frequency Response Measure to estimate the Frequency Bias
Setting in Tie-line Bias Control based Automatic Generation Control Systems. However, the
industry has recognized that there is considerable variability in measurement resulting from the
selection of Point A and Point B in the traditional measure making the traditional measurement
method unsuitable as the basis for an enforceable reliability standard in a real world setting of
multiple Balancing Authority interconnections.
10
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003148
Frequency Response
60.050
60.025
A = 60.000
60.000
Frequency (Hz)
59.975
59.950
59.925
59.900
B = 59.874
59.875
59.850
59.825
C = 59.812
59.800
59.775
59.750
-30
-20
-10
0
10
20
30
40
50
60
Time (Seconds)
Figure 1. Frequency Response Characteristic
By contrast, measuring an Interconnection’s settled frequency response is straightforward and
fairly accurate. All that’s needed to make the calculation is to know the size of a given
contingency (MW), divide this value by the change in frequency and multiply the results by 10
since frequency response is expressed in MW/0.1Hz.
Measuring a BA’s frequency response is more challenging. Prior to BAL-003-1, NERC’s
Frequency Response Characteristic Survey Training Document provided guidance to calculate
Frequency Response. In short, it told the reader to identify the BA’s interchange values
“immediately before” and “immediately after” the Disturbance event and use the difference to
calculate the MWs the BA deployed for the event. There are two challenges with this
approach:
Two people looking at the same data would come up with different values when
assessing which exact points were immediately before and after the event.
In practice, the actual response provided by the BA can change significantly in the
window of time between point B and when secondary and tertiary control can assist in
recovery.
Therefore, the measurement of settled frequency response has been standardized in a number
of ways to limit the variability in measurement resulting from the poorly specified selection of
Point A and Point B. It should be noted that t-0 has been defined as the first scan value that
11
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003149
shows a deviation in frequency of some significance, usually approaching about 10 mHz. The
goal is such that the first scan prior to t-0 was unaffected by the deviation and appropriate for
one of the averaging points.
The A-value averaging period of approximately the previous 16 seconds prior to t-0 was
selected to allow for an averaging of at least 2 scans for entities utilizing 6 second scan
rates. (All time average period references in this document are for 2 second scan rates
unless noted otherwise.)
The B-value averaging period of approximately (t+20 to t+52 seconds) was selected to
attempt to obtain the average of the data after primary frequency response was
deployed and the transient completed(settled), but before significance influence of
secondary control. Multiple periods were considered for averaging the B-value:
o 12 to 24 sec
o 18 to 30 sec
o 20 to 40 sec
o 18 to 52 sec
o 20 to 52 sec
It is necessary for all BAs from an interconnection to use the same averaging periods to
provide consistent results. In addition, the SDT decided that until more experience is
gained, it is also desirable for all interconnections to use the same averaging periods to
allow comparison between interconnections.
The methods presented in this document only address the values required to calculate the
frequency response associated with the frequency change between the initial frequency, AValue, and the settling frequency, B-Value. No reasonable or consistent calculations can be
made relating to the arresting frequency, C-Value, using Energy Management System (EMS)
scan rate data as long as 6-seconds or tie-line flow values associated with the minimum value of
the frequency response characteristic (C-value) as measured at the BA level.
Both the calculation of the frequency at Point A and the frequency at Point B began with the
assumption that a 6-second scan rate was the source of the data. Once the averaging periods
for a 6-second scan rate were selected, the averaging periods for the other scan rates were
selected to provide as much consistency as possible between BAs with different scan rates.
The Frequency at Point A was initially defined as the average of the two scans immediately
prior to the frequency event. All other averaging periods were selected to be as consistent as
possible with this 12 second average scan from the 6-second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” is defined as the average of the
same scans as used for the Point A frequency average.
The Frequency at Point B was then selected to be an average as long as the average of 6-second
scan data as possible that would not begin until most of the hydro governor response had been
delivered and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” is defined as the average of the same
scans as used for the Point B frequency average.
12
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003150
B Averaging Period Selection:
Experience from the Electric Reliability Council of Texas (“ERCOT”) and the field trail on
other interconnections indicated that the 12 to 24 second and 18 to 30 second
averaging periods were not suitable because they did not provide the consistency in
results that the other averaging periods provided, and that the remaining measuring
periods do not provide significantly different results from each other. The team
believed that this was observed because the transients were not complete in all of the
samples using these averaging periods.
The 18 to 52 second and 20 to 52 second averaging periods were compared to each
other, with the 20 to 52 second period providing more consistent values, believed to
result from the incomplete transient in some of the 18 to 52 second samples.
This left a choice between the 20 to 40 second and the 20 to 52 second averaging
periods. The team recognized that there would be more AGC response in the 20 to 52
second period, but the team also recognized that the 20 to 52 second period would
provide a better measure of squelched response from outer loop control action. The 20
to 52 second period was selected because it would indicate squelched response from
outer-loop control and provide incentive to reduce response withdrawal. The final
selections for the data averaging periods used in FRS Form 1 are shown in the table
below.
Definitions of Frequency Values for Frequency Response Calculation
Scan Rate
T 0 Scan
6-Seconds
5-Seconds
4-Seconds
3-Seconds
2-Seconds
Identify first
significant
change in
frequency as
the T 0 scan
A Value (average)
B Value (average)
Average of T-1 through T-2 scans
Average of T+4 through T+8 scans
Average of T-1 through T-2 scans
Average of T+5 through T+10 scans
Average of T-1 through T-3 scans
Average of T+6 through T+12 scans
Average of T-1 through T-5 scans
Average of T+7 through T+17 scans
Average of T-1 through T-8 scans
Average of T+10 through T+26 scans
Consistent measurement of Primary Frequency Response is achievable for a selected number of
events and can produce representative frequency response values, provided an appropriate
sample size is used in the analysis. Available research investigating the minimum sample size to
provide consistent measurements of Frequency Response has shown that a minimum sample
size of 20 events should be adequate.
Measurement of Primary Frequency Response on an individual resource or load basis requires
analysis of energy amounts that are often small and difficult to measure using current methods.
In addition, the number of an interconnection's resources and loads providing their response
could be problematic when compiling results for multiple events.
Measurement of Primary Frequency Response on an interconnection (System) basis is straight
forward provided that an accurate frequency metering source is available and the magnitude of
the resource/load imbalance is known in MWs.
13
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003151
Measurement on a Balancing Authority basis can be a challenge, since the determination of
change in MWs is determined by the change in the individual BA's metered tie lines.
Summation of tie lines is accomplished by summing the results of values obtained by the digital
scanning of meters at intervals up to six seconds, resulting in a non-coincidental summing of
values. Until the technology to GPS time stamp tie line values at the meter and the summing of
those values for coincidental times is in use throughout the industry, it is necessary to use
averaging of values described above to obtain consistent results.
Figure 2. Frequency Response Measurement
The standardized measure is shown graphically in Fig. 2 Frequency Response Measurement
with the averaging periods shown by the solid blue lines on the graph. Since FERC directed a
performance obligation for BAL-003-1, it is important to be more objective in the measurement
process. The standardized calculation is available on FRS Form 2 for EMS scan rates of 2, 3, 4, 5,
and 6 seconds at http://www.nerc.com/filez/standards/Frequency_Response.html.
Arrested Frequency Response
There is another measure of Frequency Response that is of interest when developing a
Frequency Response estimate that not only will be used for estimating the Frequency Bias
Setting, but will also be used to assure reliability by operating in a manner that will bound
interconnection frequency and prevent the operation of Under-frequency Relays. This
Frequency Response Measure has recently been named “arrested frequency response.” This
Frequency Response is significantly affected by the inertial Frequency Response, the governor
Frequency Response and the time delays associated with the delivery of governor Frequency
Response. It is calculated by using the change in frequency between the initial frequency, A,
14
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003152
and the maximum frequency change during the event, C, instead of using the change between
A and B. Arrested Frequency Response is the correct response for determining the minimum
Frequency Response related to under-frequency relay operation and the support of
interconnection reliability. This is because it can be used to provide a direct estimate of the
maximum frequency deviation an interconnection will experience for an initial frequency and a
given size event in MW. Unfortunately, arrested frequency response cannot currently be
measured using the existing EMS-based measurement infrastructure. This limitation exists
because the scan rates currently used in industry EMSs are incapable of measuring the net
actual interchange at the same instant that the maximum frequency deviation is reached.
Fortunately, the ratio of arrested frequency response and settled frequency response tends to
be stable on an interconnection. This allows the settled frequency response value to be used as
a surrogate for the arrested frequency response and implement a reasonable measure upon
which to base a standard. One consequence of using the settled frequency response as a
surrogate for the arrested frequency response is the inclusion of a large reliability margin in
Interconnection Frequency Response Obligation to allow for the difference between the settled
frequency response as measured and the arrested frequency response that indicates reliability.
As measurement infrastructure improves one might expect the Frequency Response Obligation
to transition to a measurement based directly on the arrested frequency response while the
Frequency Bias Setting will continue to be based on the settled frequency response. However,
at this time, the measurement devices and methods in use do not support the necessary level
of accuracy to estimate arrested frequency response contribution for an individual Balancing
Authority.
Frequency Response Definition and Examples
Limitations of the measurement infrastructure determine the measurement methods
recommended in this standard. The measurement limitations provide opportunities to improve
the Frequency Response as measured in the standard without contributing to an improvement
in Frequency Response that contributes to reliability. These definitions and examples provide a
basis for determining which contributions to Frequency Response contribute the most to
improved reliability. They also provide the basis for determining on a case by case basis
whether the individual contributors to the Frequency Response Measure are also contributing
to reliability.
General Frequency Response Characteristics
In the simplest case Frequency Response includes any automatic response to changes in local
frequency. If that response works to decrease that change in frequency, it is beneficial to
reliability. If that response works to increase that change in frequency, it is detrimental to
reliability. However, this definition does not address the relative value of one response as
compared to other responses that may be provided in a specific case.
There are numerous characteristics associated with the Frequency Response that affect the
reliability value and economic value of the response. These characteristics include:
1. Inertial – the response is inertial or approximates inertial response
Inertial response provides power without delay that is proportional to the frequency
and the change in frequency. Therefore, power provided by electronic control as
15
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003153
synthetic inertial response must be proportional to the frequency and change in
frequency and be provided without a time delay.
2. Immediate – no unnecessary intentional time delays or reduction in the rate of
response delivery
a. time delay before the beginning of the response
Turbines that convert heat or kinetic energy have time delays related to the time
delay from the time that the control valves are moved to initiate the change in
power and the time that the power is delivered to the generator. These times
are usually associated with the time it takes a change in mass flow to travel from
the control valve to the first blades of the turbine in the turbine generator.
b. reduction in the rate of response delivery
There are natural delays associated with the rate of response delivery that are
related to the mass flow travel from the first turbine blades to the last turbine
blades. In addition, some turbines have intentional delays designed into the
control system to slow the rate of change in the delivery of the kinetic energy or
fuel to the turbine to prevent the turbine or other equipment from being
damaged, hydro turbines, or to prevent the turbine from tripping due to
excessive rate of change, gas turbines.
3. Proportional – the amount of the total response is proportional to the frequency error
a. No Deadband – the response is proportional across the entire frequency range
b. Deadband – the response is only proportional outside of a defined deadband
4. Bi-directional – the response occurs to both increases and decreases in frequency
5. Continuous – there are no discontinuities in the delivery of the response (no step
changes)
6. Sustained – the response is sustained until frequency is returned to schedule
Frequency Response Reliability Value
This section contains a more detailed discussion of the various characteristics of Frequency
Response listed in the previous section. It also provides an indication of the relative value of
these characteristics with respect to their contribution to reliability. Finally, it includes some
examples of the described responses.
Inertial Response is provided from the stored energy in the rotating mass of the turbinegenerators and synchronous motors on the interconnection. It limits the rate of change of
frequency until sufficient Frequency Response can be supplied to arrest the change in
frequency. Its reliability value increases as the time delay associated with the delivery of other
Frequency Response on the interconnection increases. If those time delays are minimal, then
the value of inertial response is low. If all time delays associated with the Frequency Response
could be eliminated, then inertial response would have little value.
The reliability value of Inertial Response is the greatest on small interconnections because the
size of the Disturbance events is larger relative to the inertia of the interconnection. Electronic
16
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003154
controls have been developed to provide synthetic inertial response from the stored energy in
asynchronous generators to supplement the natural inertial response. Some Type III & IV Wind
Turbines have this capability. In addition, electronically controlled SCRs have been developed
that can store energy in the electrical system and release this stored energy to supply synthetic
inertial response when required.
Immediate Response is provided by load damping and because the time delays associated with
its delivery are very short (related to the speed of electrical signal in the electrical system); load
damping requires very little inertial response to limit arrested frequency effectively. Synthetic
immediate response can also be supplied from loads because in many cases, there is no mass
flow time delay associated with the load process providing the power and energy reduction.
Therefore, loads can provide an immediate response with a higher reliability value than
generators with time delays required by the physics of the turbine-generator.
Governor response has time delays associated with its delivery. Governor response provided
with shorter time delays has a higher reliability value because those shorter time delays require
less inertial response to arrest frequency. Governor response is provided by the turbinegenerators on the interconnection. Time delays associated with governor response vary
depending on the type of turbine-generator providing the response.
The longest time delays are usually associated with high head hydro turbine-generators that
require long times from the governor action until the additional mass flow through the turbine.
These units may also have the longest delivery time associated with the full delivery of
response because of the timing designed into the governor response.5
Intermediate time delays are usually associated with steam turbine-generators. The response
begins when the steam control valves are adjusted and the steam mass flows from the valves to
the first high pressure turbine blades. The delivery times associated with the full delivery of
response may require the steam to flow through high, intermediate and low pressure turbines
including reheat flows before full power is delivered. These times are shorter than those of the
hydro turbine-generators in general, but not as fast as the times associated with gas turbines.6
Gas turbines typically have the shortest time delays, because control is provided by injecting
more or less fuel into the turbine combustor and adjusting the air control dampers. These
control changes can be initiated rapidly and the mass flow has the shortest path to the turbine
blades. There may be timing limitations related to the rate of change in output of the gas
turbine-generator to maintain flame stability in some cases slowing the rate of change.7
5
6
7
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-6 – 1-9.
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-4 – 1-6.
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-16 – 1-19.
17
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003155
Synthetic Governor Response can be supplied by certain loads and storage systems. The
immediacy of the response is normally limited only by the electronic controls used to activate
the desired response. Synthetic response, when it can be supplied immediately without
significant time delay, has a higher reliability value because it requires less inertial response to
achieve smaller arrested frequency deviations.
Proportional Response indicates that the response provided is proportional in magnitude to
the frequency error. Response deadbands cause a non-proportional response and reduce the
value of the response with respect to reliability. Contrary to general consensus, deadbands do
not reduce the amount of Frequency Response that must be provided, they only transfer the
responsibility for providing that Frequency Response from one source on the interconnection to
another. For a given response, the response with the smaller deadband has the greater
reliability value. Therefore, deadbands should be set to the smallest value that supports overall
reliable operation including the reliable operation of the generator.
Electronic controls have also been developed to provide synthetic governor response. When
these controls are applied to certain loads or stored energy systems, they can be programmed
to provide synthetic governor response similar to the proportional response of a turbinegenerator governor. Governor response in generators is limited to a small percentage of the
output of the generating unit, while synthetic governor response could be applied to much
larger percentages of loads or storage devices providing such response.
Load damping provides a proportional response.
Continuous Response is response that has no discontinuous (step) changes in the frequency
versus response curve. Step changes (Non-continuous Response) in the Governor Response
curve can lead to frequency instabilities at frequencies near the changes. The ERCOT
Interconnection observed this and has since prohibited the use of governor response
characteristics incorporating step responses.
Step responses also occur with the implementation of load interruption using under-frequency
or over-frequency relays.
Bi-directional Response is response that occurs in both directions, when the frequency is
increasing and when the frequency is decreasing. A uni-directional response is a response that
only occurs once when frequency is decreasing or when frequency is increasing.
Inertial response, governor response and load damping are all bi-directional responses. Certain
loads are capable of providing proportional bi-directional response while others are only
capable of providing non-proportional bi-directional response.
The ERCOT Load Resource program is a uni-directional response program. Loads are only
tripped when frequency declines below a given set-point. When frequency is restored above
that set-point, the loads must be manually reconnected. As a consequence, the Frequency
Response only occurs once with declining frequency and does not oppose the increase in
frequency after the initial decline. If there should be a frequency oscillation, the uni-directional
response will not contribute to the opposition of a second frequency decline across the set18
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003156
point during an oscillation event. Once a uni-directional response has occurred, it is unavailable
for a second decline before reset.
Step or proportional responses implemented bi-directionally can lead to frequency instability
when there is less continuous frequency response than the magnitude of the change in
continuous response between the trip and reset frequencies in step, or the proportional
response rate of change is greater than the underlying continuous response. A step bidirectional response will have the load reconnected as frequency recovers from the event thus
opposing the increase in frequency during recovery, and also resetting the load response for
the next frequency decline automatically. Bi-directional response obviously has a greater
reliability value than uni-directional response.
Sustained Response is provided at its full value until frequency is restored to its scheduled
value. On today’s interconnections, few frequency responses are fully sustained until
frequency has been restored to its scheduled value. On steam based turbine-generators, the
steam pressure may drop after a time as the result of the additional steam flow from governor
action. However, in general this has not been a problem because most responses are
incomplete at the time that frequency has been initially arrested and the additional response
has generally been sufficient to make up for more than the these unpreventable reductions in
response. However, the intentional withdrawal of response before frequency has been
restored to schedule can cause a decline in frequency beyond that which would be otherwise
expected. This intentional withdrawal of response is highly detrimental to reliability.
Therefore, it can be concluded in general that sustained response has a higher reliability value
than un-sustained response.
On an interconnection, the withdrawal of response due to the loss of steam pressure on the
steam units may be offset by the slower response of hydro turbine-generators. In these cases,
the reliability of the combined response provides greater reliability value than the individual
response of each type. The steam turbine-generators provide a fast response that may be
reduced, while the hydro turbine-generators provide a slower response, contributing less to the
arresting response, offsetting any reduction by the steam turbine-generators to assure a
sustained response.
Sustained Response must also be considered for any resource that has a limited duration
associated with its response. The amount of stored energy available from a resource may limit
its ability to sustain response for a duration of time necessary to support reliability.
Frequency Response Cost Factors
In every system of exchange there are two sides; the supply side and the demand side. The
supply side provides the services used by the demand side. In the case of Frequency Response,
the supply side includes all providers of Frequency Response and the demand side includes all
participants that create the need for Frequency Response.
Frequency Response Costs – Supply Side
There are a number of factors that affect the cost of providing Frequency Response from
resources. Since there is a cost associated with those factors, some method of appropriate
compensation could be made available to those resources providing Frequency Response.
19
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003157
Without compensation, providers of Frequency Response will be put in the position of incurring
additional cost that can be avoided only by reducing or eliminating the response they provide.
These costs are incurred independently of whether provided for in a formal Regional
Transmission Organization/Independent System Operator (RTO/ISO) market or in a traditional
BA subject to the FERC pro-forma tariffs.
It is the responsibility of the BA or the RTO/ISO to acquire the necessary amount of Frequency
Response to support reliability in the most cost effective manner. This function is performed
best when the suppliers are evaluated based on the value of the Frequency Response they
provide and compensated appropriately for that Frequency Response. Suppliers provide
Frequency Response when they are assured that they will receive fair compensation. Before
considering how to perform this evaluation and compensation, the costs associated with
providing Frequency Response should be understood and evaluated with respect to the level of
reliability they offer.
Some cost factors that have been identified for providing Frequency Response include:
1. Capacity Opportunity Cost – the costs, including opportunity costs, associated with
reserving capacity to provide Frequency Response. These costs are usually associated
with the alternative use of the same capacity to provide energy or other ancillary
services. There may also be capacity opportunity costs associated with the loss in
average capacity by a load providing Frequency Response.
2. Fuel Cost – The cost of fuel used to provide the Frequency Response. The costs for fuel
to provide Frequency Response can result in energy costs significantly different from the
system marginal energy cost, both higher and lower. This is the case when Frequency
Response is provided by resources that are not at the system marginal cost.
3. Energy Efficiency Penalty Costs – the costs associated with the loss in efficiency when
the resource is operated in a mode that supports the delivery of Frequency Response.
This cost is usually in the form of additional fuel use to provide the same amount of
energy. An example is the difference between operating a steam turbine in valve
control mode with an active governor and sliding pressure mode with valves wide open
and no active governor control except for over-speed. This cost is incurred for all of the
energy provided by the resource, not just the energy provided for Frequency Response.
There may be additional energy costs associated with a load providing Frequency
Response from loss in efficiency of their process when load is reduced.
4. Capacity Efficiency Penalty Costs – the costs associated with any reduction in capacity
resulting from the loss of capacity associated with the loss in energy efficiency. When
efficiency is lost, capacity may be lost at the same time because of limitations in the
amount of input energy that can be provided to the resource.
5. Maintenance Costs – the operation of the resource in a manner necessary to provide
Frequency Response may result in increases in the maintenance costs associated with
the resource.
6. Emissions Costs – the additional costs incurred to manage any additional emissions that
result when the resource is providing Frequency Response or stands ready to provide
Frequency Response.
20
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003158
A good contract for the acquisition of Frequency Response from a resource will provide
appropriate compensation to the resource all of the costs the resource incurs to provide
Frequency Response. It will also provide a method to evaluate the least cost mix of resources
necessary to provide the minimum required Frequency Response for maintaining reliability.
Finally, it will provide the least complex method of evaluation considering the complexity and
efficiency of the acquisition process.
Frequency Response Costs – Demand Side
Not only are there costs associated with acquiring Frequency Response from the supplying
resources, there are costs associated with the amount of Frequency Response that must be
acquired and influenced by those participants that create the need for Frequency Response. If
the costs of acquiring Frequency Response from the supply resources can be assigned to those
parties that create the need for Frequency Response, there is the promise that the amount of
Frequency Response required to maintain reliability can be minimized. The considerations are
the same as those that are driving the development of “real time pricing” and “dynamic
pricing”. If the costs are passed on to those contributing to the need for Frequency Response,
incentives are created to reduce the need for Frequency Response making interconnection
operations less expensive and more reliable. The problem is to balance both cost and
complexity against reliability on both the supply side and the demand side.
21
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003159
Rationale by Requirement
Requirement 1
R1. Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more negative than its
Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each FRSG or Balancing Authority that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more negative than the Interconnection
Frequency Response Obligation.
Background and Rationale
R1 is intended to meet the following primary objectives:
• Determine whether a Balancing Authority (BA) has sufficient Frequency Response for
reliable operations.
• Provide the feeder information needed to calculate CPS limits and Frequency Bias
Settings.
Primary Objective
With regard to the first objective, FRS Form 1 and the process in Attachment A provide the
method for determining the Interconnections’ necessary amount of Frequency Response and
allocating it to the Balancing Authorities. The field trial for BAL-003-1 is testing an allocation
methodology based on the amount of load and generation in the BA. This is to accommodate
the wide spectrum of BAs from generation-only all the way to load-only.
Frequency Response Sharing Groups (FRSGs)
This standard proposes an entity called FRSG, which is defined as:
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to
jointly meet the sum of the Frequency Response Obligations of its members.
This standard allows Balancing Authorities to cooperatively form FRSGs as a means to jointly
meet the FRS. There is no obligation to form or be a part of FRSGs. The members of the FRSG
would determine how to allocate sanctions among its members. This standard does not
mandate the formation of FRSGs, but allows them as a means to meet one of FERC’s Order No.
693 directives.
FRSG performance may be calculated one of two ways:
Calculate a group NIA and measure the group response to all events in the reporting
year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each
participant’s individual event performance.
22
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003160
Frequency Response Obligation and Calculation
The basic Frequency Response Obligation is based on non-coincident peak load and generation
data reported in FERC Form 714 (where applicable, see below for non-jurisdictional entities) for
the previous full calendar year. The basic allocation formula used by NERC is:
Where:
Annual GenBA is the annual “Net Generation (MWh)”, FERC Form 714, line 13, column c
of Part II - Schedule 3.
Annual LoadBA is the annual “Net Energy for Load (MWh)”, FERC Form 714, line 13,
column e of Part II - Schedule 3.
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to
assemble and submit equivalent data. Until the BAL-003-1 process outlined in Attachment 1 is
implemented, Balancing Authorities can approximate their FRO by multiplying their
Interconnection’s FRO by their share of Interconnection Bias. The data used for this calculation
should be for the most recently filed Form 714. As an example, a report to NERC in January
2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that merge or that transfer load or generation need to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation for
the Interconnection remains the same and so that CPS limits can be adjusted.
Attachment A proposes the following Interconnection event criteria as a basis to determine an
Interconnection’s Frequency Response Obligation:
Largest category C loss-of-resource (N-2) event.
Largest total generating plant with common voltage switchyard.
Largest loss of generation in the interconnection in the last 10 years.
With regard to the second objective above (determining Frequency Bias Settings and CPS
limits), Balancing Authorities have been asked to perform annual reviews of their Frequency
Bias Settings by measuring their Frequency Response, dating back to Policy 1. This obligation
was carried forward into BAL-003-01.b. While the associated training document provided
useful information, it left many of the details to the judgment of the person doing the analysis.
The FRS Form 1 and FRS Form 2 provide a consistent, objective process for calculating
Frequency Response to develop an annual measure, the FRM.
23
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003161
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as:
“the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz”. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change of its net
actual interchange on its tie lines with its adjacent Balancing Authorities divided by the change
in interconnection frequency. (Some Balancing Authorities may choose to apply corrections to
their net actual interchange values to account for factors such as nonconforming loads. FRS
Form 1 shows the types of adjustments that are allowed.)
A standardized sampling interval of approximately 20 to 52 seconds will be used in the
computation of SEFRD values. Microsoft Excel® spreadsheet interfaces for EMS scan rates of 2
through 6 seconds are provided to support the computation.
Single Event Frequency Response Data8
The use of a “single event measure” was considered early in the development of the FRS for
compliance because a single event measure could be enforced for each event on the
interconnection making compliance enforcement a simpler process. The variability of the
measurement of Frequency Response for an individual BA for an individual Disturbance event
was evaluated to determine its suitability for use as a compliance measure. The individual
Disturbance events were normalized and plotted for each BA on the Eastern and Western
Interconnections. This data was plotted with a dot representing each event. Events with a
measured Frequency Response above the FRO were shown as blue dots and events with a
measured Frequency Response below the FRO were shown as red dots. In order to show the
full variability of the results the plots have been provide with two scales, a large scale to show
all of the events and small scale to show the events closer to the FRO or a value of 1.0. This
data is presented on four charts titled Frequency Response Events as Normalized by FRO.
Analysis of this data indicates a single event based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in these charts.
Based on the field trial data provided, only 3 out of 19 BAs on the Western Interconnection
would be compliant for all events with a standard based on a single event measure. Only 1 out
of 31 BAs on the Eastern Interconnection would be compliant for all events with a standard
based on a single event measure. The general consensus of the industry is that there is not a
reliability issue with insufficient Frequency Response on any of the North American
Interconnections at this time. Therefore, it is unreasonable to even consider a standard that
would indicate over 90% of the BAs in North American to be non-compliant with respect to
maintaining sufficient Frequency Response to maintain adequate reliability.
In an attempt to balance the workload of Balancing Authorities with the need for accuracy in
the FRM, the standard will require at least 20 samples selected during the course of the year to
compute the FRM. Research conducted by the FRSDT indicated that a Balancing Authority’s
FRM will converge to a reasonably stable value with at least 20 samples.
8
Single Event Analysis based on results of Frequency Response Standard Field Trial Analysis, September 17, 2012.
24
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003162
Frequency Response Events as Normalized by FRO
Eastern Interconnection - 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
-25.0
32
31
30
29
28
27
26
25
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
-50.0
Balancing Authority
25
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003163
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
-5.0
-10.0
-15.0
-20.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-25.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-10.0
Balancing Authority
26
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003164
Sample Size
In order to support field trial evaluations of sample size, sampling intervals, and aggregation
techniques, the FRSDT will be retrieving scan rate data from the Balancing Authorities for each
SEFRD. Additional frequency events may also be requested for research purposes, though they
will not be included in the FRM computation.
FERC Order No. 693 directed the ERO (at P 375) to define the number of Frequency Response
surveys that were conducted each year and to define a necessary amount of Frequency
Response. R1 addresses both of these directives:
There is a single annual survey of at least 20 events each year.
The FRM calculated on FRS Form 1 is compared by the ERO against the FRO determined
12 months earlier (when the last FRS Form 1 was submitted) to verify the Balancing
Authority provided its share of Interconnection Frequency Response.
Median as the Standard’s Measure of Balancing Authority Performance
The FRSDT evaluated different approaches for “averaging” individual event observations to
compute a technically sound estimate of Frequency Response Measure. The MW contribution
for a single BA in a multi-BA Interconnection is small compared to the minute to minute
changes in load, interchange and generation. For example, a 3000 MW BA in the east may only
be called on to contribute 10MW for the loss of a 1000MW. The 10 MW of governor and load
response may easily be masked as a coincident change in load.
In general, statisticians use the median as the best measure of central tendency when a
population has outliers. Two independent reviews by the FRSDT has shown the Median to be
less influenced by noise in the measurement process and the team has chosen the median as
the initial metric for calculating the BAs’ Frequency Response Measure.
The FRSDT performed extensive empirical studies and engaged in lively discussions in an
attempt to determine the best aggregation technique for a sample set size of at least 20 events.
Mean, median, and linear regression techniques were used on a trial basis with the data that
was available during the early phases of the effort.
A key characteristic of the “aggregation challenge” is related to the use of actual net
interchange data for measuring frequency response. The tie line flow measurements are
varying continuously due to other operational phenomena occurring concurrently with the
provision of frequency response. (See Appendix 1 for details.) All samples have “noise” in
them, as most operational personnel who have computed the frequency response of their BA
can attest. What has also become apparent to the FRSDT is that while the majority of the
frequency response samples have similar levels of noise in them, a few of the samples may
have much larger errors in them than the others that result in unrepresentative results. And
with the sample set size of interest, it is common to have unrepresentative errors in these few
samples to be very large and asymmetric. For example, one BA’s subject matter expert
observed recently that 4 out of 31 samples had a much larger error contribution than the other
27 samples, and that 3 out of 4 of the very high error samples grossly underestimated the
frequency response. The median value demonstrated greater resiliency to this data quality
problem than the mean with this data set. (The median has also demonstrated superiority to
27
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003165
linear regression in the presence of these described data quality problems in other analyses
conducted by the FRSDT, but the linear regression showed better performance than the mean.)
The above can be demonstrated with a relatively simple example. Let’s assume that a
Balancing Authority’s true frequency response has an average value of -200 MW/ .1 Hz. Let’s
also assume that this Balancing Authority installed “special” perfect metering on key loads and
generators, so that we could know the true frequency response of each sample. And then we
will compare them with that measured by typical tie line flow metering, with the kind of noise
and error that occurs commonly and “not so commonly”. Let’s start with the following 4
samples having a common level of noise, with MW/ .1 Hz as the unit of measurement.
Perfect measurement
-190
-210
-220
-180
-200
-200
Noise
-30
-20
10
20
Mean
Median
Samples from tie lines
-220
-230
-210
-160
-205
-215
Now let’s add a fifth sample, which is highly contaminated with noise and error that grossly
underestimates frequency response.
Perfect measurement
-190
-210
-220
-180
-200
-200
-200
Noise
-30
-20
10
20
250
Mean
Median
Samples from tie lines
-220
-230
-210
-160
+50
-154
-210
It is clear from the above simplistic example that the mean drops by about 25% while the
median is affected minimally by the single highly contaminated value.
Based on the analyses performed thus far, the FRSDT believes that the median’s superior
resiliency to this type of data quality problem makes it the best aggregation technique at this
time. However, the FRSDT sees merit and promise in future research with sample filtering
combined with a technique such as linear regression.
When compared with the mean, linear regression shows superior performance with respect to
the elimination of noise because the measured data is weighted by the size of the frequency
change associated with the event. Since the noise is independent from frequency change, the
greater weighting on larger events provides a superior technique for reducing the effect of
noise on the results.
However, linear regression does not provide a better method when dealing with a few samples
with large magnitudes of noise and unrepresentative error. There are only two alternatives to
improve over the use of median when dealing with these larger unrepresentative errors:
1. Increase the sample size, or
2. Actively eliminate outliers due to unrepresentative error.
28
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003166
Unfortunately, the first alternative, increasing the sample size is not available because
significantly more sample events are not available within the measurement time period of one
year. Linear regression techniques are being investigated that have an active outlier
elimination algorithm that would eliminate data that lie outside ranges of the 96th percentile
and 99th percentile, for example.
Still, the use of linear regression has value in the context of this standard. The NERC Resources
Subcommittee will use linear regression to evaluate Interconnection frequency response,
particularly to evaluate trends, seasonal impacts, time of day influences, etc. The Good
Practices and Tools section of this document outlines how a BA can use linear regression to
develop a predictive tool for its operators.
Additional discussion on this topic is contained in “Appendix 1 – Data Quality Concerns Related
to the Use of Actual Net Interchange Value” of this document.
The NERC Frequency Response Initiative Report addressed the relative merits of using the
median versus linear regression for aggregating single event frequency response samples into a
frequency response measurement score for compliance evaluation. This report provided 11
evaluation criteria as a basis for recommending the use of linear regression instead of the
median for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but concluded
that the median would be the best aggregation technique to use initially when the relative
importance of each criterion was considered. A brief summary of the FRSDT majority
consensus on the basis of each evaluation criterion is provided below.
Provides two dimensional measurement – The FRSDT agrees that the two dimensional
concept is a useful way to perceive frequency response characteristics, and that it may
be useful for potential future modeling activities. Better data quality would increase
support for such future efforts, and the use of the median for initial compliance
evaluations within BAL-003-1 should not hinder any such effort. The FRSDT perceived
this as a mild advantage for linear regression.
Represents nonlinear characteristics – With considerations similar to those applied to
the previous criterion, the FRSDT perceived this as a mild advantage for linear
regression.
Provides a single best estimator – The FRSDT put gave minimal importance to the
characteristic of the median averaging the middle values when used with an even
number of samples.
Is part of a linear system - With considerations similar to those applied to the first two
criteria, the FRSDT perceived this as a mild advantage for linear regression (particularly
in the modeling area.)
Represents bimodal distributions – The FRSDT put minimal weight of this criterion, as a
change in Balancing Authority footprint does not seem to be addressed adequately by
any aggregation technique.
Quality statistics available – The FRSDT perceived this as a mild advantage for linear
regression in that the statistics would be coupled directly to the compliance evaluation.
The FRSDT also included this criterion as part of the modeling advantages cited above.
29
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003167
The FRSDT supports collecting data and performing quality statistical analysis. If it is
determined that the use of the median, as opposed to a mean or linear regression
aggregation, is yielding undesirable consequences, the FRSDT recommends that other
aggregation techniques be re-evaluated at that time.
Reducing influence of noise - This is the dominant concern of the FRSDT, and it
perceives the median to have a major advantage over linear regression in addressing
noise in the change in actual net interchange calculation. The FRSDT bases this
judgment on: prior FRSDT studies that have shown that the median produces more
stable results; the data used in the NERC Frequency Response Initiative document
exhibits large quantities of noise; prior efforts of FRSDT members in performing
frequency response sampling for their own Balancing Authorities over many years; and
similar observations of noise in the CERTS frequency Monitoring Application. The
FRSDT has serious concerns that the influence of noise has a greater tendency to yield a
“false positive” compliance violation with linear regression than with the median. Also,
limited studies performed by the FRSDT indicates the possibility that the resultant
frequency response measure would yield more measurement variation across years
with linear regression versus the median while the actual Balancing Authority
performance remains unchanged.
Reducing the influence of outliers – This is related to the previous criterion. The FRSDT
recognizes four main sources of noise: concurrent operating phenomena (described
elsewhere in this document), transient tie line flows for nearby contingencies, data
acquisition time skew in tie line data measurements, and time skew and data
compression issues in archiving techniques and tools such as PI. Some outliers may be
caused in part by true variation in the actual frequency response, and it is desirable to
include those in the frequency response measure. The FRSDT supports efforts in the
near future to distinguish between outliers caused by noise versus true frequency
response, and progress in this area may make it feasible and desirable to replace the
median with linear regression, or some other validated technique. The FRSDT does
note that this is a substantial undertaking, and it would require substantial input from a
sufficient number of experts to help distinguish noise from true frequency response.
Easy to calculate – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made in noise elimination.
Familiar indicator – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made as a result of noise elimination.
Currently used as a measure in BAL-003 – The present standard refers to an average
and does not provide specific guidance on the computation of that average, but the
FRSDT puts minimal weight on this evaluation criterion.
In summary, the FRSDT perceives an approximate balance between the modeling advantage for
linear regression and the simplicity advantage of the median. However, the clear determinant
in endorsing the use of the median is the data quality issue related to concurrent operational
phenomena, transient tie line flows, and data acquisition and archiving limitations.
30
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003168
FERC Order No. 693 also directed the Standard (at P 375) to identify methods for Balancing
Authorities to obtain Frequency Response. Requirement R1 allows Balancing Authorities to
participate in Frequency Response Sharing Groups (FRSGs) to provide or obtain Frequency
Response. These may be the same FRSGs that cooperate for BAL-002-0 or may be FRSGs that
form for the purposes of BAL-003-1.
If BAs participate as an FRSG for BAL-003-1, compliance is based on the sum of the participants’
performance.
Two other ways that BAs could obtain Frequency Response are through Supplemental Service
or Overlap Regulation Service:
No special action is needed if a BA provides or receives supplemental regulation. If the
regulation occurs via Pseudo Tie, the transfer occurs automatically as part of Net Actual
Interchange (NIA) and in response to information transferred from recipient to
provider.
If a BA provides overlap regulation, its FRS Form 1 will include the Frequency Bias
setting as well as peak load and generation of the combined Balancing Authority Areas.
The FRM event data will be calculated on the sum of the provider’s and recipient’s
performance.
In the Violation Severity Levels for Requirement R1, the impact of a BA not having enough
frequency response depends on two factors:
Does the Interconnection have sufficient response?
How short is the BA in providing its FRO?
The VSL takes these factors into account. While the VSLs look different than some other
standards, an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is
intended to measure a violation’s impact on reliability and thus levy an appropriate sanction.
Frequency Response is an interconnection-wide resource. The proposed VSLs are intended to
put multi-BA Interconnections on the same plane as single-BA Interconnections.
Consider a small BA whose performance is 70% of its FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability,
yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection
that had insufficient Frequency Response, because this would treat multi-BA Interconnections
more harshly than single BA Interconnections on a significant scale.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and
Severe VSLs say the Interconnection does not meet the FRO and assesses sanctions based on
whether the BA is deficient by a small or larger amount respectively.
31
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003169
Requirement 2
R2. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined subject to Attachment A, as
validated by the ERO, into its Area Control Error (ACE) calculation during the implementation
period specified by the ERO.
Background and Rationale
Attachment A of the Standard discusses the process the ERO will follow to validate the BA’s FRS
Form 1 data and publish the official Frequency Bias Settings. Historically, it has taken multiple
rounds of validation and outreach to confirm each BA’s data due to transcription errors,
misunderstanding of instructions, and other issues. While BAs historically submit Bias Setting
data by January 1, it often takes one or more months to complete the process.
The target is to have BAs submit their data by January 10. The BAs are given 30 days to
assemble their data since the BAs are dependent on the ERO to provide them with FRS Form 1,
and there may be process delays in distributing the forms since they rely on identification of
frequency events through November 30 of the preceding year.
Frequency Bias Settings generally change little from year to year. Given the fact that BAs can
encounter staffing or EMS change issues coincident with the date the ERO sets for new
Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date.
To recap the annual process:
1. The ERO posts the official list of frequency events to be used for this Standard in early
December. The FRS Form 1 for each Interconnection will be posted shortly thereafter.
2. The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3. The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, The ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which
to implement revised Frequency Bias Setting values. Implementation typically would be
on or about March 1st of each year.
BAL-003-0.1b standard requires a minimum Frequency Bias Setting equal in absolute value to
one percent of the Balancing Authority’s estimated yearly peak demand (or maximum
generation level if native load is not served). For most Balancing Authorities this calculated
amount of Frequency Bias is significantly greater in absolute value than their actual Frequency
Response characteristic (which represents an over-bias condition) resulting in over-control
32
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003170
since a larger magnitude response is realized. This is especially true in the Eastern
Interconnection where this condition requires excessive secondary frequency control response
which degrades overall system performance and increases operating cost as compared to
requiring an appropriate balance of primary and secondary frequency control response.
Balancing Authorities were given a minimum Frequency Bias Setting obligation because there
had never been a mandatory Frequency Response Obligation. This historic “one percent of
peak per 0.1Hz” obligation, dating back to NERC’s predecessor, NAPSIC, was intended to ensure
all BAs provide some support to Interconnection frequency.
The ideal system control state exists when the Frequency Bias Setting of the Balancing
Authority exactly matches the actual Frequency Response characteristic of the Balancing
Authority. If this is not achievable, over-bias is significantly better from a control perspective
than under-bias with the caveat that Frequency Bias is set relatively close in magnitude to the
Balancing Authority actual Frequency Response characteristic. Setting the Frequency Bias to
better approximate the Balancing Authority natural Frequency Response characteristic will
improve the quality and accuracy of ACE control, CPS & DCS and general AGC System control
response. This is the technical basis for recommending an adjustment to the long standing “1%
of peak/0.1Hz” Frequency Bias Setting. The Procedure for ERO Support of Frequency
Response and Frequency Bias Setting Standard is intended to bring the Balancing
Authorities’ Frequency Bias Setting closer to their natural Frequency Response. Procedure for
ERO Support of Frequency Response and Frequency Bias Setting Standard balances the
following objectives:
•
Bring the Frequency Bias Setting and Frequency Response closer together.
•
Allow time to analyze impact on other Standards (CPS, BAAL and to a lesser extent DCS)
by adjustments in the minimum Frequency Bias Setting, by accommodating only minor
adjustments.
•
Do not allow the Frequency Bias Setting minimum to drop below natural Frequency
Response, because under-biasing could affect an Interconnection adversely.
Additional flexibility has been added to the Frequency Bias Setting based on the actual
Frequency Response (FRM) by allowing the Frequency Bias Setting to have a value in the range
from 100% of FRM to 125% of FRM. This change has been included for the following reasons:
•
33
When the new standardized measurement method is applied to BAs with a Frequency
Response close to the interconnection minimum response, the requirement to use FRM
is as likely to result in a Frequency Bias Setting below the actual response as it is to
result in a response above the actual response. From a reliability perspective, it is
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003171
always better to have a Frequency Bias Setting slightly above the actual Frequency
Response.
•
As with single BA interconnections, the tuning of the control system may require that
the BA implement a Frequency Response Setting slightly greater in absolute terms than
its actual Frequency Response to get the best performance.
•
The new standardized measurement method for determining FRM in some cases results
in a measured Frequency Response significantly lower than the previous methods used
by some BAs. It is desirable to not require significant change in the Frequency Bias
Setting for these BAs that experience a reduction in their measured Frequency
Response.
Requirement 3
R3. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
Less than zero at all times, and
Equal to or more negative than its Frequency Response Obligation when the Frequency
varies from 60 Hz by more that +/- 0.036 Hz.
Background and Rationale
In multi-Balancing Authority interconnections, the Frequency Bias Setting should be
coordinated among all BAs on the interconnection. When there is a minimum Frequency Bias
Setting requirement, it should apply for all BAs. However, BAs using a variable Frequency Bias
Setting may have non-linearity in their actual response for a number of reasons including the
dead-bands implemented on their generator governors. The measurement to ensure that
these BAs are conforming to the interconnection minimum is adjusted to remove the deadband range from the calculated average Frequency Bias Setting actually used. For BAs using
variable bias, FRS Form 1 has a data entry location for the previous year’s average monthly Bias.
The Balancing Authority and the ERO can compare this value to the previous year’s Frequency
Bias Setting minimum to ensure R3 has been met.
On single BA interconnections, there is no need to coordinate the Frequency Bias Setting with
other BAs. This eliminates the need to maintain a minimum Frequency Bias Setting for any
reason other than meeting the reliability requirement as specified by the Frequency Response
Obligation.
Requirement 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias Setting for
the combined Balancing Authority Area, to be equivalent to either:
34
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003172
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting as shown on FRS Form 1 and FRS Form 2 for the entirety of
the participating Balancing Authorities’ Areas.
Background and Rationale
This requirement reflects the operating principles first established by NERC Policy 1 and is
similar to Requirement R6 of the approved BAL-003-0.1b standard. Overlap Regulation Service
is a method of providing regulation service in which the Balancing Authority providing the
regulation service incorporates another Balancing Authority’s actual interchange, frequency
response, and schedules into the providing Balancing Authority’s AGC/ACE equation.
As noted earlier, a BA that is providing Overlap Regulation will report the sum of the Bias
Settings in its FRS Form 1. Balancing Authorities receiving Overlap Regulation Service have an
ACE and Frequency Bias Setting equal to zero (0).
35
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003173
How this Standard Meets the FERC Order 693
Directives
FERC Directive
The following is the relevant paragraph of Order No. 693.
Accordingly, the Commission approves Reliability Standard BAL-003-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a modification to
BAL-003-0 through the Reliability Standards development process that: (1) includes
Levels of Non-Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other requirements of
the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) defines the necessary amount of Frequency Response needed for
Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.
1. Levels of Non-Compliance
VRFs and VSLs are an equally effective way of assigning compliance elements to the standard.
2. Determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other Requirements of
the Reliability Standard are met
BAL-003 V0 R2 (the basis of Order No. 693) deals with the calculation of Frequency Bias Setting
such that it reflects natural Frequency Response.
The drafting team has determined that a sample size on the order of at least 20 events is
necessary to have a high confidence in the estimate of a BA’s Frequency Response. Selection of
the frequency excursion events used for analysis will be done via a method outlined in
Attachment A to the Standard.
On average, these events will represent the largest 2-3 “clean” frequency excursions occurring
each month.
Since Frequency Bias Setting is an annual obligation, the survey of the at least 20 frequency
excursion events will occur once each year.
3. Define the necessary amount of Frequency Response needed for
Reliable Operation for each Balancing Authority with methods of
obtaining and measuring that the frequency response is achieved
Necessary Amount of Frequency Response
The drafting team has proposed the following approach to defining the necessary amount of
frequency response. In general, the goal is to avoid triggering the first step of under-frequency
load shedding (UFLS) in the given Interconnection for reasonable contingencies expected. The
36
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003174
methodology for determining each Interconnection’s and Balancing Authority’s obligation is
outlined in Attachment A to the Standard.
It should be noted the standard cannot guarantee there will never be a triggering of UFLS as the
magnitude of “point C” differs throughout an interconnection during a disturbance and there
are local areas that see much wider swings in frequency.
The contingency protection criterion is the largest reasonably expected contingency in the
Interconnection. This can be based on the largest observed credible contingency in the
previous 10 years or the largest Category C event for the Interconnection.
Attachment A to the standard presents the base obligation by Interconnection and adds a
Reliability Margin. The Reliability Margin included addresses the difference between Points B
and C and accounts for variables.
For multiple BA interconnections, the Frequency Response Obligation is allocated to BAs based
on size. This allocation will be based on the following calculation:
Methods of Obtaining Frequency Response
The drafting team believes the following are valid methods of obtaining Frequency Response:
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a
contractual share of Frequency Response from Adjacent Balancing Authorities. See FRS
Form 1. While the final rules with regard to contractual services are being defined, the
current expectation is that the ERO and the associated Region(s) should be notified
beforehand and that the service be at least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the
development of a NAESB business practice for Frequency Response service for linear
(droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service,
BAs and FRSGs may use whatever is most appropriate for their situation.
Measuring that the Frequency Response is Achieved
FRS Form 1 and the underlying data retained by the BA will be used for measuring whether
Frequency Response was provided. FRS Form 1 will provide the guidance on how to account for
and measure Frequency Response.
37
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003175
Going Beyond the Directive
Based on the combined operating experience of the SDT, the drafting team consensus is that
each Interconnection has sufficient Frequency Response. If margins decline, there may be a
need for additional standards or tools. The drafting team and the Resources Subcommittee are
working with the ERO on its Frequency Response Initiative to develop processes and good
practices so the Interconnections are prepared. These good practices and tools are described in
the following section.
The drafting team is also evaluating a risk-based approach for basing the Interconnection
Frequency Response Obligation on an historic probability density of frequency error, and for
allocating the obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error. This allocation method uses the inverse of the rationale for allocating the CPS1
epsilon requirement by Bias share.
38
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003176
Good Practices and Tools
Background
This section outlines tips and tools to help Balancing Authorities meet the Frequency Response
Standard or to operate more reliably. If you have suggested additions, please send them to
[email protected].
Identifying and Estimating Frequency Responsive Reserves
Knowing the quantity and depth of frequency responsive reserves in real time is a possible next
step to being better prepared for the next event. The challenge in achieving this is having the
knowledge of the capabilities of all sources of frequency response. Presently the primary
source of Frequency Response remains with the generation resources in our fleets.
Understanding how each of these sources performs to changes in system frequency and
knowing their limitations would improve the BA’s ability to measure frequency responsive
reserves. Presently there are only guidelines, criteria and protocols in some regions of the
industry that identify specific settings and performance expectations of Primary Frequency
Response of resources.
One method of gaining a better understanding of performance is to measure performance
during actual events that occur on the system. Measuring performance during actual events
would only provide feedback for performance during that specific event and would not provide
insight into depth of response or other limitations.
Repeated measurements will increase confidence in expected performance. NERC modeling
standards are in process to be revised that will improve the BA’s insight into predicting
available frequency responsive reserves. However, knowing how resources are operated, what
modes of operation provide sustained Primary Frequency Response and knowing the operating
range of this response would give the BA the knowledge to accurately predict frequency
response and the amount of frequency responsive reserves available in real time.
Some benefits have been realized by communicating to generation resources (GO) the
importance of operating in modes that allow Primary Frequency Response to be sustained by
the control systems of the resource. Other improvements in implementation of Primary
Frequency Response have been achieved through improved settings on turbine governors
through the elimination of “step” frequency response with the simultaneous reduction in
governor dead-band settings.
Improvements in the full AGC control loop of the generating resource, which accounts for the
expected Primary Frequency Response, have improved the delivery of quality Primary
Frequency Response while minimizing secondary control actions of generators. Some of these
actions can provide quick improvement in delivery of Primary Frequency Response.
39
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003177
Once Primary Frequency Response sources are known, the BA could calculate available reserves
that are frequency responsive. Planning for these reserves during normal and emergency
operations could be developed and added to the normal planning process.
Using FRS Form 1 Data
The information collected for this standard can be supplemented by a few data points to
provide the Balancing Authority useful tools and information. The BA could do a regression
analysis of its frequency response against the following values:
Load (value A).
Interchange (Value A).
Total generation.
Spinning reserve.
While the last two values above are not part of Form 1, they should be readily available. Small
BAs might even include headroom on its larger generators as part of the regression.
The regression would provide a formula the BA could program in its EMS to present the
operator a real time estimate of the BA’s Frequency Response.
Statistical outliers in the regression would point to cases meriting further inspection to find
causes of low Frequency Response or opportunities for improvement.
Tools
Single generating resource performance evaluation tools for steam turbine, combustion turbine
(simple cycle or combined cycle) and for intermittent resources are available at the following
link. http://texasre.org/standards_rules/standardsdev/rsc/sar003/Pages/Default.aspx.
These tools and the regional standard associated with them are in their final stages of
development in the Texas region.
These tools will be posted on the NERC website.
40
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003178
References
NERC Frequency Response Characteristic Survey Training Document (Found in the NERC
Operating Manual)
NERC Resources Subcommittee Position Paper on Frequency Response
NERC TIS Report Interconnection Criteria for Frequency Response Requirements (for the
Determination Interconnection Frequency Response Obligations (IFRO)
Frequency Response Standard Field Trial Analysis, September 17, 2012
41
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003179
Appendix 1 - Data Quality Concerns Related To The Use Of The
Actual Net Interchange Value
Actual net interchange for a typical Balancing Authority (BA) is the summation of its tie lines to
other BAs. In some cases, there are pseudo-ties in it which reflect the effective removal or
addition of load and/or generation from another BA, or it could include supplemental
regulation as well. But in the typical scenario, actual net interchange values that are extracted
from EMS data archiving can be influenced by data latency times in the data acquisition
process, and also any timestamp skewing in the archival process.
Of greater concern, however, are the inevitable variations of other operating phenomena
occurring concurrently with a frequency event. The impacts of these phenomena are
superimposed on actual net interchange values along with the frequency response that we wish
to measure through the use of the actual net interchange value.
To explore this issue further, let’s begin with the idealized condition:
frequency is fairly stable at some value near or a little below 60 Hz
ACE of the non-contingent BA of interest is 0 and has been 0 for an extended period,
and AGC control signals have not been issued recently
Actual net interchange is “on schedule”, and there are no schedule changes in the
immediate future
BA load is flat
All generators not providing AGC are at their targets
Variable generation such as wind and solar are not varying
Operators have not directed any manual movements of generation recently
And when the contingency occurs in this idealized state, the change in actual net interchange
will be measuring only the decline in load due to lesser frequency and generator governor
response, and, none of the contaminating influences. While the ACE may become negative due
to the actual frequency response being less than that called for by the frequency bias setting
within the BA’s AGC system, this contaminating influence on measuring frequency response will
not appear in the actual net interchange value if the measurement interval ends before the
generation on AGC responds.
Now let’s explore the sensitivity of the resultant frequency response sampling to the relaxation
of these idealized circumstances.
1. The “60 Hz load” increases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be reduced by the
moderate increase in load and the frequency response will be underestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be increased by the AGC response (and/or manual
adjustments) and the frequency response will be overestimated.
42
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003180
2. The “60 Hz load” decreases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be increased by the
moderate reduction in load and the frequency response will be overestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be decreased by the AGC response (and/or manual
adjustments) and the frequency response will be underestimated.
3. In anticipation of increasing load during the next hour, the operator increases manual
generation before the load actually appears. If the frequency event happens while the
generation “leading” the load is increasing, then the actual net interchange will be
increased by the increase in manual generation and the frequency response will be
overestimated. But if the frequency event occurs when the result of AGC signals sent to
offset the operator’s leading actions take effect, then the actual net interchange will be
decreased and the frequency response is underestimated.
4. In anticipation of decreasing load during the next hour, the operator decreases manual
generation before the load actually declines. If the frequency event happens while the
generation “leading” the load downward is decreasing, then the actual net interchange
will be decreased by the reduction in manual generation and the frequency response
will be underestimated. But if the frequency event occurs when the result of AGC
signals sent to offset the operator’s leading actions take effect, then the actual net
interchange will be increased and the frequency response is overestimated.
5. A schedule change to export more energy is made at 5 minutes before the top of the
hour. The BA’s “60 Hz load” is not changing. The schedule change is small enough that
the operator is relying on upward movement of generators on AGC to provide the
additional energy to be exported. The time at which the AGC generators actually begin
to provide the additional energy is dependent on how much time passes before the AGC
algorithm gets out of its deadbands, the individual generator control errors get large
enough for sending out the control signal, and maybe 20 seconds to 3 minutes for the
response to be effected. The key point here is that it is not clear when the effects of a
schedule change, as manifested in a change in generation and then ultimately a change
in actual net interchange, will occur.
6. With the expected penetration of wind in the near future, unanticipated changes in
their output will tend to affect actual net interchange and add noise to the frequency
response observation process.
To a greater or lesser extent, 1 through 4 above are happening continuously for the most part
with most BAs in the Eastern and Western Interconnections. The frequency response is buried
within the typical hour to hour operational cacophony superimposed on actual net interchange
values. The choice of metrics will be important to artfully extract frequency response from the
noise and other unrepresentative error.
43
Frequency Response Standard Background Document – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003181
Standard BAL-003-0.1b — Frequency Response and Bias
A.
Introduction
1.
Title:
Frequency Response and Bias
2.
Number:
BAL-003-0.1b
3.
Purpose: This standard provides a consistent method for calculating the Frequency Bias
component of ACE.
4.
Applicability:
4.1.
5.
B.
Balancing Authorities.
Effective Date:
Immediately after approval of applicable regulatory authorities.
Requirements
R1. Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year
and recalculate its setting to reflect any change in the Frequency Response of the Balancing
Authority Area.
R1.1. The Balancing Authority may change its Frequency Bias Setting, and the method used
to determine the setting, whenever any of the factors used to determine the current bias
value change.
R1.2. Each Balancing Authority shall report its Frequency Bias Setting, and method for
determining that setting, to the NERC Operating Committee.
R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as
close as practical to, or greater than, the Balancing Authority’s Frequency Response.
Frequency Bias may be calculated several ways:
R2.1. The Balancing Authority may use a fixed Frequency Bias value which is based on a
fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The
Balancing Authority shall determine the fixed value by observing and averaging the
Frequency Response for several Disturbances during on-peak hours.
R2.2. The Balancing Authority may use a variable (linear or non-linear) bias value, which is
based on a variable function of Tie Line deviation to Frequency Deviation. The
Balancing Authority shall determine the variable frequency bias value by analyzing
Frequency Response as it varies with factors such as load, generation, governor
characteristics, and frequency.
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Frequency Bias, unless such operation is adverse to system or Interconnection reliability.
R4. Balancing Authorities that use Dynamic Scheduling or Pseudo-ties for jointly owned units
shall reflect their respective share of the unit governor droop response in their respective
Frequency Bias Setting.
R4.1. Fixed schedules for Jointly Owned Units mandate that Balancing Authority (A) that
contains the Jointly Owned Unit must incorporate the respective share of the unit
governor droop response for any Balancing Authorities that have fixed schedules (B
and C). See the diagram below.
R4.2. The Balancing Authorities that have a fixed schedule (B and C) but do not contain the
Jointly Owned Unit shall not include their share of the governor droop response in
their Frequency Bias Setting.
Adopted by NERC Board of Trustees: October 29, 2008
Page 1 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003182
Standard BAL-003-0.1b — Frequency Response and Bias
Jointly Owned Unit
A
C
B
R5. Balancing Authorities that serve native load shall have a monthly average Frequency Bias
Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1
Hz change.
R5.1. Balancing Authorities that do not serve native load shall have a monthly average
Frequency Bias Setting that is at least 1% of its estimated maximum generation level in
the coming year per 0.1 Hz change.
R6. A Balancing Authority that is performing Overlap Regulation Service shall increase its
Frequency Bias Setting to match the frequency response of the entire area being controlled. A
Balancing Authority shall not change its Frequency Bias Setting when performing
Supplemental Regulation Service.
C.
Measures
M1. Each Balancing Authority shall perform Frequency Response surveys when called for by the
Operating Committee to determine the Balancing Authority’s response to Interconnection
Frequency Deviations.
D.
Compliance
Not Specified.
E.
Regional Differences
None identified.
F.
Associated Documents
1.
Appendix 1 Interpretation of Requirement R3 (October 23, 2007).
2.
Appendix 2 Interpretation of Requirements R2, R2.2, R5, and R5.1 (February 12, 2008).
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Errata
0
March 16, 2007
Removed "Proposed" from Effective Date
FERC Approval — Order 693
Adopted by NERC Board of Trustees: October 29, 2008
New
Page 2 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003183
Standard BAL-003-0.1b — Frequency Response and Bias
0a
December 19, 2007
Added Appendix 1 Interpretation of R3
approved by BOT on October 23, 2007
Addition
0a
July 21, 2008
FERC Approval of Interpretation of R3
Addition
0b
February 12, 2008
Added Appendix 2 Interpretation of R2,
R2.2, R5, and R5.1 approved by BOT on
February 12, 2008
Addition
0.1b
January 16, 2008
Section F: added “1.”; changed hyphen to “en
dash.” Changed font style for “Appendix 1” to
Arial; updated version number to “0.1b”
Errata
0.1b
October 29, 2008
BOT approved errata changes
Errata
0.1a
May 13, 2009
FERC Approved errata changes – version
changed to 0.1a (Interpretation of R2, R2.2,
R5, and R5.1 not yet approved)
Errata
0.1b
May 21, 2009
FERC Approved Interpretation of R2, R2.2,
R5, and R5.1
Addition
Adopted by NERC Board of Trustees: October 29, 2008
Page 3 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003184
Standard BAL-003-0.1b — Frequency Response and Bias
Appendix 1
Interpretation of Requirement 3
Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 3 of
BAL-003-0?
Interpretation:
Requirement 3 of BAL-003-0 — Frequency Response and Bias deals with Balancing Authorities using
Tie-Line Frequency Bias as the normal mode of automatic generation control.
BAL-003-0
R3. Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line
Frequency Bias, unless such operation is adverse to system or Interconnection reliability.
Tie-Line Frequency Bias is one of the three foundational control modes available in a Balancing
Authority’s energy management system. (The other two are flat-tie and flat-frequency.) Many Balancing
Authorities layer other control objectives on top of their basic control mode, such as automatic inadvertent
payback, CPS optimization, time control (in single BA Interconnections).
As long as Tie-Line Frequency Bias is the underlying control mode and CPS1 is measured and reported
on the associated ACE equation, there is no violation of BAL-003-0 Requirement 3:
ACE = (NIA− NIS) – 10B (FA − FS) − IME
Adopted by NERC Board of Trustees: October 29, 2008
Page 4 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003185
Standard BAL-003-0.1b — Frequency Response and Bias
Appendix 2
Interpretation of Requirements R2, R2.2, R5, R5.1
Request: ERCOT specifically requests clarification that a Balancing Authority is entitled to use a
variable bias value as authorized by Requirement R2.2, even though Requirement 5 seems not to account
for the possibility of variable bias settings.
Interpretation:
The consensus of the Resources Subcommittee is that BAL-003-0 — Frequency Response and Bias —
Requirement R2 does not conflict with BAL-003-0 Requirement R5.
BAL-003-0 — Frequency Response and Bias Requirement 2 requires a Balancing Authority to analyze
its response to frequency excursions as a first step in determining its frequency bias setting. The
Balancing Authority may then choose a fixed bias (constant through the year) per Requirement 2.1, or a
variable bias (varies with load, specific generators, etc.) per Requirement 2.2.
BAL-003-0
R2. Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as close
as practical to, or greater than, the Balancing Authority’s Frequency Response. Frequency Bias
may be calculated several ways:
R2.1.
The Balancing Authority may use a fixed Frequency Bias value which is based on a
fixed, straight-line function of Tie Line deviation versus Frequency Deviation. The
Balancing Authority shall determine the fixed value by observing and averaging the
Frequency Response for several Disturbances during on-peak hours.
R2.2.
The Balancing Authority may use a variable (linear or non-linear) bias value, which is
based on a variable function of Tie Line deviation to Frequency Deviation. The
Balancing Authority shall determine the variable frequency bias value by analyzing
Frequency Response as it varies with factors such as load, generation, governor
characteristics, and frequency.
BAL-003-0 — Frequency Response and Bias Requirement 5 sets a minimum contribution for all
Balancing Authorities toward stabilizing interconnection frequency. The 1% bias setting establishes a
minimum level of automatic generation control action to help stabilize frequency following a disturbance.
By setting a floor on bias, Requirement 5 also helps ensure a consistent measure of control performance
among all Balancing Authorities within a multi-Balancing Authority interconnection. However, ERCOT
is a single Balancing Authority interconnection. The bias settings ERCOT uses do produce, on average,
the best level of automatic generation control action to meet control performance metrics. The bias value
in a single Balancing Authority interconnection does not impact the measure of control performance.
BAL-003-0
R5.
Balancing Authorities that serve native load shall have a monthly average Frequency Bias
Setting that is at least 1% of the Balancing Authority’s estimated yearly peak demand per 0.1 Hz
change.
R5.1.
Balancing Authorities that do not serve native load shall have a monthly average
Frequency Bias Setting that is at least 1% of its estimated maximum generation level in
the coming year per 0.1 Hz change.
Adopted by NERC Board of Trustees: October 29, 2008
Page 5 of 5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003186
Unofficial Comment Form
Project 2007-12 Frequency Response
Please DO NOT use this form to submit comments. Please use the electronic form to submit
comments on the BAL-003-1 Frequency Response and Bias Setting. The electronic comment
form must be completed by 8 p.m. ET November 5, 2012.
http://www.nerc.com/filez/standards/Frequency_Response.html
If you have questions please contact Darrel Richardson at [email protected] or by
telephone at (609) 613-1848.
Background Information
This posting is soliciting formal comment.
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency
immediately following the sudden loss of generation or load, is a critical component to the
reliable operation of the bulk power system, particularly during disturbances and
restoration. There is evidence of continuing decline in Frequency Response over the past 10
years, but no confirmed reason for the apparent decline. The proposed standard requires
entities to provide data so that Frequency Response in each of the Interconnections can be
analyzed, and the reasons for the decline in Frequency Response can be identified. The
standard would set a minimum Frequency Response obligation for each Balancing Authority,
provide a uniform calculation of Frequency Response and Frequency Bias Settings that
transition to values closer to natural Frequency Response, and encourage coordinated AGC
operation.
The Drafting Team made significant modifications to the proposed standard BAL-003-1 and
associated documents based on industry comments from the second posting and initial
ballot. These modifications include:
•
Modifying the definition for Frequency Response Measure
•
Removing reference to Reserve Sharing Groups and replacing with Frequency
Response Sharing Group
•
Creation of definition for Frequency Response Sharing Group
•
Modifying Requirement R2
•
Creating a new Requirement R3 for entities using variable Frequency Bias
•
Removing requirement for operating in Tie Line Bias mode
•
Removing Requirement R5 and combining into revised Requirement R2 and new
Requirement R3
•
Modifying Attachment A to provide additional clarity
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003187
•
Creating a Procedure to provide instructions for the ERO to follow in supporting the
standard
•
Re-writing the Background Document to incorporate additional language for
justification of requirements and provide additional clarity
You do not have to answer all questions. Enter all comments in simple text format.
1. The SDT has made minor modifications to the proposed definition for Frequency Response
Measure based on industry comments. Do you agree that these modifications provide
sufficient clarity? If not, please explain in the comment area.
Yes
No
Comments:
2. The SDT has created a definition for Frequency Response Sharing Group. The definition is as
follows:
A group whose members consist of two or more Balancing Authorities that collectively
maintain, allocate, and supply operating resources required to jointly meet the
Frequency Response Obligations of its members.
Do you agree with this definition? If not, please explain in the comment area.
Yes
No
Comments:
3. The SDT has added Requirement R3 for entities using variable Frequency Bias.
R3. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and utilizing a variable
Frequency Bias Setting shall maintain a Frequency Bias Setting that is:
3.1
Less than zero at all times, and
3.3
Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/-0.036 Hz.
Do you agree with the proposed requirement? If not, please explain in the comment area.
Yes
No
Comments:
Unofficial Comment Form
Project 2007-12 Frequency Response BAL-003-1
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003188
4. Based on Industry comments the SDT has modified ”Attachment A- Supporting Document”
to provide additional clarity. Do you agree with the modifications? If not, what
modifications do you disagree with?
Yes
No
Comments:
5. The SDT has moved a portion of the material located in Attachment A and all of the material
located in ”Attachment B- Process for Adjusting Bias Setting Floor” into a new document
“Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard”.
The SDT created this document to assign tasks to the ERO and provide instructions for the
ERO to follow when carrying them out under the BAL-003-1 standard. Do you agree that
the ERO should perform these tasks and that this document provides sufficient detail for
the ERO to do it under the BAL-003-1 standard? If not, what needs to be added to the
document?”.
Yes
No
Comments:
6. The SDT is now using the method detailed in the Frequency Response Initiative Report
dated September 30, 2012 to calculate the Interconnection Frequency Response Obligation.
Do you agree that this method provides for the proper amount of Frequency Response? If
not, what specifically needs to be changed?
Yes
No
Comments:
7. Based on Industry comments received the SDT made significant clarifying modifications to
the Background Document. Do you agree that this document provides sufficient
information to justify the rationale used by the SDT in developing the draft standard and
provides the industry with sufficient understanding of the issues being addressed by the
standard?
Yes
No
Comments:
Unofficial Comment Form
Project 2007-12 Frequency Response BAL-003-1
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003189
8. If you are not in support of this draft standard, what modifications do you believe need to
be made in order for you to support the standard? Please list the issues and your proposed
solution to the issue.
Yes
No
Comments:
9. Please provide any other comments (that you have not already provided in response to the
questions above) that you have on the draft standard BAL-003-1.
Comments:
Unofficial Comment Form
Project 2007-12 Frequency Response BAL-003-1
4
003190
Project 2007-12 Frequency Response BAL-003-1
Mapping Document
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
R1. Each Balancing Authority shall
This
Attachment A
review its Frequency Bias
Requirement
Balancing Authorities that merge or that transfer load or
Settings by January 1 of each
has been
generation are encouraged to notify the ERO of the change
year and recalculate its setting
moved into
in footprint and corresponding changes in allocation such
to reflect any change in the
BAL-003-1
that the net obligation to the Interconnection remains the
Frequency Response of the
Attachment A
Balancing Authority Area.
& FRS Form 1
same and so that CPS limits can be adjusted.
R1.1. The Balancing Authority
as described in
Each Balancing Authority reports its previous year’s
may change its Frequency the Proposed
Frequency Response Measure (FRM), Frequency Bias
Bias Setting, and the
Language
method used to determine Section
Setting and Frequency Bias type (fixed or variable) to the
the setting, whenever any
ERO each year to allow the ERO to validate the revised
of the factors used to
Frequency Bias Settings on FRS Form 1. If the ERO posts
determine the current bias
the official list of events after the date specified in the
value change.
timeline below, Balancing Authorities will be given 30 days
R1.2. Each Balancing Authority
from the date the ERO posts the official list of events to
shall report its Frequency
Bias Setting, and method
003191
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
for determining that
submit their FRS Form 1.
setting, to the NERC
AND
Operating Committee.
FRS Form 1
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias
Settings. The previous year’s monthly averages will be
reported annually on FRS Form 1.
R2. Each Balancing Authority shall
establish and maintain a Frequency
Bias Setting that is as close as practical
to, or greater than, the Balancing
Authority’s Frequency Response.
Frequency Bias may be calculated
several ways:
R2.1. The Balancing Authority
may use a fixed Frequency Bias
value which is based on a
fixed, straight-line function of
Tie Line deviation versus
Frequency Deviation. The
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
is included in
BAL-003-1 as
described in
the Proposed
Language
Section.
R2.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and is not receiving
Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting
determined subject to Attachment A, as validated by the
ERO, into its Area Control Error (ACE) calculation during
the implementation period specified by the ERO.
R3.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection, is not receiving
Overlap Regulation Service and is utilizing a variable
Frequency Bias Setting shall maintain a Frequency Bias
setting that is:
2
003192
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Balancing Authority shall
3.1 Less than zero at all times, and
determine the fixed value by
3.2 Equal to or more negative than its Frequency
observing and averaging the
Response Obligation when Frequency varies from 60 Hz
Frequency Response for
by more than +/- 0.036 Hz.
several Disturbances during
AND
on-peak hours.
R2.2. The Balancing Authority
may use a variable (linear or
Attachment A
non-linear) bias value, which is
Each Balancing Authority reports its previous year’s
based on a variable function of
Frequency Response Measure (FRM), Frequency Bias
Tie Line deviation to
Setting and Frequency Bias type (fixed or variable) to the
Frequency Deviation. The
Balancing Authority shall
ERO each year to allow the ERO to validate the revised
determine the variable
Frequency Bias Settings on FRS Form 1. If the ERO posts
frequency bias value by
the official list of events after the date specified in the
analyzing Frequency Response
timeline below, Balancing Authorities will be given 30 days
as it varies with factors such as
from the date the ERO posts the official list of events to
load, generation, governor
submit their FRS Form 1.
characteristics, and frequency.
AND
FRS Form 1
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
3
003193
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias
Settings. The previous year’s monthly averages will be
reported annually on FRS Form 1.
AND
R3. Each Balancing Authority shall
operate its Automatic Generation
Control (AGC) on Tie Line Frequency
Bias, unless such operation is adverse
to system or Interconnection
reliability.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
removed from
the BAL-003-1
standard.
A portion of this Requirement is being phased out in accordance
with the process detailed in the Procedure. This phase out is
intended to bring the Frequency Bias Setting closer or equal to the
natural Frequency Response.
This Requirement has been removed from proposed standard BAL003-I. It is duplicative of BAL-005-0.1b Requirements R6 and
R7.
BAL-005-0.1b
R6. The Balancing Authority’s AGC shall compare total Net
Actual Interchange to total Net Scheduled Interchange
plus Frequency Bias obligation to determine the
Balancing Authority’s ACE. Single Balancing Authorities
operating asynchronously may employ alternative ACE
calculations such as (but not limited to) flat frequency
control. If a Balancing Authority is unable to calculate
ACE for more than 30 minutes it shall notify its
4
003194
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Reliability Coordinator.
R4. Balancing Authorities that use
Dynamic Scheduling or Pseudoties for jointly owned units shall
reflect their respective share of
the unit governor droop response
in their respective Frequency Bias
Setting.
R4.1. Fixed schedules for Jointly
Owned Units mandate that
Balancing Authority (A) that
contains the Jointly Owned Unit
must incorporate the respective
share of the unit governor droop
response for any Balancing
Authorities that have fixed
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
removed from
the BAL-003-1
standard.
R7. The Balancing Authority shall operate AGC continuously
unless such operation adversely impacts the reliability
of the Interconnection. If AGC has become inoperative,
the Balancing Authority shall use manual control to
adjust generation to maintain the Net Scheduled
Interchange.
This Requirement addresses how to calculate Frequency Bias
Settings. This is no longer needed since the Frequency Bias Settings
are calculated in FRS Form 1 using Frequency Response associated
with the “official” list of events and a couple of “floor or ceiling”
limits (% of peak load/gen and FRO). The entire calculation is built
into the FRS Form 1 workbook.
5
003195
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
schedules (B and C).
R4.2. The Balancing Authorities that
have a fixed schedule (B and C)
but do not contain the Jointly
Owned Unit shall not include
their share of the governor
droop response in their
Frequency Bias Setting.
R5. Balancing Authorities that serve
This
R2. Each Balancing Authority that is a member of a multiple
native load shall have a monthly
Requirement
Balancing Authority Interconnection and is not receiving
average Frequency Bias Setting that is has been
Overlap Regulation Service and uses a fixed Frequency
at least 1% of the Balancing
combined into
Bias Setting shall implement the Frequency Bias Setting
Authority’s estimated yearly peak
Requirements
determined subject to Attachment A, as validated by the
demand per 0.1 Hz change.
R2 and R3 of
ERO, into its Area Control Error (ACE) calculation during
R5.1. Balancing Authorities
BAL-003-1.
the implementation period specified by the ERO.
that do not serve native load
R3. Each Balancing Authority that is a member of a multiple
shall have a monthly average
Balancing Authority Interconnection, is not receiving
Frequency Bias Setting that is
Overlap Regulation Service and is utilizing a variable
at least 1% of its estimated
Frequency Bias Setting shall maintain a Frequency Bias
maximum generation level in
setting that is:
the coming year per 0.1 Hz
3.1 Less than zero at all times, and
change.
3.2 Equal to or more negative than its Frequency
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
6
003196
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Response Obligation when Frequency varies from 60 Hz
by more than +/- 0.036 Hz.
R6. A Balancing Authority that is
performing Overlap Regulation
Service shall increase its Frequency
Bias Setting to match the frequency
response of the entire area being
controlled. A Balancing Authority shall
not change its Frequency Bias Setting
when performing Supplemental
Regulation Service.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
moved into
BAL-003-1
Requirement
R4.
R4.
Each Balancing Authority that is performing Overlap
Regulation Service shall modify its Frequency Bias Setting
in its ACE calculation, in order to represent the
Frequency Bias Setting for the combined Balancing
Authority Area, to be equivalent to either:
The sum of the Frequency Bias Settings as shown
on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated
by the ERO, or
The Frequency Bias Setting as shown on FRS
Form 1 and FRS Form 2 for the entirety of the
participating Balancing Authorities’ Areas.
7
003197
Project 2007-12 Frequency Response BAL-003-1
Mapping Document
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
Attachment A
R1. Each Balancing Authority shall review This
its Frequency Bias Settings by
Requirement
Balancing Authorities that merge or that transfer load or
January 1 of each year and
has been
generation are encouraged to notify the ERO of the change in
recalculate its setting to reflect any moved into
footprint and corresponding changes in allocation such that the
change in the Frequency Response BAL-003-1
net obligation to the Interconnection remains the same and so
of the Balancing Authority Area.
Attachment A &
that CPS limits can be adjusted.
R1.1. The Balancing Authority may
FRS Form 1 as
change its Frequency Bias
described in the
Each Balancing Authority shall reports its previous year’s
Setting, and the method used Proposed
to determine the setting,
Language
Frequency Response Measure (FRM), Frequency Bias Setting and
whenever any of the factors
Section
Frequency Bias type (fixed or variable) to the ERO on FRS Form 1
used to determine the
by January 10 each year to allow the ERO to validate the revised
current bias value change.
Frequency Bias Settings on FRS Form 1. If the ERO posts the
R1.2. Each Balancing Authority shall
official list of events after the date specified in the timeline
report its Frequency Bias
belowDecember 10, Balancing Authorities will be given 30 days
Setting, and method for
from the date the ERO posts the official list of events to submit
determining that setting, to
the NERC Operating
their FRS Form 1.
Committee.
AND
003198
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
FRS Form 1
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias Settings.
The previous year’s monthly averages will be reported annually
on FRS Form 1.
R2. Each Balancing Authority shall
establish and maintain a Frequency Bias
Setting that is as close as practical to, or
greater than, the Balancing Authority’s
Frequency Response. Frequency Bias may
be calculated several ways:
R2.1. The Balancing Authority
may use a fixed Frequency Bias
value which is based on a fixed,
straight-line function of Tie Line
deviation versus Frequency
Deviation. The Balancing
Authority shall determine the
fixed value by observing and
averaging the Frequency
Response for several Disturbances
during on-peak hours.
R2.2. The Balancing Authority
may use a variable (linear or nonlinear) bias value, which is based
on a variable function of Tie Line
deviation to Frequency Deviation.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement is
included in BAL003-1 as
described in the
Proposed
Language
Section.
R2.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and is not receiving
Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined
subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation
period specified by the ERO.
R3.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection, is not receiving Overlap
Regulation Service and is utilizing a variable Frequency Bias
Setting shall maintain a Frequency Bias setting that is:
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response
Obligation when Frequency varies from 60 Hz by more than
+/- 0.036 Hz.
R2.
Each Balancing Authority not participating in Overlap Regulation
Service shall implement the Frequency Bias Setting (fixed or variable)
validated by the ERO, into its Area Control Error (ACE) calculation
beginning on the date specified by the ERO to ensure effectively
2
003199
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
The Balancing Authority shall
coordinated Tie Line Bias control.
determine the variable frequency
bias value by analyzing
AND
Frequency Response as it varies
with factors such as load,
Attachment A
generation, governor
characteristics, and frequency.
Each Balancing Authority shall reports its previous year’s
Frequency Response Measure (FRM), Frequency Bias Setting and
Frequency Bias type (fixed or variable) to the ERO on FRS Form 1
by January 10 each year to allow the ERO to validate the revised
Frequency Bias Settings on FRS Form 1. If the ERO posts the
official list of events after the date specified in the timeline
belowDecember 10, Balancing Authorities will be given 30 days
from the date the ERO posts the official list of events to submit
their FRS Form 1.
AND
FRS Form 1
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias Settings.
The previous year’s monthly averages will be reported annually
on FRS Form 1.
AND
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
3
003200
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
A portion of this Requirement is being phased out in accordance with the
process detailed in the ProcedureAttachment B. This phase out is
intended to bring the Frequency Bias Setting closer or equal to the
natural Frequency Response.
R3. Each Balancing Authority shall
This
R3. Each Balancing Authority not receiving Overlap Regulation Service
operate its Automatic Generation Control Requirement
shall operate its Automatic Generation Control (AGC) in Tie Line
(AGC) on Tie Line Frequency Bias, unless
has been
Bias mode to ensure effectively coordinated control, unless such
such operation is adverse to system or
removed
operation would have an Adverse Reliability Impact on the
Interconnection reliability.
frominto the
Balancing Authority’s Area. This Requirement has been removed
BAL-003-1
from proposed standard BAL-003-I. It is duplicative of BAL-005standard
0.1b Requirements R6 and R7.
Requirement
BAL-005-0.1b
R3.
R6. The Balancing Authority’s AGC shall compare total Net Actual
Interchange to total Net Scheduled Interchange plus
Frequency Bias obligation to determine the Balancing
Authority’s ACE. Single Balancing Authorities operating
asynchronously may employ alternative ACE calculations
such as (but not limited to) flat frequency control. If a
Balancing Authority is unable to calculate ACE for more than
30 minutes it shall notify its Reliability Coordinator.
R7. The Balancing Authority shall operate AGC continuously unless
such operation adversely impacts the reliability of the
Interconnection. If AGC has become inoperative, the
Balancing Authority shall use manual control to adjust
generation to maintain the Net Scheduled Interchange.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
4
003201
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
R4. Balancing Authorities that use
This
This Requirement addresses how to calculate Frequency Bias Settings.
Dynamic Scheduling or Pseudo-ties
Requirement
This is no longer needed since the Frequency Bias Settings are calculated
for jointly owned units shall reflect
has been
in FRS Form 1 using Frequency Response associated with the “official”
their respective share of the unit
removed from
list of events and a couple of “floor or ceiling” limits (% of peak load/gen
governor droop response in their
the BAL-003-1
and FRO). The entire calculation is built into the FRS Form 1 workbook.
respective Frequency Bias Setting.
standard.
R4.1. Fixed schedules for Jointly Owned
Units mandate that Balancing
Authority (A) that contains the
Jointly Owned Unit must
incorporate the respective share of
the unit governor droop response
for any Balancing Authorities that
have fixed schedules (B and C).
R4.2. The Balancing Authorities that have
a fixed schedule (B and C) but do
not contain the Jointly Owned Unit
shall not include their share of the
governor droop response in their
Frequency Bias Setting.
R5. Balancing Authorities that serve
native load shall have a monthly average
Frequency Bias Setting that is at least 1%
of the Balancing Authority’s estimated
yearly peak demand per 0.1 Hz change.
R5.1. Balancing Authorities that
do not serve native load shall
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
combined into
Requirements
R2 and R3
R2.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and is not receiving
Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined
subject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation
5
003202
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
have a monthly average
period specified by the ERO.
ofmoved into
Frequency Bias Setting that is at
BAL-003-1
R3. Each Balancing Authority that is a member of a multiple
least 1% of its estimated
Requirement
Balancing Authority Interconnection, is not receiving Overlap
maximum generation level in the
R5.
Regulation Service and is utilizing a variable Frequency Bias
coming year per 0.1 Hz change.
Setting shall maintain a Frequency Bias setting that is:
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response
Obligation when Frequency varies from 60 Hz by more than
+/- 0.036 Hz.
R5.
In order to ensure adequate control response each Balancing
Authority shall use a monthly average Frequency Bias Setting whose
absolute value is at least equal to one of the following:
•
The minimum percentage of the Balancing
Authority Area’s estimated yearly Peak Demand within its metered
boundary per 0.1 Hz change as specified by the ERO in accordance with
Attachment B.
•
The minimum percentage of the Balancing
Authority Area’s estimated yearly peak generation for a generation-only
Balancing Authority, per 0.1 Hz change as specified by the ERO in
accordance with Attachment B.
R6. A Balancing Authority that is
performing Overlap Regulation Service
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
R4.
Each Balancing Authority that is performing Overlap
Regulation Service shall modify its Frequency Bias Setting in
6
003203
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other Action
shall increase its Frequency Bias Setting
its ACE calculation, in order to represent the Frequency Bias
has been
to match the frequency response of the
Setting for the combined Balancing Authority Area, to be
moved into
entire area being controlled. A Balancing
equivalent to either:
BAL-003-1
Authority shall not change its Frequency
Requirement
Bias Setting when performing
The sum of the Frequency Bias Settings as shown on
R4.
Supplemental Regulation Service.
FRS Form 1 and FRS Form 2 for the participating
Balancing Authorities as validated by the ERO, or
R4.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
The Frequency Bias Setting as shown on FRS Form 1
and FRS Form 2 for the entirety of the participating
Balancing Authorities’ Areas.
Each Balancing Authority that is performing Overlap Regulation
Service shall modify its Frequency Bias Setting in its ACE calculation
to be equivalent to the sum of the Frequency Bias Settings of the
participating Balancing Authorities as validated by the ERO or
calculate the Frequency Bias Setting based on the entire area being
combined and thereby represent the Frequency Response for the
combined area being controlled.
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003204
Violation Risk Factor and Violation Severity
Level Assignments
Project 2007-12 – Frequency Response
This document provides the drafting team’s justification for assigning draft standard Requirement
violation risk factors (VRFs) and violation severity levels (VSLs) for:
•
BAL-003-1 — Frequency Response and Frequency Bias Setting
Each primary Requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violation of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard Drafting Team applied the following NERC criteria when proposing
VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration
to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003205
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs 1:
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk-Power System: 2
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
1
North American Electric Reliability Corp., 119 FERC 61,145, order on reh’g and compliance filing, 120 FERC 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003206
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence that would
be reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may find
during a typical audit. The SDT based its assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement in this standard meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence
of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in
the Determination of Penalties
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003207
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a
Cumulative Number of Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement
is a separate violation. Section 4 of the Sanction Guidelines states that assessing penalties per
violation per day basis is the “default” for penalty calculations.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003208
VRF and VSL Justification
BAL-003-1 VRF and VSL Justifications
Proposed VRF
Medium
NERC VRF Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G1
Discussion
This Requirement is more administrative in nature requiring
calculated FRM to be equal to or more negative than FRO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This requirement is similar in concept to
the current enforceable BAL-003-0.1b standard Requirement R2
which specifies a Medium VRF.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
R1
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003209
Discussion
Proposed Lower VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 1% but by at most 30% or 15
MW/0.1 Hz, whichever one is the greater deviation from its
FRO
Proposed Moderate VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 30% or by more than 15 MW/0.1
Hz, whichever is the greater deviation from its FRO
Proposed High VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 1% but by at most
30% or 15 MW/0.1 Hz, whichever one is the greater deviation
from its FRO
Proposed Severe VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 30% or by more
than 15 MW/0.1 Hz, whichever is the greater deviation from its
FRO
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated FRM being less
negative than FRO.
FERC VSL G1
Discussion
This is not applicable since there was not a Requirement mandating a
certain level of Frequency Response prior to this standard.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the amount the
calculated FRM is less negative than FRO.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003210
Proposed VRF
NERC VRF Discussion
FERC VRF G1
Discussion
R2
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
This Requirement is more administrative in nature requiring entities
to implement the Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R3,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003211
Proposed Lower VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting failed to implement the
validated Frequency Bias Setting value into its ACE calculation
within the implementation period specified but did so within 5
calendar days from the implementation period specified by the
ERO.
Proposed Moderate VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 5 calendar days but less than or equal to 15
calendar days from the implementation period specified by the
ERO.
Proposed High VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 15 calendar days but less than or equal to 25
calendar days from the implementation period specified by the
ERO.
Proposed Severe VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting did not implement the
validated Frequency Bias Setting value into its ACE calculation
in more than 25 calendar days from the implementation period
specified by the ERO.
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating increments
for tardiness implementing the validated Frequency Bias Setting into
the ACE calculation.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Lower VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on how late the validated
Frequency Bias Setting is implemented.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider performance of required action. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Proposed VSL’s are based on a single violation and not a cumulative
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003212
Discussion
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting in its ACE equation and
would provide support for a contingency. This is consistent with the
NERC definition.
This Requirement is more administrative in nature requiring entities
to implement a Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R3
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R2,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for a contingency. This is consistent with
the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003213
Discussion
Proposed Lower VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 1% but by at most 10%.
Proposed Moderate VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 10% but by at most 20%.
Proposed High VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 20% but by at most 30%.
Proposed Severe VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
obligation by more than 30%..
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G1
Discussion
FERC VSL G2
Discussion
Proposed VSL is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based on the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003214
FERC VSL G3
Discussion
Proposed VSL does not expand on what is required. The VSLs
assigned only consider compliance with the Frequency Bias Setting
calculation and implementation required. Proposed VSL’s are
consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
This Requirement is more administrative in nature requiring entities
providing Overlap Regulation Services to correctly increase its
Frequency Bias Setting. The requirement does not directly correlate
to the list of critical areas identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R4
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R6 which
specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003215
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error less than
10% of the validated or calculated value.
Proposed Moderate VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
10% but less than or equal to 20% of the validated or calculated value
Proposed High VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
20% but less than or equal to 30% of the validated or calculated
value.
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with setting error more than 30% of the validated
or calculated value.
OR
The Balancing Authority failed to change the Frequency Bias Setting
value used in its ACE calculation when providing Overlap Regulation
Services
Proposed Severe VSL
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the absolute value of the
Balancing Authorities’ calculated monthly average Frequency Bias
Setting being below the minimum percentage specified by the ERO.
The VSL also includes a binary requirement for failing to change the
Frequency Bias Setting value when providing Overlap Regulation
Services.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R6 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s has both a percentage of noncompliance
performance and binary element. The binary element is designated
severe. Proposed VSL language does not include ambiguous terms
and ensures uniformity and consistency in the determination of
penalties based only on the amount the calculated monthly average
Frequency Bias Setting is below the minimum percentage specified
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003216
by the ERO or if the entity fails to change the Frequency Bias Setting
value when providing Overlap Regulation Services.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required and if the
Frequency Bias Setting is correctly set when providing Overlap
Regulation Services. Proposed VSL’s are consistent with the
requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003217
Violation Risk Factor and Violation Severity Level Assignments
Project 2007-12 – Frequency Response
This document provides the drafting team’s justification for assigning draft standard
Requirement violation risk factors (VRFs) and violation severity levels (VSLs) for:
BAL-003-1 — Frequency Response and Frequency Bias Setting
Each primary Requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violation of requirements in FERC-approved Reliability Standards, as defined in the ERO
Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard Drafting Team applied the following NERC criteria when
proposing VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would
not be expected to adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor and control the bulk electric system; or, a
requirement that is administrative in nature and a requirement in a planning time frame
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003218
that, if violated, would not, under the emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. A planning requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for
setting VRFs1:
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical
impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:2
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation
Risk Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor
Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation
Risk Factor level conforms to NERC’s definition of that risk level.
1
North American Electric Reliability Corp., 119 FERC 61,145, order on reh’g and compliance filing, 120 FERC
61,145 (2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003219
Guideline (5) — Treatment of Requirements that Co-mingle More Than One
Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser
risk reliability objective, the VRF assignment for such Requirements must not be watered
down to reflect the lower risk level associated with the less important objective of the
Reliability Standard.
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence
that would be reviewed during an audit, and developed its VSLs based on the noncompliance an
auditor may find during a typical audit. The SDT based its assignment of VSLs on the following
NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs
proposed for each requirement in this standard meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes
that may encourage a lower level of compliance than was required when levels of noncompliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003220
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on a Single Violation,
Not on a Cumulative Number of Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that
assessing penalties per violation per day basis is the “default” for penalty calculations.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003221
VRF and VSL Justification
BAL-003-1 VRF and VSL Justifications
R1
Proposed VRF
Medium
NERC VRF Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G1
Discussion
This Requirement is more administrative in nature requiring
calculated FRM to be equal to or more negative than FRO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This requirement is similar in concept to
the current enforceable BAL-003-0.1b standard Requirement R2
which specifies a Medium VRF.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003222
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 1% but by at most 30% or 15
MW/0.1 Hz, whichever one is the greater deviation from its
FROThe Interconnection met its FRO and the Balancing
Authority’s, or Reserve Sharing Groups, FRM was less negative than
its FRO by more than 1% but by at most 30% or 15 MW/0.1 Hz,
whichever one is the greater deviation from its
Proposed Moderate VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 30% or by more than 15 MW/0.1
Hz, whichever is the greater deviation from its FROThe
Interconnection met its FRO and the Balancing Authority’s, or
Reserve Sharing Groups, FRM was less negative than its FRO by
more than 30% or by more than 15 MW/0.1 Hz, whichever is the
greater deviation from its FRO
Proposed High VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 1% but by at most
30% or 15 MW/0.1 Hz, whichever one is the greater deviation
from its FROThe Interconnection did not meet its FRO and the
Balancing Authority’s, or Reserve Sharing Groups, FRM was less
negative than its FRO by more than 1% but by at most 30% or 15
MW/0.1 Hz, whichever one is the greater deviation from its FRO
Proposed Severe VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 30% or by more
than 15 MW/0.1 Hz, whichever is the greater deviation from its
FROThe Interconnection did not meet its FRO and the Balancing
Authority’s, or Reserve Sharing Groups, FRM was less negative than
its FRO by more than 30% or by more than 15 MW/0.1 Hz,
whichever is the greater deviation from its FRO
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated FRM being less
negative than FRO.
FERC VSL G1
Discussion
This is not applicable since there was not a Requirement mandating a
certain level of Frequency Response prior to this standard.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the amount the
calculated FRM is less negative than FRO.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003223
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
This Requirement is more administrative in nature requiring entities
to implement the Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R2
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-10.1b Requirements R12,
R3, and R45, and R6 specify a Medium VRF and the SDT believes it
is appropriate for this Requirement to also possess a Medium VRF
given the nature of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003224
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting failed to implement the
validated Frequency Bias Setting value into its ACE calculation
within the implementation period specified but did so within 5
calendar days from the implementation period specified by the
ERO.The Balancing Authority failed to implement the validated
Frequency Bias Setting value in to its ACE calculation on the date
specified but did so within 5 calendar days following the date
specified by the ERO.
Proposed Moderate VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 5 calendar days but less than or equal to 15
calendar days from the implementation period specified by the
ERO.The Balancing Authority implemented the validated Frequency
Bias Setting value in to its ACE calculation in more than 5 calendar
days but less than or equal to 15 calendar days following the date
specified by the ERO.
Proposed High VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 15 calendar days but less than or equal to 25
calendar days from the implementation period specified by the
ERO.The Balancing Authority implemented the validated Frequency
Bias Setting value in to its ACE calculation in more than 15 calendar
days following the date specified by the ERO, but the new Bias
Setting was within 10% of the previous year’s Bias Setting
Proposed Severe VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting did not implement the
validated Frequency Bias Setting value into its ACE calculation
in more than 25 calendar days from the implementation period
specified by the ERO. The Balancing Authority implemented the
validated Frequency Bias Setting value in to its ACE calculation in
more than 15 calendar days following the date specified by the ERO
and the Bias Setting was more than 10% different from the previous
year.
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating increments
for tardiness implementing the validated Frequency Bias Setting into
the ACE calculation..
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003225
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Lower VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on how late the validated
Frequency Bias Setting is implemented.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider performance of required action. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting in its ACE equation and
would provide support for a contingencywho was not operating its
AGC in Tie Line Bias would typically be the only Balancing
Authority that is operating in this manner and the rest of the
Balancing Authorities would pick up the slack. In addition, this
Requirement VRF is the same as the BAL-003-0 standard VRF and
was approved by FERC. This is consistent with the NERC definition.
This Requirement is more administrative in nature requiring entities
to implement a Frequency Bias Setting validated by the EROoperate
AGC in Tie-Line Bias mode. The requirement does not directly
correlate to the list of critical areas identified in the FERC VRF
Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R3
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003226
specifies a Lower VRF however BAL-003-1 Requirements R1, R2,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.R3 which specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for a contingencywho was not operating
its AGC in Tie Line Bias would typically be the only Balancing
Authority that is operating in this manner and the rest of the
Balancing Authorities would pick up the slack. In addition, this
Requirement VRF is the same as the BAL-003-0 standard VRF and
was approved by FERC. This is consistent with the NERC definition.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 1% but by at most 10%.The Balancing
Authority could not provide the type of evidence as outlined in
Measure M3 that Tie Line Bias is the normal mode of AGC.
Proposed Moderate VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 10% but by at most 20%.N/A
Proposed High VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligtation by more than 20% but by at most 30%.A spot check
during an audit found the Balancing Authority’s AGC out of Tie Line
Bias mode without documentation supporting the need to operate in a
different AGC mode.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003227
Proposed Severe VSL
Compliance with NERC
Revised VSL Guidelines
FERC VSL G1
Discussion
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
obligation by more than 30%..A system event occurred and it was
found that a contributing factor was that the Balancing Authority
failed to operate AGC in Tie Line Bias mode.
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.The NERC VSL guidelines are satisfied
by incorporating a binary requirement for failing to operating AGC in
Tie Line Bias mode when an Adverse Reliability Impact did not exist.
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R13 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.if AGC is not operating in Tie Line Bias
mode unless there is an Adverse Reliability Impact.
FERC VSL G3
Discussion
Proposed VSL does not expand on what is required. The VSLs
assigned only consider compliance with the Frequency Bias Setting
calculation and implementationAGC control mode status required.
Proposed VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
This Requirement is more administrative in nature requiring entities
providing Overlap Regulation Services to correctly increase its
Frequency Bias Setting. The requirement does not directly correlate
to the list of critical areas identified in the FERC VRF Guideline 1.
NERC VRF Discussion
R4
FERC VRF G1
Discussion
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003228
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R6 which
specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error less than
105% of the validated or calculatedcorrect value.
Proposed Moderate VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
105% but less than or equal to 2015% of the validated or
calculatedcorrect value
Proposed High VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
2015% but less than or equal to 3025% of the validated or
calculatedcorrect value.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003229
Proposed Severe VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with setting error more than 3025% of the
validated or calculatedcorrect value.
OR
The Balancing Authority failed to change the Frequency Bias Setting
value used in its ACE calculation when providing Overlap Regulation
Services
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the absolute value of the
Balancing Authorities’ calculated monthly average Frequency Bias
Setting being below the minimum percentage specified by the ERO.
The VSL also includes a binary requirement for failing to change the
Frequency Bias Setting value when providing Overlap Regulation
Services.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R6 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s has both a percentage of noncompliance
performance and binary element. The binary element is designated
severe. Proposed VSL language does not include ambiguous terms
and ensures uniformity and consistency in the determination of
penalties based only on the amount the calculated monthly average
Frequency Bias Setting is below the minimum percentage specified
by the ERO or if the entity fails to change the Frequency Bias Setting
value when providing Overlap Regulation Services.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required and if the
Frequency Bias Setting is correctly set when providing Overlap
Regulation Services. Proposed VSL’s are consistent with the
requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
This Requirement is more administrative in nature requiring entities
to determine if the monthly absolute value Frequency Bias Setting
NERC VRF Discussion
R5
FERC VRF G1
Discussion
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003230
meets specified criteria. The requirement does not directly correlate
to the list of critical areas identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R5 which
specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The absolute value of the Balancing Authorities’ calculated monthly
average Frequency Bias Setting is 5% or less below the minimum
specified by the ERO.
Proposed Moderate VSL
The absolute value of the Balancing Authorities’ calculated monthly
average Frequency Bias Setting is more than 5% but less than or
equal to 15% below the minimum specified by the ERO.
Proposed High VSL
The absolute value of the Balancing Authorities’ calculated monthly
average Frequency Bias Setting is more than 15% but less than or
equal to 25% below the minimum specified by the ERO.
Proposed Severe VSL
The absolute value of the Balancing Authorities’ calculated monthly
average Frequency Bias Setting is more than 25% below the
minimum specified by the ERO.
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated monthly average
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003231
Frequency Bias Setting absolute value being below the minimum
specified by the ERO.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R5 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the amount the
calculated monthly average Frequency Bias Setting absolute value is
below the minimum specified by the ERO.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
003232
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003233
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
MyBA
Enter Addition Data in column W ==>
UTC (t-0)
Date/Time (t-0)
Time
Date/Time (t-0)
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
BA Time
1
2
3
4
5
6
7
8
9
10
11
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
BA
Time
Zone
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
BA
DelFreq
Time
BA
Bias
DelFreq
Relay Lmt
R1
DelFreq
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0:00:00
0:00:00
0.000
0.000
0.000
0.000
Value "A" Information
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
NAI
Adjustment
NAI
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
N
N
N
N
N
N
N
N
N
N
N
1901
Eastern
MyBA
Value "A"
[email protected]
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
N
Y
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-964
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
1900
#DIV/0!
20
21
22
23
24
25
26
27
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
Value "B"
BA Delta
NAI
Load
Load
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
BA Bias Type and Bias Setting
0.0
0.0
Reason(s)
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
Calculate Regression
Fixed
0.90%
621018
#DIV/0!
#DIV/0!
#DIV/0!
n/a
-20.87
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: May be set to a value between 100% to 125% of its FRM if this value is more negative than the minimum Bias based on Peak
Demand. If not more negative, then the Bias must be the minimum Bias based on Peak Demand. If variable Bias is used, enter "Variable".
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
#DIV/0!
1901 Frequency Bias Setting - (minimum of 100% to 125% of FRM, or 0.9% of Historical Peak Demand if not Variable)
0.0
0.0
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
0.00
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
0.00
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Event
Number
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of
this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
MyBA_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For Bias
For R1
For Bias
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
#N/A
0
595
#DIV/0!
0
1
0
0
595
#DIV/0!
0
#NUM!
12
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
595
#DIV/0!
0 For R1
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
#N/A
0
595
#DIV/0!
0
1
0
0
595
#DIV/0!
0
#NUM!
11
0
0
595
#DIV/0!
0
0
0
0
0
0
0
0
0
0
0
0
0
0
003234
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003235
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
MyBA
DelFreq
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value
B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment which is
only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003236
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
Time
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
MyBA
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
003237
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
#DIV/0!
#DIV/0!
#DIV/0!
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
#DIV/0!
#DIV/0!
Unadjusted
PFR
Performance
@ T(+46)
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
20 to 52 second Average Period Evaluation
Net
Actual
Interchange
MW
JOU
NonDynamic
Conforming
Pumped
Schedules
Load
Hydro
Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
MW
MW
MW
Ramping
Units
Gen (+)
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Bias While
Hz > +/-0.036
Hz
MW/0.1 Hz
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003238
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
003239
003240
003241
003242
003243
003244
003245
003246
003247
003248
003249
003250
003251
MyBA
MyBA
T20 to T52 Average Performance
Initial Performance Adjusted P.U. Based on Bias Setting
1.00
0.80
0.80
0.60
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
MyBA
9
10
11
12
Performance based on Hz at T+76
MyBA
Performance based on Hz at T+46
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
1
12
3
4
5
Performance based on Hz at T+106
6
7
8
9
10
11
12
Performance based on Hz at T+136
MyBA
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Event
Event
MyBA
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
FRI - NERC Frequency Response Initiative
#DIV/0 Average P.U. Performance
#DIV/0! MW/0.1 Hz Median
1.00
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
MyBA
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
Event Recovery Period Average Performance
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
P.U.
P.U.
1.20
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003252
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003253
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
ERCOT
Enter Addition Data in column W ==>
UTC (t-0)
Date/Time (t-0)
Time
Date/Time (t-0)
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
BA Time
BA
Time
Zone
BA
DelFreq
Time
BA
Bias
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq MW/Load Lost
Adjustment
Value "B" Information
MW/Load Lost
Adjustment
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
Value "A"
[email protected]
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Event
Number
Value "B"
BA Delta
NAI
Load
Load
Reason(s)
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.0525249
-0.0709052
23.2
27.7
10.7
80.66089
-26.8976
1
2
3
4
5
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
CDT
CDT
CDT
CDT
CDT
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
N
N
N
N
N
1901
ERCOT
Bias Calculation Form 1 for Year
Interconnection
0.0
0.0
0.0
0.0
0.0
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
N
N
N
N
N
N
ERCOT
1
1
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.0519068
-0.0580477
-0.0755724
-0.0563805
-0.0573329
-0.0517609
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Y
1
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.0499992
-0.052
11.10075
-19.9068
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
-286
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.0559998
12.32546
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
BA Bias Type and Bias Setting
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.0584984
-0.0485001
-0.0450001
-0.0375023
-0.0475006
20
21
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
Fixed
0.750192
2.230058
9.477859
0.355309
2.170702
Bias Type utilized.
0.0
0.0
-0.0555
22
23
24
25
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
29.38207
0.90%
65300
-587.70
#DIV/0!
#DIV/0!
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.047
-0.06
-0.06
-0.051
-0.1
4.601381
1.593515
52.37091
33.94787
100
26
27
28
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
n/a
-653.00
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-653.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
-529.36
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
-529.36
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Do you RECEIVE Overlap regulation?
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1900
-286.00
-286.00
Calculate Regression
N
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
If Yes, list the BA name and the associated Bias of that BA in the table below.
Bias -MW/0.1 Hz
N
Bias -MW/0.1 Hz
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
ERCOT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
ERCOT
59.5
59.3
60.5
60.7
HQ
58.5
61.5
10 X BA
DelFreq
For Bias
10 X BA
DelFreq
For R1
SEFRDB
SEFRDR
(MW/0.1Hz) (MW/0.1Hz)
Regression
Statistics
For Bias
421.0875
726.0243
518.4755
785.5412
691.8045
-1.014658
-1.212405
-0.89661
-1.445673
-1.32911
-1.01466
-1.21241
-0.89661
-1.44567
-1.32911
-415.0044
-598.8298
-578.262
-543.3742
-520.5021
-415.0044
-598.8298
-578.262
-543.3742
-520.5021
-226.24
661.2317
995.0827
533.3253
762.3234
480.61
0.355891
-1.311035
-1.97183
-0.920725
-1.179408
-0.929121
0.355891
-1.31103
-1.97183
-0.92072
-1.17941
-0.92912
-635.7002
-504.3586
-504.6492
-579.245
-646.3608
-517.2738
-635.7002
-504.3586 For R1
-504.6492 -529.362
-579.245 18.2575
-646.3608 0.98708
-517.2738 840.664
-529.362
18.2575
0.98708
840.664
4731351
0
#N/A
75.0207
11
386.25
-0.942728
-0.94273
-409.7153
-409.7153
61909.2
4731351
0
#N/A
75.0207
11
61909.2
003254
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003255
Balancing Authority ERCOT
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
DelFreq
Load
Resources
Tripped
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value
B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment which is
only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003256
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
Time
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
ERCOT
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
003257
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Frequency
Hz
Contingent
Resource
Lost
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
#DIV/0!
#DIV/0!
#DIV/0!
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
#DIV/0!
#DIV/0!
Unadjusted
PFR
Performance
@ T(+46)
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Bias While
Hz > +/-0.036
Hz
MW/0.1 Hz
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003258
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
003259
ERCOT
ERCOT
T20 to T52 Average Performance
Initial Performance Adjusted P.U. Based on Bias Setting
1.00
0.80
0.80
0.60
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
ERCOT
9
10
11
12
Performance based on Hz at T+76
ERCOT
Performance based on Hz at T+46
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
1
12
3
4
5
Performance based on Hz at T+106
6
7
8
9
10
11
12
Performance based on Hz at T+136
ERCOT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Event
Event
ERCOT
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
FRI - NERC Frequency Response Initiative
#DIV/0 Average P.U. Performance
#DIV/0! MW/0.1 Hz Median
1.00
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
ERCOT
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
Event Recovery Period Average Performance
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
P.U.
P.U.
1.20
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003260
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003261
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
HQT
Enter Addition Data in column W ==>
Event
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time
(MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
Time
BA
Bias
DelFreq
MW/Load Lost
Adjustment
1
2
3
4
5
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
Date/Time (t-0)
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Y
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
1900
-179.00
-179.00
20
21
22
23
24
25
26
27
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
BA Time
BA
Time
Zone
BA
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq MW/Load Lost
Adjustment
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
N
N
N
N
N
N
N
N
N
N
N
Value "A"
[email protected]
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Value "B"
BA Delta
NAI
Load
Load
1
1
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
1
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
1901
HQ
HQT
Calculate Regression
BA Bias Type and Bias Setting
Fixed
0.90%
37153
-334.38
#DIV/0!
#DIV/0!
n/a
-442.00
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-442.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
0.00
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
0.00
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Reason(s)
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
HQT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For Bias
For R1
For Bias
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
#N/A
0
0
#DIV/0!
0
1
0
0
0
#DIV/0!
0
#NUM!
12
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
0
#DIV/0!
0 For R1
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
#N/A
0
0
#DIV/0!
0
1
0
0
0
#DIV/0!
0
#NUM!
12
0
0
0
#DIV/0!
0
0
0
0
0
0
0
0
0
0
0
0
0
0
003262
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003263
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
HQT
Load
Resources
Tripped
Value A
Value B
DelFreq Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
003264
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003265
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
HQT
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Frequency
Hz
Contingent
Resource
Lost
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
003266
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003267
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
T20 to T52 Average Performance
HQT
#DIV/0! MW/0.1 Hz Median
Event Recovery Period Average Performance
HQT
Initial Performance Adjusted P.U. Based on Bias Setting
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
#DIV/0 Average P.U. Performance
1.00
1.00
0.80
0.80
0.60
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
10
11
12
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
9
Performance based on Hz at T+76
HQT
Performance based on Hz at T+46
HQT
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
Event
8
9
10
11
1
12
3
4
5
6
7
8
9
10
11
12
Event
Performance based on Hz at T+136
HQT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Performance based on Hz at T+106
HQT
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
Performance based on Hz at T+166
HQT
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
T+166 Performance Adjusted P.U. Based on Bias Setting
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
FRI - NERC Frequency Response Initiative
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
P.U.
P.U.
1.20
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003268
003269
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003270
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
MyBA
Enter Addition Data in column W ==>
Event
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time
(MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
BA Time
BA
Time
Zone
Time
BA
Bias
DelFreq
Relay Lmt
R1
DelFreq
NAI
Adjustment
NAI
Adjustment
1
2
3
4
5
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
Date/Time (t-0)
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
BA
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
N
N
N
N
N
N
N
N
N
N
N
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Y
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-964
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
1900
#DIV/0!
20
21
22
23
24
25
26
27
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
DelFreq
Value "A" Information
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
1901
Eastern
MyBA
Value "A"
[email protected]
Value "B"
BA Delta
NAI
Load
Load
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
Calculate Regression
BA Bias Type and Bias Setting
Fixed
0.90%
621018
#DIV/0!
#DIV/0!
#DIV/0!
n/a
-20.87
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: May be set to a value between 100% to 125% of its FRM if this value is more negative than the minimum Bias based on Peak
Demand. If not more negative, then the Bias must be the minimum Bias based on Peak Demand. If variable Bias is used, enter "Variable".
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
#DIV/0!
1901 Frequency Bias Setting - (minimum of 100% to 125% of FRM, or 0.9% of Historical Peak Demand if not Variable)
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
0.00
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
0.00
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Reason(s)
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of
this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
MyBA_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For Bias
For R1
For Bias
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
#N/A
0
595
#DIV/0!
0
1
0
0
595
#DIV/0!
0
#NUM!
12
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
595
#DIV/0!
0 For R1
0
595
#DIV/0!
0
0
0
0
595
#DIV/0!
0
0
#N/A
0
595
#DIV/0!
0
1
0
0
595
#DIV/0!
0
#NUM!
11
0
0
595
#DIV/0!
0
0
0
0
0
0
0
0
0
0
0
0
0
0
003271
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003272
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
MyBA
JOU
Dynamic
Schedules
Value A
Value B
DelFreq Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Non
conforming
Load
Pumped Hydro
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Transferred
Frequency
Response
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003273
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
MyBA
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Bias
Frequency Interchange Imp(-) Exp (+)
Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
20 to 52 second Average Period Evaluation
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+)
Hz
MW
MW
MW
MW
Ramping
Units
Gen (+)
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
003274
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003275
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
003276
003277
003278
003279
003280
003281
003282
T20 to T52 Average Performance
MyBA
Initial Performance Adjusted P.U. Based on Bias Setting
#DIV/0! MW/0.1 Hz Median
1.00
0.80
0.80
0.60
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
9
10
11
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
0.800
0.800
P.U.
1.000
0.600
Performance based on Hz at T+76
MyBA
Performance based on Hz at T+46
MyBA
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
MyBA
11
1
12
Performance
based on Hz at T+106
T+106 Performance Adjusted P.U. Based on Bias Setting
0.800
P.U.
1.000
0.800
4
5
6
7
8
9
10
MyBA
11
12 Performance based on Hz at T+136
0.600
0.400
0.400
0.200
0.200
0.000
3
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
0.600
2
Event
Event
Adjusted PFR Performance @ T(+46) P.U.
1.200
P.U.
FRI - NERC Frequency Response Initiative
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
1.00
0.000
1
2
3
4
5
6
7
8
9
10
11
12
1
Event
Adjusted PFR Performance @ T(+106) P.U.
Performance based on Hz at T+166
MyBA
T+166 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
0.800
P.U.
Event Recovery Period Average Performance
#DIV/0 Average P.U. Performance
P.U.
P.U.
1.20
MyBA
0.600
0.400
0.200
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
Adjusted PFR Performance @ T(+166) P.U.
2
3
4
5
6
7
8
9
10
11
12
Event
Adjusted PFR Performance @ T(+136) P.U.
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003283
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003284
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
ERCOT
Enter Addition Data in column W ==>
Event
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time
(MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
Time
BA
Bias
DelFreq
MW/Load Lost
Adjustment
1
2
3
4
5
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
Date/Time (t-0)
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-286
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
1900
-286.00
-286.00
20
21
22
23
24
25
26
27
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
BA Time
BA
Time
Zone
BA
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq MW/Load Lost
Adjustment
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
N
N
N
N
N
N
N
N
N
N
N
N
Y
Value "A"
[email protected]
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Value "B"
BA Delta
NAI
Load
Load
1
1
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
1
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
1901
ERCOT
ERCOT
Calculate Regression
BA Bias Type and Bias Setting
Fixed
0.90%
65300
-587.70
#DIV/0!
#DIV/0!
n/a
-653.00
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-653.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
-529.36
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
-529.36
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Reason(s)
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
ERCOT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
421.08749
726.02426
518.4755
785.54117
691.80448
-226.24
661.23172
995.08267
533.32526
762.32339
480.61002
386.25
10 X BA
10 X BA
DelFreq
DelFreq
For Bias
For R1
-1.014658 -1.014658
-1.212405 -1.212405
-0.89661
-0.89661
-1.445673 -1.445673
-1.32911
-1.32911
0.3558911 0.355891
-1.311035 -1.311035
-1.97183
-1.97183
-0.920725 -0.920725
-1.179408 -1.179408
-0.929121 -0.929121
-0.942728
SEFRDB
SEFRDR
(MW/0.1Hz) (MW/0.1Hz)
Regression
Statistics
For Bias
-415.00442
-598.8298
-578.26195
-543.37416
-520.50213
-635.70015
-504.3586
-504.6492
-579.24498
-646.3608
-517.2738
-415.00442
-598.8298
-578.26195
-543.37416
-520.50213
-635.70015
-504.3586
-504.6492
-579.24498
-646.3608
-517.2738
-529.362
0
18.25749
#N/A
0.987084 75.02074
840.664
11
4731351 61909.23
For R1
-529.362
0
18.25749
#N/A
0.987084 75.02074
840.664
11
-0.942728 -409.71529
-409.71529
4731351 61909.23
003285
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003286
Balancing Authority ERCOT
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
Load
Resources
Tripped
Value A
Value B
DelFreq Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Non
conforming
Load
Not Used
Not Used
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003287
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
ERCOT
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Frequency
Hz
Contingent
Resource
Lost
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
003288
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003289
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
003290
T20 to T52 Average Performance
ERCOT
Initial Performance Adjusted P.U. Based on Bias Setting
#DIV/0! MW/0.1 Hz Median
1.00
0.80
0.80
0.60
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
9
10
11
12
Performance based on Hz at T+76
ERCOT
Performance based on Hz at T+46
ERCOT
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
Event
8
9
10
11
1
12
3
4
5
6
7
8
9
10
11
12
Event
Performance based on Hz at T+136
ERCOT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Performance based on Hz at T+106
ERCOT
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
FRI - NERC Frequency Response Initiative
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
1.00
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
ERCOT
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
Event Recovery Period Average Performance
#DIV/0 Average P.U. Performance
P.U.
P.U.
1.20
ERCOT
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003291
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
003292
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
HQT
Enter Addition Data in column W ==>
Event
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time
(MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
Time
BA
Bias
DelFreq
MW/Load Lost
Adjustment
1
2
3
4
5
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
Date/Time (t-0)
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Y
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
1900
-179.00
-179.00
20
21
22
23
24
25
26
27
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
BA Time
BA
Time
Zone
BA
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq MW/Load Lost
Adjustment
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
N
N
N
N
N
N
N
N
N
N
N
Value "A"
[email protected]
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
Select Reason(s) for adjustment
Information
Value "B"
BA Delta
NAI
Load
Load
1
1
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
1
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
1901
HQ
HQT
Calculate Regression
BA Bias Type and Bias Setting
Fixed
0.90%
37153
-334.38
#DIV/0!
#DIV/0!
n/a
-442.00
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-442.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
0.00
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
0.00
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Reason(s)
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
HQT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For Bias
For R1
For Bias
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
#N/A
0
0
#DIV/0!
0
1
0
0
0
#DIV/0!
0
#NUM!
12
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
0
#DIV/0!
0 For R1
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
#N/A
0
0
#DIV/0!
0
1
0
0
0
#DIV/0!
0
#NUM!
12
0
0
0
#DIV/0!
0
0
0
0
0
0
0
0
0
0
0
0
0
0
003293
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
003294
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
HQT
Load
Resources
Tripped
Value A
Value B
DelFreq Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Non
conforming
Load
Not Used
Not Used
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
003295
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
HQT
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Frequency
Hz
Contingent
Resource
Lost
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
003296
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
003297
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
003298
T20 to T52 Average Performance
HQT
Initial Performance Adjusted P.U. Based on Bias Setting
#DIV/0! MW/0.1 Hz Median
1.00
1.00
0.80
0.80
0.60
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
10
11
12
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
9
Performance based on Hz at T+76
HQT
Performance based on Hz at T+46
HQT
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
Event
8
9
10
11
1
12
3
4
5
6
7
8
9
10
11
12
Event
Performance based on Hz at T+136
HQT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Performance based on Hz at T+106
HQT
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
HQT
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
FRI - NERC Frequency Response Initiative
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
#DIV/0 Average P.U. Performance
P.U.
P.U.
1.20
Event Recovery Period Average Performance
HQT
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
003299
Time (T)
10/12/09 02:17:26
10/12/09 02:17:28
10/12/09 02:17:30
10/12/09 02:17:32
10/12/09 02:17:34
10/12/09 02:17:36
10/12/09 02:17:38
10/12/09 02:17:40
10/12/09 02:17:42
10/12/09 02:17:44
10/12/09 02:17:46
10/12/09 02:17:48
10/12/09 02:17:50
10/12/09 02:17:52
10/12/09 02:17:54
10/12/09 02:17:56
10/12/09 02:17:58
10/12/09 02:18:00
10/12/09 02:18:02
10/12/09 02:18:04
10/12/09 02:18:06
10/12/09 02:18:08
10/12/09 02:18:10
10/12/09 02:18:12
10/12/09 02:18:14
10/12/09 02:18:16
10/12/09 02:18:18
10/12/09 02:18:20
10/12/09 02:18:22
10/12/09 02:18:24
10/12/09 02:18:26
10/12/09 02:18:28
10/12/09 02:18:30
10/12/09 02:18:32
10/12/09 02:18:34
10/12/09 02:18:36
10/12/09 02:18:38
10/12/09 02:18:40
10/12/09 02:18:42
Hz
60.007
60.009
60.009
60.006
60.006
60.009
60.009
60.008
60.009
60.009
60.005
60.004
60.001
59.999
59.993
59.991
59.994
59.992
59.994
59.992
59.994
59.995
59.993
59.99
59.99
59.987
59.983
59.977
59.977
59.989
59.995
59.999
59.994
59.989
59.987
59.986
59.984
59.983
59.985
Net
Actual
Interchange
MW
3679.946
3679.44
3679.912
3679.517
3679.888
3679.608
3679.06
3679.261
3679.164
3679.025
3679.152
3678.572
3678.295
3678.249
3678.236
3677.83
3677.955
3677.772
3676.666
3677.093
3677.141
3676.401
3678.516
3679.872
3680.197
3678.743
3678.428
3677.921
3680.254
3682.07
3681.329
3678.656
3678.077
3677.78
3678.427
3678.473
3678.278
3677.822
3676.615
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
Not
Used
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
-0.003
0.000
0.003
0.000
-0.001
0.001
0.000
-0.004
-0.001
-0.003
-0.002
-0.006
-0.002
0.003
-0.002
0.002
-0.002
0.002
0.001
-0.002
-0.003
0.000
-0.003
-0.004
-0.006
0.000
0.012
0.006
0.004
-0.005
-0.005
-0.002
-0.001
-0.002
-0.001
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.003
0.000
0.003
0.000
0.001
0.001
0.000
0.004
0.001
0.003
0.002
0.006
0.002
0.003
0.002
0.002
0.002
0.002
0.001
0.002
0.003
0.000
0.003
0.004
0.006
0.000
0.012
0.006
0.004
0.005
0.005
0.002
0.001
0.002
0.001
0.002
003300
Time (T)
10/12/09 02:18:44
10/12/09 02:18:46
10/12/09 02:18:48
10/12/09 02:18:50
10/12/09 02:18:52
10/12/09 02:18:54
10/12/09 02:18:56
10/12/09 02:18:58
10/12/09 02:19:00
10/12/09 02:19:02
10/12/09 02:19:04
10/12/09 02:19:06
10/12/09 02:19:08
10/12/09 02:19:10
10/12/09 02:19:12
10/12/09 02:19:14
10/12/09 02:19:16
10/12/09 02:19:18
10/12/09 02:19:20
10/12/09 02:19:22
10/12/09 02:19:24
10/12/09 02:19:26
10/12/09 02:19:28
10/12/09 02:19:30
10/12/09 02:19:32
10/12/09 02:19:34
10/12/09 02:19:36
10/12/09 02:19:38
10/12/09 02:19:40
10/12/09 02:19:42
10/12/09 02:19:44
10/12/09 02:19:46
10/12/09 02:19:48
10/12/09 02:19:50
10/12/09 02:19:52
10/12/09 02:19:54
10/12/09 02:19:56
10/12/09 02:19:58
10/12/09 02:20:00
Hz
59.986
59.985
59.986
59.98
59.981
59.981
59.989
59.998
60.007
60.007
59.997
59.986
59.981
59.977
59.974
59.976
59.974
59.974
59.977
59.979
59.979
59.982
59.984
59.987
59.988
59.988
59.987
59.987
59.987
59.985
59.984
59.982
59.983
59.989
59.989
59.988
59.984
59.982
59.983
Net
Actual
Interchange
MW
3677.397
3677.917
3677.95
3678.617
3678.963
3681.252
3680.737
3680.045
3678.161
3674.076
3676.222
3676.669
3677.497
3677.49
3675.186
3675.437
3680.451
3682.032
3683.829
3682.843
3681.108
3680.566
3678.229
3676.752
3675.759
3671.942
3671.166
3670.476
3670.129
3671.542
3672.048
3671.576
3672.104
3672.414
3671.882
3671.837
3671.336
3670.726
3670.372
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-256.307251
0
-249.086395
0
-249.086395
0
-249.086395
0
-249.086395
0
-249.086395
0
-253.742477
0
-253.742477
0
-253.742477
0
-253.742477
0
-253.742477
0
-257.421204
0
-257.421204
0
-257.421204
0
-257.421204
0
-257.421204
0
-261.73822
0
-261.73822
0
-261.73822
0
-261.73822
0
-261.73822
0
-271.875977
0
-271.875977
0
-271.875977
0
-271.875977
0
-271.875977
0
-262.073486
0
-262.073486
0
-262.073486
0
-262.073486
0
-262.073486
0
-260.36441
0
-260.36441
0
-260.36441
0
-260.36441
0
-260.36441
0
-352.644379
0
-352.644379
0
-352.644379
0
Not
Used
101
101.5
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7566.66
7566.99
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.001
-0.001
0.001
-0.006
0.001
0.000
0.008
0.009
0.009
0.000
-0.010
-0.011
-0.005
-0.004
-0.003
0.002
-0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.001
-0.002
0.001
0.006
0.000
-0.001
-0.004
-0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.001
0.001
0.006
0.001
0.000
0.008
0.009
0.009
0.000
0.010
0.011
0.005
0.004
0.003
0.002
0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
0.001
0.000
0.000
0.002
0.001
0.002
0.001
0.006
0.000
0.001
0.004
0.002
0.001
003301
Time (T)
10/12/09 02:20:02
10/12/09 02:20:04
10/12/09 02:20:06
10/12/09 02:20:08
10/12/09 02:20:10
10/12/09 02:20:12
10/12/09 02:20:14
10/12/09 02:20:16
10/12/09 02:20:18
10/12/09 02:20:20
10/12/09 02:20:22
10/12/09 02:20:24
10/12/09 02:20:26
10/12/09 02:20:28
10/12/09 02:20:30
10/12/09 02:20:32
10/12/09 02:20:34
10/12/09 02:20:36
10/12/09 02:20:38
10/12/09 02:20:40
10/12/09 02:20:42
10/12/09 02:20:44
10/12/09 02:20:46
10/12/09 02:20:48
10/12/09 02:20:50
10/12/09 02:20:52
10/12/09 02:20:54
10/12/09 02:20:56
10/12/09 02:20:58
10/12/09 02:21:00
10/12/09 02:21:02
10/12/09 02:21:04
10/12/09 02:21:06
10/12/09 02:21:08
10/12/09 02:21:10
10/12/09 02:21:12
10/12/09 02:21:14
10/12/09 02:21:16
10/12/09 02:21:18
Hz
59.981
59.982
59.983
59.986
59.989
59.987
59.985
59.98
59.98
59.983
59.98
59.979
59.979
59.981
59.981
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.981
59.979
59.976
59.977
59.972
59.971
59.973
59.973
59.973
59.974
59.971
59.975
59.977
59.977
59.975
59.976
59.98
Net
Actual
Interchange
MW
3671.364
3671.401
3672.156
3672.181
3670.296
3668.071
3668.59
3669.908
3670.399
3670.263
3669.382
3670.102
3670.438
3671.403
3672.442
3672.372
3671.947
3670.938
3670.705
3670.137
3669.279
3672.391
3672.558
3674.052
3672.626
3671.8
3673.183
3673.874
3676.263
3676.623
3676.87
3676.543
3675.464
3675.752
3675.256
3674.87
3671.277
3671.593
3670.587
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-352.644379
0
-352.644379
0
-354.89566
0
-354.89566
0
-354.89566
0
-354.89566
0
-354.89566
0
-340.46936
0
-340.46936
0
-340.46936
0
-340.46936
0
-340.46936
0
-337.642914
0
-337.642914
0
-337.642914
0
-337.642914
0
-337.642914
0
-284.36084
0
-284.36084
0
-284.36084
0
-284.36084
0
-284.36084
0
-260.467987
0
-260.467987
0
-260.467987
0
-260.467987
0
-260.467987
0
-253.141541
0
-253.141541
0
-253.141541
0
-253.141541
0
-253.141541
0
-251.929871
0
-251.929871
0
-251.929871
0
-251.929871
0
-251.929871
0
-250.674194
0
-250.674194
0
Not
Used
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.002
0.001
0.001
0.003
0.003
-0.002
-0.002
-0.005
0.000
0.003
-0.003
-0.001
0.000
0.002
0.000
-0.001
0.000
0.001
-0.001
0.000
-0.003
0.002
0.002
-0.002
-0.003
0.001
-0.005
-0.001
0.002
0.000
0.000
0.001
-0.003
0.004
0.002
0.000
-0.002
0.001
0.004
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.001
0.001
0.003
0.003
0.002
0.002
0.005
0.000
0.003
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.003
0.002
0.002
0.002
0.003
0.001
0.005
0.001
0.002
0.000
0.000
0.001
0.003
0.004
0.002
0.000
0.002
0.001
0.004
003302
Time (T)
10/12/09 02:21:20
10/12/09 02:21:22
10/12/09 02:21:24
10/12/09 02:21:26
10/12/09 02:21:28
10/12/09 02:21:30
10/12/09 02:21:32
10/12/09 02:21:34
10/12/09 02:21:36
10/12/09 02:21:38
10/12/09 02:21:40
10/12/09 02:21:42
10/12/09 02:21:44
10/12/09 02:21:46
10/12/09 02:21:48
10/12/09 02:21:50
10/12/09 02:21:52
10/12/09 02:21:54
10/12/09 02:21:56
10/12/09 02:21:58
10/12/09 02:22:00
10/12/09 02:22:02
10/12/09 02:22:04
10/12/09 02:22:06
10/12/09 02:22:08
10/12/09 02:22:10
10/12/09 02:22:12
10/12/09 02:22:14
10/12/09 02:22:16
10/12/09 02:22:18
10/12/09 02:22:20
10/12/09 02:22:22
10/12/09 02:22:24
10/12/09 02:22:26
10/12/09 02:22:28
10/12/09 02:22:30
10/12/09 02:22:32
10/12/09 02:22:34
10/12/09 02:22:36
Hz
59.979
59.981
59.982
59.982
59.982
59.982
59.981
59.982
59.984
59.985
59.987
59.989
59.993
59.996
59.998
59.998
60.004
60.007
60.01
60.013
60.014
60.013
60.008
60.008
60.01
60.019
60.019
60.023
60.021
60.02
60.021
60.021
60.02
60.019
60.019
60.022
60.025
60.025
60.026
Net
Actual
Interchange
MW
3669.963
3669.54
3669.497
3668.706
3667.677
3666.482
3666.599
3666.911
3666.442
3666.405
3667.456
3666.38
3665.262
3664.031
3663.825
3663.229
3662.055
3661.695
3662.076
3662.224
3662.959
3663.794
3664.139
3665.278
3664.159
3663.265
3663.184
3661.929
3661.512
3659.172
3658.661
3656.785
3657.571
3658.126
3657.71
3658.015
3660.228
3659.224
3658.698
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-250.674194
0
-250.674194
0
-250.674194
0
-253.631866
0
-253.631866
0
-253.631866
0
-253.631866
0
-253.631866
0
-246.957306
0
-246.957306
0
-246.957306
0
-246.957306
0
-246.957306
0
-254.541779
0
-254.541779
0
-254.541779
0
-254.541779
0
-254.541779
0
-256.571594
0
-256.571594
0
-256.571594
0
-256.571594
0
-256.571594
0
-258.37262
0
-258.37262
0
-258.37262
0
-258.37262
0
-258.37262
0
-263.047363
0
-263.047363
0
-263.047363
0
-263.047363
0
-263.047363
0
-260.984375
0
-260.984375
0
-260.984375
0
-260.984375
0
-260.984375
0
-261.318329
0
Not
Used
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
0.002
0.001
0.000
0.000
0.000
-0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
-0.001
-0.005
0.000
0.002
0.009
0.000
0.004
-0.002
-0.001
0.001
0.000
-0.001
-0.001
0.000
0.003
0.003
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
0.001
0.005
0.000
0.002
0.009
0.000
0.004
0.002
0.001
0.001
0.000
0.001
0.001
0.000
0.003
0.003
0.000
0.001
003303
Time (T)
10/12/09 02:22:38
10/12/09 02:22:40
10/12/09 02:22:42
10/12/09 02:22:44
10/12/09 02:22:46
10/12/09 02:22:48
10/12/09 02:22:50
10/12/09 02:22:52
10/12/09 02:22:54
10/12/09 02:22:56
10/12/09 02:22:58
10/12/09 02:23:00
10/12/09 02:23:02
10/12/09 02:23:04
10/12/09 02:23:06
10/12/09 02:23:08
10/12/09 02:23:10
10/12/09 02:23:12
10/12/09 02:23:14
10/12/09 02:23:16
10/12/09 02:23:18
10/12/09 02:23:20
10/12/09 02:23:22
10/12/09 02:23:24
10/12/09 02:23:26
10/12/09 02:23:28
10/12/09 02:23:30
10/12/09 02:23:32
10/12/09 02:23:34
10/12/09 02:23:36
10/12/09 02:23:38
10/12/09 02:23:40
10/12/09 02:23:42
10/12/09 02:23:44
10/12/09 02:23:46
10/12/09 02:23:48
10/12/09 02:23:50
10/12/09 02:23:52
10/12/09 02:23:54
Hz
60.02
60.02
60.018
60.018
60.02
60.019
60.019
60.023
60.022
60.022
60.025
60.02
60.02
60.02
60.02
60.02
60.021
60.021
60.018
60.014
60.014
60.014
60.013
60.013
60.01
60.008
60.011
60.011
60.012
60.012
60.009
60.009
60.009
60.009
60.005
60.002
59.999
59.996
59.995
Net
Actual
Interchange
MW
3658.669
3658.155
3659.13
3659.778
3660.82
3662.531
3662.387
3662.079
3662.39
3662.678
3663.577
3663.539
3662.959
3662.552
3662.543
3663.601
3663.91
3663.69
3662.791
3663.396
3663.698
3664.315
3665.313
3665.798
3666.141
3666.726
3667.677
3667.545
3666.688
3666.449
3666.71
3667.696
3667.398
3667.043
3666.624
3666.223
3665.88
3665.403
3665.802
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-261.318329
0
-261.318329
0
-261.318329
0
-261.318329
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.71701
0
-262.71701
0
-262.71701
0
-262.71701
0
-262.71701
0
-260.016479
0
-260.016479
0
-260.016479
0
-260.016479
0
-260.016479
0
-263.87323
0
-263.87323
0
-263.87323
0
-263.87323
0
-263.87323
0
-264.5979
0
-264.5979
0
-264.5979
0
-264.5979
0
-264.5979
0
-262.415924
0
-262.415924
0
-262.415924
0
-262.415924
0
-262.415924
0
-259.685242
0
-259.685242
0
-259.685242
0
-259.685242
0
-259.685242
0
Not
Used
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.006
0.000
-0.002
0.000
0.002
-0.001
0.000
0.004
-0.001
0.000
0.003
-0.005
0.000
0.000
0.000
0.000
0.001
0.000
-0.003
-0.004
0.000
0.000
-0.001
0.000
-0.003
-0.002
0.003
0.000
0.001
0.000
-0.003
0.000
0.000
0.000
-0.004
-0.003
-0.003
-0.003
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.006
0.000
0.002
0.000
0.002
0.001
0.000
0.004
0.001
0.000
0.003
0.005
0.000
0.000
0.000
0.000
0.001
0.000
0.003
0.004
0.000
0.000
0.001
0.000
0.003
0.002
0.003
0.000
0.001
0.000
0.003
0.000
0.000
0.000
0.004
0.003
0.003
0.003
0.001
003304
Time (T)
10/12/09 02:23:56
10/12/09 02:23:58
10/12/09 02:24:00
10/12/09 02:24:02
10/12/09 02:24:04
10/12/09 02:24:06
10/12/09 02:24:08
10/12/09 02:24:10
10/12/09 02:24:12
10/12/09 02:24:14
10/12/09 02:24:16
10/12/09 02:24:18
10/12/09 02:24:20
10/12/09 02:24:22
10/12/09 02:24:24
10/12/09 02:24:26
10/12/09 02:24:28
10/12/09 02:24:30
10/12/09 02:24:32
10/12/09 02:24:34
10/12/09 02:24:36
10/12/09 02:24:38
10/12/09 02:24:40
10/12/09 02:24:42
10/12/09 02:24:44
10/12/09 02:24:46
10/12/09 02:24:48
10/12/09 02:24:50
10/12/09 02:24:52
10/12/09 02:24:54
10/12/09 02:24:56
10/12/09 02:24:58
10/12/09 02:25:00
10/12/09 02:25:02
10/12/09 02:25:04
10/12/09 02:25:06
10/12/09 02:25:08
10/12/09 02:25:10
10/12/09 02:25:12
Hz
59.997
59.998
59.998
59.998
59.998
59.995
59.995
59.992
59.993
59.988
59.988
59.982
59.982
59.982
59.982
59.984
59.982
59.978
59.978
59.976
59.975
59.974
59.974
59.979
59.98
59.981
59.98
59.984
59.987
59.988
59.988
59.99
59.992
59.991
59.991
59.991
59.993
59.993
59.996
Net
Actual
Interchange
MW
3665.68
3665.352
3664.948
3665.065
3666.133
3666.64
3666.735
3667.084
3667.557
3667.337
3667.853
3668.116
3668.691
3669.399
3669.606
3671.228
3670.25
3670.265
3671.549
3673.243
3674.263
3675.824
3676.418
3676.306
3674.637
3675.329
3675.226
3674.768
3674.399
3673.514
3673.04
3672.442
3673.056
3671.68
3671.493
3669.53
3670.066
3670.028
3671.744
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-255.911011
0
-255.911011
0
-255.911011
0
-255.911011
0
-255.911011
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.873596
0
-258.873596
0
-258.873596
0
-258.873596
0
-258.873596
0
-249.33757
0
-249.33757
0
-249.33757
0
-249.33757
0
-249.33757
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.406372
0
-258.406372
0
-258.406372
0
-258.406372
0
-258.406372
0
-260.538879
0
-260.538879
0
-260.538879
0
-260.538879
0
-260.538879
0
-257.88208
0
-257.88208
0
-257.88208
0
-257.88208
0
Not
Used
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.002
0.001
0.000
0.000
0.000
-0.003
0.000
-0.003
0.001
-0.005
0.000
-0.006
0.000
0.000
0.000
0.002
-0.002
-0.004
0.000
-0.002
-0.001
-0.001
0.000
0.005
0.001
0.001
-0.001
0.004
0.003
0.001
0.000
0.002
0.002
-0.001
0.000
0.000
0.002
0.000
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.001
0.000
0.000
0.000
0.003
0.000
0.003
0.001
0.005
0.000
0.006
0.000
0.000
0.000
0.002
0.002
0.004
0.000
0.002
0.001
0.001
0.000
0.005
0.001
0.001
0.001
0.004
0.003
0.001
0.000
0.002
0.002
0.001
0.000
0.000
0.002
0.000
0.003
003305
Time (T)
10/12/09 02:25:14
10/12/09 02:25:16
10/12/09 02:25:18
10/12/09 02:25:20
10/12/09 02:25:22
10/12/09 02:25:24
10/12/09 02:25:26
10/12/09 02:25:28
10/12/09 02:25:30
10/12/09 02:25:32
10/12/09 02:25:34
10/12/09 02:25:36
10/12/09 02:25:38
10/12/09 02:25:40
10/12/09 02:25:42
10/12/09 02:25:44
10/12/09 02:25:46
10/12/09 02:25:48
10/12/09 02:25:50
10/12/09 02:25:52
10/12/09 02:25:54
10/12/09 02:25:56
10/12/09 02:25:58
10/12/09 02:26:00
10/12/09 02:26:02
10/12/09 02:26:04
10/12/09 02:26:06
10/12/09 02:26:08
10/12/09 02:26:10
10/12/09 02:26:12
10/12/09 02:26:14
10/12/09 02:26:16
10/12/09 02:26:18
10/12/09 02:26:20
10/12/09 02:26:22
10/12/09 02:26:24
10/12/09 02:26:26
10/12/09 02:26:28
10/12/09 02:26:30
Hz
60.002
60.002
60.003
60.004
60.005
60.004
60.002
60.004
60.008
60.01
60.01
60.01
60.011
60.013
60.014
60.013
60.012
60.011
60.011
60.017
60.022
60.017
60.014
60.013
60.014
60.017
60.017
60.019
60.019
60.019
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
Net
Actual
Interchange
MW
3671.578
3672.625
3672.674
3673.819
3673.25
3673.182
3673.496
3672.418
3672.363
3672.217
3672.261
3673.182
3673.603
3673.553
3674.312
3674.537
3673.813
3673.204
3672.563
3673.068
3672.388
3672.52
3671.25
3671.288
3672.989
3672.982
3672.915
3671.952
3671.193
3671.627
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-257.88208
0
-258.588654
0
-258.588654
0
-258.588654
0
-258.588654
0
-258.588654
0
-261.906158
0
-261.906158
0
-261.906158
0
-261.906158
0
-261.906158
0
-256.747803
0
-256.747803
0
-256.747803
0
-256.747803
0
-256.747803
0
-167.431976
0
-167.431976
0
-167.431976
0
-167.431976
0
-167.431976
0
-164.973404
0
-164.973404
0
-164.973404
0
-164.973404
0
-164.973404
0
-157.628082
0
-157.628082
0
-157.628082
0
-157.628082
0
-157.628082
0
-155.531708
0
-155.531708
0
-155.531708
0
-155.531708
0
-155.531708
0
-160.447235
0
-160.447235
0
-160.447235
0
Not
Used
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.006
0.000
0.001
0.001
0.001
-0.001
-0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
-0.001
-0.001
-0.001
0.000
0.006
0.005
-0.005
-0.003
-0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
-0.001
0.000
-0.004
-0.003
-0.002
0.002
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.006
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.006
0.005
0.005
0.003
0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
0.001
0.000
0.004
0.003
0.002
0.002
0.001
0.001
003306
Time (T)
10/12/09 02:26:32
10/12/09 02:26:34
10/12/09 02:26:36
10/12/09 02:26:38
10/12/09 02:26:40
10/12/09 02:26:42
10/12/09 02:26:44
10/12/09 02:26:46
10/12/09 02:26:48
10/12/09 02:26:50
10/12/09 02:26:52
10/12/09 02:26:54
10/12/09 02:26:56
10/12/09 02:26:58
10/12/09 02:27:00
10/12/09 02:27:02
10/12/09 02:27:04
10/12/09 02:27:06
10/12/09 02:27:08
10/12/09 02:27:10
10/12/09 02:27:12
10/12/09 02:27:14
10/12/09 02:27:16
10/12/09 02:27:18
10/12/09 02:27:20
10/12/09 02:27:22
10/12/09 02:27:24
10/12/09 02:27:26
10/12/09 02:27:28
10/12/09 02:27:30
10/12/09 02:27:32
10/12/09 02:27:34
10/12/09 02:27:36
10/12/09 02:27:38
10/12/09 02:27:40
10/12/09 02:27:42
10/12/09 02:27:44
10/12/09 02:27:46
10/12/09 02:27:48
Hz
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
Net
Actual
Interchange
MW
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.19
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3737.157
3761.25
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-160.447235
0
-160.447235
0
-163.958603
0
-163.958603
0
-163.958603
0
-163.958603
0
-163.958603
0
-166.072449
0
-166.072449
0
-166.072449
0
-166.072449
0
-166.072449
0
-163.766586
0
-163.766586
0
-163.766586
0
-163.766586
0
-163.766586
0
-165.101685
0
-165.101685
0
-165.101685
0
-165.101685
0
-165.101685
0
-165.476395
0
-165.476395
0
-165.476395
0
-165.476395
0
-165.476395
0
-206.459106
0
-206.459106
0
-206.459106
0
-206.459106
0
-206.459106
0
-211.256042
0
-211.256042
1
-211.256042
1
-211.256042
1
-211.256042
1
-214.346695
1
-214.346695
1
Not
Used
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
0.000
0.000
-0.002
-0.001
0.004
0.009
0.006
0.000
-0.001
0.001
0.009
0.002
0.000
-0.005
-0.002
0.000
0.000
-0.002
0.002
0.002
0.002
0.001
-0.005
0.000
0.000
-0.002
-0.061
-0.126
-0.016
0.033
0.023
-0.001
-0.011
-0.004
-0.001
0.008
0.004
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.000
0.002
0.001
0.004
0.009
0.006
0.000
0.001
0.001
0.009
0.002
0.000
0.005
0.002
0.000
0.000
0.002
0.002
0.002
0.002
0.001
0.005
0.000
0.000
0.002
0.061
0.126
0.016
0.033
0.023
0.001
0.011
0.004
0.001
0.008
0.004
0.001
003307
Time (T)
10/12/09 02:27:50
10/12/09 02:27:52
10/12/09 02:27:54
10/12/09 02:27:56
10/12/09 02:27:58
10/12/09 02:28:00
10/12/09 02:28:02
10/12/09 02:28:04
10/12/09 02:28:06
10/12/09 02:28:08
10/12/09 02:28:10
10/12/09 02:28:12
10/12/09 02:28:14
10/12/09 02:28:16
10/12/09 02:28:18
10/12/09 02:28:20
10/12/09 02:28:22
10/12/09 02:28:24
10/12/09 02:28:26
10/12/09 02:28:28
10/12/09 02:28:30
10/12/09 02:28:32
10/12/09 02:28:34
10/12/09 02:28:36
10/12/09 02:28:38
10/12/09 02:28:40
10/12/09 02:28:42
10/12/09 02:28:44
10/12/09 02:28:46
10/12/09 02:28:48
10/12/09 02:28:50
10/12/09 02:28:52
10/12/09 02:28:54
10/12/09 02:28:56
10/12/09 02:28:58
10/12/09 02:29:00
10/12/09 02:29:02
10/12/09 02:29:04
10/12/09 02:29:06
Hz
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
Net
Actual
Interchange
MW
3782.5
3784.962
3784.73
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.01
3813.783
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-214.346695
1
-214.346695
2
-214.346695
3
-212.172699
4
-212.172699
5
-212.172699
6
-212.172699
7
-212.172699
8
-215.598175
9
-215.598175
10
-215.598175
11
-215.598175
12
-215.598175
13
-218.327255
14
-218.327255
15
-218.327255
16
-218.327255
16
-218.327255
16
-217.379425
16
-217.379425
16
-217.379425
16
-217.379425
16
-217.379425
16
-214.830353
16
-214.830353
16
-214.830353
16
-214.830353
16
-214.830353
16
-227.655914
16
-227.655914
16
-227.655914
16
-227.655914
16
-227.655914
16
-225.018082
16
-225.018082
16
-225.018082
16
-225.018082
16
-225.018082
16
-228.365158
16
Not
Used
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.002
0.001
0.002
0.005
-0.001
-0.001
0.001
0.000
-0.003
-0.001
-0.005
0.000
0.003
-0.001
0.001
0.000
0.002
-0.001
-0.007
-0.009
-0.016
-0.008
0.003
0.006
0.005
0.003
-0.001
0.002
-0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.002
0.001
0.002
0.005
0.001
0.001
0.001
0.000
0.003
0.001
0.005
0.000
0.003
0.001
0.001
0.000
0.002
0.001
0.007
0.009
0.016
0.008
0.003
0.006
0.005
0.003
0.001
0.002
0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
0.003
003308
Time (T)
10/12/09 02:29:08
10/12/09 02:29:10
10/12/09 02:29:12
10/12/09 02:29:14
10/12/09 02:29:16
10/12/09 02:29:18
10/12/09 02:29:20
10/12/09 02:29:22
10/12/09 02:29:24
10/12/09 02:29:26
10/12/09 02:29:28
10/12/09 02:29:30
10/12/09 02:29:32
10/12/09 02:29:34
10/12/09 02:29:36
10/12/09 02:29:38
10/12/09 02:29:40
10/12/09 02:29:42
10/12/09 02:29:44
10/12/09 02:29:46
10/12/09 02:29:48
10/12/09 02:29:50
10/12/09 02:29:52
10/12/09 02:29:54
10/12/09 02:29:56
10/12/09 02:29:58
10/12/09 02:30:00
10/12/09 02:30:02
10/12/09 02:30:04
10/12/09 02:30:06
10/12/09 02:30:08
10/12/09 02:30:10
10/12/09 02:30:12
10/12/09 02:30:14
10/12/09 02:30:16
10/12/09 02:30:18
10/12/09 02:30:20
10/12/09 02:30:22
10/12/09 02:30:24
Hz
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
Net
Actual
Interchange
MW
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.67
3769.63
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-228.365158
16
-228.365158
16
-228.365158
16
-228.365158
16
-234.075333
16
-234.075333
16
-234.075333
16
-234.075333
16
-234.075333
16
-228.798157
16
-228.798157
16
-228.798157
16
-228.798157
16
-228.798157
16
-229.466965
16
-229.466965
16
-229.466965
16
-229.466965
16
-229.466965
16
-228.980164
16
-228.980164
16
-228.980164
16
-228.980164
16
-228.980164
16
-219.975555
16
-219.975555
16
-219.975555
16
-219.975555
16
-219.975555
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.663269
16
-229.663269
16
-229.663269
16
-229.663269
16
-229.663269
16
Not
Used
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
273.5
274
274.5
275
275.5
276
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.004
0.006
0.004
-0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
-0.001
-0.003
0.003
0.001
0.002
0.003
-0.001
0.003
-0.001
0.005
-0.005
0.001
0.003
-0.002
0.002
0.002
0.004
0.000
0.008
0.004
-0.002
-0.005
-0.001
0.001
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.004
0.006
0.004
0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
0.001
0.003
0.003
0.001
0.002
0.003
0.001
0.003
0.001
0.005
0.005
0.001
0.003
0.002
0.002
0.002
0.004
0.000
0.008
0.004
0.002
0.005
0.001
0.001
0.003
003309
Time (T)
10/12/09 02:30:26
10/12/09 02:30:28
10/12/09 02:30:30
10/12/09 02:30:32
10/12/09 02:30:34
10/12/09 02:30:36
10/12/09 02:30:38
10/12/09 02:30:40
10/12/09 02:30:42
10/12/09 02:30:44
10/12/09 02:30:46
10/12/09 02:30:48
10/12/09 02:30:50
10/12/09 02:30:52
10/12/09 02:30:54
10/12/09 02:30:56
10/12/09 02:30:58
10/12/09 02:31:00
10/12/09 02:31:02
10/12/09 02:31:04
10/12/09 02:31:06
10/12/09 02:31:08
10/12/09 02:31:10
10/12/09 02:31:12
10/12/09 02:31:14
10/12/09 02:31:16
10/12/09 02:31:18
10/12/09 02:31:20
10/12/09 02:31:22
10/12/09 02:31:24
10/12/09 02:31:26
10/12/09 02:31:28
10/12/09 02:31:30
10/12/09 02:31:32
10/12/09 02:31:34
10/12/09 02:31:36
10/12/09 02:31:38
10/12/09 02:31:40
10/12/09 02:31:42
Hz
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
Net
Actual
Interchange
MW
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.81
3712.092
3714.623
3715.13
3716.168
3716.461
3716.98
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.13
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-229.233856
16
-229.233856
16
-229.233856
16
-229.233856
16
-229.233856
16
-231.409882
16
-231.409882
16
-231.409882
16
-231.409882
16
-231.409882
16
-218.622284
16
-218.622284
16
-218.622284
16
-218.622284
16
-218.622284
16
-213.535858
16
-213.535858
16
-213.535858
16
-213.535858
16
-213.535858
16
-225.651855
16
-225.651855
16
-225.651855
16
-225.651855
16
-225.651855
16
-212.573639
16
-212.573639
16
-212.573639
16
-212.573639
16
-212.573639
16
-219.897293
16
-219.897293
16
-219.897293
16
-219.897293
16
-219.897293
16
-231.1754
16
-231.1754
16
-231.1754
16
-231.1754
16
Not
Used
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
-0.001
0.002
0.002
0.001
0.001
-0.002
0.001
0.000
0.000
0.003
-0.003
0.002
-0.002
0.001
0.000
-0.001
0.002
0.000
0.005
-0.002
-0.001
-0.002
0.002
-0.001
0.003
0.003
0.001
0.000
0.006
-0.002
0.000
0.002
0.002
0.004
-0.004
-0.001
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.000
0.001
0.002
0.000
0.005
0.002
0.001
0.002
0.002
0.001
0.003
0.003
0.001
0.000
0.006
0.002
0.000
0.002
0.002
0.004
0.004
0.001
0.000
0.001
003310
Time (T)
10/12/09 02:31:44
10/12/09 02:31:46
10/12/09 02:31:48
10/12/09 02:31:50
10/12/09 02:31:52
10/12/09 02:31:54
10/12/09 02:31:56
10/12/09 02:31:58
10/12/09 02:32:00
10/12/09 02:32:02
10/12/09 02:32:04
10/12/09 02:32:06
10/12/09 02:32:08
10/12/09 02:32:10
10/12/09 02:32:12
10/12/09 02:32:14
10/12/09 02:32:16
10/12/09 02:32:18
10/12/09 02:32:20
10/12/09 02:32:22
10/12/09 02:32:24
10/12/09 02:32:26
10/12/09 02:32:28
10/12/09 02:32:30
10/12/09 02:32:32
10/12/09 02:32:34
10/12/09 02:32:36
10/12/09 02:32:38
10/12/09 02:32:40
10/12/09 02:32:42
10/12/09 02:32:44
10/12/09 02:32:46
10/12/09 02:32:48
10/12/09 02:32:50
10/12/09 02:32:52
10/12/09 02:32:54
10/12/09 02:32:56
10/12/09 02:32:58
10/12/09 02:33:00
Hz
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
Net
Actual
Interchange
MW
3732.53
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.3
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.42
3778.554
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-231.1754
16
-226.634125
16
-226.634125
16
-226.634125
16
-226.634125
16
-226.634125
16
-227.255066
16
-227.255066
16
-227.255066
16
-227.255066
16
-227.255066
16
-229.290222
16
-229.290222
16
-229.290222
16
-229.290222
16
-229.290222
16
-221.461365
16
-221.461365
16
-221.461365
16
-221.461365
16
-221.461365
16
-241.274368
16
-241.274368
16
-241.274368
16
-241.274368
16
-241.274368
16
-243.071854
16
-243.071854
16
-243.071854
16
-243.071854
16
-243.071854
16
-241.670212
16
-241.670212
16
-241.670212
16
-241.670212
16
-241.670212
16
-228.149307
16
-228.149307
16
-228.149307
16
Not
Used
296
296.5
297
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7695
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.002
0.000
0.003
0.002
0.000
-0.002
0.002
-0.002
0.002
-0.001
0.003
0.002
-0.001
-0.001
-0.001
0.001
-0.001
0.004
0.000
0.001
0.004
0.001
-0.002
0.000
0.004
0.002
-0.001
-0.001
-0.002
-0.003
-0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.002
0.002
0.002
0.001
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.004
0.000
0.001
0.004
0.001
0.002
0.000
0.004
0.002
0.001
0.001
0.002
0.003
0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
003311
Time (T)
10/12/09 02:33:02
10/12/09 02:33:04
10/12/09 02:33:06
10/12/09 02:33:08
10/12/09 02:33:10
10/12/09 02:33:12
10/12/09 02:33:14
10/12/09 02:33:16
10/12/09 02:33:18
10/12/09 02:33:20
10/12/09 02:33:22
10/12/09 02:33:24
10/12/09 02:33:26
10/12/09 02:33:28
10/12/09 02:33:30
10/12/09 02:33:32
10/12/09 02:33:34
10/12/09 02:33:36
10/12/09 02:33:38
10/12/09 02:33:40
10/12/09 02:33:42
10/12/09 02:33:44
10/12/09 02:33:46
10/12/09 02:33:48
10/12/09 02:33:50
10/12/09 02:33:52
10/12/09 02:33:54
10/12/09 02:33:56
10/12/09 02:33:58
10/12/09 02:34:00
10/12/09 02:34:02
10/12/09 02:34:04
10/12/09 02:34:06
10/12/09 02:34:08
10/12/09 02:34:10
10/12/09 02:34:12
10/12/09 02:34:14
10/12/09 02:34:16
10/12/09 02:34:18
Hz
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
Net
Actual
Interchange
MW
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.85
3786.304
3787.259
3787.516
3787.955
3788.03
3788.607
3789.216
3787.537
3785.842
3786.077
3787.93
3788.76
3786.875
3786.55
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-228.149307
16
-228.149307
16
-235.128983
16
-235.128983
16
-235.128983
16
-235.128983
16
-235.128983
16
-246.433136
16
-246.433136
16
-246.433136
16
-246.433136
16
-246.433136
16
-236.553543
16
-236.553543
16
-236.553543
16
-236.553543
16
-236.553543
16
-230.297562
16
-230.297562
16
-230.297562
16
-230.297562
16
-230.297562
16
-231.175537
16
-231.175537
16
-231.175537
16
-231.175537
16
-231.175537
16
-225.61763
16
-225.61763
16
-225.61763
16
-225.61763
16
-225.61763
16
-230.734421
16
-230.734421
16
-230.734421
16
-230.734421
16
-230.734421
16
-234.847107
16
-234.847107
16
Not
Used
315.5
316
316.5
317
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
-0.004
0.000
0.002
0.004
0.001
0.001
-0.004
-0.002
0.005
0.000
-0.003
-0.001
0.005
-0.001
-0.004
0.000
0.002
0.000
0.000
-0.001
0.000
0.002
0.000
-0.001
-0.003
-0.003
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
0.004
0.000
0.002
0.004
0.001
0.001
0.004
0.002
0.005
0.000
0.003
0.001
0.005
0.001
0.004
0.000
0.002
0.000
0.000
0.001
0.000
0.002
0.000
0.001
0.003
0.003
0.002
003312
Time (T)
10/12/09 02:34:20
10/12/09 02:34:22
10/12/09 02:34:24
10/12/09 02:34:26
10/12/09 02:34:28
10/12/09 02:34:30
10/12/09 02:34:32
10/12/09 02:34:34
10/12/09 02:34:36
10/12/09 02:34:38
10/12/09 02:34:40
10/12/09 02:34:42
10/12/09 02:34:44
10/12/09 02:34:46
10/12/09 02:34:48
10/12/09 02:34:50
10/12/09 02:34:52
10/12/09 02:34:54
10/12/09 02:34:56
10/12/09 02:34:58
10/12/09 02:35:00
10/12/09 02:35:02
10/12/09 02:35:04
10/12/09 02:35:06
10/12/09 02:35:08
10/12/09 02:35:10
10/12/09 02:35:12
10/12/09 02:35:14
10/12/09 02:35:16
10/12/09 02:35:18
10/12/09 02:35:20
10/12/09 02:35:22
10/12/09 02:35:24
10/12/09 02:35:26
10/12/09 02:35:28
10/12/09 02:35:30
10/12/09 02:35:32
10/12/09 02:35:34
10/12/09 02:35:36
Hz
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
Net
Actual
Interchange
MW
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.54
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.54
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.41
3790.467
3790.665
3790.42
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-234.847107
16
-234.847107
16
-234.847107
16
-228.960922
16
-228.960922
16
-228.960922
16
-228.960922
16
-228.960922
16
-231.177917
16
-231.177917
16
-231.177917
16
-231.177917
16
-231.177917
16
-236.489288
16
-236.489288
16
-236.489288
16
-236.489288
16
-236.489288
16
-245.038925
16
-245.038925
16
-245.038925
16
-245.038925
16
-245.038925
16
-223.605682
16
-223.605682
16
-223.605682
16
-223.605682
16
-223.605682
16
-231.119354
16
-231.119354
16
-231.119354
16
-231.119354
16
-231.119354
16
-237.20665
16
-237.20665
16
-237.20665
16
-237.20665
16
-237.20665
16
-240.516373
16
Not
Used
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.000
0.001
0.000
-0.003
-0.001
0.001
-0.002
-0.001
-0.001
0.000
-0.002
-0.003
0.000
0.002
0.000
0.001
-0.007
-0.004
-0.004
-0.003
-0.001
0.001
0.000
-0.004
-0.002
-0.001
-0.001
0.001
-0.001
-0.002
-0.001
0.001
-0.003
-0.002
-0.001
0.000
0.003
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.001
0.000
0.002
0.003
0.000
0.002
0.000
0.001
0.007
0.004
0.004
0.003
0.001
0.001
0.000
0.004
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.003
0.002
0.001
0.000
0.003
0.003
003313
Time (T)
10/12/09 02:35:38
10/12/09 02:35:40
10/12/09 02:35:42
10/12/09 02:35:44
10/12/09 02:35:46
10/12/09 02:35:48
10/12/09 02:35:50
10/12/09 02:35:52
10/12/09 02:35:54
10/12/09 02:35:56
10/12/09 02:35:58
10/12/09 02:36:00
10/12/09 02:36:02
10/12/09 02:36:04
10/12/09 02:36:06
10/12/09 02:36:08
10/12/09 02:36:10
10/12/09 02:36:12
10/12/09 02:36:14
10/12/09 02:36:16
10/12/09 02:36:18
10/12/09 02:36:20
10/12/09 02:36:22
10/12/09 02:36:24
10/12/09 02:36:26
10/12/09 02:36:28
10/12/09 02:36:30
10/12/09 02:36:32
10/12/09 02:36:34
10/12/09 02:36:36
10/12/09 02:36:38
10/12/09 02:36:40
10/12/09 02:36:42
10/12/09 02:36:44
10/12/09 02:36:46
10/12/09 02:36:48
10/12/09 02:36:50
10/12/09 02:36:52
10/12/09 02:36:54
Hz
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
Net
Actual
Interchange
MW
3789.674
3789.267
3789.148
3790.43
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.08
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.69
3784.831
3785.01
3784.32
3782.809
3782.11
3779.352
3779.056
3778.633
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-240.516373
16
-240.516373
16
-240.516373
16
-240.516373
16
-237.566055
16
-237.566055
16
-237.566055
16
-237.566055
16
-237.566055
16
-231.581421
16
-231.581421
16
-231.581421
16
-231.581421
16
-231.581421
16
-235.850845
16
-235.850845
16
-235.850845
16
-235.850845
16
-235.850845
16
-233.559982
16
-233.559982
16
-233.559982
16
-233.559982
16
-233.559982
16
-219.009995
16
-219.009995
16
-219.009995
16
-219.009995
16
-219.009995
16
-205.338913
16
-205.338913
16
-205.338913
16
-205.338913
16
-205.338913
16
-236.285355
16
-236.285355
16
-236.285355
16
-236.285355
16
-236.285355
16
Not
Used
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
371.5
372
372.5
373
373.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.004
-0.002
-0.002
0.002
0.001
0.000
-0.002
-0.002
-0.004
0.001
0.001
0.002
0.005
0.003
-0.003
-0.003
-0.003
0.004
-0.001
-0.002
-0.004
-0.003
-0.001
0.001
0.003
0.001
-0.002
-0.003
-0.001
0.006
0.002
-0.005
0.000
0.002
-0.001
0.001
-0.002
0.000
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.004
0.002
0.002
0.002
0.001
0.000
0.002
0.002
0.004
0.001
0.001
0.002
0.005
0.003
0.003
0.003
0.003
0.004
0.001
0.002
0.004
0.003
0.001
0.001
0.003
0.001
0.002
0.003
0.001
0.006
0.002
0.005
0.000
0.002
0.001
0.001
0.002
0.000
0.001
003314
Time (T)
10/12/09 02:36:56
10/12/09 02:36:58
10/12/09 02:37:00
10/12/09 02:37:02
10/12/09 02:37:04
10/12/09 02:37:06
10/12/09 02:37:08
10/12/09 02:37:10
10/12/09 02:37:12
10/12/09 02:37:14
10/12/09 02:37:16
10/12/09 02:37:18
10/12/09 02:37:20
10/12/09 02:37:22
10/12/09 02:37:24
10/12/09 02:37:26
10/12/09 02:37:28
10/12/09 02:37:30
10/12/09 02:37:32
10/12/09 02:37:34
10/12/09 02:37:36
10/12/09 02:37:38
10/12/09 02:37:40
10/12/09 02:37:42
10/12/09 02:37:44
10/12/09 02:37:46
10/12/09 02:37:48
10/12/09 02:37:50
10/12/09 02:37:52
10/12/09 02:37:54
10/12/09 02:37:56
10/12/09 02:37:58
10/12/09 02:38:00
10/12/09 02:38:02
10/12/09 02:38:04
10/12/09 02:38:06
10/12/09 02:38:08
10/12/09 02:38:10
10/12/09 02:38:12
Hz
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
Net
Actual
Interchange
MW
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.17
3771.73
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.25
3758.041
3760.965
3762.022
3763.822
3763.1
3763.858
3764.158
3766.127
3768.339
3767.972
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
374
374.5
375
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.006
-0.004
-0.002
-0.003
0.002
0.006
-0.003
0.002
-0.001
-0.005
0.002
0.005
0.003
-0.005
-0.003
0.003
0.001
-0.002
-0.003
0.002
0.013
0.011
-0.007
-0.009
-0.007
-0.002
-0.003
0.000
-0.001
0.000
-0.001
0.003
-0.004
-0.003
-0.005
0.002
0.001
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.006
0.004
0.002
0.003
0.002
0.006
0.003
0.002
0.001
0.005
0.002
0.005
0.003
0.005
0.003
0.003
0.001
0.002
0.003
0.002
0.013
0.011
0.007
0.009
0.007
0.002
0.003
0.000
0.001
0.000
0.001
0.003
0.004
0.003
0.005
0.002
0.001
0.003
003315
Time (T)
10/12/09 02:38:14
10/12/09 02:38:16
10/12/09 02:38:18
10/12/09 02:38:20
10/12/09 02:38:22
10/12/09 02:38:24
10/12/09 02:38:26
10/12/09 02:38:28
10/12/09 02:38:30
10/12/09 02:38:32
10/12/09 02:38:34
10/12/09 02:38:36
10/12/09 02:38:38
10/12/09 02:38:40
10/12/09 02:38:42
10/12/09 02:38:44
10/12/09 02:38:46
10/12/09 02:38:48
10/12/09 02:38:50
10/12/09 02:38:52
10/12/09 02:38:54
10/12/09 02:38:56
10/12/09 02:38:58
10/12/09 02:39:00
10/12/09 02:39:02
10/12/09 02:39:04
10/12/09 02:39:06
10/12/09 02:39:08
10/12/09 02:39:10
10/12/09 02:39:12
10/12/09 02:39:14
10/12/09 02:39:16
10/12/09 02:39:18
10/12/09 02:39:20
10/12/09 02:39:22
10/12/09 02:39:24
10/12/09 02:39:26
10/12/09 02:39:28
10/12/09 02:39:30
Hz
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
Net
Actual
Interchange
MW
3767.438
3765.606
3762.688
3761.57
3761.92
3759.627
3758.522
3752.429
3750.102
3753.83
3753.51
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.37
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.65
3737.541
3738.012
3736.748
3736.693
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
393.5
394
394.5
395
395.5
396
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.005
0.002
-0.002
-0.002
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
-0.002
-0.006
0.002
0.000
0.005
0.004
-0.001
-0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
-0.002
-0.001
-0.002
0.001
-0.002
0.000
0.002
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.005
0.002
0.002
0.002
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
0.002
0.006
0.002
0.000
0.005
0.004
0.001
0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
0.002
0.001
0.002
0.001
0.002
0.000
0.002
0.001
0.001
003316
Time (T)
10/12/09 02:39:32
10/12/09 02:39:34
10/12/09 02:39:36
10/12/09 02:39:38
10/12/09 02:39:40
10/12/09 02:39:42
10/12/09 02:39:44
10/12/09 02:39:46
10/12/09 02:39:48
10/12/09 02:39:50
10/12/09 02:39:52
10/12/09 02:39:54
10/12/09 02:39:56
10/12/09 02:39:58
10/12/09 02:40:00
10/12/09 02:40:02
10/12/09 02:40:04
10/12/09 02:40:06
10/12/09 02:40:08
10/12/09 02:40:10
10/12/09 02:40:12
10/12/09 02:40:14
10/12/09 02:40:16
10/12/09 02:40:18
10/12/09 02:40:20
10/12/09 02:40:22
10/12/09 02:40:24
10/12/09 02:40:26
10/12/09 02:40:28
10/12/09 02:40:30
10/12/09 02:40:32
10/12/09 02:40:34
10/12/09 02:40:36
10/12/09 02:40:38
10/12/09 02:40:40
10/12/09 02:40:42
10/12/09 02:40:44
10/12/09 02:40:46
10/12/09 02:40:48
Hz
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
Net
Actual
Interchange
MW
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.86
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.34
3750.7
3749.75
3746.217
3744.683
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
413
413.5
414
414.5
415
415.5
416
416.5
417
417.5
418
418.5
419
419.5
420
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.002
-0.004
-0.001
-0.002
0.005
0.001
0.001
-0.004
-0.003
0.002
0.003
-0.002
0.000
0.000
0.005
0.005
-0.004
-0.002
-0.003
0.001
0.003
0.000
0.001
0.001
0.002
-0.004
-0.003
-0.003
0.000
0.000
0.001
-0.004
-0.002
0.000
0.005
0.002
-0.001
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.002
0.004
0.001
0.002
0.005
0.001
0.001
0.004
0.003
0.002
0.003
0.002
0.000
0.000
0.005
0.005
0.004
0.002
0.003
0.001
0.003
0.000
0.001
0.001
0.002
0.004
0.003
0.003
0.000
0.000
0.001
0.004
0.002
0.000
0.005
0.002
0.001
0.003
003317
Time (T)
10/12/09 02:40:50
10/12/09 02:40:52
10/12/09 02:40:54
10/12/09 02:40:56
10/12/09 02:40:58
10/12/09 02:41:00
10/12/09 02:41:02
10/12/09 02:41:04
10/12/09 02:41:06
10/12/09 02:41:08
10/12/09 02:41:10
10/12/09 02:41:12
10/12/09 02:41:14
10/12/09 02:41:16
10/12/09 02:41:18
10/12/09 02:41:20
10/12/09 02:41:22
10/12/09 02:41:24
10/12/09 02:41:26
10/12/09 02:41:28
10/12/09 02:41:30
10/12/09 02:41:32
10/12/09 02:41:34
10/12/09 02:41:36
10/12/09 02:41:38
10/12/09 02:41:40
10/12/09 02:41:42
10/12/09 02:41:44
10/12/09 02:41:46
10/12/09 02:41:48
10/12/09 02:41:50
10/12/09 02:41:52
10/12/09 02:41:54
10/12/09 02:41:56
10/12/09 02:41:58
10/12/09 02:42:00
10/12/09 02:42:02
10/12/09 02:42:04
10/12/09 02:42:06
Hz
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
Net
Actual
Interchange
MW
3743.745
3743.149
3740.299
3739.453
3733.376
3731.83
3737.583
3736.229
3734.897
3733.434
3733.115
3730.51
3729.18
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.56
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
437.5
438
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
450.5
451
451.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
7797.33
7797.66
7797.99
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
-0.001
-0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
-0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.002
0.004
0.001
0.001
0.002
0.000
0.008
-0.001
0.001
0.000
-0.001
0.005
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.002
0.001
0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.002
0.004
0.001
0.001
0.002
0.000
0.008
0.001
0.001
0.000
0.001
0.005
0.002
0.001
003318
Time (T)
10/12/09 02:42:08
10/12/09 02:42:10
10/12/09 02:42:12
10/12/09 02:42:14
10/12/09 02:42:16
10/12/09 02:42:18
10/12/09 02:42:20
10/12/09 02:42:22
10/12/09 02:42:24
10/12/09 02:42:26
10/12/09 02:42:28
10/12/09 02:42:30
10/12/09 02:42:32
10/12/09 02:42:34
10/12/09 02:42:36
10/12/09 02:42:38
10/12/09 02:42:40
10/12/09 02:42:42
10/12/09 02:42:44
10/12/09 02:42:46
10/12/09 02:42:48
10/12/09 02:42:50
10/12/09 02:42:52
10/12/09 02:42:54
10/12/09 02:42:56
10/12/09 02:42:58
10/12/09 02:43:00
10/12/09 02:43:02
10/12/09 02:43:04
10/12/09 02:43:06
10/12/09 02:43:08
10/12/09 02:43:10
10/12/09 02:43:12
10/12/09 02:43:14
10/12/09 02:43:16
10/12/09 02:43:18
10/12/09 02:43:20
10/12/09 02:43:22
10/12/09 02:43:24
Hz
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
60.043
60.045
60.04
60.041
60.039
60.039
60.036
60.038
60.033
60.034
60.037
60.037
60.035
60.03
60.033
60.036
60.033
60.034
60.032
60.032
60.034
60.033
60.037
60.035
60.035
60.036
60.039
60.037
60.039
60.036
Net
Actual
Interchange
MW
3702.482
3701.316
3700.826
3699.529
3699.726
3690.1
3690.477
3696.865
3696.877
3696.182
3696.541
3696.968
3698.686
3699.631
3698.787
3699.712
3700.106
3699.968
3701.122
3701.865
3701.614
3701.998
3702.913
3703.909
3705.522
3704.967
3704.087
3702.771
3703.706
3704.905
3705.435
3704.36
3702.588
3702.204
3701.942
3702.25
3703.318
3702.457
3702.525
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
452
452.5
453
453.5
454
454.5
455
455.5
456
456.5
457
457.5
458
458.5
459
459.5
460
460.5
461
461.5
462
462.5
463
463.5
464
464.5
465
465.5
466
466.5
467
467.5
468
468.5
469
469.5
470
470.5
471
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.3
7800.63
7800.96
7801.29
7801.62
7801.95
7802.28
7802.61
7802.94
7803.27
7803.6
7803.93
7804.26
7804.59
7804.92
7805.25
7805.58
7805.91
7806.24
7806.57
7806.9
7807.23
7807.56
7807.89
7808.22
7808.55
7808.88
7809.21
7809.54
7809.87
7810.2
7810.53
7810.86
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.003
0.002
-0.002
0.000
-0.003
0.000
0.001
-0.001
0.000
0.002
-0.005
0.001
-0.002
0.000
-0.003
0.002
-0.005
0.001
0.003
0.000
-0.002
-0.005
0.003
0.003
-0.003
0.001
-0.002
0.000
0.002
-0.001
0.004
-0.002
0.000
0.001
0.003
-0.002
0.002
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.003
0.002
0.002
0.000
0.003
0.000
0.001
0.001
0.000
0.002
0.005
0.001
0.002
0.000
0.003
0.002
0.005
0.001
0.003
0.000
0.002
0.005
0.003
0.003
0.003
0.001
0.002
0.000
0.002
0.001
0.004
0.002
0.000
0.001
0.003
0.002
0.002
0.003
003319
Time (T)
10/12/09 02:43:26
10/12/09 02:43:28
10/12/09 02:43:30
10/12/09 02:43:32
10/12/09 02:43:34
10/12/09 02:43:36
10/12/09 02:43:38
10/12/09 02:43:40
10/12/09 02:43:42
10/12/09 02:43:44
10/12/09 02:43:46
10/12/09 02:43:48
10/12/09 02:43:50
10/12/09 02:43:52
10/12/09 02:43:54
10/12/09 02:43:56
10/12/09 02:43:58
10/12/09 02:44:00
10/12/09 02:44:02
10/12/09 02:44:04
10/12/09 02:44:06
10/12/09 02:44:08
10/12/09 02:44:10
10/12/09 02:44:12
10/12/09 02:44:14
10/12/09 02:44:16
10/12/09 02:44:18
10/12/09 02:44:20
10/12/09 02:44:22
10/12/09 02:44:24
10/12/09 02:44:26
10/12/09 02:44:28
10/12/09 02:44:30
10/12/09 02:44:32
10/12/09 02:44:34
10/12/09 02:44:36
10/12/09 02:44:38
10/12/09 02:44:40
10/12/09 02:44:42
Hz
60.034
60.038
60.037
60.037
60.037
60.038
60.04
60.043
60.045
60.045
60.042
60.043
60.04
60.044
60.046
60.042
60.034
60.039
60.039
60.036
60.037
60.034
60.033
60.032
60.031
60.033
60.027
60.031
60.032
60.031
60.031
60.033
60.039
60.039
60.038
60.037
60.035
60.037
60.04
Net
Actual
Interchange
MW
3703.269
3703.844
3702.865
3702.518
3702.28
3692.427
3692.178
3700.276
3698.755
3697.729
3696.916
3697.368
3697.346
3698.429
3694.763
3693.584
3693.241
3696.798
3699.364
3701.791
3700.708
3700.753
3702.148
3705.213
3707.521
3707.287
3706.988
3707.34
3707.917
3707.384
3706.857
3707.615
3706.823
3703.746
3701.582
3700.847
3701.208
3702.212
3701.686
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
471.5
472
472.5
473
473.5
474
474.5
475
475.5
476
476.5
477
477.5
478
478.5
479
479.5
480
480.5
481
481.5
482
482.5
483
483.5
484
484.5
485
485.5
486
486.5
487
487.5
488
488.5
489
489.5
490
490.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7811.19
7811.52
7811.85
7812.18
7812.51
7812.84
7813.17
7813.5
7813.83
7814.16
7814.49
7814.82
7815.15
7815.48
7815.81
7816.14
7816.47
7816.8
7817.13
7817.46
7817.79
7818.12
7818.45
7818.78
7819.11
7819.44
7819.77
7820.1
7820.43
7820.76
7821.09
7821.42
7821.75
7822.08
7822.41
7822.74
7823.07
7823.4
7823.73
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.004
-0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
-0.003
0.001
-0.003
0.004
0.002
-0.004
-0.008
0.005
0.000
-0.003
0.001
-0.003
-0.001
-0.001
-0.001
0.002
-0.006
0.004
0.001
-0.001
0.000
0.002
0.006
0.000
-0.001
-0.001
-0.002
0.002
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.004
0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.004
0.008
0.005
0.000
0.003
0.001
0.003
0.001
0.001
0.001
0.002
0.006
0.004
0.001
0.001
0.000
0.002
0.006
0.000
0.001
0.001
0.002
0.002
0.003
003320
Time (T)
10/12/09 02:44:44
10/12/09 02:44:46
10/12/09 02:44:48
10/12/09 02:44:50
10/12/09 02:44:52
10/12/09 02:44:54
10/12/09 02:44:56
10/12/09 02:44:58
10/12/09 02:45:00
10/12/09 02:45:02
10/12/09 02:45:04
10/12/09 02:45:06
10/12/09 02:45:08
10/12/09 02:45:10
10/12/09 02:45:12
10/12/09 02:45:14
10/12/09 02:45:16
10/12/09 02:45:18
10/12/09 02:45:20
10/12/09 02:45:22
10/12/09 02:45:24
10/12/09 02:45:26
10/12/09 02:45:28
10/12/09 02:45:30
10/12/09 02:45:32
10/12/09 02:45:34
10/12/09 02:45:36
10/12/09 02:45:38
10/12/09 02:45:40
10/12/09 02:45:42
10/12/09 02:45:44
10/12/09 02:45:46
10/12/09 02:45:48
10/12/09 02:45:50
10/12/09 02:45:52
10/12/09 02:45:54
10/12/09 02:45:56
10/12/09 02:45:58
10/12/09 02:46:00
Hz
60.042
60.035
60.036
60.04
60.045
60.045
60.048
60.042
60.044
60.044
60.044
60.041
60.04
60.04
60.045
60.044
60.042
60.039
60.042
60.042
60.041
60.038
60.036
60.037
60.039
60.038
60.04
60.039
60.037
60.038
60.039
60.04
60.037
60.037
60.037
60.039
60.038
60.036
60.035
Net
Actual
Interchange
MW
3700.397
3699.69
3700.366
3700.827
3700.662
3696.935
3695.688
3695.819
3693.824
3694.799
3696.897
3696.023
3697.502
3698.424
3699.427
3700.177
3699.806
3697.577
3697.681
3698.507
3698.359
3698.466
3699.077
3700.262
3701.592
3700.902
3700.143
3700.27
3701.139
3701.586
3700.264
3699.458
3699.721
3700.458
3699.505
3698.794
3699.216
3699.4
3700.661
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
491
491.5
492
492.5
493
493.5
494
494.5
495
495.5
496
496.5
497
497.5
498
498.5
499
499.5
500
500.5
501
501.5
502
502.5
503
503.5
504
504.5
505
505.5
506
506.5
507
507.5
508
508.5
509
509.5
510
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7824.06
7824.39
7824.72
7825.05
7825.38
7825.71
7826.04
7826.37
7826.7
7827.03
7827.36
7827.69
7828.02
7828.35
7828.68
7829.01
7829.34
7829.67
7830
7830.33
7830.66
7830.99
7831.32
7831.65
7831.98
7832.31
7832.64
7832.97
7833.3
7833.63
7833.96
7834.29
7834.62
7834.95
7835.28
7835.61
7835.94
7836.27
7836.6
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
-0.007
0.001
0.004
0.005
0.000
0.003
-0.006
0.002
0.000
0.000
-0.003
-0.001
0.000
0.005
-0.001
-0.002
-0.003
0.003
0.000
-0.001
-0.003
-0.002
0.001
0.002
-0.001
0.002
-0.001
-0.002
0.001
0.001
0.001
-0.003
0.000
0.000
0.002
-0.001
-0.002
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.007
0.001
0.004
0.005
0.000
0.003
0.006
0.002
0.000
0.000
0.003
0.001
0.000
0.005
0.001
0.002
0.003
0.003
0.000
0.001
0.003
0.002
0.001
0.002
0.001
0.002
0.001
0.002
0.001
0.001
0.001
0.003
0.000
0.000
0.002
0.001
0.002
0.001
003321
Time (T)
10/12/09 02:46:02
10/12/09 02:46:04
10/12/09 02:46:06
10/12/09 02:46:08
10/12/09 02:46:10
10/12/09 02:46:12
10/12/09 02:46:14
10/12/09 02:46:16
10/12/09 02:46:18
10/12/09 02:46:20
10/12/09 02:46:22
10/12/09 02:46:24
10/12/09 02:46:26
10/12/09 02:46:28
10/12/09 02:46:30
10/12/09 02:46:32
10/12/09 02:46:34
10/12/09 02:46:36
10/12/09 02:46:38
10/12/09 02:46:40
10/12/09 02:46:42
10/12/09 02:46:44
10/12/09 02:46:46
10/12/09 02:46:48
10/12/09 02:46:50
10/12/09 02:46:52
10/12/09 02:46:54
10/12/09 02:46:56
10/12/09 02:46:58
10/12/09 02:47:00
10/12/09 02:47:02
10/12/09 02:47:04
10/12/09 02:47:06
10/12/09 02:47:08
10/12/09 02:47:10
10/12/09 02:47:12
10/12/09 02:47:14
10/12/09 02:47:16
10/12/09 02:47:18
Hz
60.033
60.031
60.03
60.032
60.032
60.037
60.042
60.041
60.036
60.031
60.032
60.031
60.034
60.034
60.032
60.038
60.043
60.044
60.042
60.045
60.04
60.04
60.043
60.043
60.041
60.04
60.038
60.043
60.044
60.042
60.036
60.043
60.041
60.042
60.043
60.043
60.036
60.039
60.039
Net
Actual
Interchange
MW
3702.173
3702.968
3705.195
3704.952
3705.775
3705.621
3703.744
3701.981
3700.756
3700.747
3702.213
3705.059
3705.514
3704.449
3703.831
3703.62
3702.795
3701.432
3697.38
3696.25
3696.302
3693.518
3693.577
3695.197
3695.186
3693.786
3694.753
3694.926
3694.938
3694.159
3691.33
3692.686
3693.238
3693.39
3692.357
3690.951
3690.836
3692.042
3693.114
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
510.5
511
511.5
512
512.5
513
513.5
514
514.5
515
515.5
516
516.5
517
517.5
518
518.5
519
519.5
520
520.5
521
521.5
522
522.5
523
523.5
524
524.5
525
525.5
526
526.5
527
527.5
528
528.5
529
529.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7836.93
7837.26
7837.59
7837.92
7838.25
7838.58
7838.91
7839.24
7839.57
7839.9
7840.23
7840.56
7840.89
7841.22
7841.55
7841.88
7842.21
7842.54
7842.87
7843.2
7843.53
7843.86
7844.19
7844.52
7844.85
7845.18
7845.51
7845.84
7846.17
7846.5
7846.83
7847.16
7847.49
7847.82
7848.15
7848.48
7848.81
7849.14
7849.47
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.002
-0.001
0.002
0.000
0.005
0.005
-0.001
-0.005
-0.005
0.001
-0.001
0.003
0.000
-0.002
0.006
0.005
0.001
-0.002
0.003
-0.005
0.000
0.003
0.000
-0.002
-0.001
-0.002
0.005
0.001
-0.002
-0.006
0.007
-0.002
0.001
0.001
0.000
-0.007
0.003
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.002
0.001
0.002
0.000
0.005
0.005
0.001
0.005
0.005
0.001
0.001
0.003
0.000
0.002
0.006
0.005
0.001
0.002
0.003
0.005
0.000
0.003
0.000
0.002
0.001
0.002
0.005
0.001
0.002
0.006
0.007
0.002
0.001
0.001
0.000
0.007
0.003
0.000
003322
Time (T)
10/12/09 02:47:20
10/12/09 02:47:22
10/12/09 02:47:24
10/12/09 02:47:26
10/12/09 02:47:28
10/12/09 02:47:30
10/12/09 02:47:32
10/12/09 02:47:34
10/12/09 02:47:36
10/12/09 02:47:38
10/12/09 02:47:40
10/12/09 02:47:42
10/12/09 02:47:44
10/12/09 02:47:46
10/12/09 02:47:48
10/12/09 02:47:50
10/12/09 02:47:52
10/12/09 02:47:54
10/12/09 02:47:56
10/12/09 02:47:58
10/12/09 02:48:00
10/12/09 02:48:02
10/12/09 02:48:04
10/12/09 02:48:06
10/12/09 02:48:08
10/12/09 02:48:10
10/12/09 02:48:12
10/12/09 02:48:14
10/12/09 02:48:16
10/12/09 02:48:18
10/12/09 02:48:20
10/12/09 02:48:22
10/12/09 02:48:24
10/12/09 02:48:26
10/12/09 02:48:28
10/12/09 02:48:30
10/12/09 02:48:32
10/12/09 02:48:34
10/12/09 02:48:36
Hz
60.037
60.034
60.035
60.035
60.035
60.036
60.03
60.03
60.03
60.031
60.031
60.032
60.031
60.032
60.032
60.032
60.033
60.037
60.04
60.039
60.042
60.036
60.039
60.041
60.04
60.035
60.036
60.038
60.037
60.041
60.04
60.036
60.033
60.034
60.038
60.04
60.041
60.037
60.037
Net
Actual
Interchange
MW
3694.117
3695.258
3695.581
3695.949
3695.491
3696.305
3696.486
3697.336
3699.171
3699.357
3699.251
3699.117
3699.105
3699.126
3698.954
3698.136
3698.277
3697.412
3695.94
3693.736
3693.224
3691.759
3691.919
3692.798
3691.582
3692.374
3693.302
3694.71
3694.331
3693.815
3693.617
3694.324
3694.27
3694.66
3693.748
3692.532
3691.445
3691.012
3691.799
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
530
530.5
531
531.5
532
532.5
533
533.5
534
534.5
535
535.5
536
536.5
537
537.5
538
538.5
539
539.5
540
540.5
541
541.5
542
542.5
543
543.5
544
544.5
545
545.5
546
546.5
547
547.5
548
548.5
549
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7849.8
7850.13
7850.46
7850.79
7851.12
7851.45
7851.78
7852.11
7852.44
7852.77
7853.1
7853.43
7853.76
7854.09
7854.42
7854.75
7855.08
7855.41
7855.74
7856.07
7856.4
7856.73
7857.06
7857.39
7857.72
7858.05
7858.38
7858.71
7859.04
7859.37
7859.7
7860.03
7860.36
7860.69
7861.02
7861.35
7861.68
7862.01
7862.34
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.003
0.001
0.000
0.000
0.001
-0.006
0.000
0.000
0.001
0.000
0.001
-0.001
0.001
0.000
0.000
0.001
0.004
0.003
-0.001
0.003
-0.006
0.003
0.002
-0.001
-0.005
0.001
0.002
-0.001
0.004
-0.001
-0.004
-0.003
0.001
0.004
0.002
0.001
-0.004
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.003
0.001
0.000
0.000
0.001
0.006
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.004
0.003
0.001
0.003
0.006
0.003
0.002
0.001
0.005
0.001
0.002
0.001
0.004
0.001
0.004
0.003
0.001
0.004
0.002
0.001
0.004
0.000
003323
Time (T)
10/12/09 02:48:38
10/12/09 02:48:40
10/12/09 02:48:42
10/12/09 02:48:44
10/12/09 02:48:46
10/12/09 02:48:48
10/12/09 02:48:50
10/12/09 02:48:52
10/12/09 02:48:54
10/12/09 02:48:56
10/12/09 02:48:58
10/12/09 02:49:00
10/12/09 02:49:02
10/12/09 02:49:04
10/12/09 02:49:06
10/12/09 02:49:08
10/12/09 02:49:10
10/12/09 02:49:12
10/12/09 02:49:14
10/12/09 02:49:16
10/12/09 02:49:18
10/12/09 02:49:20
10/12/09 02:49:22
10/12/09 02:49:24
10/12/09 02:49:26
10/12/09 02:49:28
10/12/09 02:49:30
10/12/09 02:49:32
10/12/09 02:49:34
10/12/09 02:49:36
10/12/09 02:49:38
10/12/09 02:49:40
10/12/09 02:49:42
10/12/09 02:49:44
10/12/09 02:49:46
10/12/09 02:49:48
10/12/09 02:49:50
10/12/09 02:49:52
10/12/09 02:49:54
Hz
60.036
60.037
60.038
60.039
60.038
60.034
60.033
60.031
60.034
60.029
60.029
60.031
60.03
60.03
60.026
60.022
60.021
60.024
60.023
60.02
60.021
60.023
60.025
60.026
60.026
60.025
60.024
60.024
60.025
60.023
60.023
60.022
60.026
60.029
60.026
60.024
60.021
60.025
60.025
Net
Actual
Interchange
MW
3693.077
3693.727
3693.117
3692.641
3688.159
3689.02
3688.208
3690.092
3693.172
3693.321
3694.593
3695.225
3694.609
3693.412
3693.509
3696.026
3698.012
3699.062
3699.414
3698.935
3700.084
3700.544
3700.486
3698.596
3697.961
3699.914
3700.802
3701.301
3701.45
3701.349
3701.094
3701.702
3702.07
3701.965
3700.269
3700.241
3701.09
3701.268
3701.205
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
549.5
550
550.5
551
551.5
552
552.5
553
553.5
554
554.5
555
555.5
556
556.5
557
557.5
558
558.5
559
559.5
560
560.5
561
561.5
562
562.5
563
563.5
564
564.5
565
565.5
566
566.5
567
567.5
568
568.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7862.67
7863
7863.33
7863.66
7863.99
7864.32
7864.65
7864.98
7865.31
7865.64
7865.97
7866.3
7866.63
7866.96
7867.29
7867.62
7867.95
7868.28
7868.61
7868.94
7869.27
7869.6
7869.93
7870.26
7870.59
7870.92
7871.25
7871.58
7871.91
7872.24
7872.57
7872.9
7873.23
7873.56
7873.89
7874.22
7874.55
7874.88
7875.21
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.001
0.001
0.001
-0.001
-0.004
-0.001
-0.002
0.003
-0.005
0.000
0.002
-0.001
0.000
-0.004
-0.004
-0.001
0.003
-0.001
-0.003
0.001
0.002
0.002
0.001
0.000
-0.001
-0.001
0.000
0.001
-0.002
0.000
-0.001
0.004
0.003
-0.003
-0.002
-0.003
0.004
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.004
0.001
0.002
0.003
0.005
0.000
0.002
0.001
0.000
0.004
0.004
0.001
0.003
0.001
0.003
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.003
0.003
0.002
0.003
0.004
0.000
003324
Time (T)
10/12/09 02:49:56
10/12/09 02:49:58
10/12/09 02:50:00
10/12/09 02:50:02
10/12/09 02:50:04
10/12/09 02:50:06
10/12/09 02:50:08
10/12/09 02:50:10
10/12/09 02:50:12
10/12/09 02:50:14
10/12/09 02:50:16
10/12/09 02:50:18
10/12/09 02:50:20
10/12/09 02:50:22
10/12/09 02:50:24
10/12/09 02:50:26
10/12/09 02:50:28
10/12/09 02:50:30
10/12/09 02:50:32
10/12/09 02:50:34
10/12/09 02:50:36
10/12/09 02:50:38
10/12/09 02:50:40
10/12/09 02:50:42
10/12/09 02:50:44
10/12/09 02:50:46
10/12/09 02:50:48
10/12/09 02:50:50
10/12/09 02:50:52
10/12/09 02:50:54
10/12/09 02:50:56
10/12/09 02:50:58
10/12/09 02:51:00
10/12/09 02:51:02
10/12/09 02:51:04
10/12/09 02:51:06
10/12/09 02:51:08
10/12/09 02:51:10
10/12/09 02:51:12
Hz
60.025
60.023
60.026
60.024
60.022
60.023
60.026
60.025
60.02
60.02
60.019
60.015
60.016
60.017
60.015
60.015
60.017
60.017
60.012
60.01
60.008
60.002
59.999
59.999
60.002
60.003
60.004
60.001
59.996
59.993
59.992
59.989
59.987
59.985
59.985
59.986
59.984
59.981
59.98
Net
Actual
Interchange
MW
3700.587
3700.532
3700.177
3700.295
3700.277
3700.841
3700.863
3700.26
3700.052
3699.926
3700.965
3702.581
3703.516
3703.824
3703.672
3703.689
3703.003
3702.921
3703
3703.167
3703.918
3703.616
3703.775
3703.751
3701.534
3700.617
3700.88
3700.625
3701.389
3701.737
3700.671
3700.826
3700.977
3700.7
3699.854
3700.237
3700.342
3700.77
3700.789
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
569
569.5
570
570.5
571
571.5
572
572.5
573
573.5
574
574.5
575
575.5
576
576.5
577
577.5
578
578.5
579
579.5
580
580.5
581
581.5
582
582.5
583
583.5
584
584.5
585
585.5
586
586.5
587
587.5
588
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7875.54
7875.87
7876.2
7876.53
7876.86
7877.19
7877.52
7877.85
7878.18
7878.51
7878.84
7879.17
7879.5
7879.83
7880.16
7880.49
7880.82
7881.15
7881.48
7881.81
7882.14
7882.47
7882.8
7883.13
7883.46
7883.79
7884.12
7884.45
7884.78
7885.11
7885.44
7885.77
7886.1
7886.43
7886.76
7887.09
7887.42
7887.75
7888.08
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.002
0.003
-0.002
-0.002
0.001
0.003
-0.001
-0.005
0.000
-0.001
-0.004
0.001
0.001
-0.002
0.000
0.002
0.000
-0.005
-0.002
-0.002
-0.006
-0.003
0.000
0.003
0.001
0.001
-0.003
-0.005
-0.003
-0.001
-0.003
-0.002
-0.002
0.000
0.001
-0.002
-0.003
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.002
0.003
0.002
0.002
0.001
0.003
0.001
0.005
0.000
0.001
0.004
0.001
0.001
0.002
0.000
0.002
0.000
0.005
0.002
0.002
0.006
0.003
0.000
0.003
0.001
0.001
0.003
0.005
0.003
0.001
0.003
0.002
0.002
0.000
0.001
0.002
0.003
0.001
003325
Time (T)
10/12/09 02:51:14
10/12/09 02:51:16
10/12/09 02:51:18
10/12/09 02:51:20
10/12/09 02:51:22
10/12/09 02:51:24
10/12/09 02:51:26
10/12/09 02:51:28
10/12/09 02:51:30
10/12/09 02:51:32
10/12/09 02:51:34
10/12/09 02:51:36
10/12/09 02:51:38
10/12/09 02:51:40
10/12/09 02:51:42
10/12/09 02:51:44
10/12/09 02:51:46
10/12/09 02:51:48
10/12/09 02:51:50
10/12/09 02:51:52
10/12/09 02:51:54
10/12/09 02:51:56
10/12/09 02:51:58
10/12/09 02:52:00
10/12/09 02:52:02
10/12/09 02:52:04
10/12/09 02:52:06
10/12/09 02:52:08
10/12/09 02:52:10
10/12/09 02:52:12
10/12/09 02:52:14
10/12/09 02:52:16
10/12/09 02:52:18
10/12/09 02:52:20
10/12/09 02:52:22
10/12/09 02:52:24
10/12/09 02:52:26
10/12/09 02:52:28
10/12/09 02:52:30
Hz
59.977
59.975
59.976
59.972
59.974
59.977
59.975
59.973
59.971
59.971
59.976
59.979
59.98
59.979
59.982
59.982
59.983
59.981
59.979
59.978
59.976
59.978
59.977
59.976
59.978
59.975
59.971
59.97
59.97
59.971
59.99
59.998
59.999
59.999
59.998
59.999
60.003
60.005
60.005
Net
Actual
Interchange
MW
3701.625
3703.166
3704.187
3704.785
3705.811
3706.958
3706.688
3706.543
3706.257
3707.027
3710.118
3710.531
3708.701
3708.018
3706.942
3706.343
3706.125
3706.311
3706.119
3706.19
3707.721
3709.409
3708.971
3708.531
3708.071
3707.24
3709.213
3709.961
3711.75
3711.98
3710.695
3707.867
3704.912
3705.639
3703.787
3703.191
3702.071
3699.51
3698.658
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
588.5
589
589.5
590
590.5
591
591.5
592
592.5
593
593.5
594
594.5
595
595.5
596
596.5
597
597.5
598
598.5
599
599.5
600
600.5
601
601.5
602
602.5
603
603.5
604
604.5
605
605.5
606
606.5
607
607.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7888.41
7888.74
7889.07
7889.4
7889.73
7890.06
7890.39
7890.72
7891.05
7891.38
7891.71
7892.04
7892.37
7892.7
7893.03
7893.36
7893.69
7894.02
7894.35
7894.68
7895.01
7895.34
7895.67
7896
7896.33
7896.66
7896.99
7897.32
7897.65
7897.98
7898.31
7898.64
7898.97
7899.3
7899.63
7899.96
7900.29
7900.62
7900.95
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.002
0.001
-0.004
0.002
0.003
-0.002
-0.002
-0.002
0.000
0.005
0.003
0.001
-0.001
0.003
0.000
0.001
-0.002
-0.002
-0.001
-0.002
0.002
-0.001
-0.001
0.002
-0.003
-0.004
-0.001
0.000
0.001
0.019
0.008
0.001
0.000
-0.001
0.001
0.004
0.002
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.002
0.001
0.004
0.002
0.003
0.002
0.002
0.002
0.000
0.005
0.003
0.001
0.001
0.003
0.000
0.001
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.002
0.003
0.004
0.001
0.000
0.001
0.019
0.008
0.001
0.000
0.001
0.001
0.004
0.002
0.000
003326
Time (T)
10/12/09 02:52:32
10/12/09 02:52:34
10/12/09 02:52:36
10/12/09 02:52:38
10/12/09 02:52:40
10/12/09 02:52:42
10/12/09 02:52:44
10/12/09 02:52:46
10/12/09 02:52:48
10/12/09 02:52:50
10/12/09 02:52:52
10/12/09 02:52:54
10/12/09 02:52:56
10/12/09 02:52:58
10/12/09 02:53:00
10/12/09 02:53:02
10/12/09 02:53:04
10/12/09 02:53:06
10/12/09 02:53:08
10/12/09 02:53:10
10/12/09 02:53:12
10/12/09 02:53:14
10/12/09 02:53:16
10/12/09 02:53:18
10/12/09 02:53:20
10/12/09 02:53:22
10/12/09 02:53:24
10/12/09 02:53:26
10/12/09 02:53:28
10/12/09 02:53:30
10/12/09 02:53:32
10/12/09 02:53:34
10/12/09 02:53:36
10/12/09 02:53:38
10/12/09 02:53:40
10/12/09 02:53:42
10/12/09 02:53:44
10/12/09 02:53:46
10/12/09 02:53:48
Hz
60.01
60.013
60.02
60.022
60.024
60.025
60.025
60.024
60.023
60.029
60.029
60.029
60.028
60.028
60.031
60.032
60.033
60.031
60.03
60.022
60.021
60.019
60.017
60.017
60.017
60.016
60.015
60.015
60.012
60.009
60.008
60.008
60.005
60.005
60.003
59.999
59.997
59.999
60
Net
Actual
Interchange
MW
3698.137
3697.882
3698.668
3698.604
3697.868
3694.672
3693.912
3693.418
3688.301
3688.021
3689.143
3688.237
3687.878
3687.026
3686.683
3685.276
3685.576
3685.985
3686.418
3687.159
3687.873
3688.997
3690.426
3690.776
3692.715
3692.578
3692.462
3693.173
3693.249
3693.743
3695.124
3694.681
3694.741
3694.199
3693.75
3693.624
3692.806
3691.15
3691.407
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
608
608.5
609
609.5
610
610.5
611
611.5
612
612.5
613
613.5
614
614.5
615
615.5
616
616.5
617
617.5
618
618.5
619
619.5
620
620.5
621
621.5
622
622.5
623
623.5
624
624.5
625
625.5
626
626.5
627
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7901.28
7901.61
7901.94
7902.27
7902.6
7902.93
7903.26
7903.59
7903.92
7904.25
7904.58
7904.91
7905.24
7905.57
7905.9
7906.23
7906.56
7906.89
7907.22
7907.55
7907.88
7908.21
7908.54
7908.87
7909.2
7909.53
7909.86
7910.19
7910.52
7910.85
7911.18
7911.51
7911.84
7912.17
7912.5
7912.83
7913.16
7913.49
7913.82
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.005
0.003
0.007
0.002
0.002
0.001
0.000
-0.001
-0.001
0.006
0.000
0.000
-0.001
0.000
0.003
0.001
0.001
-0.002
-0.001
-0.008
-0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.001
0.000
-0.003
-0.003
-0.001
0.000
-0.003
0.000
-0.002
-0.004
-0.002
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.005
0.003
0.007
0.002
0.002
0.001
0.000
0.001
0.001
0.006
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.008
0.001
0.002
0.002
0.000
0.000
0.001
0.001
0.000
0.003
0.003
0.001
0.000
0.003
0.000
0.002
0.004
0.002
0.002
0.001
003327
Time (T)
10/12/09 02:53:50
10/12/09 02:53:52
10/12/09 02:53:54
10/12/09 02:53:56
10/12/09 02:53:58
10/12/09 02:54:00
10/12/09 02:54:02
10/12/09 02:54:04
10/12/09 02:54:06
10/12/09 02:54:08
10/12/09 02:54:10
10/12/09 02:54:12
10/12/09 02:54:14
10/12/09 02:54:16
10/12/09 02:54:18
10/12/09 02:54:20
10/12/09 02:54:22
10/12/09 02:54:24
10/12/09 02:54:26
10/12/09 02:54:28
10/12/09 02:54:30
10/12/09 02:54:32
10/12/09 02:54:34
10/12/09 02:54:36
10/12/09 02:54:38
10/12/09 02:54:40
10/12/09 02:54:42
10/12/09 02:54:44
10/12/09 02:54:46
10/12/09 02:54:48
10/12/09 02:54:50
10/12/09 02:54:52
10/12/09 02:54:54
10/12/09 02:54:56
10/12/09 02:54:58
10/12/09 02:55:00
10/12/09 02:55:02
10/12/09 02:55:04
10/12/09 02:55:06
Hz
59.998
59.995
59.994
59.992
59.993
59.988
59.985
59.986
59.988
59.988
59.985
59.983
59.983
59.985
59.986
59.987
59.99
59.986
59.985
59.984
59.983
59.982
59.982
59.98
59.978
59.977
59.975
59.973
59.975
59.976
59.976
59.979
59.982
59.979
59.979
59.977
59.977
59.978
59.978
Net
Actual
Interchange
MW
3691.077
3690.588
3689.797
3688.483
3689.445
3689.553
3689.525
3689.736
3688.853
3688.24
3687.494
3687.475
3686.707
3685.66
3684.51
3684.333
3683.911
3683.735
3684.208
3683.811
3683.473
3684.258
3684.884
3685.092
3685.654
3685.087
3685.491
3685.196
3687.412
3688.417
3688.599
3687.848
3686.678
3685.782
3684.89
3685.143
3684.549
3684.093
3684.555
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
627.5
628
628.5
629
629.5
630
630.5
631
631.5
632
632.5
633
633.5
634
634.5
635
635.5
636
636.5
637
637.5
638
638.5
639
639.5
640
640.5
641
641.5
642
642.5
643
643.5
644
644.5
645
645.5
646
646.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7914.15
7914.48
7914.81
7915.14
7915.47
7915.8
7916.13
7916.46
7916.79
7917.12
7917.45
7917.78
7918.11
7918.44
7918.77
7919.1
7919.43
7919.76
7920.09
7920.42
7920.75
7921.08
7921.41
7921.74
7922.07
7922.4
7922.73
7923.06
7923.39
7923.72
7924.05
7924.38
7924.71
7925.04
7925.37
7925.7
7926.03
7926.36
7926.69
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.003
-0.001
-0.002
0.001
-0.005
-0.003
0.001
0.002
0.000
-0.003
-0.002
0.000
0.002
0.001
0.001
0.003
-0.004
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
-0.001
-0.002
-0.002
0.002
0.001
0.000
0.003
0.003
-0.003
0.000
-0.002
0.000
0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.003
0.001
0.002
0.001
0.005
0.003
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.001
0.001
0.003
0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.000
0.002
0.000
0.001
0.000
003328
Time (T)
10/12/09 02:55:08
10/12/09 02:55:10
10/12/09 02:55:12
10/12/09 02:55:14
10/12/09 02:55:16
10/12/09 02:55:18
10/12/09 02:55:20
10/12/09 02:55:22
10/12/09 02:55:24
10/12/09 02:55:26
10/12/09 02:55:28
10/12/09 02:55:30
10/12/09 02:55:32
10/12/09 02:55:34
10/12/09 02:55:36
10/12/09 02:55:38
10/12/09 02:55:40
10/12/09 02:55:42
10/12/09 02:55:44
10/12/09 02:55:46
10/12/09 02:55:48
10/12/09 02:55:50
10/12/09 02:55:52
10/12/09 02:55:54
10/12/09 02:55:56
10/12/09 02:55:58
10/12/09 02:56:00
10/12/09 02:56:02
10/12/09 02:56:04
10/12/09 02:56:06
10/12/09 02:56:08
10/12/09 02:56:10
10/12/09 02:56:12
10/12/09 02:56:14
10/12/09 02:56:16
10/12/09 02:56:18
10/12/09 02:56:20
10/12/09 02:56:22
10/12/09 02:56:24
Hz
59.978
59.979
59.983
59.981
59.98
59.978
59.979
59.978
59.979
59.983
59.987
59.99
59.992
59.993
59.99
59.988
59.988
59.99
59.993
59.994
59.993
59.994
59.994
59.993
59.989
59.984
59.986
59.985
59.988
59.987
59.986
59.987
59.985
59.982
59.981
59.982
59.987
59.992
59.997
Net
Actual
Interchange
MW
3682.814
3682.318
3682.366
3682.647
3682.855
3683.557
3684.052
3684.318
3686.049
3686.629
3685.286
3683.415
3682.416
3681.403
3679.012
3679.436
3671.761
3670.717
3670.159
3679
3680.176
3681.799
3682.7
3684.116
3685.03
3684.878
3684.165
3684.478
3685.584
3685.148
3684.587
3684.976
3683.674
3684.872
3684.245
3684.711
3685.589
3683.736
3682.579
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
647
647.5
648
648.5
649
649.5
650
650.5
651
651.5
652
652.5
653
653.5
654
654.5
655
655.5
656
656.5
657
657.5
658
658.5
659
659.5
660
660.5
661
661.5
662
662.5
663
663.5
664
664.5
665
665.5
666
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7927.02
7927.35
7927.68
7928.01
7928.34
7928.67
7929
7929.33
7929.66
7929.99
7930.32
7930.65
7930.98
7931.31
7931.64
7931.97
7932.3
7932.63
7932.96
7933.29
7933.62
7933.95
7934.28
7934.61
7934.94
7935.27
7935.6
7935.93
7936.26
7936.59
7936.92
7937.25
7937.58
7937.91
7938.24
7938.57
7938.9
7939.23
7939.56
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.001
0.004
-0.002
-0.001
-0.002
0.001
-0.001
0.001
0.004
0.004
0.003
0.002
0.001
-0.003
-0.002
0.000
0.002
0.003
0.001
-0.001
0.001
0.000
-0.001
-0.004
-0.005
0.002
-0.001
0.003
-0.001
-0.001
0.001
-0.002
-0.003
-0.001
0.001
0.005
0.005
0.005
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.001
0.004
0.004
0.003
0.002
0.001
0.003
0.002
0.000
0.002
0.003
0.001
0.001
0.001
0.000
0.001
0.004
0.005
0.002
0.001
0.003
0.001
0.001
0.001
0.002
0.003
0.001
0.001
0.005
0.005
0.005
003329
Time (T)
10/12/09 02:56:26
10/12/09 02:56:28
10/12/09 02:56:30
10/12/09 02:56:32
10/12/09 02:56:34
10/12/09 02:56:36
10/12/09 02:56:38
10/12/09 02:56:40
10/12/09 02:56:42
10/12/09 02:56:44
10/12/09 02:56:46
10/12/09 02:56:48
10/12/09 02:56:50
10/12/09 02:56:52
10/12/09 02:56:54
10/12/09 02:56:56
10/12/09 02:56:58
10/12/09 02:57:00
10/12/09 02:57:02
10/12/09 02:57:04
10/12/09 02:57:06
10/12/09 02:57:08
10/12/09 02:57:10
10/12/09 02:57:12
10/12/09 02:57:14
10/12/09 02:57:16
10/12/09 02:57:18
10/12/09 02:57:20
10/12/09 02:57:22
10/12/09 02:57:24
10/12/09 02:57:26
10/12/09 02:57:28
10/12/09 02:57:30
10/12/09 02:57:32
10/12/09 02:57:34
10/12/09 02:57:36
10/12/09 02:57:38
10/12/09 02:57:40
10/12/09 02:57:42
Hz
60
60.003
60.003
60.003
60.002
60.003
60.002
60.003
60.004
60.005
60.006
60.009
60.012
60.017
60.021
60.022
60.021
60.02
60.018
60.021
60.02
60.02
60.018
60.018
60.019
60.019
60.018
60.017
60.016
60.016
60.016
60.015
60.014
60.014
60.013
60.013
60.015
60.017
60.016
Net
Actual
Interchange
MW
3682.234
3682.138
3682.224
3681.689
3681.458
3681.65
3681.013
3680.167
3679.943
3679.429
3679.669
3678.981
3678.267
3676.796
3676.81
3674.798
3673.906
3671.145
3670.51
3673.648
3673.684
3675.865
3676.676
3676.404
3676.437
3677.185
3677.659
3678.828
3679.289
3678.915
3679.276
3678.599
3678.367
3678.25
3678.589
3677.251
3675.698
3674.669
3674.87
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
666.5
667
667.5
668
668.5
669
669.5
670
670.5
671
671.5
672
672.5
673
673.5
674
674.5
675
675.5
676
676.5
677
677.5
678
678.5
679
679.5
680
680.5
681
681.5
682
682.5
683
683.5
684
684.5
685
685.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7939.89
7940.22
7940.55
7940.88
7941.21
7941.54
7941.87
7942.2
7942.53
7942.86
7943.19
7943.52
7943.85
7944.18
7944.51
7944.84
7945.17
7945.5
7945.83
7946.16
7946.49
7946.82
7947.15
7947.48
7947.81
7948.14
7948.47
7948.8
7949.13
7949.46
7949.79
7950.12
7950.45
7950.78
7951.11
7951.44
7951.77
7952.1
7952.43
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.003
0.000
0.000
-0.001
0.001
-0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
-0.001
-0.001
-0.002
0.003
-0.001
0.000
-0.002
0.000
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.003
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
0.001
0.001
0.002
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.001
003330
Time (T)
10/12/09 02:57:44
10/12/09 02:57:46
10/12/09 02:57:48
10/12/09 02:57:50
10/12/09 02:57:52
10/12/09 02:57:54
10/12/09 02:57:56
10/12/09 02:57:58
10/12/09 02:58:00
10/12/09 02:58:02
10/12/09 02:58:04
10/12/09 02:58:06
10/12/09 02:58:08
10/12/09 02:58:10
10/12/09 02:58:12
10/12/09 02:58:14
10/12/09 02:58:16
10/12/09 02:58:18
10/12/09 02:58:20
10/12/09 02:58:22
10/12/09 02:58:24
10/12/09 02:58:26
10/12/09 02:58:28
10/12/09 02:58:30
10/12/09 02:58:32
10/12/09 02:58:34
10/12/09 02:58:36
10/12/09 02:58:38
10/12/09 02:58:40
10/12/09 02:58:42
10/12/09 02:58:44
10/12/09 02:58:46
10/12/09 02:58:48
10/12/09 02:58:50
10/12/09 02:58:52
10/12/09 02:58:54
10/12/09 02:58:56
10/12/09 02:58:58
10/12/09 02:59:00
Hz
60.019
60.021
60.021
60.02
60.022
60.024
60.026
60.025
60.026
60.022
60.021
60.022
60.024
60.027
60.029
60.028
60.028
60.032
60.035
60.03
60.028
60.021
60.021
60.024
60.025
60.024
60.022
60.023
60.021
60.02
60.02
60.02
60.02
60.017
60.014
60.012
60.01
60.011
60.01
Net
Actual
Interchange
MW
3674.402
3674.546
3672.969
3671.914
3671.982
3670.946
3670.821
3671.06
3671.539
3673.794
3674.01
3675.102
3675.284
3676.051
3675.704
3672.583
3671.343
3670.232
3668.654
3668.767
3666.312
3667.322
3657.164
3657.714
3668.637
3669.309
3670.112
3670.735
3671.332
3672.095
3672.683
3673.833
3674.645
3675.641
3675.971
3677.009
3678.314
3679.393
3680.02
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
686
686.5
687
687.5
688
688.5
689
689.5
690
690.5
691
691.5
692
692.5
693
693.5
694
694.5
695
695.5
696
696.5
697
697.5
698
698.5
699
699.5
700
700.5
701
701.5
702
702.5
703
703.5
704
704.5
705
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7952.76
7953.09
7953.42
7953.75
7954.08
7954.41
7954.74
7955.07
7955.4
7955.73
7956.06
7956.39
7956.72
7957.05
7957.38
7957.71
7958.04
7958.37
7958.7
7959.03
7959.36
7959.69
7960.02
7960.35
7960.68
7961.01
7961.34
7961.67
7962
7962.33
7962.66
7962.99
7963.32
7963.65
7963.98
7964.31
7964.64
7964.97
7965.3
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
0.000
-0.001
0.002
0.002
0.002
-0.001
0.001
-0.004
-0.001
0.001
0.002
0.003
0.002
-0.001
0.000
0.004
0.003
-0.005
-0.002
-0.007
0.000
0.003
0.001
-0.001
-0.002
0.001
-0.002
-0.001
0.000
0.000
0.000
-0.003
-0.003
-0.002
-0.002
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.002
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.004
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.004
0.003
0.005
0.002
0.007
0.000
0.003
0.001
0.001
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.001
003331
Time (T)
10/12/09 02:59:02
10/12/09 02:59:04
10/12/09 02:59:06
10/12/09 02:59:08
10/12/09 02:59:10
10/12/09 02:59:12
10/12/09 02:59:14
10/12/09 02:59:16
10/12/09 02:59:18
10/12/09 02:59:20
10/12/09 02:59:22
10/12/09 02:59:24
10/12/09 02:59:26
10/12/09 02:59:28
10/12/09 02:59:30
10/12/09 02:59:32
10/12/09 02:59:34
10/12/09 02:59:36
10/12/09 02:59:38
10/12/09 02:59:40
10/12/09 02:59:42
10/12/09 02:59:44
10/12/09 02:59:46
10/12/09 02:59:48
10/12/09 02:59:50
10/12/09 02:59:52
10/12/09 02:59:54
10/12/09 02:59:56
10/12/09 02:59:58
10/12/09 03:00:00
10/12/09 03:00:02
10/12/09 03:00:04
10/12/09 03:00:06
10/12/09 03:00:08
10/12/09 03:00:10
10/12/09 03:00:12
10/12/09 03:00:14
10/12/09 03:00:16
10/12/09 03:00:18
Hz
60.01
60.01
60.012
60.012
60.013
60.014
60.013
60.012
60.011
60.01
60.008
60.01
60.011
60.013
60.016
60.018
60.019
60.019
60.019
60.02
60.02
60.018
60.018
60.016
60.016
60.019
60.023
60.022
60.018
60.015
60.016
60.017
60.015
60.01
60.004
59.999
59.995
59.99
59.982
Net
Actual
Interchange
MW
3679.792
3679.597
3680.315
3680.11
3679.062
3679.127
3679.587
3679.637
3679.02
3678.418
3679.383
3679.681
3679.932
3679.138
3678.469
3678.499
3678.456
3677.615
3677.446
3677.431
3677.451
3677.315
3678.151
3678.362
3678.874
3680.771
3681.058
3680.353
3679.167
3679.553
3680.672
3682.73
3682.714
3681.915
3682.01
3682.483
3683.813
3685.306
3684.846
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
705.5
706
706.5
707
707.5
708
708.5
709
709.5
710
710.5
711
711.5
712
712.5
713
713.5
714
714.5
715
715.5
716
716.5
717
717.5
718
718.5
719
719.5
720
720.5
721
721.5
722
722.5
723
723.5
724
724.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7965.63
7965.96
7966.29
7966.62
7966.95
7967.28
7967.61
7967.94
7968.27
7968.6
7968.93
7969.26
7969.59
7969.92
7970.25
7970.58
7970.91
7971.24
7971.57
7971.9
7972.23
7972.56
7972.89
7973.22
7973.55
7973.88
7974.21
7974.54
7974.87
7975.2
7975.53
7975.86
7976.19
7976.52
7976.85
7977.18
7977.51
7977.84
7978.17
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.000
0.002
0.000
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.000
-0.002
0.000
-0.002
0.000
0.003
0.004
-0.001
-0.004
-0.003
0.001
0.001
-0.002
-0.005
-0.006
-0.005
-0.004
-0.005
-0.008
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.000
0.002
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.000
0.002
0.000
0.002
0.000
0.003
0.004
0.001
0.004
0.003
0.001
0.001
0.002
0.005
0.006
0.005
0.004
0.005
0.008
003332
Time (T)
10/12/09 03:00:20
10/12/09 03:00:22
10/12/09 03:00:24
10/12/09 03:00:26
10/12/09 03:00:28
10/12/09 03:00:30
10/12/09 03:00:32
10/12/09 03:00:34
10/12/09 03:00:36
10/12/09 03:00:38
10/12/09 03:00:40
10/12/09 03:00:42
10/12/09 03:00:44
10/12/09 03:00:46
10/12/09 03:00:48
10/12/09 03:00:50
10/12/09 03:00:52
10/12/09 03:00:54
10/12/09 03:00:56
10/12/09 03:00:58
10/12/09 03:01:00
10/12/09 03:01:02
10/12/09 03:01:04
10/12/09 03:01:06
10/12/09 03:01:08
10/12/09 03:01:10
10/12/09 03:01:12
10/12/09 03:01:14
10/12/09 03:01:16
10/12/09 03:01:18
10/12/09 03:01:20
10/12/09 03:01:22
10/12/09 03:01:24
10/12/09 03:01:26
10/12/09 03:01:28
10/12/09 03:01:30
10/12/09 03:01:32
10/12/09 03:01:34
10/12/09 03:01:36
Hz
59.974
59.97
59.97
59.968
59.968
59.968
59.972
59.967
59.966
59.964
59.965
59.966
59.963
59.963
59.965
59.968
59.97
59.97
59.97
59.973
59.972
59.976
59.975
59.975
59.977
59.976
59.976
59.974
59.975
59.974
59.974
59.976
59.977
59.979
59.981
59.983
59.985
59.983
59.98
Net
Actual
Interchange
MW
3684.643
3687.527
3689.404
3692.287
3692.966
3693.793
3694.397
3694.974
3697.407
3698.502
3698.617
3698.992
3699.85
3702.645
3701.989
3702.218
3704.023
3703.365
3702.988
3703.814
3704.899
3705.625
3704.293
3702.094
3701.944
3703.142
3704.669
3705.376
3705.662
3705.855
3706.776
3707.514
3706.928
3706.446
3706.335
3706.771
3705.943
3704.127
3704.777
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
725
725.5
726
726.5
727
727.5
728
728.5
729
729.5
730
730.5
731
731.5
732
732.5
733
733.5
734
734.5
735
735.5
736
736.5
737
737.5
738
738.5
739
739.5
740
740.5
741
741.5
742
742.5
743
743.5
744
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7978.5
7978.83
7979.16
7979.49
7979.82
7980.15
7980.48
7980.81
7981.14
7981.47
7981.8
7982.13
7982.46
7982.79
7983.12
7983.45
7983.78
7984.11
7984.44
7984.77
7985.1
7985.43
7985.76
7986.09
7986.42
7986.75
7987.08
7987.41
7987.74
7988.07
7988.4
7988.73
7989.06
7989.39
7989.72
7990.05
7990.38
7990.71
7991.04
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.008
-0.004
0.000
-0.002
0.000
0.000
0.004
-0.005
-0.001
-0.002
0.001
0.001
-0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
-0.001
0.004
-0.001
0.000
0.002
-0.001
0.000
-0.002
0.001
-0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
-0.002
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.008
0.004
0.000
0.002
0.000
0.000
0.004
0.005
0.001
0.002
0.001
0.001
0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
0.001
0.004
0.001
0.000
0.002
0.001
0.000
0.002
0.001
0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
0.002
0.003
003333
Time (T)
10/12/09 03:01:38
10/12/09 03:01:40
10/12/09 03:01:42
10/12/09 03:01:44
10/12/09 03:01:46
10/12/09 03:01:48
10/12/09 03:01:50
10/12/09 03:01:52
10/12/09 03:01:54
10/12/09 03:01:56
10/12/09 03:01:58
10/12/09 03:02:00
10/12/09 03:02:02
10/12/09 03:02:04
10/12/09 03:02:06
10/12/09 03:02:08
10/12/09 03:02:10
10/12/09 03:02:12
10/12/09 03:02:14
10/12/09 03:02:16
10/12/09 03:02:18
10/12/09 03:02:20
10/12/09 03:02:22
10/12/09 03:02:24
10/12/09 03:02:26
10/12/09 03:02:28
10/12/09 03:02:30
10/12/09 03:02:32
10/12/09 03:02:34
10/12/09 03:02:36
10/12/09 03:02:38
10/12/09 03:02:40
10/12/09 03:02:42
10/12/09 03:02:44
10/12/09 03:02:46
10/12/09 03:02:48
10/12/09 03:02:50
10/12/09 03:02:52
10/12/09 03:02:54
Hz
59.979
59.983
59.987
59.986
59.984
59.98
59.982
59.984
59.985
59.987
59.989
59.992
59.996
59.999
59.997
59.997
59.997
59.997
59.996
59.997
59.996
59.998
60.003
60.009
60.01
60.008
60.005
60.004
60.006
60.003
60.001
60.002
60.004
60.007
60.007
60.008
60.008
60.006
60.006
Net
Actual
Interchange
MW
3705.974
3705.968
3705.356
3704.683
3703.913
3704.361
3704.988
3705.05
3704.893
3703.741
3701.831
3701.795
3700.07
3701.308
3700.429
3700.913
3700.541
3699.927
3700.858
3700.549
3700.614
3700.224
3699.5
3698.032
3697.96
3699.409
3699.241
3700.738
3701.11
3701.238
3699.998
3700.22
3701.823
3702.554
3702.276
3701.026
3701.923
3702.943
3704.093
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
744.5
745
745.5
746
746.5
747
747.5
748
748.5
749
749.5
750
750.5
751
751.5
752
752.5
753
753.5
754
754.5
755
755.5
756
756.5
757
757.5
758
758.5
759
759.5
760
760.5
761
761.5
762
762.5
763
763.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7991.37
7991.7
7992.03
7992.36
7992.69
7993.02
7993.35
7993.68
7994.01
7994.34
7994.67
7995
7995.33
7995.66
7995.99
7996.32
7996.65
7996.98
7997.31
7997.64
7997.97
7998.3
7998.63
7998.96
7999.29
7999.62
7999.95
8000.28
8000.61
8000.94
8001.27
8001.6
8001.93
8002.26
8002.59
8002.92
8003.25
8003.58
8003.91
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.004
0.004
-0.001
-0.002
-0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
-0.002
0.000
0.000
0.000
-0.001
0.001
-0.001
0.002
0.005
0.006
0.001
-0.002
-0.003
-0.001
0.002
-0.003
-0.002
0.001
0.002
0.003
0.000
0.001
0.000
-0.002
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.004
0.004
0.001
0.002
0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.005
0.006
0.001
0.002
0.003
0.001
0.002
0.003
0.002
0.001
0.002
0.003
0.000
0.001
0.000
0.002
0.000
003334
Time (T)
10/12/09 03:02:56
10/12/09 03:02:58
10/12/09 03:03:00
10/12/09 03:03:02
10/12/09 03:03:04
10/12/09 03:03:06
10/12/09 03:03:08
10/12/09 03:03:10
10/12/09 03:03:12
10/12/09 03:03:14
10/12/09 03:03:16
10/12/09 03:03:18
10/12/09 03:03:20
10/12/09 03:03:22
10/12/09 03:03:24
10/12/09 03:03:26
10/12/09 03:03:28
10/12/09 03:03:30
10/12/09 03:03:32
10/12/09 03:03:34
10/12/09 03:03:36
10/12/09 03:03:38
10/12/09 03:03:40
10/12/09 03:03:42
10/12/09 03:03:44
10/12/09 03:03:46
10/12/09 03:03:48
10/12/09 03:03:50
10/12/09 03:03:52
10/12/09 03:03:54
10/12/09 03:03:56
10/12/09 03:03:58
10/12/09 03:04:00
10/12/09 03:04:02
10/12/09 03:04:04
10/12/09 03:04:06
10/12/09 03:04:08
10/12/09 03:04:10
10/12/09 03:04:12
Hz
60.006
60.005
60
59.999
60
60
60.004
60.008
60.013
60.015
60.015
60.012
60.009
60.005
60.008
60.011
60.011
60.013
60.016
60.018
60.018
60.019
60.018
60.013
60.011
60.009
60.009
60.008
60.009
60.011
60.015
60.02
60.021
60.018
60.017
60.019
60.019
60.021
60.022
Net
Actual
Interchange
MW
3703.96
3703.819
3704.455
3704.346
3705.329
3704.93
3704.405
3703.675
3702.748
3702.669
3703.017
3703.416
3703.297
3705.189
3705.279
3704.646
3704.051
3703.438
3704.255
3703.708
3703.83
3704.524
3704.139
3704.27
3705.429
3705.942
3705.54
3705.634
3705.749
3707.267
3706.945
3706.63
3705.655
3703.895
3704.224
3703.887
3704.648
3704.795
3704.167
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
764
764.5
765
765.5
766
766.5
767
767.5
768
768.5
769
769.5
770
770.5
771
771.5
772
772.5
773
773.5
774
774.5
775
775.5
776
776.5
777
777.5
778
778.5
779
779.5
780
780.5
781
781.5
782
782.5
783
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8004.24
8004.57
8004.9
8005.23
8005.56
8005.89
8006.22
8006.55
8006.88
8007.21
8007.54
8007.87
8008.2
8008.53
8008.86
8009.19
8009.52
8009.85
8010.18
8010.51
8010.84
8011.17
8011.5
8011.83
8012.16
8012.49
8012.82
8013.15
8013.48
8013.81
8014.14
8014.47
8014.8
8015.13
8015.46
8015.79
8016.12
8016.45
8016.78
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.001
-0.005
-0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
-0.003
-0.003
-0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
-0.001
-0.005
-0.002
-0.002
0.000
-0.001
0.001
0.002
0.004
0.005
0.001
-0.003
-0.001
0.002
0.000
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.001
0.005
0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
0.003
0.003
0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
0.001
0.005
0.002
0.002
0.000
0.001
0.001
0.002
0.004
0.005
0.001
0.003
0.001
0.002
0.000
0.002
0.001
003335
Time (T)
10/12/09 03:04:14
10/12/09 03:04:16
10/12/09 03:04:18
10/12/09 03:04:20
10/12/09 03:04:22
10/12/09 03:04:24
10/12/09 03:04:26
10/12/09 03:04:28
10/12/09 03:04:30
10/12/09 03:04:32
10/12/09 03:04:34
10/12/09 03:04:36
10/12/09 03:04:38
10/12/09 03:04:40
10/12/09 03:04:42
10/12/09 03:04:44
10/12/09 03:04:46
10/12/09 03:04:48
10/12/09 03:04:50
10/12/09 03:04:52
10/12/09 03:04:54
10/12/09 03:04:56
10/12/09 03:04:58
10/12/09 03:05:00
10/12/09 03:05:02
10/12/09 03:05:04
10/12/09 03:05:06
10/12/09 03:05:08
10/12/09 03:05:10
10/12/09 03:05:12
10/12/09 03:05:14
10/12/09 03:05:16
10/12/09 03:05:18
10/12/09 03:05:20
10/12/09 03:05:22
10/12/09 03:05:24
10/12/09 03:05:26
10/12/09 03:05:28
10/12/09 03:05:30
Hz
60.025
60.027
60.03
60.027
60.023
60.021
60.023
60.023
60.02
60.024
60.024
60.022
60.022
60.024
60.025
60.023
60.024
60.02
60.018
60.013
60.008
60.012
60.017
60.019
60.019
60.015
60.016
60.015
60.016
60.014
60.016
60.018
60.019
60.016
60.014
60.014
60.018
60.022
60.023
Net
Actual
Interchange
MW
3702.764
3702.008
3700.36
3701.063
3700.34
3699.369
3701.568
3702.959
3704.25
3703.621
3703.374
3703.036
3703.931
3704.947
3704.208
3703.541
3703.16
3703.397
3704.376
3705.441
3706.995
3710.072
3707.971
3707.767
3707.609
3708.831
3709.465
3709.813
3709.817
3709.99
3709.094
3709.642
3709.812
3709.933
3710.677
3710.591
3709.354
3707.696
3707.38
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
783.5
784
784.5
785
785.5
786
786.5
787
787.5
788
788.5
789
789.5
790
790.5
791
791.5
792
792.5
793
793.5
794
794.5
795
795.5
796
796.5
797
797.5
798
798.5
799
799.5
800
800.5
801
801.5
802
802.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8017.11
8017.44
8017.77
8018.1
8018.43
8018.76
8019.09
8019.42
8019.75
8020.08
8020.41
8020.74
8021.07
8021.4
8021.73
8022.06
8022.39
8022.72
8023.05
8023.38
8023.71
8024.04
8024.37
8024.7
8025.03
8025.36
8025.69
8026.02
8026.35
8026.68
8027.01
8027.34
8027.67
8028
8028.33
8028.66
8028.99
8029.32
8029.65
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
0.003
-0.003
-0.004
-0.002
0.002
0.000
-0.003
0.004
0.000
-0.002
0.000
0.002
0.001
-0.002
0.001
-0.004
-0.002
-0.005
-0.005
0.004
0.005
0.002
0.000
-0.004
0.001
-0.001
0.001
-0.002
0.002
0.002
0.001
-0.003
-0.002
0.000
0.004
0.004
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.002
0.003
0.003
0.004
0.002
0.002
0.000
0.003
0.004
0.000
0.002
0.000
0.002
0.001
0.002
0.001
0.004
0.002
0.005
0.005
0.004
0.005
0.002
0.000
0.004
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.003
0.002
0.000
0.004
0.004
0.001
003336
Time (T)
10/12/09 03:05:32
10/12/09 03:05:34
10/12/09 03:05:36
10/12/09 03:05:38
10/12/09 03:05:40
10/12/09 03:05:42
10/12/09 03:05:44
10/12/09 03:05:46
10/12/09 03:05:48
10/12/09 03:05:50
10/12/09 03:05:52
10/12/09 03:05:54
10/12/09 03:05:56
10/12/09 03:05:58
10/12/09 03:06:00
10/12/09 03:06:02
10/12/09 03:06:04
10/12/09 03:06:06
10/12/09 03:06:08
10/12/09 03:06:10
10/12/09 03:06:12
10/12/09 03:06:14
10/12/09 03:06:16
10/12/09 03:06:18
10/12/09 03:06:20
10/12/09 03:06:22
10/12/09 03:06:24
10/12/09 03:06:26
10/12/09 03:06:28
10/12/09 03:06:30
10/12/09 03:06:32
10/12/09 03:06:34
10/12/09 03:06:36
10/12/09 03:06:38
10/12/09 03:06:40
10/12/09 03:06:42
10/12/09 03:06:44
10/12/09 03:06:46
10/12/09 03:06:48
Hz
60.024
60.026
60.026
60.024
60.022
60.02
60.019
60.022
60.025
60.028
60.03
60.031
60.029
60.026
60.026
60.029
60.03
60.033
60.03
60.022
60.016
60.019
60.03
60.028
60.021
60.015
60.015
60.012
60.011
60.014
60.013
60.014
60.016
60.016
60.015
60.013
60.007
59.997
59.994
Net
Actual
Interchange
MW
3707.12
3706.99
3705.848
3704.185
3704.406
3704.963
3706.567
3705.516
3704.869
3704.428
3704.773
3703.532
3702.686
3702.093
3703.169
3703.676
3701.52
3700.106
3698.222
3698.009
3700.28
3703.192
3703.815
3701.863
3699.956
3700.816
3703.802
3706.943
3708.527
3707.49
3707.647
3706.991
3707.495
3705.584
3705.398
3707.12
3709.144
3708.99
3708.291
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
803
803.5
804
804.5
805
805.5
806
806.5
807
807.5
808
808.5
809
809.5
810
810.5
811
811.5
812
812.5
813
813.5
814
814.5
815
815.5
816
816.5
817
817.5
818
818.5
819
819.5
820
820.5
821
821.5
822
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8029.98
8030.31
8030.64
8030.97
8031.3
8031.63
8031.96
8032.29
8032.62
8032.95
8033.28
8033.61
8033.94
8034.27
8034.6
8034.93
8035.26
8035.59
8035.92
8036.25
8036.58
8036.91
8037.24
8037.57
8037.9
8038.23
8038.56
8038.89
8039.22
8039.55
8039.88
8040.21
8040.54
8040.87
8041.2
8041.53
8041.86
8042.19
8042.52
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.002
0.000
-0.002
-0.002
-0.002
-0.001
0.003
0.003
0.003
0.002
0.001
-0.002
-0.003
0.000
0.003
0.001
0.003
-0.003
-0.008
-0.006
0.003
0.011
-0.002
-0.007
-0.006
0.000
-0.003
-0.001
0.003
-0.001
0.001
0.002
0.000
-0.001
-0.002
-0.006
-0.010
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.002
0.000
0.002
0.002
0.002
0.001
0.003
0.003
0.003
0.002
0.001
0.002
0.003
0.000
0.003
0.001
0.003
0.003
0.008
0.006
0.003
0.011
0.002
0.007
0.006
0.000
0.003
0.001
0.003
0.001
0.001
0.002
0.000
0.001
0.002
0.006
0.010
0.003
003337
Time (T)
10/12/09 03:06:50
10/12/09 03:06:52
10/12/09 03:06:54
10/12/09 03:06:56
10/12/09 03:06:58
10/12/09 03:07:00
10/12/09 03:07:02
10/12/09 03:07:04
10/12/09 03:07:06
10/12/09 03:07:08
10/12/09 03:07:10
10/12/09 03:07:12
10/12/09 03:07:14
10/12/09 03:07:16
10/12/09 03:07:18
10/12/09 03:07:20
10/12/09 03:07:22
10/12/09 03:07:24
10/12/09 03:07:26
10/12/09 03:07:28
10/12/09 03:07:30
10/12/09 03:07:32
10/12/09 03:07:34
10/12/09 03:07:36
10/12/09 03:07:38
10/12/09 03:07:40
10/12/09 03:07:42
10/12/09 03:07:44
10/12/09 03:07:46
10/12/09 03:07:48
10/12/09 03:07:50
10/12/09 03:07:52
10/12/09 03:07:54
10/12/09 03:07:56
10/12/09 03:07:58
10/12/09 03:08:00
10/12/09 03:08:02
10/12/09 03:08:04
10/12/09 03:08:06
Hz
59.993
59.99
59.993
59.994
59.993
59.994
59.993
59.996
59.988
59.985
59.983
59.982
59.98
59.977
59.981
59.982
59.978
59.98
59.98
59.977
59.98
59.983
59.984
59.981
59.981
59.98
59.981
59.981
59.981
59.98
59.978
59.978
59.979
59.978
59.976
59.976
59.975
59.976
59.975
Net
Actual
Interchange
MW
3706.193
3707.304
3707.903
3706.76
3706.921
3706.683
3706.888
3704.934
3705.678
3706.481
3707.071
3706.696
3707.479
3708.246
3709.436
3710.419
3710.134
3708.708
3710.024
3709.192
3708.335
3709.399
3707.911
3709.004
3707.638
3709.689
3708.945
3706.541
3711.256
3711.362
3712.303
3712.012
3711.703
3712.093
3713.992
3714.612
3715.083
3715.323
3714.794
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
822.5
823
823.5
824
824.5
825
825.5
826
826.5
827
827.5
828
828.5
829
829.5
830
830.5
831
831.5
832
832.5
833
833.5
834
834.5
835
835.5
836
836.5
837
837.5
838
838.5
839
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
-103
-103
-103
-103
-103
BA
Load
MW
8042.85
8043.18
8043.51
8043.84
8044.17
8044.5
8044.83
8045.16
8045.49
8045.82
8046.15
8046.48
8046.81
8047.14
8047.47
8047.8
8048.13
8048.46
8048.79
8049.12
8049.45
8049.78
8050.11
8050.44
8050.77
8051.1
8051.43
8051.76
8052.09
8052.42
8052.75
8053.08
8053.41
8053.74
8054.07
8054.4
8054.73
8055.06
8055.39
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
-0.003
0.003
0.001
-0.001
0.001
-0.001
0.003
-0.008
-0.003
-0.002
-0.001
-0.002
-0.003
0.004
0.001
-0.004
0.002
0.000
-0.003
0.003
0.003
0.001
-0.003
0.000
-0.001
0.001
0.000
0.000
-0.001
-0.002
0.000
0.001
-0.001
-0.002
0.000
-0.001
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.003
0.003
0.001
0.001
0.001
0.001
0.003
0.008
0.003
0.002
0.001
0.002
0.003
0.004
0.001
0.004
0.002
0.000
0.003
0.003
0.003
0.001
0.003
0.000
0.001
0.001
0.000
0.000
0.001
0.002
0.000
0.001
0.001
0.002
0.000
0.001
0.001
0.001
003338
Time (T)
10/12/09 03:08:08
10/12/09 03:08:10
10/12/09 03:08:12
10/12/09 03:08:14
10/12/09 03:08:16
10/12/09 03:08:18
10/12/09 03:08:20
10/12/09 03:08:22
10/12/09 03:08:24
10/12/09 03:08:26
10/12/09 03:08:28
10/12/09 03:08:30
10/12/09 03:08:32
10/12/09 03:08:34
10/12/09 03:08:36
10/12/09 03:08:38
10/12/09 03:08:40
10/12/09 03:08:42
10/12/09 03:08:44
10/12/09 03:08:46
10/12/09 03:08:48
10/12/09 03:08:50
10/12/09 03:08:52
10/12/09 03:08:54
10/12/09 03:08:56
10/12/09 03:08:58
10/12/09 03:09:00
10/12/09 03:09:02
10/12/09 03:09:04
10/12/09 03:09:06
10/12/09 03:09:08
10/12/09 03:09:10
10/12/09 03:09:12
10/12/09 03:09:14
10/12/09 03:09:16
10/12/09 03:09:18
10/12/09 03:09:20
10/12/09 03:09:22
10/12/09 03:09:24
Hz
59.979
59.978
59.975
59.976
59.981
59.977
59.975
59.976
59.979
59.98
59.979
59.978
59.979
59.982
59.983
59.987
59.988
59.984
59.98
59.979
59.98
59.979
59.978
59.975
59.979
59.982
59.983
59.983
59.985
59.99
59.987
59.984
59.976
59.979
59.985
59.983
59.979
59.981
59.978
Net
Actual
Interchange
MW
3714.717
3715.161
3715.001
3713.996
3714.063
3714.335
3715.631
3715.688
3715.567
3715.725
3714.848
3713.142
3713.358
3712.275
3712.619
3712.153
3710.05
3709.082
3710.472
3710.624
3710.946
3710.2
3710.475
3709.462
3710.803
3709.286
3710.573
3709.525
3708.371
3708.527
3706.512
3707.49
3708.962
3709.894
3712.303
3711.35
3711.627
3712.076
3712.393
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8055.72
8056.05
8056.38
8056.71
8057.04
8057.37
8057.7
8058.03
8058.36
8058.69
8059.02
8059.35
8059.68
8060.01
8060.34
8060.67
8061
8061.33
8061.66
8061.99
8062.32
8062.65
8062.98
8063.31
8063.64
8063.97
8064.3
8064.63
8064.96
8065.29
8065.62
8065.95
8066.28
8066.61
8066.94
8067.27
8067.6
8067.93
8068.26
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.004
-0.001
-0.003
0.001
0.005
-0.004
-0.002
0.001
0.003
0.001
-0.001
-0.001
0.001
0.003
0.001
0.004
0.001
-0.004
-0.004
-0.001
0.001
-0.001
-0.001
-0.003
0.004
0.003
0.001
0.000
0.002
0.005
-0.003
-0.003
-0.008
0.003
0.006
-0.002
-0.004
0.002
-0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.004
0.001
0.003
0.001
0.005
0.004
0.002
0.001
0.003
0.001
0.001
0.001
0.001
0.003
0.001
0.004
0.001
0.004
0.004
0.001
0.001
0.001
0.001
0.003
0.004
0.003
0.001
0.000
0.002
0.005
0.003
0.003
0.008
0.003
0.006
0.002
0.004
0.002
0.003
003339
Time (T)
10/12/09 03:09:26
10/12/09 03:09:28
10/12/09 03:09:30
10/12/09 03:09:32
10/12/09 03:09:34
10/12/09 03:09:36
10/12/09 03:09:38
10/12/09 03:09:40
10/12/09 03:09:42
10/12/09 03:09:44
10/12/09 03:09:46
10/12/09 03:09:48
10/12/09 03:09:50
10/12/09 03:09:52
10/12/09 03:09:54
10/12/09 03:09:56
10/12/09 03:09:58
10/12/09 03:10:00
10/12/09 03:10:02
10/12/09 03:10:04
10/12/09 03:10:06
10/12/09 03:10:08
10/12/09 03:10:10
10/12/09 03:10:12
10/12/09 03:10:14
10/12/09 03:10:16
10/12/09 03:10:18
10/12/09 03:10:20
10/12/09 03:10:22
10/12/09 03:10:24
10/12/09 03:10:26
10/12/09 03:10:28
10/12/09 03:10:30
10/12/09 03:10:32
10/12/09 03:10:34
10/12/09 03:10:36
10/12/09 03:10:38
10/12/09 03:10:40
10/12/09 03:10:42
Hz
59.975
59.978
59.989
59.999
59.994
59.989
59.986
59.984
59.983
59.982
59.98
59.99
59.995
59.995
59.99
59.989
59.991
59.996
60
60.002
60.004
60.004
60.002
59.999
59.998
59.995
59.996
60.001
60.002
60.001
60.003
60.005
60.004
60.004
60.004
60.006
60.003
60.005
60.006
Net
Actual
Interchange
MW
3712.999
3713.51
3716.626
3715.443
3712.092
3713.906
3714.894
3714.953
3716.122
3716.308
3715.438
3714.764
3714.714
3715.068
3715.927
3715.791
3716.285
3715.324
3714.46
3711.708
3712.698
3712.851
3713.362
3716.641
3718.292
3719.079
3718.233
3717.815
3717.889
3718.56
3718.195
3719.021
3718.821
3719.897
3719.299
3719.643
3719.527
3719.731
3720.279
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8068.59
8068.92
8069.25
8069.58
8069.91
8070.24
8070.57
8070.9
8071.23
8071.56
8071.89
8072.22
8072.55
8072.88
8073.21
8073.54
8073.87
8074.2
8074.53
8074.86
8075.19
8075.52
8075.85
8076.18
8076.51
8076.84
8077.17
8077.5
8077.83
8078.16
8078.49
8078.82
8079.15
8079.48
8079.81
8080.14
8080.47
8080.8
8081.13
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
0.003
0.011
0.010
-0.005
-0.005
-0.003
-0.002
-0.001
-0.001
-0.002
0.010
0.005
0.000
-0.005
-0.001
0.002
0.005
0.004
0.002
0.002
0.000
-0.002
-0.003
-0.001
-0.003
0.001
0.005
0.001
-0.001
0.002
0.002
-0.001
0.000
0.000
0.002
-0.003
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.003
0.011
0.010
0.005
0.005
0.003
0.002
0.001
0.001
0.002
0.010
0.005
0.000
0.005
0.001
0.002
0.005
0.004
0.002
0.002
0.000
0.002
0.003
0.001
0.003
0.001
0.005
0.001
0.001
0.002
0.002
0.001
0.000
0.000
0.002
0.003
0.002
0.001
003340
Time (T)
10/12/09 03:10:44
10/12/09 03:10:46
10/12/09 03:10:48
10/12/09 03:10:50
10/12/09 03:10:52
10/12/09 03:10:54
10/12/09 03:10:56
10/12/09 03:10:58
10/12/09 03:11:00
10/12/09 03:11:02
10/12/09 03:11:04
10/12/09 03:11:06
10/12/09 03:11:08
10/12/09 03:11:10
10/12/09 03:11:12
10/12/09 03:11:14
10/12/09 03:11:16
10/12/09 03:11:18
10/12/09 03:11:20
10/12/09 03:11:22
10/12/09 03:11:24
10/12/09 03:11:26
10/12/09 03:11:28
10/12/09 03:11:30
10/12/09 03:11:32
10/12/09 03:11:34
10/12/09 03:11:36
10/12/09 03:11:38
10/12/09 03:11:40
10/12/09 03:11:42
10/12/09 03:11:44
10/12/09 03:11:46
10/12/09 03:11:48
10/12/09 03:11:50
10/12/09 03:11:52
10/12/09 03:11:54
10/12/09 03:11:56
10/12/09 03:11:58
10/12/09 03:12:00
Hz
60.009
60.009
60.01
60.009
60.013
60.015
60.014
60.009
60.009
60.008
60.011
60.01
60.009
60.013
60.013
60.014
60.014
60.012
60.01
60.011
60.007
60.003
60.001
60
59.998
59.998
59.999
60.002
60.003
60.003
59.999
59.998
60.001
59.995
59.989
59.987
59.988
59.988
59.99
Net
Actual
Interchange
MW
3718.58
3718.976
3718.982
3720.034
3720.609
3720.811
3721.239
3720.38
3719.447
3720.807
3721.272
3720.592
3721.245
3721.594
3722.176
3721.999
3721.646
3721.678
3720.86
3721.645
3723.816
3725.07
3724.656
3724.869
3724.661
3723.696
3723.58
3723.405
3721.879
3722.401
3722.906
3724.142
3723.65
3723.201
3723.639
3723.881
3724.654
3725.361
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8081.46
8081.79
8082.12
8082.45
8082.78
8083.11
8083.44
8083.77
8084.1
8084.43
8084.76
8085.09
8085.42
8085.75
8086.08
8086.41
8086.74
8087.07
8087.4
8087.73
8088.06
8088.39
8088.72
8089.05
8089.38
8089.71
8090.04
8090.37
8090.7
8091.03
8091.36
8091.69
8092.02
8092.35
8092.68
8093.01
8093.34
8093.67
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
0
1
0
1
1
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.000
0.001
-0.001
0.004
0.002
-0.001
-0.005
0.000
-0.001
0.003
-0.001
-0.001
0.004
0.000
0.001
0.000
-0.002
-0.002
0.001
-0.004
-0.004
-0.002
-0.001
-0.002
0.000
0.001
0.003
0.001
0.000
-0.004
-0.001
0.003
-0.006
-0.006
-0.002
0.001
0.000
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.003
0.000
0.001
0.001
0.004
0.002
0.001
0.005
0.000
0.001
0.003
0.001
0.001
0.004
0.000
0.001
0.000
0.002
0.002
0.001
0.004
0.004
0.002
0.001
0.002
0.000
0.001
0.003
0.001
0.000
0.004
0.001
0.003
0.006
0.006
0.002
0.001
0.000
0.002
003341
Time (T)
10/12/09 03:12:02
10/12/09 03:12:04
10/12/09 03:12:06
10/12/09 03:12:08
10/12/09 03:12:10
10/12/09 03:12:12
10/12/09 03:12:14
10/12/09 03:12:16
10/12/09 03:12:18
10/12/09 03:12:20
10/12/09 03:12:22
10/12/09 03:12:24
10/12/09 03:12:26
10/12/09 03:12:28
10/12/09 03:12:30
10/12/09 03:12:32
10/12/09 03:12:34
10/12/09 03:12:36
10/12/09 03:12:38
10/12/09 03:12:40
10/12/09 03:12:42
10/12/09 03:12:44
10/12/09 03:12:46
10/12/09 03:12:48
10/12/09 03:12:50
10/12/09 03:12:52
10/12/09 03:12:54
10/12/09 03:12:56
10/12/09 03:12:58
10/12/09 03:13:00
10/12/09 03:13:02
10/12/09 03:13:04
10/12/09 03:13:06
10/12/09 03:13:08
10/12/09 03:13:10
10/12/09 03:13:12
10/12/09 03:13:14
10/12/09 03:13:16
10/12/09 03:13:18
Hz
59.999
60.001
60.003
60.0005
59.998
59.997
59.996
59.996
59.996
59.995
59.994
59.993
59.992
59.991
59.99
59.991
59.992
59.993
59.994
59.995
59.996
59.996
59.996
59.9965
59.997
59.997
59.997
59.997
59.997
59.999
60.001
60.001
60.001
60.004
60.007
60.009
60.011
60.0085
60.006
Net
Actual
Interchange
MW
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.009
0.002
0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
-0.003
-0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.009
0.002
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
0.003
0.002
003342
Time (T)
10/12/09 03:13:20
10/12/09 03:13:22
10/12/09 03:13:24
10/12/09 03:13:26
10/12/09 03:13:28
10/12/09 03:13:30
10/12/09 03:13:32
10/12/09 03:13:34
10/12/09 03:13:36
10/12/09 03:13:38
10/12/09 03:13:40
10/12/09 03:13:42
10/12/09 03:13:44
10/12/09 03:13:46
10/12/09 03:13:48
10/12/09 03:13:50
10/12/09 03:13:52
10/12/09 03:13:54
10/12/09 03:13:56
10/12/09 03:13:58
10/12/09 03:14:00
10/12/09 03:14:02
10/12/09 03:14:04
10/12/09 03:14:06
10/12/09 03:14:08
10/12/09 03:14:10
10/12/09 03:14:12
10/12/09 03:14:14
10/12/09 03:14:16
10/12/09 03:14:18
10/12/09 03:14:20
10/12/09 03:14:22
10/12/09 03:14:24
10/12/09 03:14:26
10/12/09 03:14:28
10/12/09 03:14:30
10/12/09 03:14:32
10/12/09 03:14:34
10/12/09 03:14:36
Hz
60.007
60.008
60.01
60.012
60.012
60.012
60.01
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.007
60.006
60.005
60.004
60.004
60.004
60.0025
60.001
59.9995
59.998
59.9965
59.995
59.995
59.995
59.996
59.997
59.995
59.993
59.9925
59.992
59.9905
59.989
59.99
59.991
59.989
Net
Actual
Interchange
MW
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.001
0.002
0.002
0.000
0.000
-0.002
-0.002
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.001
0.001
-0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.001
0.002
0.002
0.000
0.000
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.002
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.002
003343
Time (T)
10/12/09 03:14:38
10/12/09 03:14:40
10/12/09 03:14:42
10/12/09 03:14:44
10/12/09 03:14:46
10/12/09 03:14:48
10/12/09 03:14:50
10/12/09 03:14:52
10/12/09 03:14:54
10/12/09 03:14:56
10/12/09 03:14:58
10/12/09 03:15:00
10/12/09 03:15:02
10/12/09 03:15:04
10/12/09 03:15:06
10/12/09 03:15:08
10/12/09 03:15:10
10/12/09 03:15:12
10/12/09 03:15:14
10/12/09 03:15:16
10/12/09 03:15:18
10/12/09 03:15:20
10/12/09 03:15:22
10/12/09 03:15:24
10/12/09 03:15:26
10/12/09 03:15:28
10/12/09 03:15:30
10/12/09 03:15:32
10/12/09 03:15:34
10/12/09 03:15:36
10/12/09 03:15:38
10/12/09 03:15:40
10/12/09 03:15:42
10/12/09 03:15:44
10/12/09 03:15:46
10/12/09 03:15:48
10/12/09 03:15:50
10/12/09 03:15:52
10/12/09 03:15:54
Hz
59.987
59.9875
59.988
59.988
59.988
59.987
59.986
59.9855
59.985
59.9845
59.984
59.984
59.984
59.985
59.986
59.987
59.988
59.992
59.996
59.9975
59.999
60.001
60.003
60.003
60.003
60.0055
60.008
60.01
60.012
60.0105
60.009
60.01
60.011
60.012
60.013
60.013
60.013
60.0145
60.016
Net
Actual
Interchange
MW
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
-0.002
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
003344
Time (T)
10/12/09 03:15:56
10/12/09 03:15:58
10/12/09 03:15:59
10/12/09 03:16:01
10/12/09 03:16:03
10/12/09 03:16:05
10/12/09 03:16:07
10/12/09 03:16:09
10/12/09 03:16:11
10/12/09 03:16:13
10/12/09 03:16:15
10/12/09 03:16:17
10/12/09 03:16:19
10/12/09 03:16:21
10/12/09 03:16:23
10/12/09 03:16:25
10/12/09 03:16:27
10/12/09 03:16:29
10/12/09 03:16:31
10/12/09 03:16:33
10/12/09 03:16:35
10/12/09 03:16:37
10/12/09 03:16:39
10/12/09 03:16:41
10/12/09 03:16:43
10/12/09 03:16:45
10/12/09 03:16:47
10/12/09 03:16:49
10/12/09 03:16:51
10/12/09 03:16:53
10/12/09 03:16:55
10/12/09 03:16:57
10/12/09 03:16:59
10/12/09 03:17:01
10/12/09 03:17:03
10/12/09 03:17:05
10/12/09 03:17:07
10/12/09 03:17:09
10/12/09 03:17:11
Hz
60.0155
60.015
60.014
60.013
60.012
60.011
60.0105
60.01
60.008
60.006
60.006
60.006
60.0045
60.003
60.003
60.003
60.0035
60.004
60.0025
60.001
59.999
59.997
59.9965
59.996
59.9965
59.997
59.997
59.997
59.998
59.999
59.9985
59.998
59.9985
59.999
59.998
59.997
59.9985
60
60.001
Net
Actual
Interchange
MW
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.000
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
-0.001
-0.001
0.001
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.000
0.000
0.001
0.002
0.000
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
003345
Time (T)
10/12/09 03:17:13
10/12/09 03:17:15
10/12/09 03:17:17
10/12/09 03:17:19
10/12/09 03:17:21
10/12/09 03:17:23
10/12/09 03:17:25
Hz
60.002
60.0015
60.001
60.0035
60.006
60.0055
60.005
Net
Actual
Interchange
MW
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
Delta
Hz
0.001
0.000
0.000
0.003
0.002
0.000
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.001
0.000
0.000
0.003
0.002
0.000
0.000
003346
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
MyBA_091012_0227_FRS_Form2.9.xlsm
59.500 Hz
60.500 Hz
Auto Event Detection
2:27:26
1245 Manually selected row number of the Event Starting Time.
2:33:00
1442 Manually selected row number of the Event Ending Time.
Auto
Manual
Event Frequency Data
2:27:26
60.1
-0.153
2:27:26
Delta Hz Event Detected
60.05
2:33:00
60
59.95
59.9
59.85
59.8
Copy Form 2 data for
Pasting into Form 1
59.75
59.7
2:17:26
2:22:26
2:27:26
2:32:26
2:37:26
2:42:26
2:47:26
Hz
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_091012_0227_FRS_Form2.9.xlsm
2:52:26
2:57:26
3:02:26
3:07:26
3:12:26
3:17:25
003347
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
Frequency
Hz
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
Interchange
MW
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.190
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3734.673
3737.157
3761.250
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.500
3784.962
3784.730
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.010
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.670
3769.630
3768.707
3767.643
Value B
20 to 52 sec
Average
Frequency
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3788.35
157.63
-15.40
-43.39
114.21
157.60
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
Low Hz
3764.66
3804.23
3719.84
3640.68
103.04
0:05:34
No
163.55
123.97
No
Yes
Yes
60.52
20.94
Up
142.20 MW
Yes
1.109 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
Balancing Authority MyBA
Grid Nominal Frequency
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
A Point
FPointA
A Value
C Value
Delta FC
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
2:27:24
60.03900146
60.04212523
59.83599854
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
2:27:24
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3803.35
157.63
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
-43.39
114.21
157.60
198.04
350.00
165.34
0.00
MW
MW
MW
MW
MW
MW
MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
-9.734
-15.700
-19.578
-20.657
-20.277
-19.308
-19.400
-19.820
-19.733
-20.397
-20.828
-21.109
-20.571
-19.861
-20.840
-24.721
-29.407
-32.452
-34.072
-35.485
-39.649
-43.076
-45.303
-44.948
-43.997
-43.379
-42.977
-41.995
-42.077
-42.852
-44.075
-45.232
-44.182
-43.499
-43.055
-42.046
-19.399
40.744
85.606
102.870
114.091
113.094
112.806
116.583
120.481
123.375
122.373
120.278
119.277
118.988
118.079
117.127
115.788
113.114
111.737
111.202
110.494
110.034
110.817
111.686
114.054
115.593
115.511
115.819
115.658
115.553
114.765
114.613
117.037
121.857
130.759
139.429
143.983
144.779
143.495
141.579
140.693
139.397
138.914
136.799
134.342
130.943
128.372
125.621
122.750
119.443
116.572
115.788
113.835
110.404
106.731
104.704
103.386
101.809
99.702
96.891
93.261
90.902
89.008
87.416
85.661
84.159
83.544
84.225
83.587
82.811
81.585
79.708
78.848
77.207
76.501
74.240
Initial
Measure
Final
Expected
Primary
Frequency
Response
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Average
Ramp
MW/scan
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
0.000
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Period Recovery Recovery Period Recovery
Target
Period
Period
Ramp
Period
MW
MW
MW
MW
MW
3666.787
3666.265
3666.251
3665.485
3664.952
3664.570
3665.006
3665.615
3664.533
3660.551
3655.763
3652.616
3650.895
3649.380
3645.114
3641.585
3639.256
3639.509
3640.359
3640.875
3641.176
3642.056
3641.872
3640.996
3639.670
3638.411
3639.360
3639.942
3640.284
3641.191
3663.838
3724.598
3770.077
3787.958
3799.796
3799.415
3799.745
3804.139
3808.654
3812.165
3811.779
3810.302
3809.918
3810.246
3809.953
3809.618
3808.896
3806.840
3806.079
3806.161
3806.070
3806.227
3807.627
3809.113
3812.098
3814.254
3814.790
3815.714
3816.170
3816.682
3816.511
3816.976
3820.017
3825.454
3834.973
3844.260
3849.431
3850.844
3850.177
3848.877
3848.609
3847.929
3848.064
3846.566
3844.726
3841.943
3839.990
3837.855
3835.601
3832.911
3830.658
3830.490
3829.154
3826.340
3823.284
3821.874
3821.174
3820.214
3818.723
3816.529
3813.516
3811.774
3810.497
3809.522
3808.384
3807.499
3807.501
3808.799
3808.778
3808.618
3808.010
3806.750
3806.507
3805.482
3805.394
3803.750
3677.914
3696.910
3706.351
3712.015
3716.206
3722.640
3728.074
3732.310
3735.967
3739.054
3742.518
3745.523
3748.165
3750.618
3752.750
3754.613
3756.471
3758.148
3759.684
3761.055
3762.474
3763.805
3765.078
3766.452
3767.759
3768.952
3770.190
3771.319
3772.373
3773.406
3774.409
3775.354
3776.351
3777.355
3778.397
3779.410
3780.627
3781.792
3782.897
3783.986
3785.004
3785.975
3786.895
3787.758
3788.542
3789.265
3789.886
3790.461
3790.988
3791.459
3791.888
3792.265
3792.587
3792.848
3793.076
3793.271
3793.319
3793.330
3793.311
3793.281
3793.221
3793.140
3793.006
3792.853
3792.684
3792.440
3792.193
3791.938
3791.672
3791.423
3791.163
3790.896
3790.608
3790.316
3790.018
3694.218
3719.504
3736.618
3749.253
3757.614
3763.632
3768.696
3773.136
3777.038
3780.197
3782.705
3784.799
3786.616
3788.172
3789.513
3790.653
3791.552
3792.317
3793.009
3793.631
3794.203
3794.787
3795.384
3796.053
3796.753
3797.421
3798.074
3798.698
3799.297
3799.853
3800.388
3800.983
3801.702
3802.653
3803.809
3805.042
3806.247
3807.373
3808.411
3809.392
3810.309
3811.187
3811.991
3812.719
3813.354
3813.921
3814.419
3814.852
3815.213
3815.516
3815.804
3816.055
3816.246
3816.374
3816.472
3816.555
3816.618
3816.653
3816.651
3816.600
3816.522
3816.426
3816.319
3816.197
3816.065
3815.937
3815.832
3815.730
3815.628
3815.521
3815.399
3815.277
3815.145
3815.015
3814.867
3668.635
3669.252
3669.869
3670.486
3671.103
3671.720
3672.337
3672.954
3673.571
3674.188
3674.805
3675.422
3676.039
3676.656
3677.273
3677.890
3678.507
3679.124
3679.741
3680.358
3680.975
3681.592
3682.209
3682.826
3683.443
3684.060
3684.677
3685.293
3685.910
3686.527
3687.144
3687.761
3688.378
3688.995
3689.612
3690.229
3690.846
3691.463
3692.080
3692.697
3693.314
3693.931
3694.548
3695.165
3695.782
3696.399
3697.016
3697.633
3698.250
3698.867
3699.484
3700.101
3700.718
3701.335
3701.952
3702.569
3703.186
3703.803
3704.420
3705.037
3705.654
3706.271
3706.888
3707.504
3708.121
3708.738
3709.355
3709.972
3710.589
3711.206
3711.823
3712.440
3713.057
3713.674
3714.291
3668.635
3668.944
3669.252
3669.561
3669.869
3670.178
3670.486
3670.795
3671.103
3671.412
3671.720
3672.029
3672.337
3672.646
3672.954
3673.263
3673.571
3673.879
3674.188
3674.496
3674.805
3675.113
3675.422
3675.730
3676.039
3676.347
3676.656
3676.964
3677.273
3677.581
3677.890
3678.198
3678.507
3678.815
3679.124
3679.432
3679.741
3680.049
3680.358
3680.666
3680.975
3681.283
3681.592
3681.900
3682.209
3682.517
3682.826
3683.134
3683.443
3683.751
3684.060
3684.368
3684.677
3684.985
3685.293
3685.602
3685.910
3686.219
3686.527
3686.836
3687.144
3687.453
3687.761
3688.070
3688.378
3688.687
3688.995
3689.304
3689.612
3689.921
3690.229
3690.538
3690.846
3691.155
3691.463
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
-4.21 MW
15.00 MW
526.12 MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
335.00 MW
214.13 MW
6.35 MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
11.09
0.00
566.57
40.45
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.890
59.863
59.899
59.920
59.937
113.30
141.11
104.03
82.40
64.89
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-103.00
Post-Perturbation Bias Setting
-103.00
EPFR for Bias Setting Pre-Perturbation Average
-43.39
EPFR for Bias Setting Post-Perturbation Average
114.21
EPFR for Bias Setting Delta
157.60
Primary Frequency Response Delivery % of Bias
100.02%
Hz
Hz
Hz
Hz
Hz
MW
MW
MW
MW
MW
Actual
Primary
Freq Response
MW
158.51
182.41
164.54
129.49
119.99
Un-adjusted
P.U.
Performance
1.399
1.293
1.582
1.571
1.849
JOU
Dynamic
Schedules
Adjustment
-15.00
-15.00
-15.00
-15.00
-15.00
Expected
Net
Actual
Interchange
MW
Actual
Primary
Freq Response
MW
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
NonTransferred
Conforming
Pumped
Frequency
Load
Hydro
Response
Adjustment Adjustment Adjustment
50.26
11.00
15.21
49.49
16.00
17.91
63.03
16.00
14.31
64.13
16.00
12.21
63.75
16.00
10.51
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
7651.3 MW
7632.0 MW
-19.305 MW
-12.617 MW/0.1 Hz
12.25%
Average Bias Setting when Hz is greater than +/-0.036 Hz
-103.00 MW/0.1 Hz
20 to 52 second Average Period Evaluation
0.758 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Frequency
Hz
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
NonConforming
Load
Load (-)
MW
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.020
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.880
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.890
59.895
59.894
59.893
59.894
59.894
59.891
59.890
59.885
59.885
59.888
59.887
59.888
59.888
59.890
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.880
59.883
59.886
59.890
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.920
59.921
59.920
59.917
59.920
59.921
59.923
59.926
59.925
59.928
59.927
59.932
3671.19
3668.61
3665.23
3664.50
3666.06
3666.82
3666.79
3670.45
3670.27
3671.67
3672.49
3672.69
3672.86
3672.16
3671.41
3669.98
3666.47
3663.76
3661.60
3660.67
3651.49
3649.19
3650.03
3648.25
3649.51
3654.29
3655.01
3651.87
3651.06
3649.19
3648.24
3645.39
3644.63
3645.45
3640.68
3641.19
3659.46
3696.36
3734.90
3734.67
3734.67
3737.16
3761.25
3766.11
3766.19
3768.88
3769.93
3780.62
3781.59
3782.50
3784.96
3784.73
3784.42
3788.07
3788.33
3788.87
3788.47
3792.28
3793.07
3794.37
3799.43
3800.43
3799.96
3803.63
3802.93
3802.95
3804.39
3805.50
3805.62
3809.24
3811.50
3814.86
3815.89
3825.64
3826.05
3826.00
3827.52
3826.75
3826.78
3826.45
3825.71
3823.83
3822.51
3819.08
3818.06
3816.81
3815.01
3813.78
3811.84
3809.65
3806.97
3805.59
3804.19
3796.08
3793.98
3792.17
3791.50
3789.53
3788.13
3784.56
3783.03
3781.70
3776.36
3775.64
3774.60
3773.33
3773.96
3772.72
3771.67
3769.63
3768.71
3767.64
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
157.63
155.53
155.53
155.53
155.53
155.53
160.45
160.45
160.45
160.45
160.45
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
166.07
166.07
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
229.47
229.47
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
BA
Load
MW
7640.91
7641.24
7641.57
7641.90
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.20
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.50
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.80
7652.13
7652.46
7652.79
7616.00
7626.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7623.00
7621.00
7623.00
7625.00
7627.00
7628.00
7628.00
7629.00
7630.00
7631.00
7635.00
7638.00
7639.00
7642.00
7644.00
7645.00
7647.00
7648.00
7649.00
7650.00
7651.00
7652.00
7653.00
7654.00
7655.00
7655.00
7656.00
7656.00
7657.00
7657.00
7658.00
7658.00
7659.00
7659.00
7659.00
7660.00
7660.00
7661.00
7661.00
7662.00
7662.00
Expected Primary
Freq Response
Based on Bias Setting
MW
T
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Hz
MW
MW
MW
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
1.000 P.U.
0.744 P.U.
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Pumped
Hydro
Load (-) Gen (+)
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
BA
Load
MW
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
EPFR
MW
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
51.252
89.794
89.563
89.563
92.047
116.139
121.003
121.084
123.767
124.815
135.511
136.482
137.389
139.852
139.620
139.309
142.962
143.218
143.758
143.362
147.166
147.964
149.264
154.318
155.317
154.849
158.515
157.815
157.841
159.278
160.386
160.507
164.127
166.393
169.752
170.779
180.532
180.943
180.892
182.414
181.643
181.673
181.344
180.603
178.716
177.395
173.971
172.945
171.705
169.900
168.673
166.728
164.542
161.862
160.483
159.078
150.968
148.865
147.059
146.392
144.424
143.022
139.453
137.918
136.591
131.248
130.525
129.494
128.224
128.848
127.612
126.560
124.520
123.597
122.533
-26.96
-43.56
-51.73
-51.73
-61.31
-76.85
-74.64
-72.89
-74.06
-78.44
-87.36
-87.42
-87.44
-90.15
-90.59
-91.57
-97.17
-96.69
-96.40
-96.78
-99.35
-97.91
-98.12
-98.21
-98.85
-100.47
-102.19
-102.39
-102.41
-104.70
-104.74
-100.24
-97.05
-89.88
-87.90
-89.82
-98.05
-101.01
-102.71
-102.99
-103.72
-103.15
-105.97
-107.42
-109.56
-109.42
-109.33
-110.77
-112.87
-113.17
-110.15
-111.81
-114.96
-116.34
-114.53
-113.53
-109.30
-110.17
-112.15
-116.07
-114.51
-114.30
-112.35
-112.93
-112.77
-107.47
-104.32
-106.03
-105.86
-108.16
-109.89
-108.05
-109.11
-107.36
-111.27
0.0270
0.0260
0.0260
0.0220
0.0190
0.0170
0.0190
0.0200
0.0190
0.0210
0.0210
0.0210
0.0190
0.0180
0.0220
0.0310
0.0370
0.0370
0.0360
0.0370
0.0460
0.0480
0.0480
0.0430
0.0410
0.0410
0.0410
0.0390
0.0410
0.0430
0.0450
0.0460
0.0410
0.0410
0.0410
0.0390
0.0220
0.1480
0.1640
0.1310
0.1310
0.1080
0.1090
0.1200
0.1240
0.1250
0.1170
0.1130
0.1140
0.1150
0.1130
0.1120
0.1100
0.1050
0.1060
0.1070
0.1060
0.1060
0.1090
0.1100
0.1150
0.1150
0.1120
0.1130
0.1120
0.1120
0.1100
0.1110
0.1180
0.1270
0.1430
0.1510
0.1480
0.1420
0.1370
0.1340
0.1350
0.1330
0.1340
0.1290
0.1260
0.1210
0.1200
0.1170
0.1140
0.1100
0.1080
0.1110
0.1070
0.1010
0.0970
0.0980
0.0980
0.0960
0.0930
0.0890
0.0840
0.0840
0.0830
0.0820
0.0800
0.0790
0.0800
0.0830
0.0800
0.0790
0.0770
0.0740
0.0750
0.0720
0.0730
0.0680
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
Contingent
BA
Adjusted
Lost Generation
P.U.
Adjustment
Performance
-15.00
0.856
-15.00
0.808
-15.00
0.829
-15.00
0.633
-15.00
0.689
003348
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.810
3712.092
3714.623
3715.130
3716.168
3716.461
3716.980
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.130
3732.530
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.300
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.420
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.850
3786.304
3787.259
3787.516
3787.955
3788.030
3788.607
3789.216
3787.537
3785.842
3786.077
3787.930
3788.760
3786.875
3786.550
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.540
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
74.573
74.428
73.253
73.210
72.461
71.254
69.026
67.578
63.754
59.825
57.993
58.604
59.361
59.493
58.498
56.769
56.007
54.790
53.278
51.935
50.701
50.620
50.207
49.939
49.764
48.569
48.874
48.351
48.733
48.620
48.547
48.860
48.342
48.006
45.985
45.391
45.366
46.071
45.808
45.997
45.039
43.335
41.866
40.911
38.129
37.041
36.334
35.153
33.664
31.255
31.130
31.410
31.591
31.349
30.831
29.774
29.087
27.558
25.843
24.729
24.725
24.002
24.253
23.695
23.693
22.611
21.186
20.621
20.614
20.969
20.840
21.117
19.854
19.033
18.139
16.117
14.442
14.074
13.835
12.237
10.477
9.694
9.545
10.170
11.658
13.705
15.036
14.100
11.689
9.040
6.597
4.648
2.661
2.090
1.719
1.478
0.240
-1.647
-3.594
-5.220
-7.359
-9.830
-12.518
-14.986
-17.312
-17.380
-17.425
-18.176
-20.106
-21.720
-23.131
-22.606
-21.544
-22.655
-23.377
-22.765
-22.008
-23.318
-23.808
-22.685
-21.956
-22.202
-22.362
-22.466
-22.173
-21.983
-22.580
-22.968
-22.860
-21.709
-19.878
-19.411
-19.106
-18.909
-19.141
-19.291
-18.307
-17.307
-17.017
-16.108
-15.157
-14.178
-13.542
-12.407
-10.588
-9.406
-9.358
-9.327
-9.667
-7.364
-4.426
-1.074
2.185
4.665
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3804.700
3805.172
3804.614
3805.187
3805.055
3804.465
3802.855
3802.024
3798.816
3795.504
3794.290
3795.518
3796.892
3797.641
3797.263
3796.151
3796.005
3795.405
3794.510
3793.784
3793.167
3793.703
3793.907
3794.256
3794.698
3794.120
3795.042
3795.136
3796.135
3796.639
3797.183
3798.112
3798.212
3798.493
3797.088
3797.112
3797.704
3799.026
3799.380
3800.186
3799.845
3798.758
3797.906
3797.568
3795.403
3794.931
3794.841
3794.278
3793.406
3791.614
3792.106
3793.002
3793.800
3794.175
3794.274
3793.834
3793.764
3792.852
3791.754
3791.257
3791.870
3791.764
3792.632
3792.691
3793.306
3792.840
3792.033
3792.085
3792.695
3793.667
3794.155
3795.048
3794.402
3794.199
3793.922
3792.516
3791.459
3791.708
3792.085
3791.104
3789.962
3789.796
3790.264
3791.506
3793.610
3796.275
3798.223
3797.903
3796.109
3794.077
3792.251
3790.919
3788.932
3788.361
3787.990
3787.749
3786.511
3784.624
3782.677
3781.051
3778.912
3776.441
3773.754
3771.285
3768.960
3768.891
3768.846
3768.095
3766.166
3764.551
3763.140
3763.666
3764.728
3763.617
3762.894
3763.506
3764.264
3762.953
3762.463
3763.586
3764.316
3764.069
3763.909
3763.805
3764.098
3764.288
3763.691
3763.303
3763.411
3764.562
3766.393
3766.861
3767.165
3767.363
3767.131
3766.980
3767.964
3768.964
3769.254
3770.163
3771.114
3772.093
3772.729
3773.864
3775.683
3776.866
3776.913
3776.945
3776.605
3778.907
3781.845
3785.197
3788.457
3790.936
3789.719
3789.433
3789.147
3788.861
3788.574
3788.301
3788.011
3787.738
3787.446
3787.108
3786.727
3786.308
3785.865
3785.443
3785.049
3784.654
3784.245
3783.871
3783.438
3782.989
3782.506
3781.984
3781.437
3780.882
3780.306
3779.720
3779.121
3778.534
3777.937
3777.330
3776.734
3776.124
3775.525
3774.948
3774.404
3773.875
3773.364
3772.865
3772.379
3771.908
3771.485
3771.065
3770.659
3770.255
3769.859
3769.465
3769.088
3768.724
3768.362
3768.009
3767.673
3767.357
3767.052
3766.776
3766.514
3766.263
3766.039
3765.822
3765.607
3765.409
3765.223
3765.047
3764.880
3764.739
3764.611
3764.496
3764.399
3764.310
3764.230
3764.171
3764.119
3764.070
3764.046
3764.025
3764.008
3764.000
3763.994
3764.001
3764.014
3764.030
3764.050
3764.074
3764.102
3764.146
3764.198
3764.257
3764.321
3764.391
3764.457
3764.520
3764.586
3764.656
3764.738
3764.826
3764.922
3765.014
3765.118
3765.226
3765.336
3765.452
3765.565
3765.684
3765.800
3765.919
3766.038
3766.159
3766.278
3766.399
3766.523
3766.636
3766.738
3766.841
3766.953
3767.068
3767.171
3767.272
3767.376
3767.467
3767.560
3767.654
3767.746
3767.843
3767.938
3768.025
3768.113
3768.203
3768.290
3768.376
3768.463
3768.553
3768.645
3768.745
3768.845
3768.943
3769.036
3769.131
3769.226
3769.318
3769.408
3769.499
3769.596
3769.693
3769.788
3769.879
3769.977
3770.080
3770.174
3770.269
3770.363
3770.453
3770.541
3770.627
3770.710
3770.787
3814.735
3814.612
3814.485
3814.369
3814.254
3814.135
3813.999
3813.856
3813.679
3813.468
3813.248
3813.046
3812.865
3812.695
3812.526
3812.348
3812.172
3811.994
3811.810
3811.622
3811.432
3811.251
3811.076
3810.907
3810.747
3810.584
3810.433
3810.286
3810.151
3810.024
3809.904
3809.795
3809.688
3809.586
3809.474
3809.364
3809.260
3809.171
3809.085
3809.009
3808.930
3808.844
3808.752
3808.659
3808.549
3808.438
3808.327
3808.214
3808.096
3807.965
3807.840
3807.724
3807.616
3807.513
3807.412
3807.309
3807.207
3807.100
3806.986
3806.870
3806.761
3806.652
3806.551
3806.452
3806.359
3806.264
3806.164
3806.067
3805.974
3805.890
3805.810
3805.738
3805.662
3805.585
3805.508
3805.422
3805.331
3805.243
3805.158
3805.068
3804.971
3804.875
3804.784
3804.701
3804.632
3804.580
3804.541
3804.501
3804.450
3804.387
3804.315
3804.235
3804.144
3804.051
3803.958
3803.863
3803.763
3803.653
3803.533
3803.405
3803.267
3803.116
3802.952
3802.776
3802.590
3802.404
3802.221
3802.036
3801.842
3801.641
3801.435
3801.234
3801.041
3800.844
3800.646
3800.452
3800.265
3800.072
3799.879
3799.694
3799.515
3799.336
3799.158
3798.981
3798.807
3798.636
3798.464
3798.292
3798.122
3797.959
3797.806
3797.658
3797.512
3797.368
3797.225
3797.082
3796.945
3796.815
3796.686
3796.564
3796.446
3796.335
3796.227
3796.125
3796.033
3795.946
3795.861
3795.777
3795.691
3795.617
3795.556
3795.511
3795.480
3795.460
3714.908
3715.525
3716.142
3716.759
3717.376
3717.993
3718.610
3719.227
3719.844
3720.461
3721.078
3721.695
3722.312
3722.929
3723.546
3724.163
3724.780
3725.397
3726.014
3726.631
3727.248
3727.865
3728.482
3729.099
3729.715
3730.332
3730.949
3731.566
3732.183
3732.800
3733.417
3734.034
3734.651
3735.268
3735.885
3736.502
3737.119
3737.736
3738.353
3738.970
3739.587
3740.204
3740.821
3741.438
3742.055
3742.672
3743.289
3743.906
3744.523
3745.140
3745.757
3746.374
3746.991
3747.608
3748.225
3748.842
3749.459
3750.076
3750.693
3751.310
3751.927
3752.543
3753.160
3753.777
3754.394
3755.011
3755.628
3756.245
3756.862
3757.479
3758.096
3758.713
3759.330
3759.947
3760.564
3761.181
3761.798
3762.415
3763.032
3763.649
3764.266
3764.883
3765.500
3766.117
3766.734
3767.351
3767.968
3768.585
3769.202
3769.819
3770.436
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3691.772
3692.080
3692.389
3692.697
3693.006
3693.314
3693.623
3693.931
3694.240
3694.548
3694.857
3695.165
3695.474
3695.782
3696.090
3696.399
3696.707
3697.016
3697.324
3697.633
3697.941
3698.250
3698.558
3698.867
3699.175
3699.484
3699.792
3700.101
3700.409
3700.718
3701.026
3701.335
3701.643
3701.952
3702.260
3702.569
3702.877
3703.186
3703.494
3703.803
3704.111
3704.420
3704.728
3705.037
3705.345
3705.654
3705.962
3706.271
3706.579
3706.888
3707.196
3707.504
3707.813
3708.121
3708.430
3708.738
3709.047
3709.355
3709.664
3709.972
3710.281
3710.589
3710.898
3711.206
3711.515
3711.823
3712.132
3712.440
3712.749
3713.057
3713.366
3713.674
3713.983
3714.291
3714.600
3714.908
3715.217
3715.525
3715.834
3716.142
3716.451
3716.759
3717.068
3717.376
3717.685
3717.993
3718.302
3718.610
3718.918
3719.227
3719.535
3719.844
3720.149
3720.450
3720.748
3721.042
3721.333
3721.620
3721.904
3722.185
3722.463
3722.737
3723.009
3723.277
3723.542
3723.805
3724.064
3724.321
3724.575
3724.826
3725.075
3725.321
3725.564
3725.805
3726.043
3726.279
3726.512
3726.743
3726.971
3727.197
3727.421
3727.642
3727.861
3728.079
3728.293
3728.506
3728.717
3728.925
3729.132
3729.336
3729.539
3729.739
3729.938
3730.135
3730.330
3730.523
3730.714
3730.903
3731.091
3731.277
3731.461
3731.643
3731.824
3732.003
3732.181
3732.356
3732.531
3732.704
3732.875
3733.044
3733.213
3733.379
3733.545
3733.708
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.970
59.974
59.970
59.969
59.969
59.970
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.980
59.982
59.981
59.980
59.979
59.980
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.020
60.025
60.024
60.020
60.020
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.010
60.007
60.007
60.009
60.009
60.010
60.003
59.999
59.995
59.992
59.991
3767.02
3767.41
3766.79
3766.26
3765.67
3766.12
3764.24
3765.10
3762.94
3758.39
3753.92
3749.87
3746.89
3747.88
3749.59
3748.66
3746.71
3749.08
3742.74
3740.26
3736.14
3731.38
3727.84
3725.95
3722.65
3720.58
3718.00
3718.14
3715.75
3713.69
3713.48
3710.85
3710.81
3712.09
3714.62
3715.13
3716.17
3716.46
3716.98
3717.76
3722.36
3721.97
3722.66
3722.27
3722.28
3721.79
3723.09
3723.98
3723.43
3723.89
3725.40
3727.12
3728.05
3731.13
3732.53
3733.33
3736.54
3736.91
3736.82
3738.70
3739.94
3740.88
3741.79
3745.23
3746.61
3748.30
3750.72
3751.56
3752.75
3755.60
3756.41
3756.98
3760.41
3760.98
3761.41
3762.74
3763.21
3764.96
3766.09
3766.43
3767.25
3767.79
3768.63
3771.15
3772.44
3773.69
3774.67
3775.84
3775.36
3774.87
3775.49
3776.42
3778.55
3779.69
3781.26
3780.59
3783.09
3783.90
3784.42
3785.77
3785.46
3786.85
3786.30
3787.26
3787.52
3787.96
3788.03
3788.61
3789.22
3787.54
3785.84
3786.08
3787.93
3788.76
3786.87
3786.55
3787.36
3785.02
3785.61
3785.95
3785.80
3786.86
3786.88
3785.25
3785.73
3786.35
3785.82
3785.80
3786.28
3786.94
3787.63
3789.44
3789.67
3789.40
3788.48
3789.18
3789.37
3789.00
3788.66
3788.93
3790.67
3790.81
3790.41
3789.77
3791.54
3792.95
3791.03
3791.44
3791.43
3790.60
3790.46
3790.22
3789.58
3788.46
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
229.09
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
218.62
218.62
213.54
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
212.57
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
221.46
221.46
221.46
221.46
221.46
241.27
241.27
241.27
241.27
241.27
243.07
243.07
243.07
243.07
243.07
241.67
241.67
241.67
241.67
241.67
228.15
228.15
228.15
228.15
228.15
235.13
235.13
235.13
235.13
235.13
246.43
246.43
246.43
246.43
246.43
236.55
236.55
236.55
236.55
236.55
230.30
230.30
230.30
230.30
230.30
231.18
231.18
231.18
231.18
231.18
225.62
225.62
225.62
225.62
225.62
230.73
230.73
230.73
230.73
230.73
234.85
234.85
234.85
234.85
234.85
228.96
228.96
228.96
228.96
228.96
231.18
231.18
231.18
231.18
231.18
236.49
236.49
236.49
236.49
236.49
245.04
245.04
245.04
245.04
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7663.00
7663.00
7664.00
7664.00
7665.00
7666.00
7666.00
7667.00
7668.00
7668.00
7669.00
7669.00
7670.00
7670.00
7671.00
7671.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7676.00
7677.00
7678.00
7679.00
7680.00
7681.00
7682.00
7684.00
7685.00
7687.00
7689.00
7690.00
7692.00
7692.00
7693.00
7693.00
7694.00
7694.00
7695.00
7695.00
7695.00
7696.00
7696.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.30
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.60
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.90
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.20
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.50
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.80
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.10
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.40
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.70
7728.03
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
121.911
122.298
121.678
121.149
120.562
121.012
119.133
119.995
117.825
113.277
108.812
104.757
101.779
102.765
104.483
103.551
101.596
103.967
97.631
95.149
91.029
86.272
82.728
80.842
77.539
75.468
72.886
73.032
70.643
68.584
68.374
65.738
65.700
66.982
69.512
70.020
71.058
71.351
71.870
72.649
77.251
76.863
77.548
77.157
77.168
76.677
77.981
78.874
78.324
78.783
80.293
82.011
82.943
86.020
87.420
88.217
91.425
91.797
91.712
93.589
94.834
95.767
96.684
100.124
101.498
103.190
105.606
106.448
107.637
110.489
111.297
111.865
115.295
115.872
116.297
117.627
118.102
119.847
120.975
121.323
122.141
122.682
123.523
126.036
127.335
128.585
129.558
130.731
130.253
129.756
130.382
131.310
132.827
133.965
135.529
134.868
137.365
138.168
138.694
140.041
139.736
141.123
140.577
141.532
141.789
142.228
142.303
142.880
143.489
141.810
140.115
140.350
142.203
143.033
141.148
140.823
141.631
139.291
139.887
140.222
140.077
141.137
141.150
139.527
139.999
140.620
140.094
140.071
140.557
141.212
141.900
143.717
143.946
143.677
142.752
143.456
143.642
143.278
142.938
143.206
144.940
145.078
144.684
144.042
145.813
147.218
145.300
145.716
145.699
144.876
144.730
144.489
143.858
142.730
-105.89
-107.16
-109.50
-107.09
-108.49
-110.89
-113.32
-114.15
-121.31
-121.64
-114.39
-104.63
-100.65
-102.64
-107.58
-110.02
-106.80
-111.64
-107.14
-105.57
-102.14
-94.67
-91.79
-89.70
-86.03
-86.62
-80.87
-82.87
-78.38
-76.95
-76.72
-72.94
-74.55
-76.01
-83.62
-82.26
-82.51
-80.96
-83.45
-83.39
-91.83
-94.74
-96.79
-96.30
-104.10
-100.72
-102.44
-106.40
-108.60
-115.64
-111.33
-112.15
-113.43
-119.27
-122.91
-127.62
-132.26
-138.83
-143.02
-145.95
-143.42
-149.35
-146.22
-156.14
-155.85
-166.10
-175.64
-174.14
-173.26
-175.03
-179.15
-177.21
-195.01
-195.98
-200.08
-217.32
-222.30
-217.41
-219.45
-237.31
-248.63
-244.75
-241.61
-237.24
-226.88
-217.48
-219.13
-241.53
-265.15
-281.30
-295.49
-304.49
0.0730
0.0720
0.0690
0.0710
0.0690
0.0670
0.0630
0.0630
0.0550
0.0510
0.0530
0.0580
0.0590
0.0580
0.0550
0.0520
0.0530
0.0510
0.0490
0.0480
0.0470
0.0490
0.0480
0.0480
0.0480
0.0450
0.0480
0.0460
0.0480
0.0470
0.0470
0.0480
0.0460
0.0460
0.0410
0.0430
0.0440
0.0460
0.0440
0.0450
0.0420
0.0390
0.0380
0.0380
0.0320
0.0340
0.0340
0.0320
0.0300
0.0260
0.0300
0.0310
0.0310
0.0300
0.0290
0.0270
0.0270
0.0240
0.0220
0.0220
0.0240
0.0220
0.0240
0.0220
0.0230
0.0200
0.0180
0.0190
0.0200
0.0210
0.0200
0.0210
0.0170
0.0170
0.0160
0.0120
0.0110
0.0130
0.0130
0.0090
0.0070
0.0080
0.0090
0.0110
0.0140
0.0170
0.0170
0.0120
0.0070
0.0040
0.0020
0.0010
0.0010
0.0010
0.0010
0.0010
0.0020
0.0050
0.0070
0.0080
0.0110
0.0140
0.0170
0.0190
0.0210
0.0170
0.0170
0.0190
0.0230
0.0240
0.0250
0.0210
0.0190
0.0240
0.0240
0.0210
0.0200
0.0250
0.0240
0.0200
0.0200
0.0220
0.0220
0.0220
0.0210
0.0210
0.0230
0.0230
0.0220
0.0190
0.0160
0.0180
0.0180
0.0180
0.0190
0.0190
0.0160
0.0150
0.0160
0.0140
0.0130
0.0120
0.0120
0.0100
0.0070
0.0070
0.0090
0.0090
0.0100
0.0030
0.0010
0.0050
0.0080
0.0090
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003349
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
3788.105
3788.057
3788.189
3788.497
3788.540
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.410
3790.467
3790.665
3790.420
3789.674
3789.267
3789.148
3790.430
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.080
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.690
3784.831
3785.010
3784.320
3782.809
3782.110
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.170
3771.730
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.250
3758.041
3760.965
3762.022
3763.822
3763.100
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.570
3761.920
3759.627
3758.522
3752.429
3750.102
3753.830
3753.510
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.370
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.650
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
5.916
6.729
8.700
10.702
12.364
13.804
14.380
15.114
16.314
17.454
17.835
19.163
20.747
22.137
23.040
22.547
21.145
21.675
22.740
24.154
24.352
24.120
23.969
24.593
25.719
27.892
28.944
29.268
28.758
26.623
24.155
23.632
24.374
25.937
25.510
25.595
26.370
28.316
30.662
32.548
33.413
32.893
32.195
32.464
33.719
34.895
33.496
31.867
32.610
33.093
32.686
32.782
32.483
33.011
33.354
33.937
34.677
32.994
33.343
34.290
35.987
36.369
34.455
34.292
33.465
33.289
34.976
35.352
33.793
31.699
32.141
33.509
33.317
32.831
33.237
34.582
34.735
30.148
23.201
21.208
23.159
26.950
30.135
33.286
35.334
37.027
38.128
39.203
38.820
40.014
41.871
44.880
46.116
46.559
45.765
45.608
43.706
41.747
41.195
41.558
40.350
39.566
38.335
36.454
35.232
34.437
33.199
31.313
30.808
32.642
33.114
33.421
31.818
29.333
28.079
29.426
28.861
28.133
26.217
23.891
22.379
21.396
20.397
19.748
18.604
18.582
18.928
19.874
20.128
21.014
21.590
21.244
20.658
20.638
21.345
22.526
24.736
26.533
28.421
27.847
27.114
26.275
27.173
28.837
29.198
28.352
28.523
28.634
28.706
26.950
24.007
23.535
23.949
25.301
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3792.187
3793.000
3794.972
3796.973
3798.635
3800.075
3800.651
3801.386
3802.585
3803.725
3804.106
3805.434
3807.018
3808.408
3809.312
3808.818
3807.416
3807.946
3809.011
3810.426
3810.623
3810.391
3810.240
3810.864
3811.990
3814.163
3815.216
3815.539
3815.029
3812.895
3810.426
3809.903
3810.645
3812.208
3811.782
3811.866
3812.641
3814.587
3816.933
3818.819
3819.685
3819.165
3818.467
3818.735
3819.990
3821.166
3819.767
3818.138
3818.881
3819.365
3818.957
3819.053
3818.754
3819.282
3819.625
3820.208
3820.948
3819.265
3819.614
3820.562
3822.258
3822.641
3820.726
3820.564
3819.736
3819.560
3821.247
3821.623
3820.064
3817.970
3818.412
3819.780
3819.589
3819.102
3819.508
3820.853
3821.007
3816.420
3809.472
3807.480
3809.430
3813.221
3816.406
3819.557
3821.606
3823.299
3824.399
3825.475
3825.091
3826.285
3828.142
3831.151
3832.387
3832.830
3832.036
3831.880
3829.977
3828.018
3827.467
3827.829
3826.622
3825.837
3824.606
3822.726
3821.503
3820.709
3819.470
3817.584
3817.079
3818.914
3819.386
3819.692
3818.089
3815.604
3814.351
3815.698
3815.132
3814.404
3812.488
3810.162
3808.650
3807.667
3806.668
3806.019
3804.875
3804.853
3805.199
3806.145
3806.399
3807.285
3807.861
3807.515
3806.929
3806.909
3807.617
3808.797
3811.007
3812.804
3814.692
3814.118
3813.385
3812.546
3813.444
3815.108
3815.470
3814.624
3814.794
3814.905
3814.977
3813.221
3810.278
3809.807
3810.221
3811.572
3770.862
3770.936
3771.010
3771.085
3771.159
3771.233
3771.304
3771.371
3771.434
3771.502
3771.574
3771.647
3771.715
3771.784
3771.860
3771.936
3772.011
3772.082
3772.151
3772.219
3772.292
3772.362
3772.417
3772.476
3772.541
3772.611
3772.686
3772.764
3772.840
3772.903
3772.961
3773.018
3773.071
3773.125
3773.177
3773.230
3773.280
3773.332
3773.391
3773.454
3773.520
3773.588
3773.652
3773.707
3773.763
3773.819
3773.868
3773.910
3773.950
3773.989
3774.026
3774.057
3774.085
3774.104
3774.121
3774.137
3774.155
3774.173
3774.181
3774.186
3774.194
3774.202
3774.208
3774.205
3774.196
3774.178
3774.159
3774.141
3774.119
3774.088
3774.042
3773.994
3773.954
3773.914
3773.870
3773.825
3773.780
3773.733
3773.682
3773.616
3773.550
3773.480
3773.417
3773.368
3773.323
3773.275
3773.236
3773.201
3773.171
3773.140
3773.111
3773.083
3773.062
3773.047
3773.032
3773.014
3772.992
3772.960
3772.926
3772.892
3772.852
3772.809
3772.748
3772.680
3772.624
3772.567
3772.510
3772.452
3772.395
3772.337
3772.281
3772.225
3772.167
3772.101
3772.029
3771.938
3771.849
3771.777
3771.702
3771.621
3771.536
3771.447
3771.354
3771.262
3771.167
3771.071
3770.974
3770.877
3770.778
3770.681
3770.589
3770.499
3770.406
3770.313
3770.220
3770.126
3770.035
3769.949
3769.865
3769.782
3769.698
3769.612
3769.525
3769.441
3769.362
3769.285
3769.213
3769.142
3769.072
3769.001
3768.930
3768.854
3768.780
3768.705
3795.446
3795.436
3795.434
3795.440
3795.454
3795.474
3795.495
3795.520
3795.550
3795.584
3795.619
3795.660
3795.706
3795.758
3795.814
3795.867
3795.913
3795.962
3796.014
3796.072
3796.130
3796.187
3796.242
3796.300
3796.361
3796.431
3796.504
3796.578
3796.649
3796.711
3796.764
3796.814
3796.867
3796.925
3796.981
3797.037
3797.095
3797.160
3797.234
3797.314
3797.396
3797.476
3797.553
3797.631
3797.712
3797.797
3797.876
3797.949
3798.024
3798.100
3798.175
3798.249
3798.321
3798.395
3798.469
3798.545
3798.623
3798.695
3798.768
3798.843
3798.923
3799.004
3799.079
3799.152
3799.221
3799.290
3799.364
3799.439
3799.508
3799.569
3799.632
3799.699
3799.764
3799.828
3799.892
3799.961
3800.029
3800.083
3800.113
3800.137
3800.167
3800.208
3800.260
3800.322
3800.389
3800.462
3800.537
3800.616
3800.692
3800.772
3800.858
3800.952
3801.049
3801.147
3801.242
3801.336
3801.424
3801.505
3801.584
3801.663
3801.739
3801.811
3801.880
3801.942
3802.001
3802.056
3802.108
3802.154
3802.198
3802.247
3802.297
3802.348
3802.394
3802.432
3802.467
3802.505
3802.541
3802.576
3802.604
3802.626
3802.643
3802.657
3802.668
3802.678
3802.684
3802.690
3802.697
3802.707
3802.717
3802.730
3802.744
3802.757
3802.769
3802.780
3802.793
3802.810
3802.832
3802.859
3802.891
3802.921
3802.950
3802.975
3803.004
3803.036
3803.069
3803.100
3803.131
3803.162
3803.193
3803.220
3803.238
3803.255
3803.273
3803.295
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3733.871
3734.032
3734.191
3734.349
3734.506
3734.662
3734.816
3734.969
3735.120
3735.271
3735.420
3735.568
3735.714
3735.860
3736.004
3736.147
3736.289
3736.430
3736.569
3736.708
3736.845
3736.982
3737.117
3737.251
3737.384
3737.516
3737.647
3737.777
3737.906
3738.034
3738.161
3738.287
3738.412
3738.536
3738.659
3738.781
3738.903
3739.023
3739.143
3739.261
3739.379
3739.496
3739.612
3739.727
3739.841
3739.955
3740.068
3740.180
3740.291
3740.401
3740.510
3740.619
3740.727
3740.834
3740.940
3741.046
3741.151
3741.255
3741.359
3741.461
3741.563
3741.665
3741.765
3741.865
3741.965
3742.063
3742.161
3742.259
3742.355
3742.451
3742.546
3742.641
3742.735
3742.829
3742.922
3743.014
3743.105
3743.196
3743.287
3743.377
3743.466
3743.555
3743.643
3743.730
3743.817
3743.904
3743.990
3744.075
3744.160
3744.244
3744.328
3744.411
3744.494
3744.576
3744.658
3744.739
3744.820
3744.900
3744.980
3745.059
3745.138
3745.216
3745.294
3745.371
3745.448
3745.525
3745.601
3745.676
3745.751
3745.826
3745.900
3745.974
3746.047
3746.120
3746.193
3746.265
3746.336
3746.408
3746.478
3746.549
3746.619
3746.688
3746.758
3746.826
3746.895
3746.963
3747.031
3747.098
3747.165
3747.231
3747.297
3747.363
3747.429
3747.494
3747.559
3747.623
3747.687
3747.751
3747.814
3747.877
3747.940
3748.002
3748.064
3748.125
3748.187
3748.248
3748.308
3748.369
3748.429
3748.488
3748.548
3748.607
3748.666
3748.724
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.970
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.970
59.968
59.965
59.964
59.970
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.970
59.967
59.969
59.968
59.963
59.965
59.970
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.990
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.960
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.970
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.980
59.978
59.978
59.980
59.981
59.980
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
3788.10
3788.06
3788.19
3788.50
3788.54
3788.57
3788.10
3787.13
3786.45
3787.73
3788.81
3789.29
3788.26
3788.41
3790.47
3790.66
3790.42
3789.67
3789.27
3789.15
3790.43
3789.91
3786.24
3787.44
3788.96
3790.60
3791.88
3792.91
3792.31
3789.13
3788.08
3787.84
3787.14
3787.16
3787.00
3787.40
3786.49
3787.08
3789.21
3790.51
3791.22
3792.22
3790.96
3788.82
3789.03
3789.17
3787.39
3785.69
3784.83
3785.01
3784.32
3782.81
3782.11
3779.35
3779.06
3778.63
3779.21
3779.33
3776.43
3775.65
3776.60
3776.56
3776.02
3773.17
3771.73
3768.79
3768.50
3768.92
3767.37
3764.79
3760.30
3759.59
3761.89
3761.78
3760.58
3760.16
3759.78
3759.49
3757.77
3753.28
3753.09
3751.64
3753.75
3758.22
3759.25
3758.04
3760.96
3762.02
3763.82
3763.10
3763.86
3764.16
3766.13
3768.34
3767.97
3767.44
3765.61
3762.69
3761.57
3761.92
3759.63
3758.52
3752.43
3750.10
3753.83
3753.51
3753.52
3752.74
3753.18
3752.73
3753.29
3752.87
3752.36
3749.40
3747.48
3740.37
3741.29
3746.65
3745.74
3743.35
3741.62
3740.31
3738.48
3738.90
3737.40
3737.27
3736.31
3736.27
3735.45
3735.65
3737.54
3738.01
3736.75
3736.69
3736.07
3736.09
3736.57
3738.57
3738.87
3738.93
3738.65
3737.68
3737.38
3737.89
3740.02
3740.33
3742.05
3742.42
3742.52
3742.25
3741.72
3740.09
3740.63
3739.96
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
245.04
223.61
223.61
223.61
223.61
223.61
231.12
231.12
231.12
231.12
231.12
237.21
237.21
237.21
237.21
237.21
240.52
240.52
240.52
240.52
240.52
237.57
237.57
237.57
237.57
237.57
231.58
231.58
231.58
231.58
231.58
235.85
235.85
235.85
235.85
235.85
233.56
233.56
233.56
233.56
233.56
219.01
219.01
219.01
219.01
219.01
205.34
205.34
205.34
205.34
205.34
236.29
236.29
236.29
236.29
236.29
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731.00
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.30
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.60
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.90
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.20
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.50
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.80
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.10
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.40
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.70
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764.00
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.30
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.60
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.90
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.20
7777.53
7777.86
7778.19
7778.52
7778.85
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
142.378
142.330
142.462
142.770
142.813
142.844
142.374
141.406
140.726
142.005
143.086
143.558
142.529
142.683
144.740
144.938
144.693
143.947
143.540
143.421
144.703
144.187
140.516
141.715
143.236
144.875
146.150
147.184
146.584
143.398
142.353
142.117
141.408
141.437
141.269
141.678
140.760
141.352
143.487
144.785
145.494
146.491
145.232
143.097
143.299
143.440
141.667
139.963
139.104
139.282
138.593
137.082
136.383
133.625
133.329
132.906
133.485
133.608
130.702
129.920
130.870
130.832
130.296
127.443
126.003
123.066
122.776
123.190
121.639
119.059
114.568
113.865
116.167
116.050
114.855
114.430
114.054
113.768
112.046
107.550
107.360
105.910
108.024
112.498
113.523
112.314
115.238
116.295
118.095
117.373
118.131
118.431
120.400
122.612
122.245
121.710
119.879
116.961
115.843
116.193
113.900
112.795
106.702
104.375
108.103
107.783
107.796
107.014
107.451
107.002
107.563
107.145
106.632
103.671
101.749
94.643
95.558
100.924
100.011
97.624
95.891
94.579
92.757
93.174
91.677
91.546
90.581
90.545
89.721
89.923
91.813
92.285
91.021
90.966
90.340
90.367
90.848
92.844
93.148
93.208
92.920
91.957
91.655
92.165
94.290
94.602
96.326
96.697
96.797
96.518
95.996
94.358
94.902
94.237
0.0080
0.0080
0.0120
0.0140
0.0150
0.0160
0.0150
0.0160
0.0180
0.0190
0.0180
0.0210
0.0230
0.0240
0.0240
0.0210
0.0180
0.0220
0.0240
0.0260
0.0240
0.0230
0.0230
0.0250
0.0270
0.0310
0.0300
0.0290
0.0270
0.0220
0.0190
0.0220
0.0250
0.0280
0.0240
0.0250
0.0270
0.0310
0.0340
0.0350
0.0340
0.0310
0.0300
0.0320
0.0350
0.0360
0.0300
0.0280
0.0330
0.0330
0.0310
0.0320
0.0310
0.0330
0.0330
0.0340
0.0350
0.0290
0.0330
0.0350
0.0380
0.0360
0.0300
0.0330
0.0310
0.0320
0.0370
0.0350
0.0300
0.0270
0.0320
0.0350
0.0320
0.0310
0.0330
0.0360
0.0340
0.0210
0.0100
0.0170
0.0260
0.0330
0.0350
0.0380
0.0380
0.0390
0.0390
0.0400
0.0370
0.0410
0.0440
0.0490
0.0470
0.0460
0.0430
0.0440
0.0390
0.0370
0.0390
0.0410
0.0370
0.0370
0.0350
0.0320
0.0320
0.0320
0.0300
0.0270
0.0290
0.0350
0.0330
0.0330
0.0280
0.0240
0.0250
0.0310
0.0270
0.0260
0.0220
0.0190
0.0190
0.0190
0.0180
0.0180
0.0160
0.0180
0.0190
0.0210
0.0200
0.0220
0.0220
0.0200
0.0190
0.0200
0.0220
0.0240
0.0280
0.0290
0.0310
0.0260
0.0250
0.0240
0.0280
0.0310
0.0290
0.0260
0.0280
0.0280
0.0280
0.0230
0.0180
0.0220
0.0240
0.0270
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003350
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.860
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.340
3750.700
3749.750
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.830
3737.583
3736.229
3734.897
3733.434
3733.115
3730.510
3729.180
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.560
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.100
3690.477
3696.865
3696.877
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
25.819
25.073
24.589
23.913
23.114
21.874
22.509
24.004
26.057
27.391
28.259
28.462
30.037
31.781
32.915
31.849
30.435
29.877
30.595
29.981
28.861
28.493
29.335
29.522
28.563
25.055
21.693
19.508
18.087
16.443
14.654
13.491
13.816
13.667
12.488
10.280
8.125
4.921
2.118
-0.066
-2.206
-5.760
-8.791
-12.564
-15.737
-19.242
-21.881
-23.956
-26.026
-27.371
-31.129
-33.212
-34.926
-36.040
-36.404
-38.443
-40.489
-42.179
-42.918
-44.480
-46.216
-46.624
-46.889
-45.979
-45.388
-45.364
-44.988
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3812.090
3811.345
3810.860
3810.185
3809.385
3808.145
3808.780
3810.276
3812.328
3813.663
3814.530
3814.733
3816.308
3818.052
3819.186
3818.120
3816.707
3816.148
3816.866
3816.252
3815.132
3814.764
3815.606
3815.793
3814.834
3811.327
3807.964
3805.779
3804.359
3802.715
3800.926
3799.763
3800.088
3799.939
3798.759
3796.552
3794.396
3791.192
3788.389
3786.205
3784.065
3780.511
3777.480
3773.707
3770.534
3767.029
3764.390
3762.315
3760.245
3758.900
3755.142
3753.060
3751.346
3750.231
3749.868
3747.828
3745.782
3744.092
3743.353
3741.791
3740.055
3739.647
3739.382
3740.292
3740.884
3740.908
3741.284
3768.633
3768.566
3768.495
3768.421
3768.346
3768.270
3768.194
3768.122
3768.046
3767.971
3767.909
3767.847
3767.790
3767.735
3767.684
3767.641
3767.597
3767.543
3767.487
3767.428
3767.368
3767.301
3767.233
3767.150
3767.064
3766.992
3766.917
3766.839
3766.758
3766.677
3766.590
3766.500
3766.401
3766.302
3766.192
3766.084
3765.988
3765.892
3765.802
3765.713
3765.623
3765.533
3765.438
3765.347
3765.255
3765.148
3765.035
3764.924
3764.815
3764.705
3764.591
3764.474
3764.350
3764.227
3764.079
3763.930
3763.796
3763.659
3763.521
3763.380
3763.240
3763.097
3762.955
3762.793
3762.632
3762.485
3762.340
3803.318
3803.339
3803.358
3803.376
3803.391
3803.403
3803.417
3803.435
3803.457
3803.483
3803.511
3803.539
3803.572
3803.608
3803.647
3803.683
3803.716
3803.747
3803.779
3803.810
3803.838
3803.865
3803.894
3803.923
3803.950
3803.968
3803.977
3803.982
3803.983
3803.980
3803.972
3803.962
3803.953
3803.943
3803.931
3803.913
3803.891
3803.861
3803.824
3803.782
3803.736
3803.681
3803.620
3803.550
3803.473
3803.389
3803.298
3803.203
3803.104
3803.002
3802.892
3802.778
3802.660
3802.540
3802.420
3802.296
3802.168
3802.037
3801.904
3801.769
3801.630
3801.491
3801.352
3801.216
3801.082
3800.948
3800.816
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3748.782
3748.840
3748.898
3748.955
3749.012
3749.068
3749.125
3749.181
3749.237
3749.292
3749.347
3749.402
3749.457
3749.511
3749.566
3749.619
3749.673
3749.726
3749.779
3749.832
3749.885
3749.937
3749.989
3750.041
3750.092
3750.143
3750.194
3750.245
3750.296
3750.346
3750.396
3750.446
3750.495
3750.545
3750.594
3750.642
3750.691
3750.739
3750.788
3750.835
3750.883
3750.931
3750.978
3751.025
3751.072
3751.118
3751.165
3751.211
3751.257
3751.302
3751.348
3751.393
3751.438
3751.483
3751.528
3751.572
3751.617
3751.661
3751.705
3751.748
3751.792
3751.835
3751.878
3751.921
3751.964
3752.006
3752.049
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.970
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.990
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3740.78
3742.83
3741.27
3739.78
3738.97
3738.71
3738.88
3739.86
3738.10
3738.56
3743.51
3743.42
3745.25
3745.74
3747.34
3750.70
3749.75
3746.22
3744.68
3743.75
3743.15
3740.30
3739.45
3733.38
3731.83
3737.58
3736.23
3734.90
3733.43
3733.12
3730.51
3729.18
3725.46
3724.78
3720.11
3720.94
3725.66
3725.68
3727.75
3727.82
3727.68
3727.23
3725.01
3726.45
3726.02
3719.12
3716.37
3717.33
3717.56
3717.14
3715.17
3713.63
3710.28
3710.16
3699.36
3698.59
3704.59
3703.28
3702.48
3701.32
3700.83
3699.53
3699.73
3690.10
3690.48
3696.86
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7779.18
7779.51
7779.84
7780.17
7780.50
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.80
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.10
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.40
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.70
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797.00
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.30
7800.63
7800.96
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
95.048
97.105
95.541
94.049
93.239
92.979
93.152
94.133
92.375
92.831
97.780
97.692
99.524
100.017
101.613
104.973
104.023
100.490
98.956
98.018
97.422
94.572
93.726
87.649
86.103
91.855
90.502
89.170
87.707
87.388
84.783
83.453
79.732
79.058
74.381
75.211
79.934
79.950
82.027
82.098
81.956
81.504
79.285
80.719
80.289
73.396
70.647
71.605
71.833
71.415
69.439
67.905
64.556
64.431
53.629
52.864
58.864
57.548
56.755
55.589
55.099
53.802
53.999
44.373
44.750
51.137
51.150
0.0260
0.0230
0.0230
0.0220
0.0210
0.0190
0.0230
0.0260
0.0290
0.0290
0.0290
0.0280
0.0320
0.0340
0.0340
0.0290
0.0270
0.0280
0.0310
0.0280
0.0260
0.0270
0.0300
0.0290
0.0260
0.0180
0.0150
0.0150
0.0150
0.0130
0.0110
0.0110
0.0140
0.0130
0.0100
0.0060
0.0040
0.0010
0.0030
0.0040
0.0060
0.0120
0.0140
0.0190
0.0210
0.0250
0.0260
0.0270
0.0290
0.0290
0.0370
0.0360
0.0370
0.0370
0.0360
0.0410
0.0430
0.0440
0.0430
0.0460
0.0480
0.0460
0.0460
0.0430
0.0430
0.0440
0.0430
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003351
Monday, October 12, 2009
Balancing Authority
MyBA
60.08
60.06
1.000
0.744
Initial P.U. Performance
Initial P.U. Performance Adjusted
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
3900.0
20 to 52 second Average Period
60.042
3843.77
60.04
3850.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
60.02
3803.32
60
3800.0
59.98
3788.35
59.96
Frequency - Hz
59.92
59.9
3700.0
59.88
59.889
59.86
59.84
3650.0
NAI MW
3750.0
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
3645.73
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
2:26:36
2:26:46
Hz
2:26:56
2:27:06
Average Frequency
2:27:16
MW
2:27:26
2:27:36
Average MW
2:27:46
2:27:56
EPFR Adjusted
2:28:06
2:28:16
EPFR Unadjusted
3500.0
2:28:26
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003352
Monday, October 12, 2009
0.758
05:34
MyBA
60.08
Sustained P.U. Performance
Event Length mm:ss
3900.0
60.06
60.04
3850.0
60.02
60
3800.0
59.98
59.96
3750.0
59.92
3700.0
59.9
59.88
59.86
3650.0
59.84
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
3500.0
59.72
2:26:26
2:27:26
2:28:26
2:29:26
Hz
2:30:26
2:31:26
2:32:26
Interchange MW
2:33:26
2:34:26
2:35:26
2:36:26
Recovery Period Target MW
2:37:26
2:38:26
2:39:26
2:40:26
Recovery Period Ramp MW
2:41:26
2:42:26
NAI MW
Frequency - Hz
59.94
003353
Monday, October 12, 2009
-103.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
100.0
60.08
60.06
50.0
60.04
60.02
0.0
60
59.98
-50.0
59.96
-100.0
59.92
59.9
-150.0
59.88
59.86
-200.0
59.84
59.82
-250.0
59.8
59.78
-300.0
59.76
59.74
-350.0
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
Hz
2:32:26
2:33:26
BA Bias Setting
2:34:26
2:35:26
2:36:26
2:37:26
2:38:26
Actual Primary Freq Response Beta
2:39:26
2:40:26
2:41:26
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
003354
Value A Data
Date
Monday, October 12, 2009
A Value
Time
2:27:26
FPointA
Hz
60.039
A Value
Hz
60.042
t(0) Time
2:27:26
C Value
Hz
59.836
Frequency
Hz
60.042
Net
Actual
Interchange
MW
3645.73
BA Performance
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
NonConforming
Load
Load (-)
MW
165.34
Value B
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
Not
Used
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW
-4.21
Contingent
BA
BA
BA
Lost Generation
Bias
Load
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
MW
15.00
-103.00 7651.305
Bias
Setting
EPFR
MW
-43.39
Frequency
Hz
59.889
20 to 52 second Average Period Evaluation
Net
Actual
Interchange
MW
3803.35
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335.00
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
165.34
6.35
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Not
Used
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW
11.09
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
0.00
Initial
Performance
Adjusted
P.U.
0.744
Initial
Performance
Unadjusted
P.U.
1.000
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.758
-103.00
BA
Load
MW
7632.00
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
114.21
-103.00
Unadjusted
PFR
Performance
@ T(+46)
P.U.
1.399
Unadjusted
PFR
Performance
@ T(+76)
P.U.
1.293
Unadjusted
PFR
Performance
@ T(+106)
P.U.
1.582
Unadjusted
PFR
Performance
@ T(+136)
P.U.
1.571
Unadjusted
PFR
Performance
@ T(+166)
P.U.
1.849
Adjusted
PFR
Performance
@ T(+46)
P.U.
0.856
Adjusted
PFR
Performance
@ T(+76)
P.U.
0.808
Adjusted
PFR
Performance
@ T(+106)
P.U.
0.829
Adjusted
PFR
Performance
@ T(+136)
P.U.
0.633
Adjusted
PFR
Performance
@ T(+166)
P.U.
0.689
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
-103.00
-103.00
003355
Steps
1
2
3
4
5
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Not Used
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only rarely should
you have to use the "Manual" process.
6
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
B
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "NYISO".
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar to the slope of the NAI data.
When set appropriately, the "Target" trend on the "Sustained" graph will model what the Net Actua Interchange should have done during the event recovery period based on your Bias setting during the event.
003356
Monday, October 12, 2009
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MyBA
60.08
60.06
355.0
60.04
350.0
60.02
60
59.98
345.0
59.96
59.92
MW
Frequency - Hz
59.94
340.0
59.9
A Value
59.88
350.00
59.86
B Value
335.00
Average Period
20 to 52 second
335.0
59.84
59.82
59.8
330.0
59.78
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
JOU Dynamic Schedules
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
325.0
2:42:26
003357
Monday, October 12, 2009
MyBA
NonConforming
60.08
300.0
Load
60.06
Load (-)
60.04
250.0
60.02
60
59.98
200.0
59.96
59.92
MW
Frequency - Hz
59.94
150.0
59.9
A Value
59.88
165.34
B Value
214.13
Average Period
20 to 52 second
59.86
100.0
59.84
59.82
59.8
50.0
59.78
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Non- Conforming Load
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
003358
Monday, October 12, 2009
MyBA
Pumped
Hydro
60.08
18.0
Load (-) Gen (+)
60.06
16.0
60.04
60.02
14.0
60
59.98
12.0
59.96
10.0
59.92
59.9
59.88
A Value
B Value
0.00
6.35
59.86
Average Period
8.0
20 to 52 second
6.0
59.84
59.82
4.0
59.8
59.78
2.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW
Frequency - Hz
59.94
003359
Monday, October 12, 2009
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.96
59.92
0.6
59.9
A Value
59.88
B Value
Average Period
20 to 52 second
59.86
0.4
59.84
59.82
59.8
0.2
59.78
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW
Frequency - Hz
59.94
003360
Monday, October 12, 2009
MyBA
Transferred
Frequency
Response
60.08
60.06
12.0
Rec (-) Del (+)
60.04
10.0
60.02
60
59.98
8.0
59.96
59.92
6.0
59.9
A Value
59.88
B Value
11.09
-4.21
Average Period
20 to 52 second
59.86
4.0
59.84
59.82
59.8
2.0
59.78
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Frequency Response
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
003361
Monday, October 12, 2009
Contingent
BA
Lost Generation
MyBA
60.08
Load (-) Gen (+)
16.0
60.06
60.04
14.0
60.02
60
12.0
59.98
59.96
10.0
59.92
MW
Frequency - Hz
59.94
59.9
A Value
59.88
15.00
59.86
B Value
0.00
Average Period
8.0
20 to 52 second
6.0
59.84
59.82
4.0
59.8
59.78
2.0
59.76
59.74
0.0
59.72
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Lost Generation
003362
Monday, October 12, 2009
BA
Load
MyBA
7850.0
60.08
60.06
60.04
7800.0
60.02
60
59.98
7750.0
59.96
7700.0
59.92
MW
Frequency - Hz
59.94
59.9
A Value
59.88
7651.3
59.86
B Value
7632.0
Average Period
20 to 52 second
7650.0
59.84
7600.0
59.82
59.8
59.78
7550.0
59.76
59.74
59.72
7500.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Load
003363
Monday, October 12, 2009
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
200.0
60.06
60.04
150.0
60.02
60
59.98
100.0
59.96
59.92
50.0
59.9
59.88
59.86
0.0
59.84
59.82
59.8
-50.0
59.78
59.76
A Value
59.74
-43.39
B Value
114.21
Average Period
20 to 52 second
-100.0
59.72
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Expected Primary Freq Response Based on Bias Setting
MW
Frequency - Hz
59.94
003364
Time (T)
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
05/16/11 07:41:16
05/16/11 07:41:18
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
59.98578
59.9874
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
29782.73
29782.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
Rows of
data to
shift to
align T(0)
1
003365
Time (T)
05/16/11 07:41:20
05/16/11 07:41:22
05/16/11 07:41:24
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
Hz
59.98868
59.98999
59.99191
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
60.0152
60.0152
60.01486
60.01422
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.73
29782.73
29782.82
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
29787.84
29813.39
29813.39
29813.39
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.002
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
0.001
Rows of
data to
shift to
align T(0)
1
003366
Time (T)
05/16/11 07:42:40
05/16/11 07:42:42
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
Hz
60.01358
60.01227
60.01099
60.00873
60.00647
60.00485
60.00354
60.00195
60
59.99774
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29813.39
29813.39
29813.33
29813.33
29813.33
29813.33
29813.33
29797.46
29797.46
29797.46
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Rows of
data to
shift to
align T(0)
1
003367
Time (T)
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
Hz
59.98514
59.98416
59.98352
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
Rows of
data to
shift to
align T(0)
1
003368
Time (T)
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
05/16/11 07:46:16
05/16/11 07:46:18
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
Hz
60.01227
60.01163
60.01065
60.0097
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
60.01422
60.01227
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
Rows of
data to
shift to
align T(0)
1
003369
Time (T)
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
Hz
59.99646
59.99579
59.99417
59.99225
59.9903
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
60.02164
60.01971
60.01907
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.35
29782.35
29782.44
29782.44
29782.44
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
29794.69
29794.69
29794.69
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.002
-0.002
-0.002
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
-0.002
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.002
0.002
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
0.002
0.001
Rows of
data to
shift to
align T(0)
1
003370
Time (T)
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
Hz
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
0.000
0.001
-0.001
-0.003
-0.001
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.000
0.001
0.001
0.003
0.001
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
Rows of
data to
shift to
align T(0)
1
003371
Time (T)
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
05/16/11 07:49:32
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
Hz
60
60
60.00452
60.00583
60.00613
60.00583
60.00516
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
59.99225
59.99484
59.99646
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
29795.55
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.005
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
0.000
0.003
0.002
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.005
0.001
0.000
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
Rows of
data to
shift to
align T(0)
1
003372
Time (T)
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
05/16/11 07:51:24
05/16/11 07:51:26
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
Hz
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
59.97189
59.97125
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
29756.18
29756.18
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
Rows of
data to
shift to
align T(0)
1
003373
Time (T)
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
Hz
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
59.98868
59.98868
59.9874
59.98611
59.98611
59.98709
59.98837
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
29795.02
29795.02
29795.05
29795.05
29795.05
29795.05
29795.05
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
Rows of
data to
shift to
align T(0)
1
003374
Time (T)
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
Hz
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
60.00064
60.00098
60.00064
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
29823.76
29823.76
29818.41
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
Rows of
data to
shift to
align T(0)
1
003375
Time (T)
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
Hz
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
59.98547
59.98547
59.98514
59.9845
59.9845
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
29826.47
29826.41
29826.41
29826.41
29826.41
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.004
0.002
0.002
0.002
0.003
0.001
Rows of
data to
shift to
align T(0)
1
003376
Time (T)
05/16/11 07:56:00
05/16/11 07:56:02
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
05/16/11 07:56:24
05/16/11 07:56:26
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
Hz
59.97641
59.9761
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
59.97803
59.97867
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
60.01938
60.02036
60.02197
60.02423
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
29856.55
29856.55
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29889.67
29889.67
29889.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
Rows of
data to
shift to
align T(0)
1
003377
Time (T)
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
05/16/11 07:57:42
05/16/11 07:57:44
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
05/16/11 07:58:38
Hz
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
60.02261
60.02164
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
60.02069
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
29891.67
29891.64
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
29887.14
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003378
Time (T)
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
Hz
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
59.99451
59.99127
59.98965
59.98868
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
29862.1
29862.1
29861.95
29861.95
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
-0.005
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
0.005
0.003
0.002
0.001
0.002
0.002
0.002
0.002
0.003
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
Rows of
data to
shift to
align T(0)
1
003379
Time (T)
05/16/11 08:00:00
05/16/11 08:00:02
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
Hz
59.97287
59.97287
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29905.8
29905.8
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
0.002
0.000
-0.001
-0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.000
0.002
0.000
0.001
0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
Rows of
data to
shift to
align T(0)
1
003380
Time (T)
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
05/16/11 08:01:30
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
05/16/11 08:02:36
05/16/11 08:02:38
Hz
59.98709
59.98773
59.98965
59.99161
59.99255
59.99323
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
59.96512
59.96512
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29951.05
29951.05
29955.09
29955.09
29955.09
29955.09
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
30055.73
30055.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.002
0.002
0.001
0.001
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.002
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
Rows of
data to
shift to
align T(0)
1
003381
Time (T)
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
Hz
59.96576
59.96704
59.96994
59.97253
59.97415
59.9761
59.97739
59.97931
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30055.73
30055.73
30068.76
30068.76
30068.76
30068.76
30068.76
30068.21
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
Rows of
data to
shift to
align T(0)
1
003382
Time (T)
05/16/11 08:04:00
05/16/11 08:04:02
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
Hz
59.98029
59.979
59.97867
59.97931
59.97998
59.97931
59.979
59.97803
59.97675
59.97739
59.979
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30118.77
30118.77
30118.74
30118.74
30118.74
30118.74
30118.74
30106.93
30106.93
30106.93
30106.93
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.001
0.000
0.001
0.001
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003383
Time (T)
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
05/16/11 08:05:48
05/16/11 08:05:50
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
05/16/11 08:06:36
05/16/11 08:06:38
Hz
Contingent
Resource
Lost
MW
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471.3000183
471.3000183
471.3000183
471.3000183
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
470.8999939
0
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
0.000
-0.042
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
0.000
0.042
Rows of
data to
shift to
align T(0)
1
003384
Time (T)
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
Hz
59.88144
59.87237
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
Rows of
data to
shift to
align T(0)
1
003385
Time (T)
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
05/16/11 08:08:40
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
Hz
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
-0.001
-0.001
-0.001
0.000
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
0.001
0.001
0.001
0.000
0.002
Rows of
data to
shift to
align T(0)
1
003386
Time (T)
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
05/16/11 08:10:04
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
Hz
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
Rows of
data to
shift to
align T(0)
1
003387
Time (T)
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
Hz
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30300.1
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.004
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
-0.001
-0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.004
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
Rows of
data to
shift to
align T(0)
1
003388
Time (T)
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
05/16/11 08:12:56
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
Hz
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.1
30349.1
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.002
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003389
Time (T)
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
05/16/11 08:14:10
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
Hz
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
Rows of
data to
shift to
align T(0)
1
003390
Time (T)
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
05/16/11 08:15:28
05/16/11 08:15:30
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
Hz
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
-0.001
0.004
0.002
0.000
0.001
-0.002
0.000
0.001
0.000
0.000
-0.001
-0.004
-0.001
0.000
-0.002
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.002
0.000
0.001
0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.001
0.000
0.002
0.002
Rows of
data to
shift to
align T(0)
1
003391
Time (T)
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
05/16/11 08:17:16
05/16/11 08:17:18
Hz
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
-0.001
-0.003
-0.003
0.000
0.002
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.003
0.003
0.000
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.001
Rows of
data to
shift to
align T(0)
1
003392
Time (T)
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
Hz
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
Rows of
data to
shift to
align T(0)
1
003393
Time (T)
05/16/11 08:18:40
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
Hz
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30444.25
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
Rows of
data to
shift to
align T(0)
1
003394
Time (T)
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
05/16/11 08:20:32
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
Hz
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.003
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.003
0.002
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
Rows of
data to
shift to
align T(0)
1
003395
Time (T)
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
Hz
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
60.03717
60.03781
60.03781
60.03748
60.0365
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
30452.43
30473.21
30473.21
30473.21
30473.21
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
Rows of
data to
shift to
align T(0)
1
003396
Time (T)
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
05/16/11 08:23:00
05/16/11 08:23:02
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
Hz
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
60.03101
60.03232
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
60.03458
60.03488
60.0336
60.03326
60.03232
60.03134
60.03168
60.03326
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
30485.47
30505.49
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
30529.28
30529.08
30529.08
30529.08
30529.08
30529.52
30529.52
30529.52
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.000
-0.001
0.000
-0.001
-0.001
0.000
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.002
Rows of
data to
shift to
align T(0)
1
003397
Time (T)
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
Hz
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
60.03134
60.03168
60.03134
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
30521.82
30533.64
30533.64
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
Rows of
data to
shift to
align T(0)
1
003398
Time (T)
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
Hz
60.0365
60.03488
60.0336
60.03232
60.03134
60.03101
60.03101
60.0307
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30556.84
30557.42
30557.42
30557.43
30557.43
30557.43
30557.43
30566.39
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.001
-0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
Rows of
data to
shift to
align T(0)
1
003399
Time (T)
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
Hz
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
60.00388
60.00128
59.99936
59.99805
59.99741
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
30543.34
30543.34
30554.42
30554.42
30554.42
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003400
Time (T)
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
Hz
59.9971
59.99677
59.9971
59.99646
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
59.97675
59.9761
59.9761
59.97641
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30554.42
30534.33
30534.33
30533.84
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
30570.97
30593.17
30593.17
30593.17
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
Rows of
data to
shift to
align T(0)
1
003401
Time (T)
05/16/11 08:29:20
05/16/11 08:29:22
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
Hz
59.97705
59.97803
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
59.97479
59.97479
59.97641
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30593.17
30575.07
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
30603.96
30603.96
30603.96
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
-0.002
0.000
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.006
0.000
0.004
0.001
0.002
0.001
0.000
0.003
0.003
0.003
0.002
0.000
0.002
Rows of
data to
shift to
align T(0)
1
003402
Time (T)
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
05/16/11 08:31:56
05/16/11 08:31:58
Hz
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
60.0184
60.02069
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
30661.87
30661.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
0.000
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
0.000
0.002
Rows of
data to
shift to
align T(0)
1
003403
Time (T)
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
05/16/11 08:33:18
Hz
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
60.0152
60.01648
60.01614
60.0152
60.01486
60.01453
60.01291
60.01099
60.00775
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
30648.14
30648.29
30648.29
30648.29
30648.29
30648.29
30652.04
30652.04
30652.04
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.002
-0.003
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.002
0.003
Rows of
data to
shift to
align T(0)
1
003404
Time (T)
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
Hz
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
0.003
0.002
0.001
0.000
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
Rows of
data to
shift to
align T(0)
1
003405
Time (T)
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
Hz
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
59.99966
60.00064
60.00098
60.00064
60
59.99936
59.99741
59.99484
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
30686.83
30686.83
30686.83
30686.83
30686.83
30678.05
30678.05
30678.05
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.003
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.002
0.003
Rows of
data to
shift to
align T(0)
1
003406
Time (T)
05/16/11 08:36:00
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
Hz
59.99289
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
60.01227
60.01163
60.01132
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30678.05
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
30726.76
30726.76
30726.76
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003407
Time (T)
05/16/11 08:37:20
05/16/11 08:37:22
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
Hz
60.0126
60.01132
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
60.00388
60.00485
60.00549
60.00613
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30720.93
30720.93
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
30757.92
30752.27
30752.27
30752.27
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
Rows of
data to
shift to
align T(0)
1
003408
Time (T)
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
Hz
60.00647
60.00677
60.00677
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30752.27
30752.27
30752.33
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
Rows of
data to
shift to
align T(0)
1
003409
Time (T)
Hz
05/16/11 08:40:00 60.02618
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
NonConforming
Load
Load (-)
MW
0
Not
Used
Not
Used
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30803.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
Rows of
data to
shift to
align T(0)
1
003410
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
MyBA_110516_0806_FRS_Form2.9.xlsm
59.300 Hz
60.700 Hz
Auto Event Detection
8:06:38
1245 Manually selected row number of the Event Starting Time.
8:10:30
1442 Manually selected row number of the Event Ending Time.
Auto
Manual
Event Frequency Data
8:06:38
60.1
8:06:38
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
60.05
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
8:10:30
-0.101
Delta Hz Event Detected
60
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00
7:45:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
7:50:00
7:55:00
8:00:00
8:05:00
8:10:00
Hz
8:15:00
8:20:00
8:25:00
8:30:00
8:35:00
8:40:00
003411
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
Frequency
Hz
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
Contingent
Resource
Lost
MW
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Value B
20 to 52 sec
Average
Frequency
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
662.51 MW
Yes
0.711 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
Balancing Authority MyBA
Grid Nominal Frequency
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
A Point
FPointA
A Value
C Value
Delta FC
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
8:06:36
60.00195313
59.99862671
59.87011337
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
Spare
Spare
Sum of Pre Perturbation Adjustments
45.057
69.880
83.086
86.509
85.036
82.615
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
708.959
705.229
702.804
696.067
685.829
675.477
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
325.933
321.849
315.567
307.788
301.197
295.448
288.014
275.789
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average
Ramp
MW/scan
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Period Recovery Recovery Period Recovery
Target
Period
Period
Ramp
Period
MW
MW
MW
MW
MW
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
509.957
501.609
491.064
479.021
468.166
458.153
446.456
429.967
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
872.238
866.943
861.649
856.335
851.017
845.708
840.385
834.985
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
420.514
416.250
411.986
407.723
403.459
399.195
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
186.012
181.748
177.484
173.221
168.957
164.693
160.430
156.166
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
446.096
443.964
441.832
439.700
437.568
435.437
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
328.845
326.713
324.581
322.449
320.317
318.186
316.054
313.922
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Frequency
Hz
Contingent
Resource
Lost
MW
59.980
59.982
59.984
59.986
59.987
59.988
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
59.893
59.893
59.893
59.895
59.898
59.900
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
59.952
59.952
59.953
59.955
59.956
59.956
59.958
59.961
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
Hz
Hz
Hz
Hz
Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
30202.7 MW
30136.8 MW
-65.973 MW
-65.020 MW/0.1 Hz
14.00%
Average Bias Setting when Hz is greater than +/-0.036 Hz
-653.00 MW/0.1 Hz
Actual
Primary
Freq Response
MW/0.1 Hz
-481.62
-561.31
-863.83
-1000.43
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
Load
Resources
Tripped
Adjustment
0.00
0.00
0.00
0.00
0.00
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
NonConforming
Load
Spare
Spare
Adjustment Adjustment Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 52 second Average Period Evaluation
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.738 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingency MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingency Delta MW Actual
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
Expected Primary
Freq Response
Based on Bias Setting
MW
T
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
Frequency
Hz
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonContingent
Load
Conforming
Resource
Resources
Load
Lost
Tripped
Load (-)
MW
MW
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.711 P.U.
0.711 P.U.
Not
Used
Not
Used
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Not
Used
Not
Used
MW/0.1 Hz
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
EPFR
MW
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
446.26
446.26
446.26
456.01
467.62
475.25
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
1000.43
1007.61
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
0.0197
0.0178
0.0165
0.0142
0.0126
0.0120
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
0.0485
0.0481
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
Adjusted
Spare
P.U.
Adjustment
Performance
0.00
0.738
0.00
0.860
0.00
1.323
0.00
1.532
0.00
2.309
003412
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
-67.789
-55.851
-46.626
-44.326
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
-88.422
-76.483
-67.258
-64.958
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
241.944
240.477
239.065
237.677
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
113.628
113.016
112.409
111.808
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
60.008
60.005
60.005
60.006
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
0.0078
0.0052
0.0045
0.0061
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003413
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
-13.275
-13.790
-16.357
-20.257
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
-33.908
-34.423
-36.989
-40.890
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
147.518
147.032
146.542
146.058
145.591
145.147
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
139.601
139.146
138.686
138.218
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
59.915
59.699
59.483
59.269
59.057
58.845
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
56.194
55.997
55.802
55.608
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
60.003
60.004
60.003
60.001
59.999
59.997
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
60.002
60.002
60.003
60.004
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
81245.24
9243.47
7757.08
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
38591.49
25305.89
25305.89
30873.19
53229.64
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
0.0023
0.0023
0.0032
0.0042
003414
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
42.028
50.963
67.093
83.506
103.730
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
21.395
30.330
46.461
62.874
83.098
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
126.560
126.327
126.134
125.982
125.879
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
50.549
50.381
50.214
50.048
49.882
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
59.992
59.990
59.985
59.983
59.978
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
7385.93
5250.54
3492.44
2929.15
2324.79
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
0.0078
0.0103
0.0149
0.0175
0.0216
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
003415
Monday, May 16, 2011
Balancing Authority
MyBA
60.02
0.711
0.711
"Auto" Event Detection adjustment of T(0).
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
464.954
59.92
59.9
400.0
300.0
59.897
59.88
MW/0.1 Hz
Frequency - Hz
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
Hz
8:05:48
8:05:58
Average Frequency
8:06:08
8:06:18
8:06:28
Actual Primary Freq Response Beta
8:06:38
8:06:48
8:06:58
8:07:08
Actual Average Primary Freq Response
8:07:18
8:07:28
EPFR Adjusted
0.0
8:07:38
EPFR Unadjusted
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003416
Monday, May 16, 2011
-653.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
8:05:38
0.0
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
Hz
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003417
Value A Data
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Frequency
Hz
59.870
59.999
Contingent
Resource
Lost
MW
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Value B
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
0.00
-653.00 30202.74
Bias
Setting
EPFR
Frequency
MW
Hz
8.97
59.897
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
0.00
Load
Resources
Tripped
MW
0.00
NonConforming
Load
Load (-)
MW
0.00
Spare
MW
0.00
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
BA
BA
Bias
Load
Setting
P.U.
MW/0.1 Hz
MW
0.738
-653.00 30136.77
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
671.54
-653.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
0.738
0.860
1.323
1.532
2.309
0.738
0.860
1.323
1.532
2.309
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz MW/0.1 Hz
-653.00
-653.00
003418
Steps
1
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
003419
Monday, May 16, 2011
MyBA
Load
Resources
Tripped
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
0.00
B Value
Average Period
20 to 52 second
0.00
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
8:13:38
8:14:38
8:15:38
Hz
Initial Load Resources
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003420
Monday, May 16, 2011
MyBA
NonConforming
60.08
1.0
Load
60.06
Load (-)
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
8:15:38
Non- Conforming Load
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003421
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
59.9
A Value
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003422
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.94
0.6
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
0.4
59.86
59.84
59.82
0.2
59.8
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003423
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003424
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
MW
Frequency - Hz
59.96
59.92
A Value
59.9
15.00
59.88
59.86
B Value
0.00
Average Period
0.5
20 to 52 second
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Not Used
003425
Monday, May 16, 2011
BA
Load
MyBA
30600.0
60.08
60.06
30500.0
60.04
60.02
30400.0
60
59.98
30300.0
59.94
30200.0
59.92
A Value
59.9
7651.305
B Value
30136.8
Average Period
20 to 52 second
30100.0
59.88
59.86
30000.0
59.84
59.82
29900.0
59.8
59.78
29800.0
59.76
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
MW
Frequency - Hz
59.96
003426
Monday, May 16, 2011
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
1000.0
60.06
60.04
800.0
60.02
60
600.0
59.98
400.0
59.94
MW
Frequency - Hz
59.96
59.92
59.9
200.0
59.88
59.86
0.0
59.84
59.82
-200.0
59.8
A Value
59.78
8.97
B Value
671.54
Average Period
20 to 52 second
59.76
-400.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Expected Primary Freq Response Based on Bias Setting
003427
Time (T)
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
05/16/11 07:41:16
05/16/11 07:41:18
05/16/11 07:41:20
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
59.98578
59.9874
59.98868
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
29782.73
29782.73
29782.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
003428
05/16/11 07:41:22
05/16/11 07:41:24
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
05/16/11 07:42:40
05/16/11 07:42:42
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
59.98999
59.99191
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
60.0152
60.0152
60.01486
60.01422
60.01358
60.01227
60.01099
60.00873
60.00647
60.00485
60.00354
60.00195
60
59.99774
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29782.73
29782.82
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
29787.84
29813.39
29813.39
29813.39
29813.39
29813.39
29813.33
29813.33
29813.33
29813.33
29813.33
29797.46
29797.46
29797.46
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.002
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.002
-0.002
-0.002
0.001
0.002
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.002
0.002
0.002
003429
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
59.98514
59.98416
59.98352
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
003430
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
60.01227
60.01163
60.01065
60.0097
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
003431
05/16/11 07:46:16
05/16/11 07:46:18
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
60.01422
60.01227
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
59.99646
59.99579
59.99417
59.99225
59.9903
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
29782.35
29782.35
29782.44
29782.44
29782.44
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
-0.001
-0.001
-0.002
-0.002
-0.002
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
0.001
0.001
0.002
0.002
0.002
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
003432
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
60.02164
60.01971
60.01907
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
60
60
60.00452
60.00583
60.00613
60.00583
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29794.69
29794.69
29794.69
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.002
-0.001
-0.002
0.000
0.001
-0.001
-0.003
-0.001
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
0.000
0.002
0.001
0.002
0.000
0.001
0.001
0.003
0.001
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
003433
05/16/11 07:49:32
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
60.00516
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
59.99225
59.99484
59.99646
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29795.55
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
0.000
0.003
0.002
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.000
0.001
003434
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
05/16/11 07:51:24
05/16/11 07:51:26
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
59.97189
59.97125
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
59.98868
59.98868
59.9874
59.98611
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
29756.18
29756.18
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
29795.02
29795.02
29795.05
29795.05
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.001
003435
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
59.98611
59.98709
59.98837
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
60.00064
60.00098
60.00064
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29795.05
29795.05
29795.05
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
29823.76
29823.76
29818.41
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.000
003436
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
05/16/11 07:56:00
05/16/11 07:56:02
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
59.98547
59.98547
59.98514
59.9845
59.9845
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
59.97641
59.9761
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
29826.47
29826.41
29826.41
29826.41
29826.41
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
29831.33
29831.33
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.004
0.002
0.002
0.002
0.003
0.001
0.000
0.000
003437
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
05/16/11 07:56:24
05/16/11 07:56:26
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
59.97803
59.97867
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
60.01938
60.02036
60.02197
60.02423
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
29856.55
29856.55
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29889.67
29889.67
29889.67
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
003438
05/16/11 07:57:42
05/16/11 07:57:44
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
05/16/11 07:58:38
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
60.02261
60.02164
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
60.02069
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
59.99451
59.99127
59.98965
59.98868
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29891.67
29891.64
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
29887.14
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
29862.1
29862.1
29861.95
29861.95
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
-0.001
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
-0.005
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
0.005
0.003
0.002
0.001
0.002
0.002
0.002
0.002
0.003
0.002
003439
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
05/16/11 08:00:00
05/16/11 08:00:02
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
59.97287
59.97287
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
29905.8
29905.8
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
-0.001
-0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
0.001
0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
003440
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
05/16/11 08:01:30
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
59.98709
59.98773
59.98965
59.99161
59.99255
59.99323
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
29951.05
29951.05
29955.09
29955.09
29955.09
29955.09
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
003441
05/16/11 08:02:36
05/16/11 08:02:38
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
05/16/11 08:04:00
05/16/11 08:04:02
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
59.96512
59.96512
59.96576
59.96704
59.96994
59.97253
59.97415
59.9761
59.97739
59.97931
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
59.98029
59.979
59.97867
59.97931
59.97998
59.97931
59.979
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30055.73
30055.73
30055.73
30055.73
30068.76
30068.76
30068.76
30068.76
30068.76
30068.21
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
30118.77
30118.77
30118.74
30118.74
30118.74
30118.74
30118.74
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
-0.001
0.000
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.001
0.000
003442
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
05/16/11 08:05:48
05/16/11 08:05:50
59.97803
59.97675
59.97739
59.979
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471.3000183
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30106.93
30106.93
30106.93
30106.93
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
003443
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
05/16/11 08:06:36
05/16/11 08:06:38
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
471.3000183
471.3000183
471.3000183
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
470.8999939
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
0.000
-0.042
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
0.000
0.042
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
003444
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
05/16/11 08:08:40
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
003445
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
05/16/11 08:10:04
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
30300.1
30314.84
30314.84
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.001
-0.001
-0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
-0.001
-0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
0.001
0.004
003446
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
-0.001
-0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
003447
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
05/16/11 08:12:56
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.1
30349.1
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.002
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
003448
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
05/16/11 08:14:10
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
05/16/11 08:15:28
05/16/11 08:15:30
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
-0.001
0.004
0.002
0.000
0.001
-0.002
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.002
0.000
0.001
0.002
003449
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
05/16/11 08:17:16
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
0.000
-0.001
-0.004
-0.001
0.000
-0.002
-0.002
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
-0.001
-0.003
-0.003
0.000
0.002
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.001
0.000
0.002
0.002
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.003
0.003
0.000
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.002
003450
05/16/11 08:17:18
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
05/16/11 08:18:40
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30416.87
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
0.003
0.000
0.001
0.002
0.002
0.002
0.001
0.000
003451
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
05/16/11 08:20:32
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
0.000
-0.001
-0.003
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
0.000
0.001
0.003
0.002
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
0.000
003452
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
003453
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
05/16/11 08:23:00
05/16/11 08:23:02
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
60.03717
60.03781
60.03781
60.03748
60.0365
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
60.03101
60.03232
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
60.03458
60.03488
60.0336
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30452.43
30473.21
30473.21
30473.21
30473.21
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
30485.47
30505.49
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
30529.28
30529.08
30529.08
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.000
-0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
003454
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
60.03326
60.03232
60.03134
60.03168
60.03326
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
60.03134
60.03168
60.03134
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
60.0365
60.03488
60.0336
60.03232
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30529.08
30529.08
30529.52
30529.52
30529.52
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
30521.82
30533.64
30533.64
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
30556.84
30557.42
30557.42
30557.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
0.000
0.002
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
003455
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
60.03134
60.03101
60.03101
60.0307
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30557.43
30557.43
30557.43
30566.39
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.001
-0.001
0.000
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.003
0.002
003456
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
60.00388
60.00128
59.99936
59.99805
59.99741
59.9971
59.99677
59.9971
59.99646
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
30543.34
30543.34
30554.42
30554.42
30554.42
30554.42
30534.33
30534.33
30533.84
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
003457
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
05/16/11 08:29:20
05/16/11 08:29:22
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
59.97675
59.9761
59.9761
59.97641
59.97705
59.97803
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
30570.97
30593.17
30593.17
30593.17
30593.17
30575.07
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.006
0.000
0.004
0.001
003458
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
05/16/11 08:31:56
05/16/11 08:31:58
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
59.97479
59.97479
59.97641
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
60.0184
60.02069
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
30603.96
30603.96
30603.96
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
30661.87
30661.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
-0.002
0.000
0.002
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
0.000
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.002
0.000
0.002
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
0.000
0.002
003459
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
05/16/11 08:33:18
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
60.0152
60.01648
60.01614
60.0152
60.01486
60.01453
60.01291
60.01099
60.00775
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
30648.14
30648.29
30648.29
30648.29
30648.29
30648.29
30652.04
30652.04
30652.04
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.002
-0.003
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.002
0.003
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
003460
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
0.003
0.002
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
003461
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
05/16/11 08:36:00
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
59.99966
60.00064
60.00098
60.00064
60
59.99936
59.99741
59.99484
59.99289
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
30686.83
30686.83
30686.83
30686.83
30686.83
30678.05
30678.05
30678.05
30678.05
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.002
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
003462
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
05/16/11 08:37:20
05/16/11 08:37:22
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
60.01227
60.01163
60.01132
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
60.0126
60.01132
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
30726.76
30726.76
30726.76
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
30720.93
30720.93
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
0.000
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
003463
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
05/16/11 08:40:00
60.00388
60.00485
60.00549
60.00613
60.00647
60.00677
60.00677
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
60.02618
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
30757.92
30752.27
30752.27
30752.27
30752.27
30752.27
30752.33
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
30803.58
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
003464
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as
well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1
"BA Event Data" worksheet.
MyBA_110516_0806_FRS_Form2.9.xlsm
58.500 Hz
61.500 Hz
Event Detection
Auto
8:06:38
1245 Manually selected row number of the Event Starting Time.
8:10:30
1442 Manually selected row number of the Event Ending Time.
Event Frequency Data
8:06:38
60.1
8:06:38
-0.101
Delta Hz Event Detected
60.05
60
8:10:30
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00
7:45:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
7:50:00
7:55:00
8:00:00
8:05:00
8:10:00
Hz
8:15:00
8:20:00
8:25:00
8:30:00
8:35:00
8:40:00
003465
Auto
Manual
003466
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
Balancing Authority MyBA
Grid Nominal Frequency
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
662.51 MW
Yes
Initial Response P.U. Performance
0.711 P.U.
T
T-72 sec
T-70 sec
T-68 sec
Frequency
Hz
8:05:26 59.98029
8:05:28 59.98224
8:05:30 59.98352
Contingent
Resource
Lost
MW
471.000
471.000
471.000
Value B
20 to 52 sec
Average
Frequency
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
19590
19590
19590
Droop Setting
Deadband Setting
Hz Span
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
128.735
115.981
107.611
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.738 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
45.057
69.880
83.086
Initial
Measure
Final
Expected
Primary
Frequency
Response
A Point
FPointA
A Value
C Value
Delta FC
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
003467
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
86.509
85.036
82.615
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
003468
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
708.959
705.229
702.804
696.067
685.829
675.477
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
420.514
416.250
411.986
407.723
403.459
399.195
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
446.096
443.964
441.832
439.700
437.568
435.437
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
003469
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
325.933
321.849
315.567
307.788
301.197
295.448
288.014
275.789
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
509.957
501.609
491.064
479.021
468.166
458.153
446.456
429.967
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
872.238
866.943
861.649
856.335
851.017
845.708
840.385
834.985
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
186.012
181.748
177.484
173.221
168.957
164.693
160.430
156.166
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
328.845
326.713
324.581
322.449
320.317
318.186
316.054
313.922
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
003470
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
003471
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
003472
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
-67.789
-55.851
-46.626
-44.326
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
-88.422
-76.483
-67.258
-64.958
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
241.944
240.477
239.065
237.677
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
113.628
113.016
112.409
111.808
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
003473
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
003474
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
003475
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
147.518
147.032
146.542
146.058
145.591
145.147
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
59.915
59.699
59.483
59.269
59.057
58.845
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
003476
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
-13.275
-13.790
-16.357
-20.257
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
42.028
50.963
67.093
83.506
103.730
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-33.908
-34.423
-36.989
-40.890
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
21.395
30.330
46.461
62.874
83.098
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
139.601
139.146
138.686
138.218
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
126.560
126.327
126.134
125.982
125.879
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
56.194
55.997
55.802
55.608
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
50.549
50.381
50.214
50.048
49.882
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
003477
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
003478
8:06:36
60.00195313
59.99862671
59.87011337
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
Time of Frequency R
Value A Pre-Perturba
Value B Post-Perturbat
Value A Pre-Perturb
Value B Post-Perturbation Ave
ncy recovery period (indicates ramp direction during recovery period)
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
T
T-72 sec
T-70 sec
T-68 sec
8:05:26
8:05:28
8:05:30
Frequency
Hz
59.980
59.982
59.984
Contingent
Resource
Lost
MW
471.00
471.00
471.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
20 to 52 second Ave
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
Expected Primary
Freq Response
Based on Bias Setting
MW
128.735 T-72 sec
115.981 T-70 sec
107.611 T-68 sec
T
8:05:26
8:05:28
8:05:30
003479
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
59.986
59.987
59.988
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
003480
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
59.893
59.893
59.893
59.895
59.898
59.900
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
003481
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
59.952
59.952
59.953
59.955
59.956
59.956
59.958
59.961
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
003482
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
003483
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
003484
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
60.008
60.005
60.005
60.006
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
003485
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
003486
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
003487
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
60.003
60.004
60.003
60.001
59.999
59.997
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
003488
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
60.002
60.002
60.003
60.004
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
59.992
59.990
59.985
59.983
59.978
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
003489
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
003490
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Po
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingency MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingency Delta MW Actual
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
Spare
Spare
Sum of Pre Perturbation Adjustments
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
Hz
Hz
Hz
Hz
Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
Average Bias Setting when Hz is greater than +/-0.036 Hz
30202.7
30136.8
-65.973
-65.020
14.00%
Actual
Primary
Freq Response
MW/0.1 Hz
-481.62
-561.31
-863.83
-1000.43
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
Load
NonResources
Conforming
Tripped
Load
Adjustment
Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW/0.1 Hz
-653.00 MW/0.1 Hz
20 to 52 second Average Period Evaluation
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonContingent
Load
Conforming
Resource
Resources
Load
Lost
Tripped
Load (-)
MW
MW
MW
0.711 P.U.
0.711 P.U.
Not
Used
MW
Not
Used
Not
Used
Not
Used
MW/0.1 Hz
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
0.0197
0.0178
0.0165
003491
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
653.00
653.00
653.00
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
0.0142
0.0126
0.0120
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
003492
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
446.26
446.26
446.26
456.01
467.62
475.25
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
003493
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
1000.43
1007.61
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
0.0485
0.0481
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
003494
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
003495
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
003496
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
0.0078
0.0052
0.0045
0.0061
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
003497
81245.24
9243.47
7757.08
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
003498
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
003499
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
38591.49
25305.89
25305.89
30873.19
53229.64
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
003500
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
7385.93
5250.54
3492.44
2929.15
2324.79
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
0.0023
0.0023
0.0032
0.0042
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
0.0078
0.0103
0.0149
0.0175
0.0216
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
003501
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
003502
ncy Response Evaluation Points
Spare
Spare
Adjustment Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Adjusted
Spare
P.U.
Adjustment
Performance
0.00
0.738
0.00
0.860
0.00
1.323
0.00
1.532
0.00
2.309
003503
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003504
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003505
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003506
003507
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003508
003509
003510
003511
003512
003513
003514
Monday, May 16, 2011
Balancing Authority
MyBA
60.02
0.711
0.711
"Auto" Event Detection adjustment of T(0).
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
464.954
400.0
59.92
59.9
300.0
59.897
59.88
MW/0.1 Hz
Frequency - Hz
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
Hz
8:05:48
8:05:58
Average Frequency
8:06:08
8:06:18
8:06:28
Actual Primary Freq Response Beta
8:06:38
8:06:48
8:06:58
8:07:08
Actual Average Primary Freq Response
8:07:18
8:07:28
EPFR Adjusted
0.0
8:07:38
EPFR Unadjusted
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003515
Monday, May 16, 2011
-653.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
8:05:38
0.0
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
Hz
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003516
Value A Data
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
59.870
59.999
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
003517
Value B
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
-653.00 30202.74
Bias
Setting
EPFR
Frequency
MW
Hz
8.97
59.897
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
0.00
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
P.U.
0.738
003518
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
-653.00 30136.77
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
671.54
-653.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
0.738
0.860
1.323
1.532
2.309
0.738
0.860
1.323
1.532
2.309
003519
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
-653.00
-653.00
003520
Steps
1
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6".
Only rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
003521
Monday, May 16, 2011
MyBA
Load
Resources
Tripped
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
A Value
59.9
0.00
B Value
Average Period
20 to 52 second
0.00
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
8:13:38
8:14:38
8:15:38
Hz
Initial Load Resources
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003522
Monday, May 16, 2011
MyBA
NonConforming
60.08
1.0
Load
60.06
Load (-)
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
8:15:38
Non- Conforming Load
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003523
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
59.9
A Value
B Value
0.00
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003524
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.94
MW
Frequency - Hz
59.96
59.92
0.6
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
0.4
59.86
59.84
59.82
0.2
59.8
59.78
59.76
8:05:38 8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003525
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
59.92
0.5
A Value
59.9
B Value
0.00
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW/0.1 Hz
Frequency - Hz
0.6
003526
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
A Value
59.9
15.00
B Value
0.00
Average Period
0.5
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38 8:06:38 8:07:38
8:08:38 8:09:38
8:10:38 8:11:38
8:12:38 8:13:38 8:14:38
Hz
Not Used
8:15:38 8:16:38
8:17:38 8:18:38
0.0
8:19:38 8:20:38 8:21:38
003527
Monday, May 16, 2011
BA
Load
MyBA
60.08
30600.0
60.06
60.04
30500.0
60.02
60
30400.0
59.98
30300.0
59.94
MW
Frequency - Hz
59.96
59.92
30200.0
A Value
59.9
7651.305
59.88
B Value
30136.8
Average Period
20 to 52 second
30100.0
59.86
59.84
30000.0
59.82
59.8
29900.0
59.78
59.76
29800.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
003528
Monday, May 16, 2011
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
1000.0
60.06
60.04
800.0
60.02
60
600.0
59.98
400.0
59.94
59.92
59.9
200.0
59.88
59.86
0.0
59.84
59.82
-200.0
59.8
A Value
59.78
8.97
59.76
8:05:38 8:06:38 8:07:38
8:08:38
8:09:38 8:10:38 8:11:38
Hz
8:12:38 8:13:38 8:14:38
8:15:38
B Value
671.54
Average Period
20 to 52 second
8:16:38 8:17:38 8:18:38
Expected Primary Freq Response Based on Bias Setting
-400.0
8:19:38 8:20:38 8:21:38
MW
Frequency - Hz
59.96
003529
Time (T)
10/12/09 02:17:26
10/12/09 02:17:28
10/12/09 02:17:30
10/12/09 02:17:32
10/12/09 02:17:34
10/12/09 02:17:36
10/12/09 02:17:38
10/12/09 02:17:40
10/12/09 02:17:42
10/12/09 02:17:44
10/12/09 02:17:46
10/12/09 02:17:48
10/12/09 02:17:50
10/12/09 02:17:52
10/12/09 02:17:54
10/12/09 02:17:56
10/12/09 02:17:58
10/12/09 02:18:00
10/12/09 02:18:02
10/12/09 02:18:04
10/12/09 02:18:06
10/12/09 02:18:08
10/12/09 02:18:10
10/12/09 02:18:12
10/12/09 02:18:14
10/12/09 02:18:16
10/12/09 02:18:18
10/12/09 02:18:20
10/12/09 02:18:22
10/12/09 02:18:24
10/12/09 02:18:26
10/12/09 02:18:28
10/12/09 02:18:30
10/12/09 02:18:32
10/12/09 02:18:34
10/12/09 02:18:36
10/12/09 02:18:38
10/12/09 02:18:40
10/12/09 02:18:42
10/12/09 02:18:44
10/12/09 02:18:46
Hz
60.007
60.009
60.009
60.006
60.006
60.009
60.009
60.008
60.009
60.009
60.005
60.004
60.001
59.999
59.993
59.991
59.994
59.992
59.994
59.992
59.994
59.995
59.993
59.99
59.99
59.987
59.983
59.977
59.977
59.989
59.995
59.999
59.994
59.989
59.987
59.986
59.984
59.983
59.985
59.986
59.985
Net
Actual
Interchange
MW
3679.946
3679.44
3679.912
3679.517
3679.888
3679.608
3679.06
3679.261
3679.164
3679.025
3679.152
3678.572
3678.295
3678.249
3678.236
3677.83
3677.955
3677.772
3676.666
3677.093
3677.141
3676.401
3678.516
3679.872
3680.197
3678.743
3678.428
3677.921
3680.254
3682.07
3681.329
3678.656
3678.077
3677.78
3678.427
3678.473
3678.278
3677.822
3676.615
3677.397
3677.917
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-249.086395
0
Not
Used
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.126
-0.126
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
-0.003
0.000
0.003
0.000
-0.001
0.001
0.000
-0.004
-0.001
-0.003
-0.002
-0.006
-0.002
0.003
-0.002
0.002
-0.002
0.002
0.001
-0.002
-0.003
0.000
-0.003
-0.004
-0.006
0.000
0.012
0.006
0.004
-0.005
-0.005
-0.002
-0.001
-0.002
-0.001
0.002
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.003
0.000
0.003
0.000
0.001
0.001
0.000
0.004
0.001
0.003
0.002
0.006
0.002
0.003
0.002
0.002
0.002
0.002
0.001
0.002
0.003
0.000
0.003
0.004
0.006
0.000
0.012
0.006
0.004
0.005
0.005
0.002
0.001
0.002
0.001
0.002
0.001
0.001
003530
10/12/09 02:18:48
10/12/09 02:18:50
10/12/09 02:18:52
10/12/09 02:18:54
10/12/09 02:18:56
10/12/09 02:18:58
10/12/09 02:19:00
10/12/09 02:19:02
10/12/09 02:19:04
10/12/09 02:19:06
10/12/09 02:19:08
10/12/09 02:19:10
10/12/09 02:19:12
10/12/09 02:19:14
10/12/09 02:19:16
10/12/09 02:19:18
10/12/09 02:19:20
10/12/09 02:19:22
10/12/09 02:19:24
10/12/09 02:19:26
10/12/09 02:19:28
10/12/09 02:19:30
10/12/09 02:19:32
10/12/09 02:19:34
10/12/09 02:19:36
10/12/09 02:19:38
10/12/09 02:19:40
10/12/09 02:19:42
10/12/09 02:19:44
10/12/09 02:19:46
10/12/09 02:19:48
10/12/09 02:19:50
10/12/09 02:19:52
10/12/09 02:19:54
10/12/09 02:19:56
10/12/09 02:19:58
10/12/09 02:20:00
10/12/09 02:20:02
10/12/09 02:20:04
10/12/09 02:20:06
10/12/09 02:20:08
10/12/09 02:20:10
10/12/09 02:20:12
10/12/09 02:20:14
10/12/09 02:20:16
10/12/09 02:20:18
10/12/09 02:20:20
10/12/09 02:20:22
10/12/09 02:20:24
59.986
59.98
59.981
59.981
59.989
59.998
60.007
60.007
59.997
59.986
59.981
59.977
59.974
59.976
59.974
59.974
59.977
59.979
59.979
59.982
59.984
59.987
59.988
59.988
59.987
59.987
59.987
59.985
59.984
59.982
59.983
59.989
59.989
59.988
59.984
59.982
59.983
59.981
59.982
59.983
59.986
59.989
59.987
59.985
59.98
59.98
59.983
59.98
59.979
3677.95
3678.617
3678.963
3681.252
3680.737
3680.045
3678.161
3674.076
3676.222
3676.669
3677.497
3677.49
3675.186
3675.437
3680.451
3682.032
3683.829
3682.843
3681.108
3680.566
3678.229
3676.752
3675.759
3671.942
3671.166
3670.476
3670.129
3671.542
3672.048
3671.576
3672.104
3672.414
3671.882
3671.837
3671.336
3670.726
3670.372
3671.364
3671.401
3672.156
3672.181
3670.296
3668.071
3668.59
3669.908
3670.399
3670.263
3669.382
3670.102
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-249.086395
-249.086395
-249.086395
-249.086395
-253.742477
-253.742477
-253.742477
-253.742477
-253.742477
-257.421204
-257.421204
-257.421204
-257.421204
-257.421204
-261.73822
-261.73822
-261.73822
-261.73822
-261.73822
-271.875977
-271.875977
-271.875977
-271.875977
-271.875977
-262.073486
-262.073486
-262.073486
-262.073486
-262.073486
-260.36441
-260.36441
-260.36441
-260.36441
-260.36441
-352.644379
-352.644379
-352.644379
-352.644379
-352.644379
-354.89566
-354.89566
-354.89566
-354.89566
-354.89566
-340.46936
-340.46936
-340.46936
-340.46936
-340.46936
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
-0.006
0.001
0.000
0.008
0.009
0.009
0.000
-0.010
-0.011
-0.005
-0.004
-0.003
0.002
-0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.001
-0.002
0.001
0.006
0.000
-0.001
-0.004
-0.002
0.001
-0.002
0.001
0.001
0.003
0.003
-0.002
-0.002
-0.005
0.000
0.003
-0.003
-0.001
0.001
0.006
0.001
0.000
0.008
0.009
0.009
0.000
0.010
0.011
0.005
0.004
0.003
0.002
0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
0.001
0.000
0.000
0.002
0.001
0.002
0.001
0.006
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.003
0.003
0.002
0.002
0.005
0.000
0.003
0.003
0.001
003531
10/12/09 02:20:26
10/12/09 02:20:28
10/12/09 02:20:30
10/12/09 02:20:32
10/12/09 02:20:34
10/12/09 02:20:36
10/12/09 02:20:38
10/12/09 02:20:40
10/12/09 02:20:42
10/12/09 02:20:44
10/12/09 02:20:46
10/12/09 02:20:48
10/12/09 02:20:50
10/12/09 02:20:52
10/12/09 02:20:54
10/12/09 02:20:56
10/12/09 02:20:58
10/12/09 02:21:00
10/12/09 02:21:02
10/12/09 02:21:04
10/12/09 02:21:06
10/12/09 02:21:08
10/12/09 02:21:10
10/12/09 02:21:12
10/12/09 02:21:14
10/12/09 02:21:16
10/12/09 02:21:18
10/12/09 02:21:20
10/12/09 02:21:22
10/12/09 02:21:24
10/12/09 02:21:26
10/12/09 02:21:28
10/12/09 02:21:30
10/12/09 02:21:32
10/12/09 02:21:34
10/12/09 02:21:36
10/12/09 02:21:38
10/12/09 02:21:40
10/12/09 02:21:42
10/12/09 02:21:44
10/12/09 02:21:46
10/12/09 02:21:48
10/12/09 02:21:50
10/12/09 02:21:52
10/12/09 02:21:54
10/12/09 02:21:56
10/12/09 02:21:58
10/12/09 02:22:00
10/12/09 02:22:02
59.979
59.981
59.981
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.981
59.979
59.976
59.977
59.972
59.971
59.973
59.973
59.973
59.974
59.971
59.975
59.977
59.977
59.975
59.976
59.98
59.979
59.981
59.982
59.982
59.982
59.982
59.981
59.982
59.984
59.985
59.987
59.989
59.993
59.996
59.998
59.998
60.004
60.007
60.01
60.013
60.014
60.013
3670.438
3671.403
3672.442
3672.372
3671.947
3670.938
3670.705
3670.137
3669.279
3672.391
3672.558
3674.052
3672.626
3671.8
3673.183
3673.874
3676.263
3676.623
3676.87
3676.543
3675.464
3675.752
3675.256
3674.87
3671.277
3671.593
3670.587
3669.963
3669.54
3669.497
3668.706
3667.677
3666.482
3666.599
3666.911
3666.442
3666.405
3667.456
3666.38
3665.262
3664.031
3663.825
3663.229
3662.055
3661.695
3662.076
3662.224
3662.959
3663.794
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-337.642914
-337.642914
-337.642914
-337.642914
-337.642914
-284.36084
-284.36084
-284.36084
-284.36084
-284.36084
-260.467987
-260.467987
-260.467987
-260.467987
-260.467987
-253.141541
-253.141541
-253.141541
-253.141541
-253.141541
-251.929871
-251.929871
-251.929871
-251.929871
-251.929871
-250.674194
-250.674194
-250.674194
-250.674194
-250.674194
-253.631866
-253.631866
-253.631866
-253.631866
-253.631866
-246.957306
-246.957306
-246.957306
-246.957306
-246.957306
-254.541779
-254.541779
-254.541779
-254.541779
-254.541779
-256.571594
-256.571594
-256.571594
-256.571594
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.002
0.000
-0.001
0.000
0.001
-0.001
0.000
-0.003
0.002
0.002
-0.002
-0.003
0.001
-0.005
-0.001
0.002
0.000
0.000
0.001
-0.003
0.004
0.002
0.000
-0.002
0.001
0.004
-0.001
0.002
0.001
0.000
0.000
0.000
-0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.003
0.002
0.002
0.002
0.003
0.001
0.005
0.001
0.002
0.000
0.000
0.001
0.003
0.004
0.002
0.000
0.002
0.001
0.004
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
0.001
003532
10/12/09 02:22:04
10/12/09 02:22:06
10/12/09 02:22:08
10/12/09 02:22:10
10/12/09 02:22:12
10/12/09 02:22:14
10/12/09 02:22:16
10/12/09 02:22:18
10/12/09 02:22:20
10/12/09 02:22:22
10/12/09 02:22:24
10/12/09 02:22:26
10/12/09 02:22:28
10/12/09 02:22:30
10/12/09 02:22:32
10/12/09 02:22:34
10/12/09 02:22:36
10/12/09 02:22:38
10/12/09 02:22:40
10/12/09 02:22:42
10/12/09 02:22:44
10/12/09 02:22:46
10/12/09 02:22:48
10/12/09 02:22:50
10/12/09 02:22:52
10/12/09 02:22:54
10/12/09 02:22:56
10/12/09 02:22:58
10/12/09 02:23:00
10/12/09 02:23:02
10/12/09 02:23:04
10/12/09 02:23:06
10/12/09 02:23:08
10/12/09 02:23:10
10/12/09 02:23:12
10/12/09 02:23:14
10/12/09 02:23:16
10/12/09 02:23:18
10/12/09 02:23:20
10/12/09 02:23:22
10/12/09 02:23:24
10/12/09 02:23:26
10/12/09 02:23:28
10/12/09 02:23:30
10/12/09 02:23:32
10/12/09 02:23:34
10/12/09 02:23:36
10/12/09 02:23:38
10/12/09 02:23:40
60.008
60.008
60.01
60.019
60.019
60.023
60.021
60.02
60.021
60.021
60.02
60.019
60.019
60.022
60.025
60.025
60.026
60.02
60.02
60.018
60.018
60.02
60.019
60.019
60.023
60.022
60.022
60.025
60.02
60.02
60.02
60.02
60.02
60.021
60.021
60.018
60.014
60.014
60.014
60.013
60.013
60.01
60.008
60.011
60.011
60.012
60.012
60.009
60.009
3664.139
3665.278
3664.159
3663.265
3663.184
3661.929
3661.512
3659.172
3658.661
3656.785
3657.571
3658.126
3657.71
3658.015
3660.228
3659.224
3658.698
3658.669
3658.155
3659.13
3659.778
3660.82
3662.531
3662.387
3662.079
3662.39
3662.678
3663.577
3663.539
3662.959
3662.552
3662.543
3663.601
3663.91
3663.69
3662.791
3663.396
3663.698
3664.315
3665.313
3665.798
3666.141
3666.726
3667.677
3667.545
3666.688
3666.449
3666.71
3667.696
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-256.571594
-258.37262
-258.37262
-258.37262
-258.37262
-258.37262
-263.047363
-263.047363
-263.047363
-263.047363
-263.047363
-260.984375
-260.984375
-260.984375
-260.984375
-260.984375
-261.318329
-261.318329
-261.318329
-261.318329
-261.318329
-262.1026
-262.1026
-262.1026
-262.1026
-262.1026
-262.71701
-262.71701
-262.71701
-262.71701
-262.71701
-260.016479
-260.016479
-260.016479
-260.016479
-260.016479
-263.87323
-263.87323
-263.87323
-263.87323
-263.87323
-264.5979
-264.5979
-264.5979
-264.5979
-264.5979
-262.415924
-262.415924
-262.415924
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.005
0.000
0.002
0.009
0.000
0.004
-0.002
-0.001
0.001
0.000
-0.001
-0.001
0.000
0.003
0.003
0.000
0.001
-0.006
0.000
-0.002
0.000
0.002
-0.001
0.000
0.004
-0.001
0.000
0.003
-0.005
0.000
0.000
0.000
0.000
0.001
0.000
-0.003
-0.004
0.000
0.000
-0.001
0.000
-0.003
-0.002
0.003
0.000
0.001
0.000
-0.003
0.000
0.005
0.000
0.002
0.009
0.000
0.004
0.002
0.001
0.001
0.000
0.001
0.001
0.000
0.003
0.003
0.000
0.001
0.006
0.000
0.002
0.000
0.002
0.001
0.000
0.004
0.001
0.000
0.003
0.005
0.000
0.000
0.000
0.000
0.001
0.000
0.003
0.004
0.000
0.000
0.001
0.000
0.003
0.002
0.003
0.000
0.001
0.000
0.003
0.000
003533
10/12/09 02:23:42
10/12/09 02:23:44
10/12/09 02:23:46
10/12/09 02:23:48
10/12/09 02:23:50
10/12/09 02:23:52
10/12/09 02:23:54
10/12/09 02:23:56
10/12/09 02:23:58
10/12/09 02:24:00
10/12/09 02:24:02
10/12/09 02:24:04
10/12/09 02:24:06
10/12/09 02:24:08
10/12/09 02:24:10
10/12/09 02:24:12
10/12/09 02:24:14
10/12/09 02:24:16
10/12/09 02:24:18
10/12/09 02:24:20
10/12/09 02:24:22
10/12/09 02:24:24
10/12/09 02:24:26
10/12/09 02:24:28
10/12/09 02:24:30
10/12/09 02:24:32
10/12/09 02:24:34
10/12/09 02:24:36
10/12/09 02:24:38
10/12/09 02:24:40
10/12/09 02:24:42
10/12/09 02:24:44
10/12/09 02:24:46
10/12/09 02:24:48
10/12/09 02:24:50
10/12/09 02:24:52
10/12/09 02:24:54
10/12/09 02:24:56
10/12/09 02:24:58
10/12/09 02:25:00
10/12/09 02:25:02
10/12/09 02:25:04
10/12/09 02:25:06
10/12/09 02:25:08
10/12/09 02:25:10
10/12/09 02:25:12
10/12/09 02:25:14
10/12/09 02:25:16
10/12/09 02:25:18
60.009
60.009
60.005
60.002
59.999
59.996
59.995
59.997
59.998
59.998
59.998
59.998
59.995
59.995
59.992
59.993
59.988
59.988
59.982
59.982
59.982
59.982
59.984
59.982
59.978
59.978
59.976
59.975
59.974
59.974
59.979
59.98
59.981
59.98
59.984
59.987
59.988
59.988
59.99
59.992
59.991
59.991
59.991
59.993
59.993
59.996
60.002
60.002
60.003
3667.398
3667.043
3666.624
3666.223
3665.88
3665.403
3665.802
3665.68
3665.352
3664.948
3665.065
3666.133
3666.64
3666.735
3667.084
3667.557
3667.337
3667.853
3668.116
3668.691
3669.399
3669.606
3671.228
3670.25
3670.265
3671.549
3673.243
3674.263
3675.824
3676.418
3676.306
3674.637
3675.329
3675.226
3674.768
3674.399
3673.514
3673.04
3672.442
3673.056
3671.68
3671.493
3669.53
3670.066
3670.028
3671.744
3671.578
3672.625
3672.674
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-262.415924
-262.415924
-259.685242
-259.685242
-259.685242
-259.685242
-259.685242
-255.911011
-255.911011
-255.911011
-255.911011
-255.911011
-258.148193
-258.148193
-258.148193
-258.148193
-258.148193
-258.873596
-258.873596
-258.873596
-258.873596
-258.873596
-249.33757
-249.33757
-249.33757
-249.33757
-249.33757
-258.278168
-258.278168
-258.278168
-258.278168
-258.278168
-258.406372
-258.406372
-258.406372
-258.406372
-258.406372
-260.538879
-260.538879
-260.538879
-260.538879
-260.538879
-257.88208
-257.88208
-257.88208
-257.88208
-257.88208
-258.588654
-258.588654
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
-0.004
-0.003
-0.003
-0.003
-0.001
0.002
0.001
0.000
0.000
0.000
-0.003
0.000
-0.003
0.001
-0.005
0.000
-0.006
0.000
0.000
0.000
0.002
-0.002
-0.004
0.000
-0.002
-0.001
-0.001
0.000
0.005
0.001
0.001
-0.001
0.004
0.003
0.001
0.000
0.002
0.002
-0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
0.000
0.000
0.004
0.003
0.003
0.003
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.000
0.003
0.001
0.005
0.000
0.006
0.000
0.000
0.000
0.002
0.002
0.004
0.000
0.002
0.001
0.001
0.000
0.005
0.001
0.001
0.001
0.004
0.003
0.001
0.000
0.002
0.002
0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
003534
10/12/09 02:25:20
10/12/09 02:25:22
10/12/09 02:25:24
10/12/09 02:25:26
10/12/09 02:25:28
10/12/09 02:25:30
10/12/09 02:25:32
10/12/09 02:25:34
10/12/09 02:25:36
10/12/09 02:25:38
10/12/09 02:25:40
10/12/09 02:25:42
10/12/09 02:25:44
10/12/09 02:25:46
10/12/09 02:25:48
10/12/09 02:25:50
10/12/09 02:25:52
10/12/09 02:25:54
10/12/09 02:25:56
10/12/09 02:25:58
10/12/09 02:26:00
10/12/09 02:26:02
10/12/09 02:26:04
10/12/09 02:26:06
10/12/09 02:26:08
10/12/09 02:26:10
10/12/09 02:26:12
10/12/09 02:26:14
10/12/09 02:26:16
10/12/09 02:26:18
10/12/09 02:26:20
10/12/09 02:26:22
10/12/09 02:26:24
10/12/09 02:26:26
10/12/09 02:26:28
10/12/09 02:26:30
10/12/09 02:26:32
10/12/09 02:26:34
10/12/09 02:26:36
10/12/09 02:26:38
10/12/09 02:26:40
10/12/09 02:26:42
10/12/09 02:26:44
10/12/09 02:26:46
10/12/09 02:26:48
10/12/09 02:26:50
10/12/09 02:26:52
10/12/09 02:26:54
10/12/09 02:26:56
60.004
60.005
60.004
60.002
60.004
60.008
60.01
60.01
60.01
60.011
60.013
60.014
60.013
60.012
60.011
60.011
60.017
60.022
60.017
60.014
60.013
60.014
60.017
60.017
60.019
60.019
60.019
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
3673.819
3673.25
3673.182
3673.496
3672.418
3672.363
3672.217
3672.261
3673.182
3673.603
3673.553
3674.312
3674.537
3673.813
3673.204
3672.563
3673.068
3672.388
3672.52
3671.25
3671.288
3672.989
3672.982
3672.915
3671.952
3671.193
3671.627
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.19
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-258.588654
-258.588654
-258.588654
-261.906158
-261.906158
-261.906158
-261.906158
-261.906158
-256.747803
-256.747803
-256.747803
-256.747803
-256.747803
-167.431976
-167.431976
-167.431976
-167.431976
-167.431976
-164.973404
-164.973404
-164.973404
-164.973404
-164.973404
-157.628082
-157.628082
-157.628082
-157.628082
-157.628082
-155.531708
-155.531708
-155.531708
-155.531708
-155.531708
-160.447235
-160.447235
-160.447235
-160.447235
-160.447235
-163.958603
-163.958603
-163.958603
-163.958603
-163.958603
-166.072449
-166.072449
-166.072449
-166.072449
-166.072449
-163.766586
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
-0.001
-0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
-0.001
-0.001
-0.001
0.000
0.006
0.005
-0.005
-0.003
-0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
-0.001
0.000
-0.004
-0.003
-0.002
0.002
0.001
-0.001
0.002
0.000
0.000
-0.002
-0.001
0.004
0.009
0.006
0.000
-0.001
0.001
0.009
0.002
0.001
0.001
0.001
0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.006
0.005
0.005
0.003
0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
0.001
0.000
0.004
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.000
0.002
0.001
0.004
0.009
0.006
0.000
0.001
0.001
0.009
0.002
003535
10/12/09 02:26:58
10/12/09 02:27:00
10/12/09 02:27:02
10/12/09 02:27:04
10/12/09 02:27:06
10/12/09 02:27:08
10/12/09 02:27:10
10/12/09 02:27:12
10/12/09 02:27:14
10/12/09 02:27:16
10/12/09 02:27:18
10/12/09 02:27:20
10/12/09 02:27:22
10/12/09 02:27:24
10/12/09 02:27:26
10/12/09 02:27:28
10/12/09 02:27:30
10/12/09 02:27:32
10/12/09 02:27:34
10/12/09 02:27:36
10/12/09 02:27:38
10/12/09 02:27:40
10/12/09 02:27:42
10/12/09 02:27:44
10/12/09 02:27:46
10/12/09 02:27:48
10/12/09 02:27:50
10/12/09 02:27:52
10/12/09 02:27:54
10/12/09 02:27:56
10/12/09 02:27:58
10/12/09 02:28:00
10/12/09 02:28:02
10/12/09 02:28:04
10/12/09 02:28:06
10/12/09 02:28:08
10/12/09 02:28:10
10/12/09 02:28:12
10/12/09 02:28:14
10/12/09 02:28:16
10/12/09 02:28:18
10/12/09 02:28:20
10/12/09 02:28:22
10/12/09 02:28:24
10/12/09 02:28:26
10/12/09 02:28:28
10/12/09 02:28:30
10/12/09 02:28:32
10/12/09 02:28:34
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3737.157
3761.25
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.5
3784.962
3784.73
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-163.766586
-163.766586
-163.766586
-163.766586
-165.101685
-165.101685
-165.101685
-165.101685
-165.101685
-165.476395
-165.476395
-165.476395
-165.476395
-165.476395
-206.459106
-206.459106
-206.459106
-206.459106
-206.459106
-211.256042
-211.256042
-211.256042
-211.256042
-211.256042
-214.346695
-214.346695
-214.346695
-214.346695
-214.346695
-212.172699
-212.172699
-212.172699
-212.172699
-212.172699
-215.598175
-215.598175
-215.598175
-215.598175
-215.598175
-218.327255
-218.327255
-218.327255
-218.327255
-218.327255
-217.379425
-217.379425
-217.379425
-217.379425
-217.379425
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.005
-0.002
0.000
0.000
-0.002
0.002
0.002
0.002
0.001
-0.005
0.000
0.000
-0.002
-0.061
-0.126
-0.016
0.033
0.023
-0.001
-0.011
-0.004
-0.001
0.008
0.004
-0.001
-0.001
0.002
0.001
0.002
0.005
-0.001
-0.001
0.001
0.000
-0.003
-0.001
-0.005
0.000
0.003
-0.001
0.001
0.000
0.002
-0.001
-0.007
-0.009
-0.016
-0.008
0.000
0.005
0.002
0.000
0.000
0.002
0.002
0.002
0.002
0.001
0.005
0.000
0.000
0.002
0.061
0.126
0.016
0.033
0.023
0.001
0.011
0.004
0.001
0.008
0.004
0.001
0.001
0.002
0.001
0.002
0.005
0.001
0.001
0.001
0.000
0.003
0.001
0.005
0.000
0.003
0.001
0.001
0.000
0.002
0.001
0.007
0.009
0.016
0.008
003536
10/12/09 02:28:36
10/12/09 02:28:38
10/12/09 02:28:40
10/12/09 02:28:42
10/12/09 02:28:44
10/12/09 02:28:46
10/12/09 02:28:48
10/12/09 02:28:50
10/12/09 02:28:52
10/12/09 02:28:54
10/12/09 02:28:56
10/12/09 02:28:58
10/12/09 02:29:00
10/12/09 02:29:02
10/12/09 02:29:04
10/12/09 02:29:06
10/12/09 02:29:08
10/12/09 02:29:10
10/12/09 02:29:12
10/12/09 02:29:14
10/12/09 02:29:16
10/12/09 02:29:18
10/12/09 02:29:20
10/12/09 02:29:22
10/12/09 02:29:24
10/12/09 02:29:26
10/12/09 02:29:28
10/12/09 02:29:30
10/12/09 02:29:32
10/12/09 02:29:34
10/12/09 02:29:36
10/12/09 02:29:38
10/12/09 02:29:40
10/12/09 02:29:42
10/12/09 02:29:44
10/12/09 02:29:46
10/12/09 02:29:48
10/12/09 02:29:50
10/12/09 02:29:52
10/12/09 02:29:54
10/12/09 02:29:56
10/12/09 02:29:58
10/12/09 02:30:00
10/12/09 02:30:02
10/12/09 02:30:04
10/12/09 02:30:06
10/12/09 02:30:08
10/12/09 02:30:10
10/12/09 02:30:12
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.01
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.67
3769.63
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-214.830353
-214.830353
-214.830353
-214.830353
-214.830353
-227.655914
-227.655914
-227.655914
-227.655914
-227.655914
-225.018082
-225.018082
-225.018082
-225.018082
-225.018082
-228.365158
-228.365158
-228.365158
-228.365158
-228.365158
-234.075333
-234.075333
-234.075333
-234.075333
-234.075333
-228.798157
-228.798157
-228.798157
-228.798157
-228.798157
-229.466965
-229.466965
-229.466965
-229.466965
-229.466965
-228.980164
-228.980164
-228.980164
-228.980164
-228.980164
-219.975555
-219.975555
-219.975555
-219.975555
-219.975555
-229.089249
-229.089249
-229.089249
-229.089249
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
249
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.006
0.005
0.003
-0.001
0.002
-0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
-0.003
0.004
0.006
0.004
-0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
-0.001
-0.003
0.003
0.001
0.002
0.003
-0.001
0.003
-0.001
0.005
-0.005
0.001
0.003
-0.002
0.002
0.002
0.004
0.000
0.008
0.003
0.006
0.005
0.003
0.001
0.002
0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
0.003
0.004
0.006
0.004
0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
0.001
0.003
0.003
0.001
0.002
0.003
0.001
0.003
0.001
0.005
0.005
0.001
0.003
0.002
0.002
0.002
0.004
0.000
0.008
003537
10/12/09 02:30:14
10/12/09 02:30:16
10/12/09 02:30:18
10/12/09 02:30:20
10/12/09 02:30:22
10/12/09 02:30:24
10/12/09 02:30:26
10/12/09 02:30:28
10/12/09 02:30:30
10/12/09 02:30:32
10/12/09 02:30:34
10/12/09 02:30:36
10/12/09 02:30:38
10/12/09 02:30:40
10/12/09 02:30:42
10/12/09 02:30:44
10/12/09 02:30:46
10/12/09 02:30:48
10/12/09 02:30:50
10/12/09 02:30:52
10/12/09 02:30:54
10/12/09 02:30:56
10/12/09 02:30:58
10/12/09 02:31:00
10/12/09 02:31:02
10/12/09 02:31:04
10/12/09 02:31:06
10/12/09 02:31:08
10/12/09 02:31:10
10/12/09 02:31:12
10/12/09 02:31:14
10/12/09 02:31:16
10/12/09 02:31:18
10/12/09 02:31:20
10/12/09 02:31:22
10/12/09 02:31:24
10/12/09 02:31:26
10/12/09 02:31:28
10/12/09 02:31:30
10/12/09 02:31:32
10/12/09 02:31:34
10/12/09 02:31:36
10/12/09 02:31:38
10/12/09 02:31:40
10/12/09 02:31:42
10/12/09 02:31:44
10/12/09 02:31:46
10/12/09 02:31:48
10/12/09 02:31:50
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.81
3712.092
3714.623
3715.13
3716.168
3716.461
3716.98
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.13
3732.53
3733.327
3736.535
3736.907
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-229.089249
-229.663269
-229.663269
-229.663269
-229.663269
-229.663269
-229.233856
-229.233856
-229.233856
-229.233856
-229.233856
-231.409882
-231.409882
-231.409882
-231.409882
-231.409882
-218.622284
-218.622284
-218.622284
-218.622284
-218.622284
-213.535858
-213.535858
-213.535858
-213.535858
-213.535858
-225.651855
-225.651855
-225.651855
-225.651855
-225.651855
-212.573639
-212.573639
-212.573639
-212.573639
-212.573639
-219.897293
-219.897293
-219.897293
-219.897293
-219.897293
-231.1754
-231.1754
-231.1754
-231.1754
-231.1754
-226.634125
-226.634125
-226.634125
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
297.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
-0.002
-0.005
-0.001
0.001
0.003
0.003
-0.001
0.002
0.002
0.001
0.001
-0.002
0.001
0.000
0.000
0.003
-0.003
0.002
-0.002
0.001
0.000
-0.001
0.002
0.000
0.005
-0.002
-0.001
-0.002
0.002
-0.001
0.003
0.003
0.001
0.000
0.006
-0.002
0.000
0.002
0.002
0.004
-0.004
-0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.004
0.002
0.005
0.001
0.001
0.003
0.003
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.000
0.001
0.002
0.000
0.005
0.002
0.001
0.002
0.002
0.001
0.003
0.003
0.001
0.000
0.006
0.002
0.000
0.002
0.002
0.004
0.004
0.001
0.000
0.001
0.001
0.002
0.000
0.003
003538
10/12/09 02:31:52
10/12/09 02:31:54
10/12/09 02:31:56
10/12/09 02:31:58
10/12/09 02:32:00
10/12/09 02:32:02
10/12/09 02:32:04
10/12/09 02:32:06
10/12/09 02:32:08
10/12/09 02:32:10
10/12/09 02:32:12
10/12/09 02:32:14
10/12/09 02:32:16
10/12/09 02:32:18
10/12/09 02:32:20
10/12/09 02:32:22
10/12/09 02:32:24
10/12/09 02:32:26
10/12/09 02:32:28
10/12/09 02:32:30
10/12/09 02:32:32
10/12/09 02:32:34
10/12/09 02:32:36
10/12/09 02:32:38
10/12/09 02:32:40
10/12/09 02:32:42
10/12/09 02:32:44
10/12/09 02:32:46
10/12/09 02:32:48
10/12/09 02:32:50
10/12/09 02:32:52
10/12/09 02:32:54
10/12/09 02:32:56
10/12/09 02:32:58
10/12/09 02:33:00
10/12/09 02:33:02
10/12/09 02:33:04
10/12/09 02:33:06
10/12/09 02:33:08
10/12/09 02:33:10
10/12/09 02:33:12
10/12/09 02:33:14
10/12/09 02:33:16
10/12/09 02:33:18
10/12/09 02:33:20
10/12/09 02:33:22
10/12/09 02:33:24
10/12/09 02:33:26
10/12/09 02:33:28
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.3
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.42
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.85
3786.304
3787.259
3787.516
3787.955
3788.03
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-226.634125
-226.634125
-227.255066
-227.255066
-227.255066
-227.255066
-227.255066
-229.290222
-229.290222
-229.290222
-229.290222
-229.290222
-221.461365
-221.461365
-221.461365
-221.461365
-221.461365
-241.274368
-241.274368
-241.274368
-241.274368
-241.274368
-243.071854
-243.071854
-243.071854
-243.071854
-243.071854
-241.670212
-241.670212
-241.670212
-241.670212
-241.670212
-228.149307
-228.149307
-228.149307
-228.149307
-228.149307
-235.128983
-235.128983
-235.128983
-235.128983
-235.128983
-246.433136
-246.433136
-246.433136
-246.433136
-246.433136
-236.553543
-236.553543
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.000
-0.002
0.002
-0.002
0.002
-0.001
0.003
0.002
-0.001
-0.001
-0.001
0.001
-0.001
0.004
0.000
0.001
0.004
0.001
-0.002
0.000
0.004
0.002
-0.001
-0.001
-0.002
-0.003
-0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
-0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
-0.004
0.000
0.002
0.000
0.002
0.002
0.002
0.002
0.001
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.004
0.000
0.001
0.004
0.001
0.002
0.000
0.004
0.002
0.001
0.001
0.002
0.003
0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
0.004
0.000
003539
10/12/09 02:33:30
10/12/09 02:33:32
10/12/09 02:33:34
10/12/09 02:33:36
10/12/09 02:33:38
10/12/09 02:33:40
10/12/09 02:33:42
10/12/09 02:33:44
10/12/09 02:33:46
10/12/09 02:33:48
10/12/09 02:33:50
10/12/09 02:33:52
10/12/09 02:33:54
10/12/09 02:33:56
10/12/09 02:33:58
10/12/09 02:34:00
10/12/09 02:34:02
10/12/09 02:34:04
10/12/09 02:34:06
10/12/09 02:34:08
10/12/09 02:34:10
10/12/09 02:34:12
10/12/09 02:34:14
10/12/09 02:34:16
10/12/09 02:34:18
10/12/09 02:34:20
10/12/09 02:34:22
10/12/09 02:34:24
10/12/09 02:34:26
10/12/09 02:34:28
10/12/09 02:34:30
10/12/09 02:34:32
10/12/09 02:34:34
10/12/09 02:34:36
10/12/09 02:34:38
10/12/09 02:34:40
10/12/09 02:34:42
10/12/09 02:34:44
10/12/09 02:34:46
10/12/09 02:34:48
10/12/09 02:34:50
10/12/09 02:34:52
10/12/09 02:34:54
10/12/09 02:34:56
10/12/09 02:34:58
10/12/09 02:35:00
10/12/09 02:35:02
10/12/09 02:35:04
10/12/09 02:35:06
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
3788.607
3789.216
3787.537
3785.842
3786.077
3787.93
3788.76
3786.875
3786.55
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.54
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-236.553543
-236.553543
-236.553543
-230.297562
-230.297562
-230.297562
-230.297562
-230.297562
-231.175537
-231.175537
-231.175537
-231.175537
-231.175537
-225.61763
-225.61763
-225.61763
-225.61763
-225.61763
-230.734421
-230.734421
-230.734421
-230.734421
-230.734421
-234.847107
-234.847107
-234.847107
-234.847107
-234.847107
-228.960922
-228.960922
-228.960922
-228.960922
-228.960922
-231.177917
-231.177917
-231.177917
-231.177917
-231.177917
-236.489288
-236.489288
-236.489288
-236.489288
-236.489288
-245.038925
-245.038925
-245.038925
-245.038925
-245.038925
-223.605682
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.004
0.001
0.001
-0.004
-0.002
0.005
0.000
-0.003
-0.001
0.005
-0.001
-0.004
0.000
0.002
0.000
0.000
-0.001
0.000
0.002
0.000
-0.001
-0.003
-0.003
0.002
0.000
0.000
0.001
0.000
-0.003
-0.001
0.001
-0.002
-0.001
-0.001
0.000
-0.002
-0.003
0.000
0.002
0.000
0.001
-0.007
-0.004
-0.004
-0.003
-0.001
0.001
0.000
0.002
0.004
0.001
0.001
0.004
0.002
0.005
0.000
0.003
0.001
0.005
0.001
0.004
0.000
0.002
0.000
0.000
0.001
0.000
0.002
0.000
0.001
0.003
0.003
0.002
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.001
0.000
0.002
0.003
0.000
0.002
0.000
0.001
0.007
0.004
0.004
0.003
0.001
0.001
0.000
003540
10/12/09 02:35:08
10/12/09 02:35:10
10/12/09 02:35:12
10/12/09 02:35:14
10/12/09 02:35:16
10/12/09 02:35:18
10/12/09 02:35:20
10/12/09 02:35:22
10/12/09 02:35:24
10/12/09 02:35:26
10/12/09 02:35:28
10/12/09 02:35:30
10/12/09 02:35:32
10/12/09 02:35:34
10/12/09 02:35:36
10/12/09 02:35:38
10/12/09 02:35:40
10/12/09 02:35:42
10/12/09 02:35:44
10/12/09 02:35:46
10/12/09 02:35:48
10/12/09 02:35:50
10/12/09 02:35:52
10/12/09 02:35:54
10/12/09 02:35:56
10/12/09 02:35:58
10/12/09 02:36:00
10/12/09 02:36:02
10/12/09 02:36:04
10/12/09 02:36:06
10/12/09 02:36:08
10/12/09 02:36:10
10/12/09 02:36:12
10/12/09 02:36:14
10/12/09 02:36:16
10/12/09 02:36:18
10/12/09 02:36:20
10/12/09 02:36:22
10/12/09 02:36:24
10/12/09 02:36:26
10/12/09 02:36:28
10/12/09 02:36:30
10/12/09 02:36:32
10/12/09 02:36:34
10/12/09 02:36:36
10/12/09 02:36:38
10/12/09 02:36:40
10/12/09 02:36:42
10/12/09 02:36:44
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
3788.189
3788.497
3788.54
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.41
3790.467
3790.665
3790.42
3789.674
3789.267
3789.148
3790.43
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.08
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.69
3784.831
3785.01
3784.32
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.605682
-223.605682
-223.605682
-223.605682
-231.119354
-231.119354
-231.119354
-231.119354
-231.119354
-237.20665
-237.20665
-237.20665
-237.20665
-237.20665
-240.516373
-240.516373
-240.516373
-240.516373
-240.516373
-237.566055
-237.566055
-237.566055
-237.566055
-237.566055
-231.581421
-231.581421
-231.581421
-231.581421
-231.581421
-235.850845
-235.850845
-235.850845
-235.850845
-235.850845
-233.559982
-233.559982
-233.559982
-233.559982
-233.559982
-219.009995
-219.009995
-219.009995
-219.009995
-219.009995
-205.338913
-205.338913
-205.338913
-205.338913
-205.338913
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.004
-0.002
-0.001
-0.001
0.001
-0.001
-0.002
-0.001
0.001
-0.003
-0.002
-0.001
0.000
0.003
0.003
-0.004
-0.002
-0.002
0.002
0.001
0.000
-0.002
-0.002
-0.004
0.001
0.001
0.002
0.005
0.003
-0.003
-0.003
-0.003
0.004
-0.001
-0.002
-0.004
-0.003
-0.001
0.001
0.003
0.001
-0.002
-0.003
-0.001
0.006
0.002
-0.005
0.000
0.002
0.004
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.003
0.002
0.001
0.000
0.003
0.003
0.004
0.002
0.002
0.002
0.001
0.000
0.002
0.002
0.004
0.001
0.001
0.002
0.005
0.003
0.003
0.003
0.003
0.004
0.001
0.002
0.004
0.003
0.001
0.001
0.003
0.001
0.002
0.003
0.001
0.006
0.002
0.005
0.000
0.002
003541
10/12/09 02:36:46
10/12/09 02:36:48
10/12/09 02:36:50
10/12/09 02:36:52
10/12/09 02:36:54
10/12/09 02:36:56
10/12/09 02:36:58
10/12/09 02:37:00
10/12/09 02:37:02
10/12/09 02:37:04
10/12/09 02:37:06
10/12/09 02:37:08
10/12/09 02:37:10
10/12/09 02:37:12
10/12/09 02:37:14
10/12/09 02:37:16
10/12/09 02:37:18
10/12/09 02:37:20
10/12/09 02:37:22
10/12/09 02:37:24
10/12/09 02:37:26
10/12/09 02:37:28
10/12/09 02:37:30
10/12/09 02:37:32
10/12/09 02:37:34
10/12/09 02:37:36
10/12/09 02:37:38
10/12/09 02:37:40
10/12/09 02:37:42
10/12/09 02:37:44
10/12/09 02:37:46
10/12/09 02:37:48
10/12/09 02:37:50
10/12/09 02:37:52
10/12/09 02:37:54
10/12/09 02:37:56
10/12/09 02:37:58
10/12/09 02:38:00
10/12/09 02:38:02
10/12/09 02:38:04
10/12/09 02:38:06
10/12/09 02:38:08
10/12/09 02:38:10
10/12/09 02:38:12
10/12/09 02:38:14
10/12/09 02:38:16
10/12/09 02:38:18
10/12/09 02:38:20
10/12/09 02:38:22
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
3782.809
3782.11
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.17
3771.73
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.25
3758.041
3760.965
3762.022
3763.822
3763.1
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.57
3761.92
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-236.285355
-236.285355
-236.285355
-236.285355
-236.285355
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
371.5
372
372.5
373
373.5
374
374.5
375
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.001
-0.002
0.000
-0.001
-0.001
0.006
-0.004
-0.002
-0.003
0.002
0.006
-0.003
0.002
-0.001
-0.005
0.002
0.005
0.003
-0.005
-0.003
0.003
0.001
-0.002
-0.003
0.002
0.013
0.011
-0.007
-0.009
-0.007
-0.002
-0.003
0.000
-0.001
0.000
-0.001
0.003
-0.004
-0.003
-0.005
0.002
0.001
0.003
-0.001
0.005
0.002
-0.002
-0.002
0.001
0.001
0.002
0.000
0.001
0.001
0.006
0.004
0.002
0.003
0.002
0.006
0.003
0.002
0.001
0.005
0.002
0.005
0.003
0.005
0.003
0.003
0.001
0.002
0.003
0.002
0.013
0.011
0.007
0.009
0.007
0.002
0.003
0.000
0.001
0.000
0.001
0.003
0.004
0.003
0.005
0.002
0.001
0.003
0.001
0.005
0.002
0.002
0.002
003542
10/12/09 02:38:24
10/12/09 02:38:26
10/12/09 02:38:28
10/12/09 02:38:30
10/12/09 02:38:32
10/12/09 02:38:34
10/12/09 02:38:36
10/12/09 02:38:38
10/12/09 02:38:40
10/12/09 02:38:42
10/12/09 02:38:44
10/12/09 02:38:46
10/12/09 02:38:48
10/12/09 02:38:50
10/12/09 02:38:52
10/12/09 02:38:54
10/12/09 02:38:56
10/12/09 02:38:58
10/12/09 02:39:00
10/12/09 02:39:02
10/12/09 02:39:04
10/12/09 02:39:06
10/12/09 02:39:08
10/12/09 02:39:10
10/12/09 02:39:12
10/12/09 02:39:14
10/12/09 02:39:16
10/12/09 02:39:18
10/12/09 02:39:20
10/12/09 02:39:22
10/12/09 02:39:24
10/12/09 02:39:26
10/12/09 02:39:28
10/12/09 02:39:30
10/12/09 02:39:32
10/12/09 02:39:34
10/12/09 02:39:36
10/12/09 02:39:38
10/12/09 02:39:40
10/12/09 02:39:42
10/12/09 02:39:44
10/12/09 02:39:46
10/12/09 02:39:48
10/12/09 02:39:50
10/12/09 02:39:52
10/12/09 02:39:54
10/12/09 02:39:56
10/12/09 02:39:58
10/12/09 02:40:00
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
3759.627
3758.522
3752.429
3750.102
3753.83
3753.51
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.37
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.65
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
396
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
413
413.5
414
414.5
415
415.5
416
416.5
417
417.5
418
418.5
419
419.5
420
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
-0.002
-0.006
0.002
0.000
0.005
0.004
-0.001
-0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
-0.002
-0.001
-0.002
0.001
-0.002
0.000
0.002
0.001
-0.001
-0.002
-0.002
-0.004
-0.001
-0.002
0.005
0.001
0.001
-0.004
-0.003
0.002
0.003
-0.002
0.000
0.000
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
0.002
0.006
0.002
0.000
0.005
0.004
0.001
0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
0.002
0.001
0.002
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.002
0.004
0.001
0.002
0.005
0.001
0.001
0.004
0.003
0.002
0.003
0.002
0.000
0.000
003543
10/12/09 02:40:02
10/12/09 02:40:04
10/12/09 02:40:06
10/12/09 02:40:08
10/12/09 02:40:10
10/12/09 02:40:12
10/12/09 02:40:14
10/12/09 02:40:16
10/12/09 02:40:18
10/12/09 02:40:20
10/12/09 02:40:22
10/12/09 02:40:24
10/12/09 02:40:26
10/12/09 02:40:28
10/12/09 02:40:30
10/12/09 02:40:32
10/12/09 02:40:34
10/12/09 02:40:36
10/12/09 02:40:38
10/12/09 02:40:40
10/12/09 02:40:42
10/12/09 02:40:44
10/12/09 02:40:46
10/12/09 02:40:48
10/12/09 02:40:50
10/12/09 02:40:52
10/12/09 02:40:54
10/12/09 02:40:56
10/12/09 02:40:58
10/12/09 02:41:00
10/12/09 02:41:02
10/12/09 02:41:04
10/12/09 02:41:06
10/12/09 02:41:08
10/12/09 02:41:10
10/12/09 02:41:12
10/12/09 02:41:14
10/12/09 02:41:16
10/12/09 02:41:18
10/12/09 02:41:20
10/12/09 02:41:22
10/12/09 02:41:24
10/12/09 02:41:26
10/12/09 02:41:28
10/12/09 02:41:30
10/12/09 02:41:32
10/12/09 02:41:34
10/12/09 02:41:36
10/12/09 02:41:38
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.86
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.34
3750.7
3749.75
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.83
3737.583
3736.229
3734.897
3733.434
3733.115
3730.51
3729.18
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
437.5
438
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.005
-0.004
-0.002
-0.003
0.001
0.003
0.000
0.001
0.001
0.002
-0.004
-0.003
-0.003
0.000
0.000
0.001
-0.004
-0.002
0.000
0.005
0.002
-0.001
-0.003
0.003
0.002
-0.001
-0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
-0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.005
0.005
0.004
0.002
0.003
0.001
0.003
0.000
0.001
0.001
0.002
0.004
0.003
0.003
0.000
0.000
0.001
0.004
0.002
0.000
0.005
0.002
0.001
0.003
0.003
0.002
0.001
0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
003544
10/12/09 02:41:40
10/12/09 02:41:42
10/12/09 02:41:44
10/12/09 02:41:46
10/12/09 02:41:48
10/12/09 02:41:50
10/12/09 02:41:52
10/12/09 02:41:54
10/12/09 02:41:56
10/12/09 02:41:58
10/12/09 02:42:00
10/12/09 02:42:02
10/12/09 02:42:04
10/12/09 02:42:06
10/12/09 02:42:08
10/12/09 02:42:10
10/12/09 02:42:12
10/12/09 02:42:14
10/12/09 02:42:16
10/12/09 02:42:18
10/12/09 02:42:20
10/12/09 02:42:22
10/12/09 02:42:24
10/12/09 02:42:26
10/12/09 02:42:28
10/12/09 02:42:30
10/12/09 02:42:32
10/12/09 02:42:34
10/12/09 02:42:36
10/12/09 02:42:38
10/12/09 02:42:40
10/12/09 02:42:42
10/12/09 02:42:44
10/12/09 02:42:46
10/12/09 02:42:48
10/12/09 02:42:50
10/12/09 02:42:52
10/12/09 02:42:54
10/12/09 02:42:56
10/12/09 02:42:58
10/12/09 02:43:00
10/12/09 02:43:02
10/12/09 02:43:04
10/12/09 02:43:06
10/12/09 02:43:08
10/12/09 02:43:10
10/12/09 02:43:12
10/12/09 02:43:14
10/12/09 02:43:16
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
60.043
60.045
60.04
60.041
60.039
60.039
60.036
60.038
60.033
60.034
60.037
60.037
60.035
60.03
60.033
60.036
60.033
60.034
60.032
60.032
60.034
60.033
60.037
60.035
60.035
60.036
3726.016
3719.123
3716.375
3717.333
3717.56
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.1
3690.477
3696.865
3696.877
3696.182
3696.541
3696.968
3698.686
3699.631
3698.787
3699.712
3700.106
3699.968
3701.122
3701.865
3701.614
3701.998
3702.913
3703.909
3705.522
3704.967
3704.087
3702.771
3703.706
3704.905
3705.435
3704.36
3702.588
3702.204
3701.942
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
450.5
451
451.5
452
452.5
453
453.5
454
454.5
455
455.5
456
456.5
457
457.5
458
458.5
459
459.5
460
460.5
461
461.5
462
462.5
463
463.5
464
464.5
465
465.5
466
466.5
467
467.5
468
468.5
469
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.3
7800.63
7800.96
7801.29
7801.62
7801.95
7802.28
7802.61
7802.94
7803.27
7803.6
7803.93
7804.26
7804.59
7804.92
7805.25
7805.58
7805.91
7806.24
7806.57
7806.9
7807.23
7807.56
7807.89
7808.22
7808.55
7808.88
7809.21
7809.54
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.004
0.001
0.001
0.002
0.000
0.008
-0.001
0.001
0.000
-0.001
0.005
0.002
0.001
-0.001
0.003
0.002
-0.002
0.000
-0.003
0.000
0.001
-0.001
0.000
0.002
-0.005
0.001
-0.002
0.000
-0.003
0.002
-0.005
0.001
0.003
0.000
-0.002
-0.005
0.003
0.003
-0.003
0.001
-0.002
0.000
0.002
-0.001
0.004
-0.002
0.000
0.001
0.002
0.004
0.001
0.001
0.002
0.000
0.008
0.001
0.001
0.000
0.001
0.005
0.002
0.001
0.001
0.003
0.002
0.002
0.000
0.003
0.000
0.001
0.001
0.000
0.002
0.005
0.001
0.002
0.000
0.003
0.002
0.005
0.001
0.003
0.000
0.002
0.005
0.003
0.003
0.003
0.001
0.002
0.000
0.002
0.001
0.004
0.002
0.000
0.001
003545
10/12/09 02:43:18
10/12/09 02:43:20
10/12/09 02:43:22
10/12/09 02:43:24
10/12/09 02:43:26
10/12/09 02:43:28
10/12/09 02:43:30
10/12/09 02:43:32
10/12/09 02:43:34
10/12/09 02:43:36
10/12/09 02:43:38
10/12/09 02:43:40
10/12/09 02:43:42
10/12/09 02:43:44
10/12/09 02:43:46
10/12/09 02:43:48
10/12/09 02:43:50
10/12/09 02:43:52
10/12/09 02:43:54
10/12/09 02:43:56
10/12/09 02:43:58
10/12/09 02:44:00
10/12/09 02:44:02
10/12/09 02:44:04
10/12/09 02:44:06
10/12/09 02:44:08
10/12/09 02:44:10
10/12/09 02:44:12
10/12/09 02:44:14
10/12/09 02:44:16
10/12/09 02:44:18
10/12/09 02:44:20
10/12/09 02:44:22
10/12/09 02:44:24
10/12/09 02:44:26
10/12/09 02:44:28
10/12/09 02:44:30
10/12/09 02:44:32
10/12/09 02:44:34
10/12/09 02:44:36
10/12/09 02:44:38
10/12/09 02:44:40
10/12/09 02:44:42
10/12/09 02:44:44
10/12/09 02:44:46
10/12/09 02:44:48
10/12/09 02:44:50
10/12/09 02:44:52
10/12/09 02:44:54
60.039
60.037
60.039
60.036
60.034
60.038
60.037
60.037
60.037
60.038
60.04
60.043
60.045
60.045
60.042
60.043
60.04
60.044
60.046
60.042
60.034
60.039
60.039
60.036
60.037
60.034
60.033
60.032
60.031
60.033
60.027
60.031
60.032
60.031
60.031
60.033
60.039
60.039
60.038
60.037
60.035
60.037
60.04
60.042
60.035
60.036
60.04
60.045
60.045
3702.25
3703.318
3702.457
3702.525
3703.269
3703.844
3702.865
3702.518
3702.28
3692.427
3692.178
3700.276
3698.755
3697.729
3696.916
3697.368
3697.346
3698.429
3694.763
3693.584
3693.241
3696.798
3699.364
3701.791
3700.708
3700.753
3702.148
3705.213
3707.521
3707.287
3706.988
3707.34
3707.917
3707.384
3706.857
3707.615
3706.823
3703.746
3701.582
3700.847
3701.208
3702.212
3701.686
3700.397
3699.69
3700.366
3700.827
3700.662
3696.935
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
469.5
470
470.5
471
471.5
472
472.5
473
473.5
474
474.5
475
475.5
476
476.5
477
477.5
478
478.5
479
479.5
480
480.5
481
481.5
482
482.5
483
483.5
484
484.5
485
485.5
486
486.5
487
487.5
488
488.5
489
489.5
490
490.5
491
491.5
492
492.5
493
493.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7809.87
7810.2
7810.53
7810.86
7811.19
7811.52
7811.85
7812.18
7812.51
7812.84
7813.17
7813.5
7813.83
7814.16
7814.49
7814.82
7815.15
7815.48
7815.81
7816.14
7816.47
7816.8
7817.13
7817.46
7817.79
7818.12
7818.45
7818.78
7819.11
7819.44
7819.77
7820.1
7820.43
7820.76
7821.09
7821.42
7821.75
7822.08
7822.41
7822.74
7823.07
7823.4
7823.73
7824.06
7824.39
7824.72
7825.05
7825.38
7825.71
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.002
0.002
-0.003
-0.002
0.004
-0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
-0.003
0.001
-0.003
0.004
0.002
-0.004
-0.008
0.005
0.000
-0.003
0.001
-0.003
-0.001
-0.001
-0.001
0.002
-0.006
0.004
0.001
-0.001
0.000
0.002
0.006
0.000
-0.001
-0.001
-0.002
0.002
0.003
0.002
-0.007
0.001
0.004
0.005
0.000
0.003
0.002
0.002
0.003
0.002
0.004
0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.004
0.008
0.005
0.000
0.003
0.001
0.003
0.001
0.001
0.001
0.002
0.006
0.004
0.001
0.001
0.000
0.002
0.006
0.000
0.001
0.001
0.002
0.002
0.003
0.002
0.007
0.001
0.004
0.005
0.000
003546
10/12/09 02:44:56
10/12/09 02:44:58
10/12/09 02:45:00
10/12/09 02:45:02
10/12/09 02:45:04
10/12/09 02:45:06
10/12/09 02:45:08
10/12/09 02:45:10
10/12/09 02:45:12
10/12/09 02:45:14
10/12/09 02:45:16
10/12/09 02:45:18
10/12/09 02:45:20
10/12/09 02:45:22
10/12/09 02:45:24
10/12/09 02:45:26
10/12/09 02:45:28
10/12/09 02:45:30
10/12/09 02:45:32
10/12/09 02:45:34
10/12/09 02:45:36
10/12/09 02:45:38
10/12/09 02:45:40
10/12/09 02:45:42
10/12/09 02:45:44
10/12/09 02:45:46
10/12/09 02:45:48
10/12/09 02:45:50
10/12/09 02:45:52
10/12/09 02:45:54
10/12/09 02:45:56
10/12/09 02:45:58
10/12/09 02:46:00
10/12/09 02:46:02
10/12/09 02:46:04
10/12/09 02:46:06
10/12/09 02:46:08
10/12/09 02:46:10
10/12/09 02:46:12
10/12/09 02:46:14
10/12/09 02:46:16
10/12/09 02:46:18
10/12/09 02:46:20
10/12/09 02:46:22
10/12/09 02:46:24
10/12/09 02:46:26
10/12/09 02:46:28
10/12/09 02:46:30
10/12/09 02:46:32
60.048
60.042
60.044
60.044
60.044
60.041
60.04
60.04
60.045
60.044
60.042
60.039
60.042
60.042
60.041
60.038
60.036
60.037
60.039
60.038
60.04
60.039
60.037
60.038
60.039
60.04
60.037
60.037
60.037
60.039
60.038
60.036
60.035
60.033
60.031
60.03
60.032
60.032
60.037
60.042
60.041
60.036
60.031
60.032
60.031
60.034
60.034
60.032
60.038
3695.688
3695.819
3693.824
3694.799
3696.897
3696.023
3697.502
3698.424
3699.427
3700.177
3699.806
3697.577
3697.681
3698.507
3698.359
3698.466
3699.077
3700.262
3701.592
3700.902
3700.143
3700.27
3701.139
3701.586
3700.264
3699.458
3699.721
3700.458
3699.505
3698.794
3699.216
3699.4
3700.661
3702.173
3702.968
3705.195
3704.952
3705.775
3705.621
3703.744
3701.981
3700.756
3700.747
3702.213
3705.059
3705.514
3704.449
3703.831
3703.62
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
494
494.5
495
495.5
496
496.5
497
497.5
498
498.5
499
499.5
500
500.5
501
501.5
502
502.5
503
503.5
504
504.5
505
505.5
506
506.5
507
507.5
508
508.5
509
509.5
510
510.5
511
511.5
512
512.5
513
513.5
514
514.5
515
515.5
516
516.5
517
517.5
518
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7826.04
7826.37
7826.7
7827.03
7827.36
7827.69
7828.02
7828.35
7828.68
7829.01
7829.34
7829.67
7830
7830.33
7830.66
7830.99
7831.32
7831.65
7831.98
7832.31
7832.64
7832.97
7833.3
7833.63
7833.96
7834.29
7834.62
7834.95
7835.28
7835.61
7835.94
7836.27
7836.6
7836.93
7837.26
7837.59
7837.92
7838.25
7838.58
7838.91
7839.24
7839.57
7839.9
7840.23
7840.56
7840.89
7841.22
7841.55
7841.88
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.006
0.002
0.000
0.000
-0.003
-0.001
0.000
0.005
-0.001
-0.002
-0.003
0.003
0.000
-0.001
-0.003
-0.002
0.001
0.002
-0.001
0.002
-0.001
-0.002
0.001
0.001
0.001
-0.003
0.000
0.000
0.002
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.002
0.000
0.005
0.005
-0.001
-0.005
-0.005
0.001
-0.001
0.003
0.000
-0.002
0.006
0.003
0.006
0.002
0.000
0.000
0.003
0.001
0.000
0.005
0.001
0.002
0.003
0.003
0.000
0.001
0.003
0.002
0.001
0.002
0.001
0.002
0.001
0.002
0.001
0.001
0.001
0.003
0.000
0.000
0.002
0.001
0.002
0.001
0.002
0.002
0.001
0.002
0.000
0.005
0.005
0.001
0.005
0.005
0.001
0.001
0.003
0.000
0.002
0.006
003547
10/12/09 02:46:34
10/12/09 02:46:36
10/12/09 02:46:38
10/12/09 02:46:40
10/12/09 02:46:42
10/12/09 02:46:44
10/12/09 02:46:46
10/12/09 02:46:48
10/12/09 02:46:50
10/12/09 02:46:52
10/12/09 02:46:54
10/12/09 02:46:56
10/12/09 02:46:58
10/12/09 02:47:00
10/12/09 02:47:02
10/12/09 02:47:04
10/12/09 02:47:06
10/12/09 02:47:08
10/12/09 02:47:10
10/12/09 02:47:12
10/12/09 02:47:14
10/12/09 02:47:16
10/12/09 02:47:18
10/12/09 02:47:20
10/12/09 02:47:22
10/12/09 02:47:24
10/12/09 02:47:26
10/12/09 02:47:28
10/12/09 02:47:30
10/12/09 02:47:32
10/12/09 02:47:34
10/12/09 02:47:36
10/12/09 02:47:38
10/12/09 02:47:40
10/12/09 02:47:42
10/12/09 02:47:44
10/12/09 02:47:46
10/12/09 02:47:48
10/12/09 02:47:50
10/12/09 02:47:52
10/12/09 02:47:54
10/12/09 02:47:56
10/12/09 02:47:58
10/12/09 02:48:00
10/12/09 02:48:02
10/12/09 02:48:04
10/12/09 02:48:06
10/12/09 02:48:08
10/12/09 02:48:10
60.043
60.044
60.042
60.045
60.04
60.04
60.043
60.043
60.041
60.04
60.038
60.043
60.044
60.042
60.036
60.043
60.041
60.042
60.043
60.043
60.036
60.039
60.039
60.037
60.034
60.035
60.035
60.035
60.036
60.03
60.03
60.03
60.031
60.031
60.032
60.031
60.032
60.032
60.032
60.033
60.037
60.04
60.039
60.042
60.036
60.039
60.041
60.04
60.035
3702.795
3701.432
3697.38
3696.25
3696.302
3693.518
3693.577
3695.197
3695.186
3693.786
3694.753
3694.926
3694.938
3694.159
3691.33
3692.686
3693.238
3693.39
3692.357
3690.951
3690.836
3692.042
3693.114
3694.117
3695.258
3695.581
3695.949
3695.491
3696.305
3696.486
3697.336
3699.171
3699.357
3699.251
3699.117
3699.105
3699.126
3698.954
3698.136
3698.277
3697.412
3695.94
3693.736
3693.224
3691.759
3691.919
3692.798
3691.582
3692.374
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
518.5
519
519.5
520
520.5
521
521.5
522
522.5
523
523.5
524
524.5
525
525.5
526
526.5
527
527.5
528
528.5
529
529.5
530
530.5
531
531.5
532
532.5
533
533.5
534
534.5
535
535.5
536
536.5
537
537.5
538
538.5
539
539.5
540
540.5
541
541.5
542
542.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7842.21
7842.54
7842.87
7843.2
7843.53
7843.86
7844.19
7844.52
7844.85
7845.18
7845.51
7845.84
7846.17
7846.5
7846.83
7847.16
7847.49
7847.82
7848.15
7848.48
7848.81
7849.14
7849.47
7849.8
7850.13
7850.46
7850.79
7851.12
7851.45
7851.78
7852.11
7852.44
7852.77
7853.1
7853.43
7853.76
7854.09
7854.42
7854.75
7855.08
7855.41
7855.74
7856.07
7856.4
7856.73
7857.06
7857.39
7857.72
7858.05
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.001
-0.002
0.003
-0.005
0.000
0.003
0.000
-0.002
-0.001
-0.002
0.005
0.001
-0.002
-0.006
0.007
-0.002
0.001
0.001
0.000
-0.007
0.003
0.000
-0.002
-0.003
0.001
0.000
0.000
0.001
-0.006
0.000
0.000
0.001
0.000
0.001
-0.001
0.001
0.000
0.000
0.001
0.004
0.003
-0.001
0.003
-0.006
0.003
0.002
-0.001
-0.005
0.005
0.001
0.002
0.003
0.005
0.000
0.003
0.000
0.002
0.001
0.002
0.005
0.001
0.002
0.006
0.007
0.002
0.001
0.001
0.000
0.007
0.003
0.000
0.002
0.003
0.001
0.000
0.000
0.001
0.006
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.004
0.003
0.001
0.003
0.006
0.003
0.002
0.001
0.005
003548
10/12/09 02:48:12
10/12/09 02:48:14
10/12/09 02:48:16
10/12/09 02:48:18
10/12/09 02:48:20
10/12/09 02:48:22
10/12/09 02:48:24
10/12/09 02:48:26
10/12/09 02:48:28
10/12/09 02:48:30
10/12/09 02:48:32
10/12/09 02:48:34
10/12/09 02:48:36
10/12/09 02:48:38
10/12/09 02:48:40
10/12/09 02:48:42
10/12/09 02:48:44
10/12/09 02:48:46
10/12/09 02:48:48
10/12/09 02:48:50
10/12/09 02:48:52
10/12/09 02:48:54
10/12/09 02:48:56
10/12/09 02:48:58
10/12/09 02:49:00
10/12/09 02:49:02
10/12/09 02:49:04
10/12/09 02:49:06
10/12/09 02:49:08
10/12/09 02:49:10
10/12/09 02:49:12
10/12/09 02:49:14
10/12/09 02:49:16
10/12/09 02:49:18
10/12/09 02:49:20
10/12/09 02:49:22
10/12/09 02:49:24
10/12/09 02:49:26
10/12/09 02:49:28
10/12/09 02:49:30
10/12/09 02:49:32
10/12/09 02:49:34
10/12/09 02:49:36
10/12/09 02:49:38
10/12/09 02:49:40
10/12/09 02:49:42
10/12/09 02:49:44
10/12/09 02:49:46
10/12/09 02:49:48
60.036
60.038
60.037
60.041
60.04
60.036
60.033
60.034
60.038
60.04
60.041
60.037
60.037
60.036
60.037
60.038
60.039
60.038
60.034
60.033
60.031
60.034
60.029
60.029
60.031
60.03
60.03
60.026
60.022
60.021
60.024
60.023
60.02
60.021
60.023
60.025
60.026
60.026
60.025
60.024
60.024
60.025
60.023
60.023
60.022
60.026
60.029
60.026
60.024
3693.302
3694.71
3694.331
3693.815
3693.617
3694.324
3694.27
3694.66
3693.748
3692.532
3691.445
3691.012
3691.799
3693.077
3693.727
3693.117
3692.641
3688.159
3689.02
3688.208
3690.092
3693.172
3693.321
3694.593
3695.225
3694.609
3693.412
3693.509
3696.026
3698.012
3699.062
3699.414
3698.935
3700.084
3700.544
3700.486
3698.596
3697.961
3699.914
3700.802
3701.301
3701.45
3701.349
3701.094
3701.702
3702.07
3701.965
3700.269
3700.241
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
543
543.5
544
544.5
545
545.5
546
546.5
547
547.5
548
548.5
549
549.5
550
550.5
551
551.5
552
552.5
553
553.5
554
554.5
555
555.5
556
556.5
557
557.5
558
558.5
559
559.5
560
560.5
561
561.5
562
562.5
563
563.5
564
564.5
565
565.5
566
566.5
567
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7858.38
7858.71
7859.04
7859.37
7859.7
7860.03
7860.36
7860.69
7861.02
7861.35
7861.68
7862.01
7862.34
7862.67
7863
7863.33
7863.66
7863.99
7864.32
7864.65
7864.98
7865.31
7865.64
7865.97
7866.3
7866.63
7866.96
7867.29
7867.62
7867.95
7868.28
7868.61
7868.94
7869.27
7869.6
7869.93
7870.26
7870.59
7870.92
7871.25
7871.58
7871.91
7872.24
7872.57
7872.9
7873.23
7873.56
7873.89
7874.22
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.002
-0.001
0.004
-0.001
-0.004
-0.003
0.001
0.004
0.002
0.001
-0.004
0.000
-0.001
0.001
0.001
0.001
-0.001
-0.004
-0.001
-0.002
0.003
-0.005
0.000
0.002
-0.001
0.000
-0.004
-0.004
-0.001
0.003
-0.001
-0.003
0.001
0.002
0.002
0.001
0.000
-0.001
-0.001
0.000
0.001
-0.002
0.000
-0.001
0.004
0.003
-0.003
-0.002
0.001
0.002
0.001
0.004
0.001
0.004
0.003
0.001
0.004
0.002
0.001
0.004
0.000
0.001
0.001
0.001
0.001
0.001
0.004
0.001
0.002
0.003
0.005
0.000
0.002
0.001
0.000
0.004
0.004
0.001
0.003
0.001
0.003
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.003
0.003
0.002
003549
10/12/09 02:49:50
10/12/09 02:49:52
10/12/09 02:49:54
10/12/09 02:49:56
10/12/09 02:49:58
10/12/09 02:50:00
10/12/09 02:50:02
10/12/09 02:50:04
10/12/09 02:50:06
10/12/09 02:50:08
10/12/09 02:50:10
10/12/09 02:50:12
10/12/09 02:50:14
10/12/09 02:50:16
10/12/09 02:50:18
10/12/09 02:50:20
10/12/09 02:50:22
10/12/09 02:50:24
10/12/09 02:50:26
10/12/09 02:50:28
10/12/09 02:50:30
10/12/09 02:50:32
10/12/09 02:50:34
10/12/09 02:50:36
10/12/09 02:50:38
10/12/09 02:50:40
10/12/09 02:50:42
10/12/09 02:50:44
10/12/09 02:50:46
10/12/09 02:50:48
10/12/09 02:50:50
10/12/09 02:50:52
10/12/09 02:50:54
10/12/09 02:50:56
10/12/09 02:50:58
10/12/09 02:51:00
10/12/09 02:51:02
10/12/09 02:51:04
10/12/09 02:51:06
10/12/09 02:51:08
10/12/09 02:51:10
10/12/09 02:51:12
10/12/09 02:51:14
10/12/09 02:51:16
10/12/09 02:51:18
10/12/09 02:51:20
10/12/09 02:51:22
10/12/09 02:51:24
10/12/09 02:51:26
60.021
60.025
60.025
60.025
60.023
60.026
60.024
60.022
60.023
60.026
60.025
60.02
60.02
60.019
60.015
60.016
60.017
60.015
60.015
60.017
60.017
60.012
60.01
60.008
60.002
59.999
59.999
60.002
60.003
60.004
60.001
59.996
59.993
59.992
59.989
59.987
59.985
59.985
59.986
59.984
59.981
59.98
59.977
59.975
59.976
59.972
59.974
59.977
59.975
3701.09
3701.268
3701.205
3700.587
3700.532
3700.177
3700.295
3700.277
3700.841
3700.863
3700.26
3700.052
3699.926
3700.965
3702.581
3703.516
3703.824
3703.672
3703.689
3703.003
3702.921
3703
3703.167
3703.918
3703.616
3703.775
3703.751
3701.534
3700.617
3700.88
3700.625
3701.389
3701.737
3700.671
3700.826
3700.977
3700.7
3699.854
3700.237
3700.342
3700.77
3700.789
3701.625
3703.166
3704.187
3704.785
3705.811
3706.958
3706.688
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
567.5
568
568.5
569
569.5
570
570.5
571
571.5
572
572.5
573
573.5
574
574.5
575
575.5
576
576.5
577
577.5
578
578.5
579
579.5
580
580.5
581
581.5
582
582.5
583
583.5
584
584.5
585
585.5
586
586.5
587
587.5
588
588.5
589
589.5
590
590.5
591
591.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7874.55
7874.88
7875.21
7875.54
7875.87
7876.2
7876.53
7876.86
7877.19
7877.52
7877.85
7878.18
7878.51
7878.84
7879.17
7879.5
7879.83
7880.16
7880.49
7880.82
7881.15
7881.48
7881.81
7882.14
7882.47
7882.8
7883.13
7883.46
7883.79
7884.12
7884.45
7884.78
7885.11
7885.44
7885.77
7886.1
7886.43
7886.76
7887.09
7887.42
7887.75
7888.08
7888.41
7888.74
7889.07
7889.4
7889.73
7890.06
7890.39
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
0.004
0.000
0.000
-0.002
0.003
-0.002
-0.002
0.001
0.003
-0.001
-0.005
0.000
-0.001
-0.004
0.001
0.001
-0.002
0.000
0.002
0.000
-0.005
-0.002
-0.002
-0.006
-0.003
0.000
0.003
0.001
0.001
-0.003
-0.005
-0.003
-0.001
-0.003
-0.002
-0.002
0.000
0.001
-0.002
-0.003
-0.001
-0.003
-0.002
0.001
-0.004
0.002
0.003
-0.002
0.003
0.004
0.000
0.000
0.002
0.003
0.002
0.002
0.001
0.003
0.001
0.005
0.000
0.001
0.004
0.001
0.001
0.002
0.000
0.002
0.000
0.005
0.002
0.002
0.006
0.003
0.000
0.003
0.001
0.001
0.003
0.005
0.003
0.001
0.003
0.002
0.002
0.000
0.001
0.002
0.003
0.001
0.003
0.002
0.001
0.004
0.002
0.003
0.002
003550
10/12/09 02:51:28
10/12/09 02:51:30
10/12/09 02:51:32
10/12/09 02:51:34
10/12/09 02:51:36
10/12/09 02:51:38
10/12/09 02:51:40
10/12/09 02:51:42
10/12/09 02:51:44
10/12/09 02:51:46
10/12/09 02:51:48
10/12/09 02:51:50
10/12/09 02:51:52
10/12/09 02:51:54
10/12/09 02:51:56
10/12/09 02:51:58
10/12/09 02:52:00
10/12/09 02:52:02
10/12/09 02:52:04
10/12/09 02:52:06
10/12/09 02:52:08
10/12/09 02:52:10
10/12/09 02:52:12
10/12/09 02:52:14
10/12/09 02:52:16
10/12/09 02:52:18
10/12/09 02:52:20
10/12/09 02:52:22
10/12/09 02:52:24
10/12/09 02:52:26
10/12/09 02:52:28
10/12/09 02:52:30
10/12/09 02:52:32
10/12/09 02:52:34
10/12/09 02:52:36
10/12/09 02:52:38
10/12/09 02:52:40
10/12/09 02:52:42
10/12/09 02:52:44
10/12/09 02:52:46
10/12/09 02:52:48
10/12/09 02:52:50
10/12/09 02:52:52
10/12/09 02:52:54
10/12/09 02:52:56
10/12/09 02:52:58
10/12/09 02:53:00
10/12/09 02:53:02
10/12/09 02:53:04
59.973
59.971
59.971
59.976
59.979
59.98
59.979
59.982
59.982
59.983
59.981
59.979
59.978
59.976
59.978
59.977
59.976
59.978
59.975
59.971
59.97
59.97
59.971
59.99
59.998
59.999
59.999
59.998
59.999
60.003
60.005
60.005
60.01
60.013
60.02
60.022
60.024
60.025
60.025
60.024
60.023
60.029
60.029
60.029
60.028
60.028
60.031
60.032
60.033
3706.543
3706.257
3707.027
3710.118
3710.531
3708.701
3708.018
3706.942
3706.343
3706.125
3706.311
3706.119
3706.19
3707.721
3709.409
3708.971
3708.531
3708.071
3707.24
3709.213
3709.961
3711.75
3711.98
3710.695
3707.867
3704.912
3705.639
3703.787
3703.191
3702.071
3699.51
3698.658
3698.137
3697.882
3698.668
3698.604
3697.868
3694.672
3693.912
3693.418
3688.301
3688.021
3689.143
3688.237
3687.878
3687.026
3686.683
3685.276
3685.576
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
592
592.5
593
593.5
594
594.5
595
595.5
596
596.5
597
597.5
598
598.5
599
599.5
600
600.5
601
601.5
602
602.5
603
603.5
604
604.5
605
605.5
606
606.5
607
607.5
608
608.5
609
609.5
610
610.5
611
611.5
612
612.5
613
613.5
614
614.5
615
615.5
616
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7890.72
7891.05
7891.38
7891.71
7892.04
7892.37
7892.7
7893.03
7893.36
7893.69
7894.02
7894.35
7894.68
7895.01
7895.34
7895.67
7896
7896.33
7896.66
7896.99
7897.32
7897.65
7897.98
7898.31
7898.64
7898.97
7899.3
7899.63
7899.96
7900.29
7900.62
7900.95
7901.28
7901.61
7901.94
7902.27
7902.6
7902.93
7903.26
7903.59
7903.92
7904.25
7904.58
7904.91
7905.24
7905.57
7905.9
7906.23
7906.56
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
0.000
0.005
0.003
0.001
-0.001
0.003
0.000
0.001
-0.002
-0.002
-0.001
-0.002
0.002
-0.001
-0.001
0.002
-0.003
-0.004
-0.001
0.000
0.001
0.019
0.008
0.001
0.000
-0.001
0.001
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
-0.001
-0.001
0.006
0.000
0.000
-0.001
0.000
0.003
0.001
0.001
0.002
0.002
0.000
0.005
0.003
0.001
0.001
0.003
0.000
0.001
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.002
0.003
0.004
0.001
0.000
0.001
0.019
0.008
0.001
0.000
0.001
0.001
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
0.001
0.001
0.006
0.000
0.000
0.001
0.000
0.003
0.001
0.001
003551
10/12/09 02:53:06
10/12/09 02:53:08
10/12/09 02:53:10
10/12/09 02:53:12
10/12/09 02:53:14
10/12/09 02:53:16
10/12/09 02:53:18
10/12/09 02:53:20
10/12/09 02:53:22
10/12/09 02:53:24
10/12/09 02:53:26
10/12/09 02:53:28
10/12/09 02:53:30
10/12/09 02:53:32
10/12/09 02:53:34
10/12/09 02:53:36
10/12/09 02:53:38
10/12/09 02:53:40
10/12/09 02:53:42
10/12/09 02:53:44
10/12/09 02:53:46
10/12/09 02:53:48
10/12/09 02:53:50
10/12/09 02:53:52
10/12/09 02:53:54
10/12/09 02:53:56
10/12/09 02:53:58
10/12/09 02:54:00
10/12/09 02:54:02
10/12/09 02:54:04
10/12/09 02:54:06
10/12/09 02:54:08
10/12/09 02:54:10
10/12/09 02:54:12
10/12/09 02:54:14
10/12/09 02:54:16
10/12/09 02:54:18
10/12/09 02:54:20
10/12/09 02:54:22
10/12/09 02:54:24
10/12/09 02:54:26
10/12/09 02:54:28
10/12/09 02:54:30
10/12/09 02:54:32
10/12/09 02:54:34
10/12/09 02:54:36
10/12/09 02:54:38
10/12/09 02:54:40
10/12/09 02:54:42
60.031
60.03
60.022
60.021
60.019
60.017
60.017
60.017
60.016
60.015
60.015
60.012
60.009
60.008
60.008
60.005
60.005
60.003
59.999
59.997
59.999
60
59.998
59.995
59.994
59.992
59.993
59.988
59.985
59.986
59.988
59.988
59.985
59.983
59.983
59.985
59.986
59.987
59.99
59.986
59.985
59.984
59.983
59.982
59.982
59.98
59.978
59.977
59.975
3685.985
3686.418
3687.159
3687.873
3688.997
3690.426
3690.776
3692.715
3692.578
3692.462
3693.173
3693.249
3693.743
3695.124
3694.681
3694.741
3694.199
3693.75
3693.624
3692.806
3691.15
3691.407
3691.077
3690.588
3689.797
3688.483
3689.445
3689.553
3689.525
3689.736
3688.853
3688.24
3687.494
3687.475
3686.707
3685.66
3684.51
3684.333
3683.911
3683.735
3684.208
3683.811
3683.473
3684.258
3684.884
3685.092
3685.654
3685.087
3685.491
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
616.5
617
617.5
618
618.5
619
619.5
620
620.5
621
621.5
622
622.5
623
623.5
624
624.5
625
625.5
626
626.5
627
627.5
628
628.5
629
629.5
630
630.5
631
631.5
632
632.5
633
633.5
634
634.5
635
635.5
636
636.5
637
637.5
638
638.5
639
639.5
640
640.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7906.89
7907.22
7907.55
7907.88
7908.21
7908.54
7908.87
7909.2
7909.53
7909.86
7910.19
7910.52
7910.85
7911.18
7911.51
7911.84
7912.17
7912.5
7912.83
7913.16
7913.49
7913.82
7914.15
7914.48
7914.81
7915.14
7915.47
7915.8
7916.13
7916.46
7916.79
7917.12
7917.45
7917.78
7918.11
7918.44
7918.77
7919.1
7919.43
7919.76
7920.09
7920.42
7920.75
7921.08
7921.41
7921.74
7922.07
7922.4
7922.73
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
-0.008
-0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.001
0.000
-0.003
-0.003
-0.001
0.000
-0.003
0.000
-0.002
-0.004
-0.002
0.002
0.001
-0.002
-0.003
-0.001
-0.002
0.001
-0.005
-0.003
0.001
0.002
0.000
-0.003
-0.002
0.000
0.002
0.001
0.001
0.003
-0.004
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
-0.001
-0.002
0.002
0.001
0.008
0.001
0.002
0.002
0.000
0.000
0.001
0.001
0.000
0.003
0.003
0.001
0.000
0.003
0.000
0.002
0.004
0.002
0.002
0.001
0.002
0.003
0.001
0.002
0.001
0.005
0.003
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.001
0.001
0.003
0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.002
003552
10/12/09 02:54:44
10/12/09 02:54:46
10/12/09 02:54:48
10/12/09 02:54:50
10/12/09 02:54:52
10/12/09 02:54:54
10/12/09 02:54:56
10/12/09 02:54:58
10/12/09 02:55:00
10/12/09 02:55:02
10/12/09 02:55:04
10/12/09 02:55:06
10/12/09 02:55:08
10/12/09 02:55:10
10/12/09 02:55:12
10/12/09 02:55:14
10/12/09 02:55:16
10/12/09 02:55:18
10/12/09 02:55:20
10/12/09 02:55:22
10/12/09 02:55:24
10/12/09 02:55:26
10/12/09 02:55:28
10/12/09 02:55:30
10/12/09 02:55:32
10/12/09 02:55:34
10/12/09 02:55:36
10/12/09 02:55:38
10/12/09 02:55:40
10/12/09 02:55:42
10/12/09 02:55:44
10/12/09 02:55:46
10/12/09 02:55:48
10/12/09 02:55:50
10/12/09 02:55:52
10/12/09 02:55:54
10/12/09 02:55:56
10/12/09 02:55:58
10/12/09 02:56:00
10/12/09 02:56:02
10/12/09 02:56:04
10/12/09 02:56:06
10/12/09 02:56:08
10/12/09 02:56:10
10/12/09 02:56:12
10/12/09 02:56:14
10/12/09 02:56:16
10/12/09 02:56:18
10/12/09 02:56:20
59.973
59.975
59.976
59.976
59.979
59.982
59.979
59.979
59.977
59.977
59.978
59.978
59.978
59.979
59.983
59.981
59.98
59.978
59.979
59.978
59.979
59.983
59.987
59.99
59.992
59.993
59.99
59.988
59.988
59.99
59.993
59.994
59.993
59.994
59.994
59.993
59.989
59.984
59.986
59.985
59.988
59.987
59.986
59.987
59.985
59.982
59.981
59.982
59.987
3685.196
3687.412
3688.417
3688.599
3687.848
3686.678
3685.782
3684.89
3685.143
3684.549
3684.093
3684.555
3682.814
3682.318
3682.366
3682.647
3682.855
3683.557
3684.052
3684.318
3686.049
3686.629
3685.286
3683.415
3682.416
3681.403
3679.012
3679.436
3671.761
3670.717
3670.159
3679
3680.176
3681.799
3682.7
3684.116
3685.03
3684.878
3684.165
3684.478
3685.584
3685.148
3684.587
3684.976
3683.674
3684.872
3684.245
3684.711
3685.589
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
641
641.5
642
642.5
643
643.5
644
644.5
645
645.5
646
646.5
647
647.5
648
648.5
649
649.5
650
650.5
651
651.5
652
652.5
653
653.5
654
654.5
655
655.5
656
656.5
657
657.5
658
658.5
659
659.5
660
660.5
661
661.5
662
662.5
663
663.5
664
664.5
665
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7923.06
7923.39
7923.72
7924.05
7924.38
7924.71
7925.04
7925.37
7925.7
7926.03
7926.36
7926.69
7927.02
7927.35
7927.68
7928.01
7928.34
7928.67
7929
7929.33
7929.66
7929.99
7930.32
7930.65
7930.98
7931.31
7931.64
7931.97
7932.3
7932.63
7932.96
7933.29
7933.62
7933.95
7934.28
7934.61
7934.94
7935.27
7935.6
7935.93
7936.26
7936.59
7936.92
7937.25
7937.58
7937.91
7938.24
7938.57
7938.9
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
0.002
0.001
0.000
0.003
0.003
-0.003
0.000
-0.002
0.000
0.001
0.000
0.000
0.001
0.004
-0.002
-0.001
-0.002
0.001
-0.001
0.001
0.004
0.004
0.003
0.002
0.001
-0.003
-0.002
0.000
0.002
0.003
0.001
-0.001
0.001
0.000
-0.001
-0.004
-0.005
0.002
-0.001
0.003
-0.001
-0.001
0.001
-0.002
-0.003
-0.001
0.001
0.005
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.000
0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.001
0.004
0.004
0.003
0.002
0.001
0.003
0.002
0.000
0.002
0.003
0.001
0.001
0.001
0.000
0.001
0.004
0.005
0.002
0.001
0.003
0.001
0.001
0.001
0.002
0.003
0.001
0.001
0.005
003553
10/12/09 02:56:22
10/12/09 02:56:24
10/12/09 02:56:26
10/12/09 02:56:28
10/12/09 02:56:30
10/12/09 02:56:32
10/12/09 02:56:34
10/12/09 02:56:36
10/12/09 02:56:38
10/12/09 02:56:40
10/12/09 02:56:42
10/12/09 02:56:44
10/12/09 02:56:46
10/12/09 02:56:48
10/12/09 02:56:50
10/12/09 02:56:52
10/12/09 02:56:54
10/12/09 02:56:56
10/12/09 02:56:58
10/12/09 02:57:00
10/12/09 02:57:02
10/12/09 02:57:04
10/12/09 02:57:06
10/12/09 02:57:08
10/12/09 02:57:10
10/12/09 02:57:12
10/12/09 02:57:14
10/12/09 02:57:16
10/12/09 02:57:18
10/12/09 02:57:20
10/12/09 02:57:22
10/12/09 02:57:24
10/12/09 02:57:26
10/12/09 02:57:28
10/12/09 02:57:30
10/12/09 02:57:32
10/12/09 02:57:34
10/12/09 02:57:36
10/12/09 02:57:38
10/12/09 02:57:40
10/12/09 02:57:42
10/12/09 02:57:44
10/12/09 02:57:46
10/12/09 02:57:48
10/12/09 02:57:50
10/12/09 02:57:52
10/12/09 02:57:54
10/12/09 02:57:56
10/12/09 02:57:58
59.992
59.997
60
60.003
60.003
60.003
60.002
60.003
60.002
60.003
60.004
60.005
60.006
60.009
60.012
60.017
60.021
60.022
60.021
60.02
60.018
60.021
60.02
60.02
60.018
60.018
60.019
60.019
60.018
60.017
60.016
60.016
60.016
60.015
60.014
60.014
60.013
60.013
60.015
60.017
60.016
60.019
60.021
60.021
60.02
60.022
60.024
60.026
60.025
3683.736
3682.579
3682.234
3682.138
3682.224
3681.689
3681.458
3681.65
3681.013
3680.167
3679.943
3679.429
3679.669
3678.981
3678.267
3676.796
3676.81
3674.798
3673.906
3671.145
3670.51
3673.648
3673.684
3675.865
3676.676
3676.404
3676.437
3677.185
3677.659
3678.828
3679.289
3678.915
3679.276
3678.599
3678.367
3678.25
3678.589
3677.251
3675.698
3674.669
3674.87
3674.402
3674.546
3672.969
3671.914
3671.982
3670.946
3670.821
3671.06
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
665.5
666
666.5
667
667.5
668
668.5
669
669.5
670
670.5
671
671.5
672
672.5
673
673.5
674
674.5
675
675.5
676
676.5
677
677.5
678
678.5
679
679.5
680
680.5
681
681.5
682
682.5
683
683.5
684
684.5
685
685.5
686
686.5
687
687.5
688
688.5
689
689.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7939.23
7939.56
7939.89
7940.22
7940.55
7940.88
7941.21
7941.54
7941.87
7942.2
7942.53
7942.86
7943.19
7943.52
7943.85
7944.18
7944.51
7944.84
7945.17
7945.5
7945.83
7946.16
7946.49
7946.82
7947.15
7947.48
7947.81
7948.14
7948.47
7948.8
7949.13
7949.46
7949.79
7950.12
7950.45
7950.78
7951.11
7951.44
7951.77
7952.1
7952.43
7952.76
7953.09
7953.42
7953.75
7954.08
7954.41
7954.74
7955.07
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.005
0.003
0.003
0.000
0.000
-0.001
0.001
-0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
-0.001
-0.001
-0.002
0.003
-0.001
0.000
-0.002
0.000
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
-0.001
0.003
0.002
0.000
-0.001
0.002
0.002
0.002
-0.001
0.005
0.005
0.003
0.003
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
0.001
0.001
0.002
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.002
0.001
003554
10/12/09 02:58:00
10/12/09 02:58:02
10/12/09 02:58:04
10/12/09 02:58:06
10/12/09 02:58:08
10/12/09 02:58:10
10/12/09 02:58:12
10/12/09 02:58:14
10/12/09 02:58:16
10/12/09 02:58:18
10/12/09 02:58:20
10/12/09 02:58:22
10/12/09 02:58:24
10/12/09 02:58:26
10/12/09 02:58:28
10/12/09 02:58:30
10/12/09 02:58:32
10/12/09 02:58:34
10/12/09 02:58:36
10/12/09 02:58:38
10/12/09 02:58:40
10/12/09 02:58:42
10/12/09 02:58:44
10/12/09 02:58:46
10/12/09 02:58:48
10/12/09 02:58:50
10/12/09 02:58:52
10/12/09 02:58:54
10/12/09 02:58:56
10/12/09 02:58:58
10/12/09 02:59:00
10/12/09 02:59:02
10/12/09 02:59:04
10/12/09 02:59:06
10/12/09 02:59:08
10/12/09 02:59:10
10/12/09 02:59:12
10/12/09 02:59:14
10/12/09 02:59:16
10/12/09 02:59:18
10/12/09 02:59:20
10/12/09 02:59:22
10/12/09 02:59:24
10/12/09 02:59:26
10/12/09 02:59:28
10/12/09 02:59:30
10/12/09 02:59:32
10/12/09 02:59:34
10/12/09 02:59:36
60.026
60.022
60.021
60.022
60.024
60.027
60.029
60.028
60.028
60.032
60.035
60.03
60.028
60.021
60.021
60.024
60.025
60.024
60.022
60.023
60.021
60.02
60.02
60.02
60.02
60.017
60.014
60.012
60.01
60.011
60.01
60.01
60.01
60.012
60.012
60.013
60.014
60.013
60.012
60.011
60.01
60.008
60.01
60.011
60.013
60.016
60.018
60.019
60.019
3671.539
3673.794
3674.01
3675.102
3675.284
3676.051
3675.704
3672.583
3671.343
3670.232
3668.654
3668.767
3666.312
3667.322
3657.164
3657.714
3668.637
3669.309
3670.112
3670.735
3671.332
3672.095
3672.683
3673.833
3674.645
3675.641
3675.971
3677.009
3678.314
3679.393
3680.02
3679.792
3679.597
3680.315
3680.11
3679.062
3679.127
3679.587
3679.637
3679.02
3678.418
3679.383
3679.681
3679.932
3679.138
3678.469
3678.499
3678.456
3677.615
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
690
690.5
691
691.5
692
692.5
693
693.5
694
694.5
695
695.5
696
696.5
697
697.5
698
698.5
699
699.5
700
700.5
701
701.5
702
702.5
703
703.5
704
704.5
705
705.5
706
706.5
707
707.5
708
708.5
709
709.5
710
710.5
711
711.5
712
712.5
713
713.5
714
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7955.4
7955.73
7956.06
7956.39
7956.72
7957.05
7957.38
7957.71
7958.04
7958.37
7958.7
7959.03
7959.36
7959.69
7960.02
7960.35
7960.68
7961.01
7961.34
7961.67
7962
7962.33
7962.66
7962.99
7963.32
7963.65
7963.98
7964.31
7964.64
7964.97
7965.3
7965.63
7965.96
7966.29
7966.62
7966.95
7967.28
7967.61
7967.94
7968.27
7968.6
7968.93
7969.26
7969.59
7969.92
7970.25
7970.58
7970.91
7971.24
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.004
-0.001
0.001
0.002
0.003
0.002
-0.001
0.000
0.004
0.003
-0.005
-0.002
-0.007
0.000
0.003
0.001
-0.001
-0.002
0.001
-0.002
-0.001
0.000
0.000
0.000
-0.003
-0.003
-0.002
-0.002
0.001
-0.001
0.000
0.000
0.002
0.000
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.004
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.004
0.003
0.005
0.002
0.007
0.000
0.003
0.001
0.001
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
003555
10/12/09 02:59:38
10/12/09 02:59:40
10/12/09 02:59:42
10/12/09 02:59:44
10/12/09 02:59:46
10/12/09 02:59:48
10/12/09 02:59:50
10/12/09 02:59:52
10/12/09 02:59:54
10/12/09 02:59:56
10/12/09 02:59:58
10/12/09 03:00:00
10/12/09 03:00:02
10/12/09 03:00:04
10/12/09 03:00:06
10/12/09 03:00:08
10/12/09 03:00:10
10/12/09 03:00:12
10/12/09 03:00:14
10/12/09 03:00:16
10/12/09 03:00:18
10/12/09 03:00:20
10/12/09 03:00:22
10/12/09 03:00:24
10/12/09 03:00:26
10/12/09 03:00:28
10/12/09 03:00:30
10/12/09 03:00:32
10/12/09 03:00:34
10/12/09 03:00:36
10/12/09 03:00:38
10/12/09 03:00:40
10/12/09 03:00:42
10/12/09 03:00:44
10/12/09 03:00:46
10/12/09 03:00:48
10/12/09 03:00:50
10/12/09 03:00:52
10/12/09 03:00:54
10/12/09 03:00:56
10/12/09 03:00:58
10/12/09 03:01:00
10/12/09 03:01:02
10/12/09 03:01:04
10/12/09 03:01:06
10/12/09 03:01:08
10/12/09 03:01:10
10/12/09 03:01:12
10/12/09 03:01:14
60.019
60.02
60.02
60.018
60.018
60.016
60.016
60.019
60.023
60.022
60.018
60.015
60.016
60.017
60.015
60.01
60.004
59.999
59.995
59.99
59.982
59.974
59.97
59.97
59.968
59.968
59.968
59.972
59.967
59.966
59.964
59.965
59.966
59.963
59.963
59.965
59.968
59.97
59.97
59.97
59.973
59.972
59.976
59.975
59.975
59.977
59.976
59.976
59.974
3677.446
3677.431
3677.451
3677.315
3678.151
3678.362
3678.874
3680.771
3681.058
3680.353
3679.167
3679.553
3680.672
3682.73
3682.714
3681.915
3682.01
3682.483
3683.813
3685.306
3684.846
3684.643
3687.527
3689.404
3692.287
3692.966
3693.793
3694.397
3694.974
3697.407
3698.502
3698.617
3698.992
3699.85
3702.645
3701.989
3702.218
3704.023
3703.365
3702.988
3703.814
3704.899
3705.625
3704.293
3702.094
3701.944
3703.142
3704.669
3705.376
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
714.5
715
715.5
716
716.5
717
717.5
718
718.5
719
719.5
720
720.5
721
721.5
722
722.5
723
723.5
724
724.5
725
725.5
726
726.5
727
727.5
728
728.5
729
729.5
730
730.5
731
731.5
732
732.5
733
733.5
734
734.5
735
735.5
736
736.5
737
737.5
738
738.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7971.57
7971.9
7972.23
7972.56
7972.89
7973.22
7973.55
7973.88
7974.21
7974.54
7974.87
7975.2
7975.53
7975.86
7976.19
7976.52
7976.85
7977.18
7977.51
7977.84
7978.17
7978.5
7978.83
7979.16
7979.49
7979.82
7980.15
7980.48
7980.81
7981.14
7981.47
7981.8
7982.13
7982.46
7982.79
7983.12
7983.45
7983.78
7984.11
7984.44
7984.77
7985.1
7985.43
7985.76
7986.09
7986.42
7986.75
7987.08
7987.41
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
-0.002
0.000
-0.002
0.000
0.003
0.004
-0.001
-0.004
-0.003
0.001
0.001
-0.002
-0.005
-0.006
-0.005
-0.004
-0.005
-0.008
-0.008
-0.004
0.000
-0.002
0.000
0.000
0.004
-0.005
-0.001
-0.002
0.001
0.001
-0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
-0.001
0.004
-0.001
0.000
0.002
-0.001
0.000
-0.002
0.000
0.001
0.000
0.002
0.000
0.002
0.000
0.003
0.004
0.001
0.004
0.003
0.001
0.001
0.002
0.005
0.006
0.005
0.004
0.005
0.008
0.008
0.004
0.000
0.002
0.000
0.000
0.004
0.005
0.001
0.002
0.001
0.001
0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
0.001
0.004
0.001
0.000
0.002
0.001
0.000
0.002
003556
10/12/09 03:01:16
10/12/09 03:01:18
10/12/09 03:01:20
10/12/09 03:01:22
10/12/09 03:01:24
10/12/09 03:01:26
10/12/09 03:01:28
10/12/09 03:01:30
10/12/09 03:01:32
10/12/09 03:01:34
10/12/09 03:01:36
10/12/09 03:01:38
10/12/09 03:01:40
10/12/09 03:01:42
10/12/09 03:01:44
10/12/09 03:01:46
10/12/09 03:01:48
10/12/09 03:01:50
10/12/09 03:01:52
10/12/09 03:01:54
10/12/09 03:01:56
10/12/09 03:01:58
10/12/09 03:02:00
10/12/09 03:02:02
10/12/09 03:02:04
10/12/09 03:02:06
10/12/09 03:02:08
10/12/09 03:02:10
10/12/09 03:02:12
10/12/09 03:02:14
10/12/09 03:02:16
10/12/09 03:02:18
10/12/09 03:02:20
10/12/09 03:02:22
10/12/09 03:02:24
10/12/09 03:02:26
10/12/09 03:02:28
10/12/09 03:02:30
10/12/09 03:02:32
10/12/09 03:02:34
10/12/09 03:02:36
10/12/09 03:02:38
10/12/09 03:02:40
10/12/09 03:02:42
10/12/09 03:02:44
10/12/09 03:02:46
10/12/09 03:02:48
10/12/09 03:02:50
10/12/09 03:02:52
59.975
59.974
59.974
59.976
59.977
59.979
59.981
59.983
59.985
59.983
59.98
59.979
59.983
59.987
59.986
59.984
59.98
59.982
59.984
59.985
59.987
59.989
59.992
59.996
59.999
59.997
59.997
59.997
59.997
59.996
59.997
59.996
59.998
60.003
60.009
60.01
60.008
60.005
60.004
60.006
60.003
60.001
60.002
60.004
60.007
60.007
60.008
60.008
60.006
3705.662
3705.855
3706.776
3707.514
3706.928
3706.446
3706.335
3706.771
3705.943
3704.127
3704.777
3705.974
3705.968
3705.356
3704.683
3703.913
3704.361
3704.988
3705.05
3704.893
3703.741
3701.831
3701.795
3700.07
3701.308
3700.429
3700.913
3700.541
3699.927
3700.858
3700.549
3700.614
3700.224
3699.5
3698.032
3697.96
3699.409
3699.241
3700.738
3701.11
3701.238
3699.998
3700.22
3701.823
3702.554
3702.276
3701.026
3701.923
3702.943
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
739
739.5
740
740.5
741
741.5
742
742.5
743
743.5
744
744.5
745
745.5
746
746.5
747
747.5
748
748.5
749
749.5
750
750.5
751
751.5
752
752.5
753
753.5
754
754.5
755
755.5
756
756.5
757
757.5
758
758.5
759
759.5
760
760.5
761
761.5
762
762.5
763
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7987.74
7988.07
7988.4
7988.73
7989.06
7989.39
7989.72
7990.05
7990.38
7990.71
7991.04
7991.37
7991.7
7992.03
7992.36
7992.69
7993.02
7993.35
7993.68
7994.01
7994.34
7994.67
7995
7995.33
7995.66
7995.99
7996.32
7996.65
7996.98
7997.31
7997.64
7997.97
7998.3
7998.63
7998.96
7999.29
7999.62
7999.95
8000.28
8000.61
8000.94
8001.27
8001.6
8001.93
8002.26
8002.59
8002.92
8003.25
8003.58
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
-0.002
-0.003
-0.001
0.004
0.004
-0.001
-0.002
-0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
-0.002
0.000
0.000
0.000
-0.001
0.001
-0.001
0.002
0.005
0.006
0.001
-0.002
-0.003
-0.001
0.002
-0.003
-0.002
0.001
0.002
0.003
0.000
0.001
0.000
-0.002
0.001
0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
0.002
0.003
0.001
0.004
0.004
0.001
0.002
0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.005
0.006
0.001
0.002
0.003
0.001
0.002
0.003
0.002
0.001
0.002
0.003
0.000
0.001
0.000
0.002
003557
10/12/09 03:02:54
10/12/09 03:02:56
10/12/09 03:02:58
10/12/09 03:03:00
10/12/09 03:03:02
10/12/09 03:03:04
10/12/09 03:03:06
10/12/09 03:03:08
10/12/09 03:03:10
10/12/09 03:03:12
10/12/09 03:03:14
10/12/09 03:03:16
10/12/09 03:03:18
10/12/09 03:03:20
10/12/09 03:03:22
10/12/09 03:03:24
10/12/09 03:03:26
10/12/09 03:03:28
10/12/09 03:03:30
10/12/09 03:03:32
10/12/09 03:03:34
10/12/09 03:03:36
10/12/09 03:03:38
10/12/09 03:03:40
10/12/09 03:03:42
10/12/09 03:03:44
10/12/09 03:03:46
10/12/09 03:03:48
10/12/09 03:03:50
10/12/09 03:03:52
10/12/09 03:03:54
10/12/09 03:03:56
10/12/09 03:03:58
10/12/09 03:04:00
10/12/09 03:04:02
10/12/09 03:04:04
10/12/09 03:04:06
10/12/09 03:04:08
10/12/09 03:04:10
10/12/09 03:04:12
10/12/09 03:04:14
10/12/09 03:04:16
10/12/09 03:04:18
10/12/09 03:04:20
10/12/09 03:04:22
10/12/09 03:04:24
10/12/09 03:04:26
10/12/09 03:04:28
10/12/09 03:04:30
60.006
60.006
60.005
60
59.999
60
60
60.004
60.008
60.013
60.015
60.015
60.012
60.009
60.005
60.008
60.011
60.011
60.013
60.016
60.018
60.018
60.019
60.018
60.013
60.011
60.009
60.009
60.008
60.009
60.011
60.015
60.02
60.021
60.018
60.017
60.019
60.019
60.021
60.022
60.025
60.027
60.03
60.027
60.023
60.021
60.023
60.023
60.02
3704.093
3703.96
3703.819
3704.455
3704.346
3705.329
3704.93
3704.405
3703.675
3702.748
3702.669
3703.017
3703.416
3703.297
3705.189
3705.279
3704.646
3704.051
3703.438
3704.255
3703.708
3703.83
3704.524
3704.139
3704.27
3705.429
3705.942
3705.54
3705.634
3705.749
3707.267
3706.945
3706.63
3705.655
3703.895
3704.224
3703.887
3704.648
3704.795
3704.167
3702.764
3702.008
3700.36
3701.063
3700.34
3699.369
3701.568
3702.959
3704.25
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
763.5
764
764.5
765
765.5
766
766.5
767
767.5
768
768.5
769
769.5
770
770.5
771
771.5
772
772.5
773
773.5
774
774.5
775
775.5
776
776.5
777
777.5
778
778.5
779
779.5
780
780.5
781
781.5
782
782.5
783
783.5
784
784.5
785
785.5
786
786.5
787
787.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8003.91
8004.24
8004.57
8004.9
8005.23
8005.56
8005.89
8006.22
8006.55
8006.88
8007.21
8007.54
8007.87
8008.2
8008.53
8008.86
8009.19
8009.52
8009.85
8010.18
8010.51
8010.84
8011.17
8011.5
8011.83
8012.16
8012.49
8012.82
8013.15
8013.48
8013.81
8014.14
8014.47
8014.8
8015.13
8015.46
8015.79
8016.12
8016.45
8016.78
8017.11
8017.44
8017.77
8018.1
8018.43
8018.76
8019.09
8019.42
8019.75
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
-0.001
-0.005
-0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
-0.003
-0.003
-0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
-0.001
-0.005
-0.002
-0.002
0.000
-0.001
0.001
0.002
0.004
0.005
0.001
-0.003
-0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
-0.003
-0.004
-0.002
0.002
0.000
-0.003
0.000
0.000
0.001
0.005
0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
0.003
0.003
0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
0.001
0.005
0.002
0.002
0.000
0.001
0.001
0.002
0.004
0.005
0.001
0.003
0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
0.003
0.004
0.002
0.002
0.000
0.003
003558
10/12/09 03:04:32
10/12/09 03:04:34
10/12/09 03:04:36
10/12/09 03:04:38
10/12/09 03:04:40
10/12/09 03:04:42
10/12/09 03:04:44
10/12/09 03:04:46
10/12/09 03:04:48
10/12/09 03:04:50
10/12/09 03:04:52
10/12/09 03:04:54
10/12/09 03:04:56
10/12/09 03:04:58
10/12/09 03:05:00
10/12/09 03:05:02
10/12/09 03:05:04
10/12/09 03:05:06
10/12/09 03:05:08
10/12/09 03:05:10
10/12/09 03:05:12
10/12/09 03:05:14
10/12/09 03:05:16
10/12/09 03:05:18
10/12/09 03:05:20
10/12/09 03:05:22
10/12/09 03:05:24
10/12/09 03:05:26
10/12/09 03:05:28
10/12/09 03:05:30
10/12/09 03:05:32
10/12/09 03:05:34
10/12/09 03:05:36
10/12/09 03:05:38
10/12/09 03:05:40
10/12/09 03:05:42
10/12/09 03:05:44
10/12/09 03:05:46
10/12/09 03:05:48
10/12/09 03:05:50
10/12/09 03:05:52
10/12/09 03:05:54
10/12/09 03:05:56
10/12/09 03:05:58
10/12/09 03:06:00
10/12/09 03:06:02
10/12/09 03:06:04
10/12/09 03:06:06
10/12/09 03:06:08
60.024
60.024
60.022
60.022
60.024
60.025
60.023
60.024
60.02
60.018
60.013
60.008
60.012
60.017
60.019
60.019
60.015
60.016
60.015
60.016
60.014
60.016
60.018
60.019
60.016
60.014
60.014
60.018
60.022
60.023
60.024
60.026
60.026
60.024
60.022
60.02
60.019
60.022
60.025
60.028
60.03
60.031
60.029
60.026
60.026
60.029
60.03
60.033
60.03
3703.621
3703.374
3703.036
3703.931
3704.947
3704.208
3703.541
3703.16
3703.397
3704.376
3705.441
3706.995
3710.072
3707.971
3707.767
3707.609
3708.831
3709.465
3709.813
3709.817
3709.99
3709.094
3709.642
3709.812
3709.933
3710.677
3710.591
3709.354
3707.696
3707.38
3707.12
3706.99
3705.848
3704.185
3704.406
3704.963
3706.567
3705.516
3704.869
3704.428
3704.773
3703.532
3702.686
3702.093
3703.169
3703.676
3701.52
3700.106
3698.222
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
788
788.5
789
789.5
790
790.5
791
791.5
792
792.5
793
793.5
794
794.5
795
795.5
796
796.5
797
797.5
798
798.5
799
799.5
800
800.5
801
801.5
802
802.5
803
803.5
804
804.5
805
805.5
806
806.5
807
807.5
808
808.5
809
809.5
810
810.5
811
811.5
812
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8020.08
8020.41
8020.74
8021.07
8021.4
8021.73
8022.06
8022.39
8022.72
8023.05
8023.38
8023.71
8024.04
8024.37
8024.7
8025.03
8025.36
8025.69
8026.02
8026.35
8026.68
8027.01
8027.34
8027.67
8028
8028.33
8028.66
8028.99
8029.32
8029.65
8029.98
8030.31
8030.64
8030.97
8031.3
8031.63
8031.96
8032.29
8032.62
8032.95
8033.28
8033.61
8033.94
8034.27
8034.6
8034.93
8035.26
8035.59
8035.92
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
0.000
-0.002
0.000
0.002
0.001
-0.002
0.001
-0.004
-0.002
-0.005
-0.005
0.004
0.005
0.002
0.000
-0.004
0.001
-0.001
0.001
-0.002
0.002
0.002
0.001
-0.003
-0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
-0.002
-0.002
-0.002
-0.001
0.003
0.003
0.003
0.002
0.001
-0.002
-0.003
0.000
0.003
0.001
0.003
-0.003
0.004
0.000
0.002
0.000
0.002
0.001
0.002
0.001
0.004
0.002
0.005
0.005
0.004
0.005
0.002
0.000
0.004
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.003
0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
0.002
0.002
0.002
0.001
0.003
0.003
0.003
0.002
0.001
0.002
0.003
0.000
0.003
0.001
0.003
0.003
003559
10/12/09 03:06:10
10/12/09 03:06:12
10/12/09 03:06:14
10/12/09 03:06:16
10/12/09 03:06:18
10/12/09 03:06:20
10/12/09 03:06:22
10/12/09 03:06:24
10/12/09 03:06:26
10/12/09 03:06:28
10/12/09 03:06:30
10/12/09 03:06:32
10/12/09 03:06:34
10/12/09 03:06:36
10/12/09 03:06:38
10/12/09 03:06:40
10/12/09 03:06:42
10/12/09 03:06:44
10/12/09 03:06:46
10/12/09 03:06:48
10/12/09 03:06:50
10/12/09 03:06:52
10/12/09 03:06:54
10/12/09 03:06:56
10/12/09 03:06:58
10/12/09 03:07:00
10/12/09 03:07:02
10/12/09 03:07:04
10/12/09 03:07:06
10/12/09 03:07:08
10/12/09 03:07:10
10/12/09 03:07:12
10/12/09 03:07:14
10/12/09 03:07:16
10/12/09 03:07:18
10/12/09 03:07:20
10/12/09 03:07:22
10/12/09 03:07:24
10/12/09 03:07:26
10/12/09 03:07:28
10/12/09 03:07:30
10/12/09 03:07:32
10/12/09 03:07:34
10/12/09 03:07:36
10/12/09 03:07:38
10/12/09 03:07:40
10/12/09 03:07:42
10/12/09 03:07:44
10/12/09 03:07:46
60.022
60.016
60.019
60.03
60.028
60.021
60.015
60.015
60.012
60.011
60.014
60.013
60.014
60.016
60.016
60.015
60.013
60.007
59.997
59.994
59.993
59.99
59.993
59.994
59.993
59.994
59.993
59.996
59.988
59.985
59.983
59.982
59.98
59.977
59.981
59.982
59.978
59.98
59.98
59.977
59.98
59.983
59.984
59.981
59.981
59.98
59.981
59.981
59.981
3698.009
3700.28
3703.192
3703.815
3701.863
3699.956
3700.816
3703.802
3706.943
3708.527
3707.49
3707.647
3706.991
3707.495
3705.584
3705.398
3707.12
3709.144
3708.99
3708.291
3706.193
3707.304
3707.903
3706.76
3706.921
3706.683
3706.888
3704.934
3705.678
3706.481
3707.071
3706.696
3707.479
3708.246
3709.436
3710.419
3710.134
3708.708
3710.024
3709.192
3708.335
3709.399
3707.911
3709.004
3707.638
3709.689
3708.945
3706.541
3711.256
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
812.5
813
813.5
814
814.5
815
815.5
816
816.5
817
817.5
818
818.5
819
819.5
820
820.5
821
821.5
822
822.5
823
823.5
824
824.5
825
825.5
826
826.5
827
827.5
828
828.5
829
829.5
830
830.5
831
831.5
832
832.5
833
833.5
834
834.5
835
835.5
836
836.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8036.25
8036.58
8036.91
8037.24
8037.57
8037.9
8038.23
8038.56
8038.89
8039.22
8039.55
8039.88
8040.21
8040.54
8040.87
8041.2
8041.53
8041.86
8042.19
8042.52
8042.85
8043.18
8043.51
8043.84
8044.17
8044.5
8044.83
8045.16
8045.49
8045.82
8046.15
8046.48
8046.81
8047.14
8047.47
8047.8
8048.13
8048.46
8048.79
8049.12
8049.45
8049.78
8050.11
8050.44
8050.77
8051.1
8051.43
8051.76
8052.09
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.008
-0.006
0.003
0.011
-0.002
-0.007
-0.006
0.000
-0.003
-0.001
0.003
-0.001
0.001
0.002
0.000
-0.001
-0.002
-0.006
-0.010
-0.003
-0.001
-0.003
0.003
0.001
-0.001
0.001
-0.001
0.003
-0.008
-0.003
-0.002
-0.001
-0.002
-0.003
0.004
0.001
-0.004
0.002
0.000
-0.003
0.003
0.003
0.001
-0.003
0.000
-0.001
0.001
0.000
0.000
0.008
0.006
0.003
0.011
0.002
0.007
0.006
0.000
0.003
0.001
0.003
0.001
0.001
0.002
0.000
0.001
0.002
0.006
0.010
0.003
0.001
0.003
0.003
0.001
0.001
0.001
0.001
0.003
0.008
0.003
0.002
0.001
0.002
0.003
0.004
0.001
0.004
0.002
0.000
0.003
0.003
0.003
0.001
0.003
0.000
0.001
0.001
0.000
0.000
003560
10/12/09 03:07:48
10/12/09 03:07:50
10/12/09 03:07:52
10/12/09 03:07:54
10/12/09 03:07:56
10/12/09 03:07:58
10/12/09 03:08:00
10/12/09 03:08:02
10/12/09 03:08:04
10/12/09 03:08:06
10/12/09 03:08:08
10/12/09 03:08:10
10/12/09 03:08:12
10/12/09 03:08:14
10/12/09 03:08:16
10/12/09 03:08:18
10/12/09 03:08:20
10/12/09 03:08:22
10/12/09 03:08:24
10/12/09 03:08:26
10/12/09 03:08:28
10/12/09 03:08:30
10/12/09 03:08:32
10/12/09 03:08:34
10/12/09 03:08:36
10/12/09 03:08:38
10/12/09 03:08:40
10/12/09 03:08:42
10/12/09 03:08:44
10/12/09 03:08:46
10/12/09 03:08:48
10/12/09 03:08:50
10/12/09 03:08:52
10/12/09 03:08:54
10/12/09 03:08:56
10/12/09 03:08:58
10/12/09 03:09:00
10/12/09 03:09:02
10/12/09 03:09:04
10/12/09 03:09:06
10/12/09 03:09:08
10/12/09 03:09:10
10/12/09 03:09:12
10/12/09 03:09:14
10/12/09 03:09:16
10/12/09 03:09:18
10/12/09 03:09:20
10/12/09 03:09:22
10/12/09 03:09:24
59.98
59.978
59.978
59.979
59.978
59.976
59.976
59.975
59.976
59.975
59.979
59.978
59.975
59.976
59.981
59.977
59.975
59.976
59.979
59.98
59.979
59.978
59.979
59.982
59.983
59.987
59.988
59.984
59.98
59.979
59.98
59.979
59.978
59.975
59.979
59.982
59.983
59.983
59.985
59.99
59.987
59.984
59.976
59.979
59.985
59.983
59.979
59.981
59.978
3711.362
3712.303
3712.012
3711.703
3712.093
3713.992
3714.612
3715.083
3715.323
3714.794
3714.717
3715.161
3715.001
3713.996
3714.063
3714.335
3715.631
3715.688
3715.567
3715.725
3714.848
3713.142
3713.358
3712.275
3712.619
3712.153
3710.05
3709.082
3710.472
3710.624
3710.946
3710.2
3710.475
3709.462
3710.803
3709.286
3710.573
3709.525
3708.371
3708.527
3706.512
3707.49
3708.962
3709.894
3712.303
3711.35
3711.627
3712.076
3712.393
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
837
837.5
838
838.5
839
10
10
10
10
10
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8052.42
8052.75
8053.08
8053.41
8053.74
8054.07
8054.4
8054.73
8055.06
8055.39
8055.72
8056.05
8056.38
8056.71
8057.04
8057.37
8057.7
8058.03
8058.36
8058.69
8059.02
8059.35
8059.68
8060.01
8060.34
8060.67
8061
8061.33
8061.66
8061.99
8062.32
8062.65
8062.98
8063.31
8063.64
8063.97
8064.3
8064.63
8064.96
8065.29
8065.62
8065.95
8066.28
8066.61
8066.94
8067.27
8067.6
8067.93
8068.26
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.002
0.000
0.001
-0.001
-0.002
0.000
-0.001
0.001
-0.001
0.004
-0.001
-0.003
0.001
0.005
-0.004
-0.002
0.001
0.003
0.001
-0.001
-0.001
0.001
0.003
0.001
0.004
0.001
-0.004
-0.004
-0.001
0.001
-0.001
-0.001
-0.003
0.004
0.003
0.001
0.000
0.002
0.005
-0.003
-0.003
-0.008
0.003
0.006
-0.002
-0.004
0.002
-0.003
0.001
0.002
0.000
0.001
0.001
0.002
0.000
0.001
0.001
0.001
0.004
0.001
0.003
0.001
0.005
0.004
0.002
0.001
0.003
0.001
0.001
0.001
0.001
0.003
0.001
0.004
0.001
0.004
0.004
0.001
0.001
0.001
0.001
0.003
0.004
0.003
0.001
0.000
0.002
0.005
0.003
0.003
0.008
0.003
0.006
0.002
0.004
0.002
0.003
003561
10/12/09 03:09:26
10/12/09 03:09:28
10/12/09 03:09:30
10/12/09 03:09:32
10/12/09 03:09:34
10/12/09 03:09:36
10/12/09 03:09:38
10/12/09 03:09:40
10/12/09 03:09:42
10/12/09 03:09:44
10/12/09 03:09:46
10/12/09 03:09:48
10/12/09 03:09:50
10/12/09 03:09:52
10/12/09 03:09:54
10/12/09 03:09:56
10/12/09 03:09:58
10/12/09 03:10:00
10/12/09 03:10:02
10/12/09 03:10:04
10/12/09 03:10:06
10/12/09 03:10:08
10/12/09 03:10:10
10/12/09 03:10:12
10/12/09 03:10:14
10/12/09 03:10:16
10/12/09 03:10:18
10/12/09 03:10:20
10/12/09 03:10:22
10/12/09 03:10:24
10/12/09 03:10:26
10/12/09 03:10:28
10/12/09 03:10:30
10/12/09 03:10:32
10/12/09 03:10:34
10/12/09 03:10:36
10/12/09 03:10:38
10/12/09 03:10:40
10/12/09 03:10:42
10/12/09 03:10:44
10/12/09 03:10:46
10/12/09 03:10:48
10/12/09 03:10:50
10/12/09 03:10:52
10/12/09 03:10:54
10/12/09 03:10:56
10/12/09 03:10:58
10/12/09 03:11:00
10/12/09 03:11:02
59.975
59.978
59.989
59.999
59.994
59.989
59.986
59.984
59.983
59.982
59.98
59.99
59.995
59.995
59.99
59.989
59.991
59.996
60
60.002
60.004
60.004
60.002
59.999
59.998
59.995
59.996
60.001
60.002
60.001
60.003
60.005
60.004
60.004
60.004
60.006
60.003
60.005
60.006
60.009
60.009
60.01
60.009
60.013
60.015
60.014
60.009
60.009
60.008
3712.999
3713.51
3716.626
3715.443
3712.092
3713.906
3714.894
3714.953
3716.122
3716.308
3715.438
3714.764
3714.714
3715.068
3715.927
3715.791
3716.285
3715.324
3714.46
3711.708
3712.698
3712.851
3713.362
3716.641
3718.292
3719.079
3718.233
3717.815
3717.889
3718.56
3718.195
3719.021
3718.821
3719.897
3719.299
3719.643
3719.527
3719.731
3720.279
3718.58
3718.976
3718.982
3720.034
3720.609
3720.811
3721.239
3720.38
3719.447
3720.807
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8068.59
8068.92
8069.25
8069.58
8069.91
8070.24
8070.57
8070.9
8071.23
8071.56
8071.89
8072.22
8072.55
8072.88
8073.21
8073.54
8073.87
8074.2
8074.53
8074.86
8075.19
8075.52
8075.85
8076.18
8076.51
8076.84
8077.17
8077.5
8077.83
8078.16
8078.49
8078.82
8079.15
8079.48
8079.81
8080.14
8080.47
8080.8
8081.13
8081.46
8081.79
8082.12
8082.45
8082.78
8083.11
8083.44
8083.77
8084.1
8084.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
0.003
0.011
0.010
-0.005
-0.005
-0.003
-0.002
-0.001
-0.001
-0.002
0.010
0.005
0.000
-0.005
-0.001
0.002
0.005
0.004
0.002
0.002
0.000
-0.002
-0.003
-0.001
-0.003
0.001
0.005
0.001
-0.001
0.002
0.002
-0.001
0.000
0.000
0.002
-0.003
0.002
0.001
0.003
0.000
0.001
-0.001
0.004
0.002
-0.001
-0.005
0.000
-0.001
0.003
0.003
0.011
0.010
0.005
0.005
0.003
0.002
0.001
0.001
0.002
0.010
0.005
0.000
0.005
0.001
0.002
0.005
0.004
0.002
0.002
0.000
0.002
0.003
0.001
0.003
0.001
0.005
0.001
0.001
0.002
0.002
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.003
0.000
0.001
0.001
0.004
0.002
0.001
0.005
0.000
0.001
003562
10/12/09 03:11:04
10/12/09 03:11:06
10/12/09 03:11:08
10/12/09 03:11:10
10/12/09 03:11:12
10/12/09 03:11:14
10/12/09 03:11:16
10/12/09 03:11:18
10/12/09 03:11:20
10/12/09 03:11:22
10/12/09 03:11:24
10/12/09 03:11:26
10/12/09 03:11:28
10/12/09 03:11:30
10/12/09 03:11:32
10/12/09 03:11:34
10/12/09 03:11:36
10/12/09 03:11:38
10/12/09 03:11:40
10/12/09 03:11:42
10/12/09 03:11:44
10/12/09 03:11:46
10/12/09 03:11:48
10/12/09 03:11:50
10/12/09 03:11:52
10/12/09 03:11:54
10/12/09 03:11:56
10/12/09 03:11:58
10/12/09 03:12:00
10/12/09 03:12:02
10/12/09 03:12:04
10/12/09 03:12:06
10/12/09 03:12:08
10/12/09 03:12:10
10/12/09 03:12:12
10/12/09 03:12:14
10/12/09 03:12:16
10/12/09 03:12:18
10/12/09 03:12:20
10/12/09 03:12:22
10/12/09 03:12:24
10/12/09 03:12:26
10/12/09 03:12:28
10/12/09 03:12:30
10/12/09 03:12:32
10/12/09 03:12:34
10/12/09 03:12:36
10/12/09 03:12:38
10/12/09 03:12:40
60.011
60.01
60.009
60.013
60.013
60.014
60.014
60.012
60.01
60.011
60.007
60.003
60.001
60
59.998
59.998
59.999
60.002
60.003
60.003
59.999
59.998
60.001
59.995
59.989
59.987
59.988
59.988
59.99
59.999
60.001
60.003
60.0005
59.998
59.997
59.996
59.996
59.996
59.995
59.994
59.993
59.992
59.991
59.99
59.991
59.992
59.993
59.994
59.995
3721.272
3720.592
3721.245
3721.594
3722.176
3721.999
3721.646
3721.678
3720.86
3721.645
3723.816
3725.07
3724.656
3724.869
3724.661
3723.696
3723.58
3723.405
3721.879
3722.401
3722.906
3724.142
3723.65
3723.201
3723.639
3723.881
3724.654
3725.361
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8084.76
8085.09
8085.42
8085.75
8086.08
8086.41
8086.74
8087.07
8087.4
8087.73
8088.06
8088.39
8088.72
8089.05
8089.38
8089.71
8090.04
8090.37
8090.7
8091.03
8091.36
8091.69
8092.02
8092.35
8092.68
8093.01
8093.34
8093.67
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
0
0
1
0
0
0
0
0
0
0
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.001
-0.001
0.004
0.000
0.001
0.000
-0.002
-0.002
0.001
-0.004
-0.004
-0.002
-0.001
-0.002
0.000
0.001
0.003
0.001
0.000
-0.004
-0.001
0.003
-0.006
-0.006
-0.002
0.001
0.000
0.002
0.009
0.002
0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.001
0.001
0.004
0.000
0.001
0.000
0.002
0.002
0.001
0.004
0.004
0.002
0.001
0.002
0.000
0.001
0.003
0.001
0.000
0.004
0.001
0.003
0.006
0.006
0.002
0.001
0.000
0.002
0.009
0.002
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
003563
10/12/09 03:12:42
10/12/09 03:12:44
10/12/09 03:12:46
10/12/09 03:12:48
10/12/09 03:12:50
10/12/09 03:12:52
10/12/09 03:12:54
10/12/09 03:12:56
10/12/09 03:12:58
10/12/09 03:13:00
10/12/09 03:13:02
10/12/09 03:13:04
10/12/09 03:13:06
10/12/09 03:13:08
10/12/09 03:13:10
10/12/09 03:13:12
10/12/09 03:13:14
10/12/09 03:13:16
10/12/09 03:13:18
10/12/09 03:13:20
10/12/09 03:13:22
10/12/09 03:13:24
10/12/09 03:13:26
10/12/09 03:13:28
10/12/09 03:13:30
10/12/09 03:13:32
10/12/09 03:13:34
10/12/09 03:13:36
10/12/09 03:13:38
10/12/09 03:13:40
10/12/09 03:13:42
10/12/09 03:13:44
10/12/09 03:13:46
10/12/09 03:13:48
10/12/09 03:13:50
10/12/09 03:13:52
10/12/09 03:13:54
10/12/09 03:13:56
10/12/09 03:13:58
10/12/09 03:14:00
10/12/09 03:14:02
10/12/09 03:14:04
10/12/09 03:14:06
10/12/09 03:14:08
10/12/09 03:14:10
10/12/09 03:14:12
10/12/09 03:14:14
10/12/09 03:14:16
10/12/09 03:14:18
59.996
59.996
59.996
59.9965
59.997
59.997
59.997
59.997
59.997
59.999
60.001
60.001
60.001
60.004
60.007
60.009
60.011
60.0085
60.006
60.007
60.008
60.01
60.012
60.012
60.012
60.01
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.007
60.006
60.005
60.004
60.004
60.004
60.0025
60.001
59.9995
59.998
59.9965
59.995
59.995
59.995
59.996
59.997
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
-0.003
-0.002
0.001
0.001
0.002
0.002
0.000
0.000
-0.002
-0.002
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.002
0.000
0.000
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
003564
10/12/09 03:14:20
10/12/09 03:14:22
10/12/09 03:14:24
10/12/09 03:14:26
10/12/09 03:14:28
10/12/09 03:14:30
10/12/09 03:14:32
10/12/09 03:14:34
10/12/09 03:14:36
10/12/09 03:14:38
10/12/09 03:14:40
10/12/09 03:14:42
10/12/09 03:14:44
10/12/09 03:14:46
10/12/09 03:14:48
10/12/09 03:14:50
10/12/09 03:14:52
10/12/09 03:14:54
10/12/09 03:14:56
10/12/09 03:14:58
10/12/09 03:15:00
10/12/09 03:15:02
10/12/09 03:15:04
10/12/09 03:15:06
10/12/09 03:15:08
10/12/09 03:15:10
10/12/09 03:15:12
10/12/09 03:15:14
10/12/09 03:15:16
10/12/09 03:15:18
10/12/09 03:15:20
10/12/09 03:15:22
10/12/09 03:15:24
10/12/09 03:15:26
10/12/09 03:15:28
10/12/09 03:15:30
10/12/09 03:15:32
10/12/09 03:15:34
10/12/09 03:15:36
10/12/09 03:15:38
10/12/09 03:15:40
10/12/09 03:15:42
10/12/09 03:15:44
10/12/09 03:15:46
10/12/09 03:15:48
10/12/09 03:15:50
10/12/09 03:15:52
10/12/09 03:15:54
10/12/09 03:15:56
59.995
59.993
59.9925
59.992
59.9905
59.989
59.99
59.991
59.989
59.987
59.9875
59.988
59.988
59.988
59.987
59.986
59.9855
59.985
59.9845
59.984
59.984
59.984
59.985
59.986
59.987
59.988
59.992
59.996
59.9975
59.999
60.001
60.003
60.003
60.003
60.0055
60.008
60.01
60.012
60.0105
60.009
60.01
60.011
60.012
60.013
60.013
60.013
60.0145
60.016
60.0155
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.001
0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
-0.002
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
003565
10/12/09 03:15:58
10/12/09 03:15:59
10/12/09 03:16:01
10/12/09 03:16:03
10/12/09 03:16:05
10/12/09 03:16:07
10/12/09 03:16:09
10/12/09 03:16:11
10/12/09 03:16:13
10/12/09 03:16:15
10/12/09 03:16:17
10/12/09 03:16:19
10/12/09 03:16:21
10/12/09 03:16:23
10/12/09 03:16:25
10/12/09 03:16:27
10/12/09 03:16:29
10/12/09 03:16:31
10/12/09 03:16:33
10/12/09 03:16:35
10/12/09 03:16:37
10/12/09 03:16:39
10/12/09 03:16:41
10/12/09 03:16:43
10/12/09 03:16:45
10/12/09 03:16:47
10/12/09 03:16:49
10/12/09 03:16:51
10/12/09 03:16:53
10/12/09 03:16:55
10/12/09 03:16:57
10/12/09 03:16:59
10/12/09 03:17:01
10/12/09 03:17:03
10/12/09 03:17:05
10/12/09 03:17:07
10/12/09 03:17:09
10/12/09 03:17:11
10/12/09 03:17:13
10/12/09 03:17:15
10/12/09 03:17:17
10/12/09 03:17:19
10/12/09 03:17:21
10/12/09 03:17:23
10/12/09 03:17:25
60.015
60.014
60.013
60.012
60.011
60.0105
60.01
60.008
60.006
60.006
60.006
60.0045
60.003
60.003
60.003
60.0035
60.004
60.0025
60.001
59.999
59.997
59.9965
59.996
59.9965
59.997
59.997
59.997
59.998
59.999
59.9985
59.998
59.9985
59.999
59.998
59.997
59.9985
60
60.001
60.002
60.0015
60.001
60.0035
60.006
60.0055
60.005
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.000
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
-0.001
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.000
0.000
0.001
0.002
0.000
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
003566
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
MyBA_091012_0227_FRS_Form2.9.xlsm
59.500 Hz
60.500 Hz
Auto
Event Detection
2:27:26
1245 Manually selected row number of the Event Starting Time.
2:33:00
1442 Manually selected row number of the Event Ending Time.
Event Frequency Data
2:27:26
60.1
-0.153
2:27:26
Delta Hz Event Detected
60.05
2:33:00
60
59.95
59.9
59.85
59.8
Copy Form 2 data for
Pasting into Form 1
59.75
59.7
2:17:26
2:22:26
2:27:26
2:32:26
2:37:26
2:42:26
2:47:26
Hz
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_091012_0227_FRS_Form2.9.xlsm
2:52:26
2:57:26
3:02:26
3:07:26
3:12:26
3:17:25
003567
Auto
Manual
003568
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3788.35
157.63
-15.40
-43.39
114.21
157.60
Balancing Authority MyBA
Grid Nominal Frequency
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
142.20 MW
Yes
Initial Response P.U. Performance
1.109 P.U.
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
Frequency
Hz
60.027
60.026
60.026
60.022
60.019
60.017
Interchange
MW
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
Value B
20 to 52 sec
Average
Frequency
Droop Setting
Deadband Setting
Hz Span
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
TC (frequency response filter constant)
Low Hz
3764.66
3804.23
3719.84
3640.68
103.04
0:05:34
No
163.55
123.97
No
Yes
Yes
60.52
20.94
Up
3090
3090
3090
3090
3090
3090
5.00% 3.00000 Hz
0.000 Hz
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
(TC)
Delayed
Delivery
Frequency
Response
-9.734
-15.700
-19.578
-20.657
-20.277
-19.308
Initial
Measure
Final
Expected
Primary
Frequency
Response
A Point
FPointA
A Value
C Value
Delta FC
2:27:24
60.03900146
60.04212523
59.83599854
3.00000 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during re
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.758 P.U. Sustianed Response P.U. Performance
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
60.000 Hz
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
003569
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.190
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3734.673
3737.157
3761.250
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.500
3784.962
3784.730
3784.419
3788.072
3788.328
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
-19.400
-19.820
-19.733
-20.397
-20.828
-21.109
-20.571
-19.861
-20.840
-24.721
-29.407
-32.452
-34.072
-35.485
-39.649
-43.076
-45.303
-44.948
-43.997
-43.379
-42.977
-41.995
-42.077
-42.852
-44.075
-45.232
-44.182
-43.499
-43.055
-42.046
-19.399
40.744
85.606
102.870
114.091
113.094
112.806
116.583
120.481
123.375
122.373
120.278
119.277
118.988
118.079
117.127
115.788
113.114
111.737
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
0.000
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3666.787
3666.265
3666.251
3665.485
3664.952
3664.570
3665.006
3665.615
3664.533
3660.551
3655.763
3652.616
3650.895
3649.380
3645.114
3641.585
3639.256
3639.509
3640.359
3640.875
3641.176
3642.056
3641.872
3640.996
3639.670
3638.411
3639.360
3639.942
3640.284
3641.191
3663.838
3724.598
3770.077
3787.958
3799.796
3799.415
3799.745
3804.139
3808.654
3812.165
3811.779
3810.302
3809.918
3810.246
3809.953
3809.618
3808.896
3806.840
3806.079
3677.914
3696.910
3706.351
3712.015
3716.206
3722.640
3728.074
3732.310
3735.967
3739.054
3742.518
3745.523
3748.165
3750.618
3752.750
3754.613
3756.471
3758.148
3694.218
3719.504
3736.618
3749.253
3757.614
3763.632
3768.696
3773.136
3777.038
3780.197
3782.705
3784.799
3786.616
3788.172
3789.513
3790.653
3791.552
3792.317
3668.635
3669.252
3669.869
3670.486
3671.103
3671.720
3672.337
3672.954
3673.571
3674.188
3674.805
3675.422
3676.039
3676.656
3677.273
3677.890
3678.507
3679.124
3668.635
3668.944
3669.252
3669.561
3669.869
3670.178
3670.486
3670.795
3671.103
3671.412
3671.720
3672.029
3672.337
3672.646
3672.954
3673.263
3673.571
3673.879
003570
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.010
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
111.202
110.494
110.034
110.817
111.686
114.054
115.593
115.511
115.819
115.658
115.553
114.765
114.613
117.037
121.857
130.759
139.429
143.983
144.779
143.495
141.579
140.693
139.397
138.914
136.799
134.342
130.943
128.372
125.621
122.750
119.443
116.572
115.788
113.835
110.404
106.731
104.704
103.386
101.809
99.702
96.891
93.261
90.902
89.008
87.416
85.661
84.159
83.544
84.225
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3806.161
3806.070
3806.227
3807.627
3809.113
3812.098
3814.254
3814.790
3815.714
3816.170
3816.682
3816.511
3816.976
3820.017
3825.454
3834.973
3844.260
3849.431
3850.844
3850.177
3848.877
3848.609
3847.929
3848.064
3846.566
3844.726
3841.943
3839.990
3837.855
3835.601
3832.911
3830.658
3830.490
3829.154
3826.340
3823.284
3821.874
3821.174
3820.214
3818.723
3816.529
3813.516
3811.774
3810.497
3809.522
3808.384
3807.499
3807.501
3808.799
3759.684
3761.055
3762.474
3763.805
3765.078
3766.452
3767.759
3768.952
3770.190
3771.319
3772.373
3773.406
3774.409
3775.354
3776.351
3777.355
3778.397
3779.410
3780.627
3781.792
3782.897
3783.986
3785.004
3785.975
3786.895
3787.758
3788.542
3789.265
3789.886
3790.461
3790.988
3791.459
3791.888
3792.265
3792.587
3792.848
3793.076
3793.271
3793.319
3793.330
3793.311
3793.281
3793.221
3793.140
3793.006
3792.853
3792.684
3792.440
3792.193
3793.009
3793.631
3794.203
3794.787
3795.384
3796.053
3796.753
3797.421
3798.074
3798.698
3799.297
3799.853
3800.388
3800.983
3801.702
3802.653
3803.809
3805.042
3806.247
3807.373
3808.411
3809.392
3810.309
3811.187
3811.991
3812.719
3813.354
3813.921
3814.419
3814.852
3815.213
3815.516
3815.804
3816.055
3816.246
3816.374
3816.472
3816.555
3816.618
3816.653
3816.651
3816.600
3816.522
3816.426
3816.319
3816.197
3816.065
3815.937
3815.832
3679.741
3680.358
3680.975
3681.592
3682.209
3682.826
3683.443
3684.060
3684.677
3685.293
3685.910
3686.527
3687.144
3687.761
3688.378
3688.995
3689.612
3690.229
3690.846
3691.463
3692.080
3692.697
3693.314
3693.931
3694.548
3695.165
3695.782
3696.399
3697.016
3697.633
3698.250
3698.867
3699.484
3700.101
3700.718
3701.335
3701.952
3702.569
3703.186
3703.803
3704.420
3705.037
3705.654
3706.271
3706.888
3707.504
3708.121
3708.738
3709.355
3674.188
3674.496
3674.805
3675.113
3675.422
3675.730
3676.039
3676.347
3676.656
3676.964
3677.273
3677.581
3677.890
3678.198
3678.507
3678.815
3679.124
3679.432
3679.741
3680.049
3680.358
3680.666
3680.975
3681.283
3681.592
3681.900
3682.209
3682.517
3682.826
3683.134
3683.443
3683.751
3684.060
3684.368
3684.677
3684.985
3685.293
3685.602
3685.910
3686.219
3686.527
3686.836
3687.144
3687.453
3687.761
3688.070
3688.378
3688.687
3688.995
003571
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
3774.604
3773.334
3773.958
3772.722
3771.670
3769.630
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.810
3712.092
3714.623
3715.130
3716.168
3716.461
3716.980
3717.759
3722.361
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
83.587
82.811
81.585
79.708
78.848
77.207
76.501
74.240
74.573
74.428
73.253
73.210
72.461
71.254
69.026
67.578
63.754
59.825
57.993
58.604
59.361
59.493
58.498
56.769
56.007
54.790
53.278
51.935
50.701
50.620
50.207
49.939
49.764
48.569
48.874
48.351
48.733
48.620
48.547
48.860
48.342
48.006
45.985
45.391
45.366
46.071
45.808
45.997
45.039
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3808.778
3808.618
3808.010
3806.750
3806.507
3805.482
3805.394
3803.750
3804.700
3805.172
3804.614
3805.187
3805.055
3804.465
3802.855
3802.024
3798.816
3795.504
3794.290
3795.518
3796.892
3797.641
3797.263
3796.151
3796.005
3795.405
3794.510
3793.784
3793.167
3793.703
3793.907
3794.256
3794.698
3794.120
3795.042
3795.136
3796.135
3796.639
3797.183
3798.112
3798.212
3798.493
3797.088
3797.112
3797.704
3799.026
3799.380
3800.186
3799.845
3791.938
3791.672
3791.423
3791.163
3790.896
3790.608
3790.316
3790.018
3789.719
3789.433
3789.147
3788.861
3788.574
3788.301
3788.011
3787.738
3787.446
3787.108
3786.727
3786.308
3785.865
3785.443
3785.049
3784.654
3784.245
3783.871
3783.438
3782.989
3782.506
3781.984
3781.437
3780.882
3780.306
3779.720
3779.121
3778.534
3777.937
3777.330
3776.734
3776.124
3775.525
3774.948
3774.404
3773.875
3773.364
3772.865
3772.379
3771.908
3771.485
3815.730
3815.628
3815.521
3815.399
3815.277
3815.145
3815.015
3814.867
3814.735
3814.612
3814.485
3814.369
3814.254
3814.135
3813.999
3813.856
3813.679
3813.468
3813.248
3813.046
3812.865
3812.695
3812.526
3812.348
3812.172
3811.994
3811.810
3811.622
3811.432
3811.251
3811.076
3810.907
3810.747
3810.584
3810.433
3810.286
3810.151
3810.024
3809.904
3809.795
3809.688
3809.586
3809.474
3809.364
3809.260
3809.171
3809.085
3809.009
3808.930
3709.972
3710.589
3711.206
3711.823
3712.440
3713.057
3713.674
3714.291
3714.908
3715.525
3716.142
3716.759
3717.376
3717.993
3718.610
3719.227
3719.844
3720.461
3721.078
3721.695
3722.312
3722.929
3723.546
3724.163
3724.780
3725.397
3726.014
3726.631
3727.248
3727.865
3728.482
3729.099
3729.715
3730.332
3730.949
3731.566
3732.183
3732.800
3733.417
3734.034
3734.651
3735.268
3735.885
3736.502
3737.119
3737.736
3738.353
3738.970
3739.587
3689.304
3689.612
3689.921
3690.229
3690.538
3690.846
3691.155
3691.463
3691.772
3692.080
3692.389
3692.697
3693.006
3693.314
3693.623
3693.931
3694.240
3694.548
3694.857
3695.165
3695.474
3695.782
3696.090
3696.399
3696.707
3697.016
3697.324
3697.633
3697.941
3698.250
3698.558
3698.867
3699.175
3699.484
3699.792
3700.101
3700.409
3700.718
3701.026
3701.335
3701.643
3701.952
3702.260
3702.569
3702.877
3703.186
3703.494
3703.803
3704.111
003572
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.130
3732.530
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.300
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
43.335
41.866
40.911
38.129
37.041
36.334
35.153
33.664
31.255
31.130
31.410
31.591
31.349
30.831
29.774
29.087
27.558
25.843
24.729
24.725
24.002
24.253
23.695
23.693
22.611
21.186
20.621
20.614
20.969
20.840
21.117
19.854
19.033
18.139
16.117
14.442
14.074
13.835
12.237
10.477
9.694
9.545
10.170
11.658
13.705
15.036
14.100
11.689
9.040
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3798.758
3797.906
3797.568
3795.403
3794.931
3794.841
3794.278
3793.406
3791.614
3792.106
3793.002
3793.800
3794.175
3794.274
3793.834
3793.764
3792.852
3791.754
3791.257
3791.870
3791.764
3792.632
3792.691
3793.306
3792.840
3792.033
3792.085
3792.695
3793.667
3794.155
3795.048
3794.402
3794.199
3793.922
3792.516
3791.459
3791.708
3792.085
3791.104
3789.962
3789.796
3790.264
3791.506
3793.610
3796.275
3798.223
3797.903
3796.109
3794.077
3771.065
3770.659
3770.255
3769.859
3769.465
3769.088
3768.724
3768.362
3768.009
3767.673
3767.357
3767.052
3766.776
3766.514
3766.263
3766.039
3765.822
3765.607
3765.409
3765.223
3765.047
3764.880
3764.739
3764.611
3764.496
3764.399
3764.310
3764.230
3764.171
3764.119
3764.070
3764.046
3764.025
3764.008
3764.000
3763.994
3764.001
3764.014
3764.030
3764.050
3764.074
3764.102
3764.146
3764.198
3764.257
3764.321
3764.391
3764.457
3764.520
3808.844
3808.752
3808.659
3808.549
3808.438
3808.327
3808.214
3808.096
3807.965
3807.840
3807.724
3807.616
3807.513
3807.412
3807.309
3807.207
3807.100
3806.986
3806.870
3806.761
3806.652
3806.551
3806.452
3806.359
3806.264
3806.164
3806.067
3805.974
3805.890
3805.810
3805.738
3805.662
3805.585
3805.508
3805.422
3805.331
3805.243
3805.158
3805.068
3804.971
3804.875
3804.784
3804.701
3804.632
3804.580
3804.541
3804.501
3804.450
3804.387
3740.204
3740.821
3741.438
3742.055
3742.672
3743.289
3743.906
3744.523
3745.140
3745.757
3746.374
3746.991
3747.608
3748.225
3748.842
3749.459
3750.076
3750.693
3751.310
3751.927
3752.543
3753.160
3753.777
3754.394
3755.011
3755.628
3756.245
3756.862
3757.479
3758.096
3758.713
3759.330
3759.947
3760.564
3761.181
3761.798
3762.415
3763.032
3763.649
3764.266
3764.883
3765.500
3766.117
3766.734
3767.351
3767.968
3768.585
3769.202
3769.819
3704.420
3704.728
3705.037
3705.345
3705.654
3705.962
3706.271
3706.579
3706.888
3707.196
3707.504
3707.813
3708.121
3708.430
3708.738
3709.047
3709.355
3709.664
3709.972
3710.281
3710.589
3710.898
3711.206
3711.515
3711.823
3712.132
3712.440
3712.749
3713.057
3713.366
3713.674
3713.983
3714.291
3714.600
3714.908
3715.217
3715.525
3715.834
3716.142
3716.451
3716.759
3717.068
3717.376
3717.685
3717.993
3718.302
3718.610
3718.918
3719.227
003573
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
3775.492
3776.420
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.850
3786.304
3787.259
3787.516
3787.955
3788.030
3788.607
3789.216
3787.537
3785.842
3786.077
3787.930
3788.760
3786.875
3786.550
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
6.597
4.648
2.661
2.090
1.719
1.478
0.240
-1.647
-3.594
-5.220
-7.359
-9.830
-12.518
-14.986
-17.312
-17.380
-17.425
-18.176
-20.106
-21.720
-23.131
-22.606
-21.544
-22.655
-23.377
-22.765
-22.008
-23.318
-23.808
-22.685
-21.956
-22.202
-22.362
-22.466
-22.173
-21.983
-22.580
-22.968
-22.860
-21.709
-19.878
-19.411
-19.106
-18.909
-19.141
-19.291
-18.307
-17.307
-17.017
0.617
0.617
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3792.251
3790.919
3788.932
3788.361
3787.990
3787.749
3786.511
3784.624
3782.677
3781.051
3778.912
3776.441
3773.754
3771.285
3768.960
3768.891
3768.846
3768.095
3766.166
3764.551
3763.140
3763.666
3764.728
3763.617
3762.894
3763.506
3764.264
3762.953
3762.463
3763.586
3764.316
3764.069
3763.909
3763.805
3764.098
3764.288
3763.691
3763.303
3763.411
3764.562
3766.393
3766.861
3767.165
3767.363
3767.131
3766.980
3767.964
3768.964
3769.254
3764.586
3764.656
3764.738
3764.826
3764.922
3765.014
3765.118
3765.226
3765.336
3765.452
3765.565
3765.684
3765.800
3765.919
3766.038
3766.159
3766.278
3766.399
3766.523
3766.636
3766.738
3766.841
3766.953
3767.068
3767.171
3767.272
3767.376
3767.467
3767.560
3767.654
3767.746
3767.843
3767.938
3768.025
3768.113
3768.203
3768.290
3768.376
3768.463
3768.553
3768.645
3768.745
3768.845
3768.943
3769.036
3769.131
3769.226
3769.318
3769.408
3804.315
3804.235
3804.144
3804.051
3803.958
3803.863
3803.763
3803.653
3803.533
3803.405
3803.267
3803.116
3802.952
3802.776
3802.590
3802.404
3802.221
3802.036
3801.842
3801.641
3801.435
3801.234
3801.041
3800.844
3800.646
3800.452
3800.265
3800.072
3799.879
3799.694
3799.515
3799.336
3799.158
3798.981
3798.807
3798.636
3798.464
3798.292
3798.122
3797.959
3797.806
3797.658
3797.512
3797.368
3797.225
3797.082
3796.945
3796.815
3796.686
3770.436
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3719.535
3719.844
3720.149
3720.450
3720.748
3721.042
3721.333
3721.620
3721.904
3722.185
3722.463
3722.737
3723.009
3723.277
3723.542
3723.805
3724.064
3724.321
3724.575
3724.826
3725.075
3725.321
3725.564
3725.805
3726.043
3726.279
3726.512
3726.743
3726.971
3727.197
3727.421
3727.642
3727.861
3728.079
3728.293
3728.506
3728.717
3728.925
3729.132
3729.336
3729.539
3729.739
3729.938
3730.135
3730.330
3730.523
3730.714
3730.903
3731.091
003574
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
3788.933
3790.667
3790.805
3790.411
3789.769
3791.540
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.540
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.410
3790.467
3790.665
3790.420
3789.674
3789.267
3789.148
3790.430
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.080
3787.844
3787.135
3787.164
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
-16.108
-15.157
-14.178
-13.542
-12.407
-10.588
-9.406
-9.358
-9.327
-9.667
-7.364
-4.426
-1.074
2.185
4.665
5.916
6.729
8.700
10.702
12.364
13.804
14.380
15.114
16.314
17.454
17.835
19.163
20.747
22.137
23.040
22.547
21.145
21.675
22.740
24.154
24.352
24.120
23.969
24.593
25.719
27.892
28.944
29.268
28.758
26.623
24.155
23.632
24.374
25.937
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3770.163
3771.114
3772.093
3772.729
3773.864
3775.683
3776.866
3776.913
3776.945
3776.605
3778.907
3781.845
3785.197
3788.457
3790.936
3792.187
3793.000
3794.972
3796.973
3798.635
3800.075
3800.651
3801.386
3802.585
3803.725
3804.106
3805.434
3807.018
3808.408
3809.312
3808.818
3807.416
3807.946
3809.011
3810.426
3810.623
3810.391
3810.240
3810.864
3811.990
3814.163
3815.216
3815.539
3815.029
3812.895
3810.426
3809.903
3810.645
3812.208
3769.499
3769.596
3769.693
3769.788
3769.879
3769.977
3770.080
3770.174
3770.269
3770.363
3770.453
3770.541
3770.627
3770.710
3770.787
3770.862
3770.936
3771.010
3771.085
3771.159
3771.233
3771.304
3771.371
3771.434
3771.502
3771.574
3771.647
3771.715
3771.784
3771.860
3771.936
3772.011
3772.082
3772.151
3772.219
3772.292
3772.362
3772.417
3772.476
3772.541
3772.611
3772.686
3772.764
3772.840
3772.903
3772.961
3773.018
3773.071
3773.125
3796.564
3796.446
3796.335
3796.227
3796.125
3796.033
3795.946
3795.861
3795.777
3795.691
3795.617
3795.556
3795.511
3795.480
3795.460
3795.446
3795.436
3795.434
3795.440
3795.454
3795.474
3795.495
3795.520
3795.550
3795.584
3795.619
3795.660
3795.706
3795.758
3795.814
3795.867
3795.913
3795.962
3796.014
3796.072
3796.130
3796.187
3796.242
3796.300
3796.361
3796.431
3796.504
3796.578
3796.649
3796.711
3796.764
3796.814
3796.867
3796.925
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3731.277
3731.461
3731.643
3731.824
3732.003
3732.181
3732.356
3732.531
3732.704
3732.875
3733.044
3733.213
3733.379
3733.545
3733.708
3733.871
3734.032
3734.191
3734.349
3734.506
3734.662
3734.816
3734.969
3735.120
3735.271
3735.420
3735.568
3735.714
3735.860
3736.004
3736.147
3736.289
3736.430
3736.569
3736.708
3736.845
3736.982
3737.117
3737.251
3737.384
3737.516
3737.647
3737.777
3737.906
3738.034
3738.161
3738.287
3738.412
3738.536
003575
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.690
3784.831
3785.010
3784.320
3782.809
3782.110
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.170
3771.730
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
25.510
25.595
26.370
28.316
30.662
32.548
33.413
32.893
32.195
32.464
33.719
34.895
33.496
31.867
32.610
33.093
32.686
32.782
32.483
33.011
33.354
33.937
34.677
32.994
33.343
34.290
35.987
36.369
34.455
34.292
33.465
33.289
34.976
35.352
33.793
31.699
32.141
33.509
33.317
32.831
33.237
34.582
34.735
30.148
23.201
21.208
23.159
26.950
30.135
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3811.782
3811.866
3812.641
3814.587
3816.933
3818.819
3819.685
3819.165
3818.467
3818.735
3819.990
3821.166
3819.767
3818.138
3818.881
3819.365
3818.957
3819.053
3818.754
3819.282
3819.625
3820.208
3820.948
3819.265
3819.614
3820.562
3822.258
3822.641
3820.726
3820.564
3819.736
3819.560
3821.247
3821.623
3820.064
3817.970
3818.412
3819.780
3819.589
3819.102
3819.508
3820.853
3821.007
3816.420
3809.472
3807.480
3809.430
3813.221
3816.406
3773.177
3773.230
3773.280
3773.332
3773.391
3773.454
3773.520
3773.588
3773.652
3773.707
3773.763
3773.819
3773.868
3773.910
3773.950
3773.989
3774.026
3774.057
3774.085
3774.104
3774.121
3774.137
3774.155
3774.173
3774.181
3774.186
3774.194
3774.202
3774.208
3774.205
3774.196
3774.178
3774.159
3774.141
3774.119
3774.088
3774.042
3773.994
3773.954
3773.914
3773.870
3773.825
3773.780
3773.733
3773.682
3773.616
3773.550
3773.480
3773.417
3796.981
3797.037
3797.095
3797.160
3797.234
3797.314
3797.396
3797.476
3797.553
3797.631
3797.712
3797.797
3797.876
3797.949
3798.024
3798.100
3798.175
3798.249
3798.321
3798.395
3798.469
3798.545
3798.623
3798.695
3798.768
3798.843
3798.923
3799.004
3799.079
3799.152
3799.221
3799.290
3799.364
3799.439
3799.508
3799.569
3799.632
3799.699
3799.764
3799.828
3799.892
3799.961
3800.029
3800.083
3800.113
3800.137
3800.167
3800.208
3800.260
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3738.659
3738.781
3738.903
3739.023
3739.143
3739.261
3739.379
3739.496
3739.612
3739.727
3739.841
3739.955
3740.068
3740.180
3740.291
3740.401
3740.510
3740.619
3740.727
3740.834
3740.940
3741.046
3741.151
3741.255
3741.359
3741.461
3741.563
3741.665
3741.765
3741.865
3741.965
3742.063
3742.161
3742.259
3742.355
3742.451
3742.546
3742.641
3742.735
3742.829
3742.922
3743.014
3743.105
3743.196
3743.287
3743.377
3743.466
3743.555
3743.643
003576
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
3758.225
3759.250
3758.041
3760.965
3762.022
3763.822
3763.100
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.570
3761.920
3759.627
3758.522
3752.429
3750.102
3753.830
3753.510
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.370
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.650
3737.541
3738.012
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
33.286
35.334
37.027
38.128
39.203
38.820
40.014
41.871
44.880
46.116
46.559
45.765
45.608
43.706
41.747
41.195
41.558
40.350
39.566
38.335
36.454
35.232
34.437
33.199
31.313
30.808
32.642
33.114
33.421
31.818
29.333
28.079
29.426
28.861
28.133
26.217
23.891
22.379
21.396
20.397
19.748
18.604
18.582
18.928
19.874
20.128
21.014
21.590
21.244
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3819.557
3821.606
3823.299
3824.399
3825.475
3825.091
3826.285
3828.142
3831.151
3832.387
3832.830
3832.036
3831.880
3829.977
3828.018
3827.467
3827.829
3826.622
3825.837
3824.606
3822.726
3821.503
3820.709
3819.470
3817.584
3817.079
3818.914
3819.386
3819.692
3818.089
3815.604
3814.351
3815.698
3815.132
3814.404
3812.488
3810.162
3808.650
3807.667
3806.668
3806.019
3804.875
3804.853
3805.199
3806.145
3806.399
3807.285
3807.861
3807.515
3773.368
3773.323
3773.275
3773.236
3773.201
3773.171
3773.140
3773.111
3773.083
3773.062
3773.047
3773.032
3773.014
3772.992
3772.960
3772.926
3772.892
3772.852
3772.809
3772.748
3772.680
3772.624
3772.567
3772.510
3772.452
3772.395
3772.337
3772.281
3772.225
3772.167
3772.101
3772.029
3771.938
3771.849
3771.777
3771.702
3771.621
3771.536
3771.447
3771.354
3771.262
3771.167
3771.071
3770.974
3770.877
3770.778
3770.681
3770.589
3770.499
3800.322
3800.389
3800.462
3800.537
3800.616
3800.692
3800.772
3800.858
3800.952
3801.049
3801.147
3801.242
3801.336
3801.424
3801.505
3801.584
3801.663
3801.739
3801.811
3801.880
3801.942
3802.001
3802.056
3802.108
3802.154
3802.198
3802.247
3802.297
3802.348
3802.394
3802.432
3802.467
3802.505
3802.541
3802.576
3802.604
3802.626
3802.643
3802.657
3802.668
3802.678
3802.684
3802.690
3802.697
3802.707
3802.717
3802.730
3802.744
3802.757
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3743.730
3743.817
3743.904
3743.990
3744.075
3744.160
3744.244
3744.328
3744.411
3744.494
3744.576
3744.658
3744.739
3744.820
3744.900
3744.980
3745.059
3745.138
3745.216
3745.294
3745.371
3745.448
3745.525
3745.601
3745.676
3745.751
3745.826
3745.900
3745.974
3746.047
3746.120
3746.193
3746.265
3746.336
3746.408
3746.478
3746.549
3746.619
3746.688
3746.758
3746.826
3746.895
3746.963
3747.031
3747.098
3747.165
3747.231
3747.297
3747.363
003577
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.860
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.340
3750.700
3749.750
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.830
3737.583
3736.229
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
20.658
20.638
21.345
22.526
24.736
26.533
28.421
27.847
27.114
26.275
27.173
28.837
29.198
28.352
28.523
28.634
28.706
26.950
24.007
23.535
23.949
25.301
25.819
25.073
24.589
23.913
23.114
21.874
22.509
24.004
26.057
27.391
28.259
28.462
30.037
31.781
32.915
31.849
30.435
29.877
30.595
29.981
28.861
28.493
29.335
29.522
28.563
25.055
21.693
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3806.929
3806.909
3807.617
3808.797
3811.007
3812.804
3814.692
3814.118
3813.385
3812.546
3813.444
3815.108
3815.470
3814.624
3814.794
3814.905
3814.977
3813.221
3810.278
3809.807
3810.221
3811.572
3812.090
3811.345
3810.860
3810.185
3809.385
3808.145
3808.780
3810.276
3812.328
3813.663
3814.530
3814.733
3816.308
3818.052
3819.186
3818.120
3816.707
3816.148
3816.866
3816.252
3815.132
3814.764
3815.606
3815.793
3814.834
3811.327
3807.964
3770.406
3770.313
3770.220
3770.126
3770.035
3769.949
3769.865
3769.782
3769.698
3769.612
3769.525
3769.441
3769.362
3769.285
3769.213
3769.142
3769.072
3769.001
3768.930
3768.854
3768.780
3768.705
3768.633
3768.566
3768.495
3768.421
3768.346
3768.270
3768.194
3768.122
3768.046
3767.971
3767.909
3767.847
3767.790
3767.735
3767.684
3767.641
3767.597
3767.543
3767.487
3767.428
3767.368
3767.301
3767.233
3767.150
3767.064
3766.992
3766.917
3802.769
3802.780
3802.793
3802.810
3802.832
3802.859
3802.891
3802.921
3802.950
3802.975
3803.004
3803.036
3803.069
3803.100
3803.131
3803.162
3803.193
3803.220
3803.238
3803.255
3803.273
3803.295
3803.318
3803.339
3803.358
3803.376
3803.391
3803.403
3803.417
3803.435
3803.457
3803.483
3803.511
3803.539
3803.572
3803.608
3803.647
3803.683
3803.716
3803.747
3803.779
3803.810
3803.838
3803.865
3803.894
3803.923
3803.950
3803.968
3803.977
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3747.429
3747.494
3747.559
3747.623
3747.687
3747.751
3747.814
3747.877
3747.940
3748.002
3748.064
3748.125
3748.187
3748.248
3748.308
3748.369
3748.429
3748.488
3748.548
3748.607
3748.666
3748.724
3748.782
3748.840
3748.898
3748.955
3749.012
3749.068
3749.125
3749.181
3749.237
3749.292
3749.347
3749.402
3749.457
3749.511
3749.566
3749.619
3749.673
3749.726
3749.779
3749.832
3749.885
3749.937
3749.989
3750.041
3750.092
3750.143
3750.194
003578
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3734.897
3733.434
3733.115
3730.510
3729.180
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.560
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.100
3690.477
3696.865
3696.877
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
19.508
18.087
16.443
14.654
13.491
13.816
13.667
12.488
10.280
8.125
4.921
2.118
-0.066
-2.206
-5.760
-8.791
-12.564
-15.737
-19.242
-21.881
-23.956
-26.026
-27.371
-31.129
-33.212
-34.926
-36.040
-36.404
-38.443
-40.489
-42.179
-42.918
-44.480
-46.216
-46.624
-46.889
-45.979
-45.388
-45.364
-44.988
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3805.779
3804.359
3802.715
3800.926
3799.763
3800.088
3799.939
3798.759
3796.552
3794.396
3791.192
3788.389
3786.205
3784.065
3780.511
3777.480
3773.707
3770.534
3767.029
3764.390
3762.315
3760.245
3758.900
3755.142
3753.060
3751.346
3750.231
3749.868
3747.828
3745.782
3744.092
3743.353
3741.791
3740.055
3739.647
3739.382
3740.292
3740.884
3740.908
3741.284
3766.839
3766.758
3766.677
3766.590
3766.500
3766.401
3766.302
3766.192
3766.084
3765.988
3765.892
3765.802
3765.713
3765.623
3765.533
3765.438
3765.347
3765.255
3765.148
3765.035
3764.924
3764.815
3764.705
3764.591
3764.474
3764.350
3764.227
3764.079
3763.930
3763.796
3763.659
3763.521
3763.380
3763.240
3763.097
3762.955
3762.793
3762.632
3762.485
3762.340
3803.982
3803.983
3803.980
3803.972
3803.962
3803.953
3803.943
3803.931
3803.913
3803.891
3803.861
3803.824
3803.782
3803.736
3803.681
3803.620
3803.550
3803.473
3803.389
3803.298
3803.203
3803.104
3803.002
3802.892
3802.778
3802.660
3802.540
3802.420
3802.296
3802.168
3802.037
3801.904
3801.769
3801.630
3801.491
3801.352
3801.216
3801.082
3800.948
3800.816
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3750.245
3750.296
3750.346
3750.396
3750.446
3750.495
3750.545
3750.594
3750.642
3750.691
3750.739
3750.788
3750.835
3750.883
3750.931
3750.978
3751.025
3751.072
3751.118
3751.165
3751.211
3751.257
3751.302
3751.348
3751.393
3751.438
3751.483
3751.528
3751.572
3751.617
3751.661
3751.705
3751.748
3751.792
3751.835
3751.878
3751.921
3751.964
3752.006
3752.049
003579
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
2:27:24
Time of Frequency Recovery to 60 Hz or Pre-Perturbatio
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(Value B Post-Perturbation Average Frequency [T(+20 to T(+
Pre to Post Perturbation Delta Frequency Ac
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(Value B Post-Perturbation Average Interchange MW [T(+20 to T(+
Pre to Post Perturbation Interchange Delta MW Ac
EPFR Pre-Perturbation Ave
EPFR Post-Perturbation Ave
Pre JOU Dynamic Schedules
Pre Non-Conforming Load
Pre Transferred Frequency Response
Pre Contingent BA Lost Generation
Sum of Pre Perturbation Adjustm
eriod (indicates ramp direction during recovery period)
Post JOU Dynamic Schedules
Post Non-Conforming Load
Post Transferred Frequency Response
Post Contingent BA Lost Generation
Sum of Post Perturbation Adjustm
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
20 to 52 second Average Period Evaluation
Initial P.U. Performance for
Initial P.U. Performance Adjusted for
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
Frequency
Hz
Net
Actual
Interchange
MW
60.027
60.026
60.026
60.022
60.019
60.017
3671.19
3668.61
3665.23
3664.50
3666.06
3666.82
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
157.63
155.53
155.53
155.53
155.53
155.53
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
0.00
0.00
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
10.00
10.00
10.00
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
BA
Load
MW
7640.91
7641.24
7641.57
7641.90
7642.23
7642.56
Expected Primary
Freq Response
Based on Bias Setting
MW
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
Frequency
Hz
Net
Actual
Interchange
MW
003580
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
60.019
60.020
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.880
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.890
59.895
59.894
3666.79
3670.45
3670.27
3671.67
3672.49
3672.69
3672.86
3672.16
3671.41
3669.98
3666.47
3663.76
3661.60
3660.67
3651.49
3649.19
3650.03
3648.25
3649.51
3654.29
3655.01
3651.87
3651.06
3649.19
3648.24
3645.39
3644.63
3645.45
3640.68
3641.19
3659.46
3696.36
3734.90
3734.67
3734.67
3737.16
3761.25
3766.11
3766.19
3768.88
3769.93
3780.62
3781.59
3782.50
3784.96
3784.73
3784.42
3788.07
3788.33
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
160.45
160.45
160.45
160.45
160.45
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
166.07
166.07
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
3.00
4.00
5.00
6.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.20
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.50
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.80
7652.13
7652.46
7652.79
7616.00
7626.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
003581
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
59.893
59.894
59.894
59.891
59.890
59.885
59.885
59.888
59.887
59.888
59.888
59.890
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.880
59.883
59.886
59.890
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.920
59.921
59.920
59.917
3788.87
3788.47
3792.28
3793.07
3794.37
3799.43
3800.43
3799.96
3803.63
3802.93
3802.95
3804.39
3805.50
3805.62
3809.24
3811.50
3814.86
3815.89
3825.64
3826.05
3826.00
3827.52
3826.75
3826.78
3826.45
3825.71
3823.83
3822.51
3819.08
3818.06
3816.81
3815.01
3813.78
3811.84
3809.65
3806.97
3805.59
3804.19
3796.08
3793.98
3792.17
3791.50
3789.53
3788.13
3784.56
3783.03
3781.70
3776.36
3775.64
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
212.17
212.17
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
229.47
229.47
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7623.00
7621.00
7623.00
7625.00
7627.00
7628.00
7628.00
7629.00
7630.00
7631.00
7635.00
7638.00
7639.00
7642.00
7644.00
7645.00
7647.00
7648.00
7649.00
7650.00
7651.00
7652.00
7653.00
7654.00
7655.00
7655.00
7656.00
7656.00
7657.00
7657.00
7658.00
7658.00
7659.00
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
003582
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
59.920
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
3774.60
3773.33
3773.96
3772.72
3771.67
3769.63
3768.71
3767.64
3767.02
3767.41
3766.79
3766.26
3765.67
3766.12
3764.24
3765.10
3762.94
3758.39
3753.92
3749.87
3746.89
3747.88
3749.59
3748.66
3746.71
3749.08
3742.74
3740.26
3736.14
3731.38
3727.84
3725.95
3722.65
3720.58
3718.00
3718.14
3715.75
3713.69
3713.48
3710.85
3710.81
3712.09
3714.62
3715.13
3716.17
3716.46
3716.98
3717.76
3722.36
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
229.09
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
218.62
218.62
213.54
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
212.57
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7659.00
7659.00
7660.00
7660.00
7661.00
7661.00
7662.00
7662.00
7663.00
7663.00
7664.00
7664.00
7665.00
7666.00
7666.00
7667.00
7668.00
7668.00
7669.00
7669.00
7670.00
7670.00
7671.00
7671.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7676.00
7677.00
7678.00
7679.00
7680.00
7681.00
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
003583
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.970
59.974
59.970
59.969
59.969
59.970
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.980
59.982
59.981
59.980
59.979
59.980
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
3721.97
3722.66
3722.27
3722.28
3721.79
3723.09
3723.98
3723.43
3723.89
3725.40
3727.12
3728.05
3731.13
3732.53
3733.33
3736.54
3736.91
3736.82
3738.70
3739.94
3740.88
3741.79
3745.23
3746.61
3748.30
3750.72
3751.56
3752.75
3755.60
3756.41
3756.98
3760.41
3760.98
3761.41
3762.74
3763.21
3764.96
3766.09
3766.43
3767.25
3767.79
3768.63
3771.15
3772.44
3773.69
3774.67
3775.84
3775.36
3774.87
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
221.46
221.46
221.46
221.46
221.46
241.27
241.27
241.27
241.27
241.27
243.07
243.07
243.07
243.07
243.07
241.67
241.67
241.67
241.67
241.67
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7682.00
7684.00
7685.00
7687.00
7689.00
7690.00
7692.00
7692.00
7693.00
7693.00
7694.00
7694.00
7695.00
7695.00
7695.00
7696.00
7696.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.30
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.60
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
003584
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.020
60.025
60.024
60.020
60.020
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
3775.49
3776.42
3778.55
3779.69
3781.26
3780.59
3783.09
3783.90
3784.42
3785.77
3785.46
3786.85
3786.30
3787.26
3787.52
3787.96
3788.03
3788.61
3789.22
3787.54
3785.84
3786.08
3787.93
3788.76
3786.87
3786.55
3787.36
3785.02
3785.61
3785.95
3785.80
3786.86
3786.88
3785.25
3785.73
3786.35
3785.82
3785.80
3786.28
3786.94
3787.63
3789.44
3789.67
3789.40
3788.48
3789.18
3789.37
3789.00
3788.66
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
228.15
228.15
228.15
228.15
228.15
235.13
235.13
235.13
235.13
235.13
246.43
246.43
246.43
246.43
246.43
236.55
236.55
236.55
236.55
236.55
230.30
230.30
230.30
230.30
230.30
231.18
231.18
231.18
231.18
231.18
225.62
225.62
225.62
225.62
225.62
230.73
230.73
230.73
230.73
230.73
234.85
234.85
234.85
234.85
234.85
228.96
228.96
228.96
228.96
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7707.24
7707.57
7707.90
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.20
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.50
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.80
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.10
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
003585
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
60.014
60.013
60.012
60.012
60.010
60.007
60.007
60.009
60.009
60.010
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.970
59.971
59.973
59.978
59.981
59.978
59.975
59.972
3788.93
3790.67
3790.81
3790.41
3789.77
3791.54
3792.95
3791.03
3791.44
3791.43
3790.60
3790.46
3790.22
3789.58
3788.46
3788.10
3788.06
3788.19
3788.50
3788.54
3788.57
3788.10
3787.13
3786.45
3787.73
3788.81
3789.29
3788.26
3788.41
3790.47
3790.66
3790.42
3789.67
3789.27
3789.15
3790.43
3789.91
3786.24
3787.44
3788.96
3790.60
3791.88
3792.91
3792.31
3789.13
3788.08
3787.84
3787.14
3787.16
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
228.96
231.18
231.18
231.18
231.18
231.18
236.49
236.49
236.49
236.49
236.49
245.04
245.04
245.04
245.04
245.04
223.61
223.61
223.61
223.61
223.61
231.12
231.12
231.12
231.12
231.12
237.21
237.21
237.21
237.21
237.21
240.52
240.52
240.52
240.52
240.52
237.57
237.57
237.57
237.57
237.57
231.58
231.58
231.58
231.58
231.58
235.85
235.85
235.85
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7723.41
7723.74
7724.07
7724.40
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.70
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731.00
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.30
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.60
7737.93
7738.26
7738.59
7738.92
7739.25
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
003586
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.970
59.968
59.965
59.964
59.970
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.970
59.967
59.969
59.968
59.963
59.965
59.970
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.990
59.983
59.974
59.967
59.965
3787.00
3787.40
3786.49
3787.08
3789.21
3790.51
3791.22
3792.22
3790.96
3788.82
3789.03
3789.17
3787.39
3785.69
3784.83
3785.01
3784.32
3782.81
3782.11
3779.35
3779.06
3778.63
3779.21
3779.33
3776.43
3775.65
3776.60
3776.56
3776.02
3773.17
3771.73
3768.79
3768.50
3768.92
3767.37
3764.79
3760.30
3759.59
3761.89
3761.78
3760.58
3760.16
3759.78
3759.49
3757.77
3753.28
3753.09
3751.64
3753.75
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
235.85
235.85
233.56
233.56
233.56
233.56
233.56
219.01
219.01
219.01
219.01
219.01
205.34
205.34
205.34
205.34
205.34
236.29
236.29
236.29
236.29
236.29
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7739.58
7739.91
7740.24
7740.57
7740.90
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.20
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.50
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.80
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.10
7754.43
7754.76
7755.09
7755.42
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
003587
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
59.962
59.962
59.961
59.961
59.960
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.970
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.980
59.978
59.978
59.980
3758.22
3759.25
3758.04
3760.96
3762.02
3763.82
3763.10
3763.86
3764.16
3766.13
3768.34
3767.97
3767.44
3765.61
3762.69
3761.57
3761.92
3759.63
3758.52
3752.43
3750.10
3753.83
3753.51
3753.52
3752.74
3753.18
3752.73
3753.29
3752.87
3752.36
3749.40
3747.48
3740.37
3741.29
3746.65
3745.74
3743.35
3741.62
3740.31
3738.48
3738.90
3737.40
3737.27
3736.31
3736.27
3735.45
3735.65
3737.54
3738.01
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7755.75
7756.08
7756.41
7756.74
7757.07
7757.40
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.70
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764.00
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.30
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.60
7770.93
7771.26
7771.59
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
003588
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
59.981
59.980
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.970
59.971
59.974
59.982
59.985
3736.75
3736.69
3736.07
3736.09
3736.57
3738.57
3738.87
3738.93
3738.65
3737.68
3737.38
3737.89
3740.02
3740.33
3742.05
3742.42
3742.52
3742.25
3741.72
3740.09
3740.63
3739.96
3740.78
3742.83
3741.27
3739.78
3738.97
3738.71
3738.88
3739.86
3738.10
3738.56
3743.51
3743.42
3745.25
3745.74
3747.34
3750.70
3749.75
3746.22
3744.68
3743.75
3743.15
3740.30
3739.45
3733.38
3731.83
3737.58
3736.23
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.90
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.20
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.50
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.80
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.10
7787.43
7787.76
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
003589
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.990
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3734.90
3733.43
3733.12
3730.51
3729.18
3725.46
3724.78
3720.11
3720.94
3725.66
3725.68
3727.75
3727.82
3727.68
3727.23
3725.01
3726.45
3726.02
3719.12
3716.37
3717.33
3717.56
3717.14
3715.17
3713.63
3710.28
3710.16
3699.36
3698.59
3704.59
3703.28
3702.48
3701.32
3700.83
3699.53
3699.73
3690.10
3690.48
3696.86
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.40
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.70
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797.00
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.30
7800.63
7800.96
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
003590
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
uency Recovery to 60 Hz or Pre-Perturbation Hz
erturbation Average Frequency [T(-2 ) to T(-16)]
rturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
ation Average Interchange MW [T(-2 ) to T(-16)]
tion Average Interchange MW [T(+20 to T(+52)]
Post Perturbation Interchange Delta MW Actual
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3803.35
157.63
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
-43.39
114.21
157.60
198.04
350.00
165.34
0.00
MW
MW
MW
MW
MW
MW
MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
-4.21 MW
15.00 MW
526.12 MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
335.00 MW
214.13 MW
6.35 MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
11.09
0.00
566.57
40.45
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.890
59.863
59.899
59.920
59.937
113.30
141.11
104.03
82.40
64.89
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-103.00
Post-Perturbation Bias Setting
-103.00
EPFR for Bias Setting Pre-Perturbation Average
-43.39
EPFR for Bias Setting Post-Perturbation Average
114.21
EPFR for Bias Setting Delta
157.60
Primary Frequency Response Delivery % of Bias
100.02%
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
Average Bias Setting when Hz is greater than +/-0.036 Hz
7651.3
7632.0
-19.305
-12.617
12.25%
Hz
Hz
Hz
Hz
Hz
MW
MW
MW
MW
MW
Actual
Primary
Freq Response
MW
158.51
182.41
164.54
129.49
119.99
Un-adjusted
P.U.
Performance
1.399
1.293
1.582
1.571
1.849
JOU
NonTransferred
Contingent
Dynamic
Conforming
Pumped
Frequency
BA
Schedules
Load
Hydro
Response
Lost Generation
Adjustment
Adjustment Adjustment Adjustment
Adjustment
-15.00
50.26
11.00
15.21
-15.00
-15.00
49.49
16.00
17.91
-15.00
-15.00
63.03
16.00
14.31
-15.00
-15.00
64.13
16.00
12.21
-15.00
-15.00
63.75
16.00
10.51
-15.00
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
-103.00 MW/0.1 Hz
d Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonDynamic
Conforming
Schedules
Load
Imp(-) Exp (+)
Load (-)
MW
MW
1.000 P.U.
0.744 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
Actual
Primary
Freq Response
MW
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
0.0270
0.0260
0.0260
0.0220
0.0190
0.0170
003591
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
51.252
89.794
89.563
89.563
92.047
116.139
121.003
121.084
123.767
124.815
135.511
136.482
137.389
139.852
139.620
139.309
142.962
143.218
-26.96
-43.56
-51.73
-51.73
-61.31
-76.85
-74.64
-72.89
-74.06
-78.44
-87.36
-87.42
-87.44
-90.15
-90.59
-91.57
-97.17
-96.69
0.0190
0.0200
0.0190
0.0210
0.0210
0.0210
0.0190
0.0180
0.0220
0.0310
0.0370
0.0370
0.0360
0.0370
0.0460
0.0480
0.0480
0.0430
0.0410
0.0410
0.0410
0.0390
0.0410
0.0430
0.0450
0.0460
0.0410
0.0410
0.0410
0.0390
0.0220
0.1480
0.1640
0.1310
0.1310
0.1080
0.1090
0.1200
0.1240
0.1250
0.1170
0.1130
0.1140
0.1150
0.1130
0.1120
0.1100
0.1050
0.1060
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003592
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
143.758
143.362
147.166
147.964
149.264
154.318
155.317
154.849
158.515
157.815
157.841
159.278
160.386
160.507
164.127
166.393
169.752
170.779
180.532
180.943
180.892
182.414
181.643
181.673
181.344
180.603
178.716
177.395
173.971
172.945
171.705
169.900
168.673
166.728
164.542
161.862
160.483
159.078
150.968
148.865
147.059
146.392
144.424
143.022
139.453
137.918
136.591
131.248
130.525
-96.40
-96.78
-99.35
-97.91
-98.12
-98.21
-98.85
-100.47
-102.19
-102.39
-102.41
-104.70
-104.74
-100.24
-97.05
-89.88
-87.90
-89.82
-98.05
-101.01
-102.71
-102.99
-103.72
-103.15
-105.97
-107.42
-109.56
-109.42
-109.33
-110.77
-112.87
-113.17
-110.15
-111.81
-114.96
-116.34
-114.53
-113.53
-109.30
-110.17
-112.15
-116.07
-114.51
-114.30
-112.35
-112.93
-112.77
-107.47
-104.32
0.1070
0.1060
0.1060
0.1090
0.1100
0.1150
0.1150
0.1120
0.1130
0.1120
0.1120
0.1100
0.1110
0.1180
0.1270
0.1430
0.1510
0.1480
0.1420
0.1370
0.1340
0.1350
0.1330
0.1340
0.1290
0.1260
0.1210
0.1200
0.1170
0.1140
0.1100
0.1080
0.1110
0.1070
0.1010
0.0970
0.0980
0.0980
0.0960
0.0930
0.0890
0.0840
0.0840
0.0830
0.0820
0.0800
0.0790
0.0800
0.0830
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003593
129.494
128.224
128.848
127.612
126.560
124.520
123.597
122.533
121.911
122.298
121.678
121.149
120.562
121.012
119.133
119.995
117.825
113.277
108.812
104.757
101.779
102.765
104.483
103.551
101.596
103.967
97.631
95.149
91.029
86.272
82.728
80.842
77.539
75.468
72.886
73.032
70.643
68.584
68.374
65.738
65.700
66.982
69.512
70.020
71.058
71.351
71.870
72.649
77.251
-106.03
-105.86
-108.16
-109.89
-108.05
-109.11
-107.36
-111.27
-105.89
-107.16
-109.50
-107.09
-108.49
-110.89
-113.32
-114.15
-121.31
-121.64
-114.39
-104.63
-100.65
-102.64
-107.58
-110.02
-106.80
-111.64
-107.14
-105.57
-102.14
-94.67
-91.79
-89.70
-86.03
-86.62
-80.87
-82.87
-78.38
-76.95
-76.72
-72.94
-74.55
-76.01
-83.62
-82.26
-82.51
-80.96
-83.45
-83.39
-91.83
0.0800
0.0790
0.0770
0.0740
0.0750
0.0720
0.0730
0.0680
0.0730
0.0720
0.0690
0.0710
0.0690
0.0670
0.0630
0.0630
0.0550
0.0510
0.0530
0.0580
0.0590
0.0580
0.0550
0.0520
0.0530
0.0510
0.0490
0.0480
0.0470
0.0490
0.0480
0.0480
0.0480
0.0450
0.0480
0.0460
0.0480
0.0470
0.0470
0.0480
0.0460
0.0460
0.0410
0.0430
0.0440
0.0460
0.0440
0.0450
0.0420
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003594
76.863
77.548
77.157
77.168
76.677
77.981
78.874
78.324
78.783
80.293
82.011
82.943
86.020
87.420
88.217
91.425
91.797
91.712
93.589
94.834
95.767
96.684
100.124
101.498
103.190
105.606
106.448
107.637
110.489
111.297
111.865
115.295
115.872
116.297
117.627
118.102
119.847
120.975
121.323
122.141
122.682
123.523
126.036
127.335
128.585
129.558
130.731
130.253
129.756
-94.74
-96.79
-96.30
-104.10
-100.72
-102.44
-106.40
-108.60
-115.64
-111.33
-112.15
-113.43
-119.27
-122.91
-127.62
-132.26
-138.83
-143.02
-145.95
-143.42
-149.35
-146.22
-156.14
-155.85
-166.10
-175.64
-174.14
-173.26
-175.03
-179.15
-177.21
-195.01
-195.98
-200.08
-217.32
-222.30
-217.41
-219.45
-237.31
-248.63
-244.75
-241.61
-237.24
-226.88
-217.48
-219.13
-241.53
-265.15
-281.30
0.0390
0.0380
0.0380
0.0320
0.0340
0.0340
0.0320
0.0300
0.0260
0.0300
0.0310
0.0310
0.0300
0.0290
0.0270
0.0270
0.0240
0.0220
0.0220
0.0240
0.0220
0.0240
0.0220
0.0230
0.0200
0.0180
0.0190
0.0200
0.0210
0.0200
0.0210
0.0170
0.0170
0.0160
0.0120
0.0110
0.0130
0.0130
0.0090
0.0070
0.0080
0.0090
0.0110
0.0140
0.0170
0.0170
0.0120
0.0070
0.0040
-103
-103
-103
003595
130.382
131.310
132.827
133.965
135.529
134.868
137.365
138.168
138.694
140.041
139.736
141.123
140.577
141.532
141.789
142.228
142.303
142.880
143.489
141.810
140.115
140.350
142.203
143.033
141.148
140.823
141.631
139.291
139.887
140.222
140.077
141.137
141.150
139.527
139.999
140.620
140.094
140.071
140.557
141.212
141.900
143.717
143.946
143.677
142.752
143.456
143.642
143.278
142.938
-295.49
-304.49
0.0020
0.0010
0.0010
0.0010
0.0010
0.0010
0.0020
0.0050
0.0070
0.0080
0.0110
0.0140
0.0170
0.0190
0.0210
0.0170
0.0170
0.0190
0.0230
0.0240
0.0250
0.0210
0.0190
0.0240
0.0240
0.0210
0.0200
0.0250
0.0240
0.0200
0.0200
0.0220
0.0220
0.0220
0.0210
0.0210
0.0230
0.0230
0.0220
0.0190
0.0160
0.0180
0.0180
0.0180
0.0190
0.0190
0.0160
0.0150
0.0160
003596
143.206
144.940
145.078
144.684
144.042
145.813
147.218
145.300
145.716
145.699
144.876
144.730
144.489
143.858
142.730
142.378
142.330
142.462
142.770
142.813
142.844
142.374
141.406
140.726
142.005
143.086
143.558
142.529
142.683
144.740
144.938
144.693
143.947
143.540
143.421
144.703
144.187
140.516
141.715
143.236
144.875
146.150
147.184
146.584
143.398
142.353
142.117
141.408
141.437
0.0140
0.0130
0.0120
0.0120
0.0100
0.0070
0.0070
0.0090
0.0090
0.0100
0.0030
0.0010
0.0050
0.0080
0.0090
0.0080
0.0080
0.0120
0.0140
0.0150
0.0160
0.0150
0.0160
0.0180
0.0190
0.0180
0.0210
0.0230
0.0240
0.0240
0.0210
0.0180
0.0220
0.0240
0.0260
0.0240
0.0230
0.0230
0.0250
0.0270
0.0310
0.0300
0.0290
0.0270
0.0220
0.0190
0.0220
0.0250
0.0280
003597
141.269
141.678
140.760
141.352
143.487
144.785
145.494
146.491
145.232
143.097
143.299
143.440
141.667
139.963
139.104
139.282
138.593
137.082
136.383
133.625
133.329
132.906
133.485
133.608
130.702
129.920
130.870
130.832
130.296
127.443
126.003
123.066
122.776
123.190
121.639
119.059
114.568
113.865
116.167
116.050
114.855
114.430
114.054
113.768
112.046
107.550
107.360
105.910
108.024
0.0240
0.0250
0.0270
0.0310
0.0340
0.0350
0.0340
0.0310
0.0300
0.0320
0.0350
0.0360
0.0300
0.0280
0.0330
0.0330
0.0310
0.0320
0.0310
0.0330
0.0330
0.0340
0.0350
0.0290
0.0330
0.0350
0.0380
0.0360
0.0300
0.0330
0.0310
0.0320
0.0370
0.0350
0.0300
0.0270
0.0320
0.0350
0.0320
0.0310
0.0330
0.0360
0.0340
0.0210
0.0100
0.0170
0.0260
0.0330
0.0350
-103
-103
003598
112.498
113.523
112.314
115.238
116.295
118.095
117.373
118.131
118.431
120.400
122.612
122.245
121.710
119.879
116.961
115.843
116.193
113.900
112.795
106.702
104.375
108.103
107.783
107.796
107.014
107.451
107.002
107.563
107.145
106.632
103.671
101.749
94.643
95.558
100.924
100.011
97.624
95.891
94.579
92.757
93.174
91.677
91.546
90.581
90.545
89.721
89.923
91.813
92.285
0.0380
0.0380
0.0390
0.0390
0.0400
0.0370
0.0410
0.0440
0.0490
0.0470
0.0460
0.0430
0.0440
0.0390
0.0370
0.0390
0.0410
0.0370
0.0370
0.0350
0.0320
0.0320
0.0320
0.0300
0.0270
0.0290
0.0350
0.0330
0.0330
0.0280
0.0240
0.0250
0.0310
0.0270
0.0260
0.0220
0.0190
0.0190
0.0190
0.0180
0.0180
0.0160
0.0180
0.0190
0.0210
0.0200
0.0220
0.0220
0.0200
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003599
91.021
90.966
90.340
90.367
90.848
92.844
93.148
93.208
92.920
91.957
91.655
92.165
94.290
94.602
96.326
96.697
96.797
96.518
95.996
94.358
94.902
94.237
95.048
97.105
95.541
94.049
93.239
92.979
93.152
94.133
92.375
92.831
97.780
97.692
99.524
100.017
101.613
104.973
104.023
100.490
98.956
98.018
97.422
94.572
93.726
87.649
86.103
91.855
90.502
0.0190
0.0200
0.0220
0.0240
0.0280
0.0290
0.0310
0.0260
0.0250
0.0240
0.0280
0.0310
0.0290
0.0260
0.0280
0.0280
0.0280
0.0230
0.0180
0.0220
0.0240
0.0270
0.0260
0.0230
0.0230
0.0220
0.0210
0.0190
0.0230
0.0260
0.0290
0.0290
0.0290
0.0280
0.0320
0.0340
0.0340
0.0290
0.0270
0.0280
0.0310
0.0280
0.0260
0.0270
0.0300
0.0290
0.0260
0.0180
0.0150
003600
89.170
87.707
87.388
84.783
83.453
79.732
79.058
74.381
75.211
79.934
79.950
82.027
82.098
81.956
81.504
79.285
80.719
80.289
73.396
70.647
71.605
71.833
71.415
69.439
67.905
64.556
64.431
53.629
52.864
58.864
57.548
56.755
55.589
55.099
53.802
53.999
44.373
44.750
51.137
51.150
0.0150
0.0150
0.0130
0.0110
0.0110
0.0140
0.0130
0.0100
0.0060
0.0040
0.0010
0.0030
0.0040
0.0060
0.0120
0.0140
0.0190
0.0210
0.0250
0.0260
0.0270
0.0290
0.0290
0.0370
0.0360
0.0370
0.0370
0.0360
0.0410
0.0430
0.0440
0.0430
0.0460
0.0480
0.0460
0.0460
0.0430
0.0430
0.0440
0.0430
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
003601
Adjusted
P.U.
Performance
0.856
0.808
0.829
0.633
0.689
003602
Monday, October 12, 2009
Balancing Authority
MyBA
60.08
60.06
1.000
0.744
Initial P.U. Performance
Initial P.U. Performance Adjusted
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
3900.0
20 to 52 second Average Period
60.042
3843.77
60.04
3850.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
60.02
3803.32
60
3800.0
59.98
3788.35
59.96
Frequency - Hz
59.92
59.9
3700.0
59.88
59.889
59.86
3650.0
NAI MW
3750.0
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
59.84
3645.73
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
2:26:36
2:26:46
Hz
2:26:56
2:27:06
Average Frequency
2:27:16
MW
2:27:26
2:27:36
Average MW
2:27:46
2:27:56
EPFR Adjusted
2:28:06
2:28:16
EPFR Unadjusted
3500.0
2:28:26
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003603
Monday, October 12, 2009
0.758
05:34
MyBA
60.08
Sustained P.U. Performance
Event Length mm:ss
3900.0
60.06
60.04
3850.0
60.02
60
3800.0
59.98
59.96
3750.0
59.92
59.9
3700.0
59.88
59.86
3650.0
59.84
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
3500.0
2:27:26
2:28:26
2:29:26
Hz
2:30:26
2:31:26
2:32:26
Interchange MW
2:33:26
2:34:26
2:35:26
2:36:26
Recovery Period Target MW
2:37:26
2:38:26
2:39:26
2:40:26
Recovery Period Ramp MW
2:41:26
2:42:26
NAI MW
Frequency - Hz
59.94
003604
Monday, October 12, 2009
-103.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
100.0
60.06
60.04
50.0
60.02
60
0.0
59.98
59.96
-50.0
59.92
-100.0
59.9
59.88
-150.0
59.86
59.84
-200.0
59.82
59.8
-250.0
59.78
59.76
-300.0
59.74
59.72
2:26:26
-350.0
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
Hz
2:32:26
2:33:26
BA Bias Setting
2:34:26
2:35:26
2:36:26
2:37:26
2:38:26
Actual Primary Freq Response Beta
2:39:26
2:40:26
2:41:26
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
003605
Value A Data
Date
Monday, October 12, 2009
A Value
Time
2:27:26
FPointA
Hz
60.039
A Value
Hz
60.042
t(0) Time
2:27:26
BA Performance
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
Hz
MW
MW
MW
MW
59.836
60.042
3645.73
350.00
165.34
0.00
C Value
Hz
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
0.00
-4.21
15.00
Not
Used
003606
Value B
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
-103.00 7651.305
20 to 52 second Average Period Evaluation
JOU
NonBias
Net
Dynamic
Conforming
Pumped
Setting
Actual
Schedules
Load
Hydro
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
MW
Hz
MW
MW
MW
MW
-43.39
59.889
3803.35
335.00
165.34
6.35
Not
Used
0.00
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+)
Load (-) Gen (+)
MW
MW
11.09
0.00
Initial
Performance
Adjusted
P.U.
0.744
Initial
Performance
Unadjusted
P.U.
1.000
Sustained
Performance
P.U.
0.758
003607
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
BA
Bias
Setting
MW/0.1 Hz
-103.00
BA
Load
MW
7632.00
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
114.21
-103.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
1.399
1.293
1.582
1.571
1.849
0.856
0.808
0.829
0.633
0.689
003608
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
-103.00
-103.00
003609
Steps
1
2
3
4
5
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Not Used
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only rarely should
you have to use the "Manual" process.
6
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
B
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "NYISO".
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar to the slope of the NAI data.
When set appropriately, the "Target" trend on the "Sustained" graph will model what the Net Actua Interchange should have done during the event recovery period based on your Bias setting during the event.
003610
Monday, October 12, 2009
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MyBA
60.08
355.0
60.06
60.04
60.02
350.0
60
59.98
59.96
345.0
59.92
MW
Frequency - Hz
59.94
59.9
340.0
A Value
B Value
Average Period
59.88
350.00
59.86
335.00
20 to 52 second
59.84
335.0
59.82
59.8
59.78
330.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
JOU Dynamic Schedules
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
325.0
2:42:26
003611
Monday, October 12, 2009
MyBA
NonConforming
60.08
300.0
Load
60.06
Load (-)
60.04
60.02
250.0
60
59.98
59.96
200.0
59.92
MW
Frequency - Hz
59.94
59.9
150.0
A Value
B Value
59.88
165.34
214.13
Average Period
20 to 52 second
59.86
59.84
100.0
59.82
59.8
59.78
50.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Non- Conforming Load
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
003612
Monday, October 12, 2009
MyBA
Pumped
Hydro
60.08
Load (-) Gen (+)
18.0
60.06
60.04
16.0
60.02
60
14.0
59.98
59.96
12.0
59.92
10.0
59.9
A Value
B Value
0.00
6.35
Average Period
59.88
8.0
20 to 52 second
59.86
59.84
6.0
59.82
59.8
4.0
59.78
59.76
2.0
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW
Frequency - Hz
59.94
003613
Monday, October 12, 2009
MyBA
Not
Used
60.08
1.2
60.06
60.04
60.02
1.0
60
59.98
59.96
0.8
59.92
MW
Frequency - Hz
59.94
59.9
0.6
A Value
B Value
59.88
Average Period
20 to 52 second
59.86
59.84
0.4
59.82
59.8
59.78
0.2
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
003614
Monday, October 12, 2009
Transferred
MyBA
Frequency
Response
60.08
60.06
12.0
Rec (-) Del (+)
60.04
60.02
10.0
60
59.98
59.96
8.0
59.92
59.9
6.0
A Value
B Value
59.88
11.09
-4.21
Average Period
20 to 52 second
59.86
59.84
4.0
59.82
59.8
59.78
2.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Frequency Response
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
003615
Monday, October 12, 2009
Contingent
BA
Lost Generation
MyBA
60.08
Load (-) Gen (+)
16.0
60.06
60.04
14.0
60.02
60
12.0
59.98
59.96
10.0
MW
Frequency - Hz
59.94
59.92
59.9
A Value
59.88
15.00
B Value
0.00
59.86
Average Period
8.0
20 to 52 second
6.0
59.84
59.82
4.0
59.8
59.78
2.0
59.76
59.74
59.72
2:26:26 2:27:26
2:28:26 2:29:26 2:30:26 2:31:26
2:32:26 2:33:26 2:34:26
Hz
2:35:26
2:36:26 2:37:26 2:38:26
BA Lost Generation
2:39:26
0.0
2:40:26 2:41:26 2:42:26
003616
Monday, October 12, 2009
BA
Load
MyBA
60.08
7850.0
60.06
60.04
7800.0
60.02
60
59.98
7750.0
59.96
7700.0
59.92
59.9
A Value
B Value
Average Period
59.88
7651.3
59.86
7632.0
20 to 52 second
7650.0
59.84
7600.0
59.82
59.8
59.78
7550.0
59.76
59.74
59.72
7500.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Load
MW
Frequency - Hz
59.94
003617
Monday, October 12, 2009
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
200.0
60.06
60.04
60.02
150.0
60
59.98
59.96
100.0
59.92
MW
Frequency - Hz
59.94
59.9
50.0
59.88
59.86
59.84
0.0
59.82
59.8
59.78
-50.0
59.76
A Value
B Value
59.74
-43.39
59.72
2:26:26 2:27:26
2:28:26 2:29:26
2:30:26 2:31:26 2:32:26
Hz
2:33:26 2:34:26
114.21
2:35:26 2:36:26 2:37:26
Average Period
20 to 52 second
2:38:26 2:39:26
Expected Primary Freq Response Based on Bias Setting
-100.0
2:40:26 2:41:26 2:42:26
003618
Time (T)
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
05/16/11 07:41:16
05/16/11 07:41:18
05/16/11 07:41:20
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
59.98578
59.9874
59.98868
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
29782.73
29782.73
29782.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
003619
05/16/11 07:41:22
05/16/11 07:41:24
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
05/16/11 07:42:40
05/16/11 07:42:42
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
59.98999
59.99191
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
60.0152
60.0152
60.01486
60.01422
60.01358
60.01227
60.01099
60.00873
60.00647
60.00485
60.00354
60.00195
60
59.99774
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29782.73
29782.82
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
29787.84
29813.39
29813.39
29813.39
29813.39
29813.39
29813.33
29813.33
29813.33
29813.33
29813.33
29797.46
29797.46
29797.46
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.002
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.002
-0.002
-0.002
0.001
0.002
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.002
0.002
0.002
003620
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
59.98514
59.98416
59.98352
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
003621
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
60.01227
60.01163
60.01065
60.0097
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
003622
05/16/11 07:46:16
05/16/11 07:46:18
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
60.01422
60.01227
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
59.99646
59.99579
59.99417
59.99225
59.9903
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
29782.35
29782.35
29782.44
29782.44
29782.44
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
-0.001
-0.001
-0.002
-0.002
-0.002
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
0.001
0.001
0.002
0.002
0.002
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
003623
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
60.02164
60.01971
60.01907
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
60
60
60.00452
60.00583
60.00613
60.00583
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29794.69
29794.69
29794.69
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.002
-0.001
-0.002
0.000
0.001
-0.001
-0.003
-0.001
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
0.000
0.002
0.001
0.002
0.000
0.001
0.001
0.003
0.001
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
003624
05/16/11 07:49:32
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
60.00516
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
59.99225
59.99484
59.99646
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29795.55
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
0.000
0.003
0.002
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.000
0.001
003625
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
05/16/11 07:51:24
05/16/11 07:51:26
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
59.97189
59.97125
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
59.98868
59.98868
59.9874
59.98611
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
29756.18
29756.18
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
29795.02
29795.02
29795.05
29795.05
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.001
003626
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
59.98611
59.98709
59.98837
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
60.00064
60.00098
60.00064
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29795.05
29795.05
29795.05
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
29823.76
29823.76
29818.41
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.000
003627
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
05/16/11 07:56:00
05/16/11 07:56:02
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
59.98547
59.98547
59.98514
59.9845
59.9845
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
59.97641
59.9761
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
29826.47
29826.41
29826.41
29826.41
29826.41
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
29831.33
29831.33
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.004
0.002
0.002
0.002
0.003
0.001
0.000
0.000
003628
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
05/16/11 07:56:24
05/16/11 07:56:26
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
59.97803
59.97867
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
60.01938
60.02036
60.02197
60.02423
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
29856.55
29856.55
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29889.67
29889.67
29889.67
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
003629
05/16/11 07:57:42
05/16/11 07:57:44
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
05/16/11 07:58:38
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
60.02261
60.02164
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
60.02069
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
59.99451
59.99127
59.98965
59.98868
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29891.67
29891.64
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
29887.14
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
29862.1
29862.1
29861.95
29861.95
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
-0.001
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
-0.005
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
0.005
0.003
0.002
0.001
0.002
0.002
0.002
0.002
0.003
0.002
003630
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
05/16/11 08:00:00
05/16/11 08:00:02
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
59.97287
59.97287
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
29905.8
29905.8
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
-0.001
-0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
0.001
0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
003631
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
05/16/11 08:01:30
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
59.98709
59.98773
59.98965
59.99161
59.99255
59.99323
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
29951.05
29951.05
29955.09
29955.09
29955.09
29955.09
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
003632
05/16/11 08:02:36
05/16/11 08:02:38
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
05/16/11 08:04:00
05/16/11 08:04:02
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
59.96512
59.96512
59.96576
59.96704
59.96994
59.97253
59.97415
59.9761
59.97739
59.97931
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
59.98029
59.979
59.97867
59.97931
59.97998
59.97931
59.979
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30055.73
30055.73
30055.73
30055.73
30068.76
30068.76
30068.76
30068.76
30068.76
30068.21
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
30118.77
30118.77
30118.74
30118.74
30118.74
30118.74
30118.74
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
-0.001
0.000
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.001
0.000
003633
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
05/16/11 08:05:48
05/16/11 08:05:50
59.97803
59.97675
59.97739
59.979
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471.3000183
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30106.93
30106.93
30106.93
30106.93
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
003634
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
05/16/11 08:06:36
05/16/11 08:06:38
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
471.3000183
471.3000183
471.3000183
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
470.8999939
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
0.000
-0.042
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
0.000
0.042
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
003635
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
05/16/11 08:08:40
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
003636
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
05/16/11 08:10:04
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
30300.1
30314.84
30314.84
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.001
-0.001
-0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
-0.001
-0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
0.001
0.004
003637
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
-0.001
-0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
003638
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
05/16/11 08:12:56
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.1
30349.1
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.002
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
003639
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
05/16/11 08:14:10
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
05/16/11 08:15:28
05/16/11 08:15:30
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
-0.001
0.004
0.002
0.000
0.001
-0.002
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.002
0.000
0.001
0.002
003640
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
05/16/11 08:17:16
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
0.000
-0.001
-0.004
-0.001
0.000
-0.002
-0.002
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
-0.001
-0.003
-0.003
0.000
0.002
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.001
0.000
0.002
0.002
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.003
0.003
0.000
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.002
003641
05/16/11 08:17:18
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
05/16/11 08:18:40
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30416.87
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
0.003
0.000
0.001
0.002
0.002
0.002
0.001
0.000
003642
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
05/16/11 08:20:32
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
0.000
-0.001
-0.003
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
0.000
0.001
0.003
0.002
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
0.000
003643
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
003644
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
05/16/11 08:23:00
05/16/11 08:23:02
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
60.03717
60.03781
60.03781
60.03748
60.0365
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
60.03101
60.03232
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
60.03458
60.03488
60.0336
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30452.43
30473.21
30473.21
30473.21
30473.21
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
30485.47
30505.49
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
30529.28
30529.08
30529.08
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.000
-0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
003645
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
60.03326
60.03232
60.03134
60.03168
60.03326
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
60.03134
60.03168
60.03134
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
60.0365
60.03488
60.0336
60.03232
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30529.08
30529.08
30529.52
30529.52
30529.52
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
30521.82
30533.64
30533.64
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
30556.84
30557.42
30557.42
30557.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
0.000
0.002
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
003646
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
60.03134
60.03101
60.03101
60.0307
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30557.43
30557.43
30557.43
30566.39
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.001
-0.001
0.000
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.003
0.002
003647
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
60.00388
60.00128
59.99936
59.99805
59.99741
59.9971
59.99677
59.9971
59.99646
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
30543.34
30543.34
30554.42
30554.42
30554.42
30554.42
30534.33
30534.33
30533.84
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
003648
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
05/16/11 08:29:20
05/16/11 08:29:22
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
59.97675
59.9761
59.9761
59.97641
59.97705
59.97803
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
30570.97
30593.17
30593.17
30593.17
30593.17
30575.07
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.006
0.000
0.004
0.001
003649
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
05/16/11 08:31:56
05/16/11 08:31:58
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
59.97479
59.97479
59.97641
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
60.0184
60.02069
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
30603.96
30603.96
30603.96
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
30661.87
30661.87
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
-0.002
0.000
0.002
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
0.000
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.002
0.000
0.002
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
0.000
0.002
003650
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
05/16/11 08:33:18
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
60.0152
60.01648
60.01614
60.0152
60.01486
60.01453
60.01291
60.01099
60.00775
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
30648.14
30648.29
30648.29
30648.29
30648.29
30648.29
30652.04
30652.04
30652.04
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.002
-0.003
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.002
0.003
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
003651
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
0.003
0.002
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
003652
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
05/16/11 08:36:00
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
59.99966
60.00064
60.00098
60.00064
60
59.99936
59.99741
59.99484
59.99289
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
30686.83
30686.83
30686.83
30686.83
30686.83
30678.05
30678.05
30678.05
30678.05
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.002
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
003653
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
05/16/11 08:37:20
05/16/11 08:37:22
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
60.01227
60.01163
60.01132
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
60.0126
60.01132
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
30726.76
30726.76
30726.76
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
30720.93
30720.93
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
0.000
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
003654
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
05/16/11 08:40:00
60.00388
60.00485
60.00549
60.00613
60.00647
60.00677
60.00677
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
60.02618
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
30757.92
30752.27
30752.27
30752.27
30752.27
30752.27
30752.33
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
30803.58
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
003655
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
MyBA_110516_0806_FRS_Form2.9.xlsm
59.300 Hz
60.700 Hz
Auto
Event Detection
8:06:38
1245 Manually selected row number of the Event Starting Time.
8:10:30
1442 Manually selected row number of the Event Ending Time.
Event Frequency Data
8:06:38
60.1
8:06:38
-0.101
Delta Hz Event Detected
60.05
60
8:10:30
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00
7:45:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
7:50:00
7:55:00
8:00:00
8:05:00
8:10:00
Hz
8:15:00
8:20:00
8:25:00
8:30:00
8:35:00
8:40:00
003656
Auto
Manual
003657
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
Balancing Authority MyBA
Grid Nominal Frequency
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
662.51 MW
Yes
Initial Response P.U. Performance
0.711 P.U.
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
Frequency
Hz
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
Contingent
Resource
Lost
MW
471.000
471.000
471.000
471.000
471.000
471.000
Value B
20 to 52 sec
Average
Frequency
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
19590
19590
19590
19590
19590
19590
Droop Setting
Deadband Setting
Hz Span
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
128.735
115.981
107.611
92.864
82.303
78.118
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
(TC)
Delayed
Delivery
Frequency
Response
45.057
69.880
83.086
86.509
85.036
82.615
8:06:36
60.00195313
59.99862671
59.87011337
3.00000 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during re
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.738 P.U. Sustianed Response P.U. Performance
Initial
Measure
Final
Expected
Primary
Frequency
Response
A Point
FPointA
A Value
C Value
Delta FC
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
003658
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
708.959
705.229
702.804
696.067
685.829
675.477
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
420.514
416.250
411.986
407.723
403.459
399.195
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
446.096
443.964
441.832
439.700
437.568
435.437
003659
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
003660
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
325.933
321.849
315.567
307.788
301.197
295.448
288.014
275.789
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
509.957
501.609
491.064
479.021
468.166
458.153
446.456
429.967
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
872.238
866.943
861.649
856.335
851.017
845.708
840.385
834.985
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
186.012
181.748
177.484
173.221
168.957
164.693
160.430
156.166
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
328.845
326.713
324.581
322.449
320.317
318.186
316.054
313.922
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
003661
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
003662
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
003663
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-67.789
-55.851
-46.626
-44.326
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-88.422
-76.483
-67.258
-64.958
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
241.944
240.477
239.065
237.677
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
113.628
113.016
112.409
111.808
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
003664
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
003665
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
003666
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
-13.275
-13.790
-16.357
-20.257
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
-33.908
-34.423
-36.989
-40.890
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
147.518
147.032
146.542
146.058
145.591
145.147
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
139.601
139.146
138.686
138.218
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
59.915
59.699
59.483
59.269
59.057
58.845
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
56.194
55.997
55.802
55.608
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
003667
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
42.028
50.963
67.093
83.506
103.730
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
21.395
30.330
46.461
62.874
83.098
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
126.560
126.327
126.134
125.982
125.879
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
50.549
50.381
50.214
50.048
49.882
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
003668
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
Time of Frequency Recovery to 60 Hz or Pre-Perturbatio
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(Value B Post-Perturbation Average Frequency [T(+20 to T(+
Pre to Post Perturbation Delta Frequency Ac
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(Value B Post-Perturbation Average Contingency MW [T(+20 to T(+
Pre to Post Perturbation Contingency Delta MW Ac
EPFR Pre-Perturbation Ave
EPFR Post-Perturbation Ave
Pre Non-Conforming Load
eriod (indicates ramp direction during recovery period)
Sum of Pre Perturbation Adjustm
Post Non-Conforming Load
Sum of Post Perturbation Adjustm
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
20 to 52 second Average Period Evaluation
Initial P.U. Performance for
Initial P.U. Performance Adjusted for
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
Frequency
Hz
59.980
59.982
59.984
59.986
59.987
59.988
Contingent
Resource
Lost
MW
471.00
471.00
471.00
471.00
471.00
471.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
Expected Primary
Freq Response
Based on Bias Setting
MW
128.735
115.981
107.611
92.864
82.303
78.118
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
Frequency
Hz
Contingent
Resource
Lost
MW
003669
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
59.893
59.893
59.893
59.895
59.898
59.900
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
003670
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
003671
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
59.952
59.952
59.953
59.955
59.956
59.956
59.958
59.961
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
003672
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
003673
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
003674
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
60.008
60.005
60.005
60.006
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
003675
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
003676
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
003677
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
60.003
60.004
60.003
60.001
59.999
59.997
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
60.002
60.002
60.003
60.004
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
003678
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.992
59.990
59.985
59.983
59.978
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
003679
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
uency Recovery to 60 Hz or Pre-Perturbation Hz
erturbation Average Frequency [T(-2 ) to T(-16)]
rturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
-Perturbation Contingency MW [T(-2 ) to T(-16)]
tion Average Contingency MW [T(+20 to T(+52)]
Post Perturbation Contingency Delta MW Actual
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
Spare
Spare
Sum of Pre Perturbation Adjustments
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00
0.00
0.00
0.00
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
Hz
Hz
Hz
Hz
Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
Average Bias Setting when Hz is greater than +/-0.036 Hz
30202.7
30136.8
-65.973
-65.020
14.00%
Actual
Primary
Freq Response
MW/0.1 Hz
-481.62
-561.31
-863.83
-1000.43
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
Load
NonResources
Conforming
Tripped
Load
Spare
Spare
Adjustment
Adjustment Adjustment Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW/0.1 Hz
-653.00 MW/0.1 Hz
d Average Period Evaluation
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.711 P.U.
0.711 P.U.
Not
Used
MW
Not
Used
Not
Used
Not
Used
MW/0.1 Hz
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
0.0197
0.0178
0.0165
0.0142
0.0126
0.0120
Spare
Adjustment
0.00
0.00
0.00
0.00
0.00
003680
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
446.26
446.26
446.26
456.01
467.62
475.25
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003681
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003682
1000.43
1007.61
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
0.0485
0.0481
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003683
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003684
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003685
0.0078
0.0052
0.0045
0.0061
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
003686
81245.24
9243.47
7757.08
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
003687
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
003688
38591.49
25305.89
25305.89
30873.19
53229.64
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
0.0023
0.0023
0.0032
0.0042
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
003689
7385.93
5250.54
3492.44
2929.15
2324.79
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0078
0.0103
0.0149
0.0175
0.0216
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
003690
Adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
003691
Monday, May 16, 2011
Balancing Authority
MyBA
60.02
0.711
0.711
"Auto" Event Detection adjustment of T(0).
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
464.954
400.0
59.92
59.9
300.0
59.897
59.88
MW/0.1 Hz
Frequency - Hz
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
8:05:48
8:05:58
8:06:08
8:06:18
8:06:28
8:06:38
8:06:48
8:06:58
8:07:08
8:07:18
8:07:28
Hz
Average Frequency
Actual Primary Freq Response Beta
Actual Average Primary Freq Response
EPFR Adjusted
EPFR Unadjusted
0.0
8:07:38
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003692
Monday, May 16, 2011
-653.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
8:05:38
0.0
8:06:38
8:07:38
8:08:38
8:09:38
Hz
8:10:38
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003693
Value A Data
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
59.870
59.999
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Value B
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
0.00
BA
BA
Bias
Load
Spare
Setting
MW
MW/0.1 Hz
MW
0.00
-653.00 30202.74
Bias
Setting
EPFR
Frequency
MW
Hz
8.97
59.897
20 to 52 second Average
Contingent
Resource
Lost
MW
0.00
003694
20 to 52 second Average Period Evaluation
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Spare
MW
0.00
Frequency Response Initiative - Additional Primary Frequenc
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
BA
BA
Bias
Load
Setting
P.U.
MW/0.1 Hz
MW
0.738
-653.00 30136.77
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
671.54
-653.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
0.738
0.860
1.323
1.532
2.309
003695
Additional Primary Frequency Response Evaluation Points
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance
Maximum
Minimum
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
Bias Setting Bias Setting
P.U.
P.U.
P.U.
P.U.
P.U.
MW/0.1 Hz
MW/0.1 Hz
0.738
0.860
1.323
1.532
2.309
-653.00
-653.00
003696
Steps
1
2
3
4
5
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6".
Only rarely should you have to use the "Manual" process.
6
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
003697
Monday, May 16, 2011
MyBA
Load
Resources
Tripped
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
A Value
59.9
0.00
B Value
Average Period
20 to 52 second
0.00
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
8:13:38
8:14:38
8:15:38
Hz
Initial Load Resources
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003698
Monday, May 16, 2011
MyBA
NonConforming
60.08
1.0
Load
60.06
Load (-)
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
8:15:38
Non- Conforming Load
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003699
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
0.5
59.9
A Value
B Value
0.00
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003700
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.94
MW
Frequency - Hz
59.96
59.92
0.6
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
0.4
59.86
59.84
59.82
0.2
59.8
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003701
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
59.92
0.5
A Value
59.9
B Value
0.00
0.00
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW/0.1 Hz
Frequency - Hz
0.6
003702
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
59.96
59.94
MW
Frequency - Hz
0.6
59.92
A Value
59.9
15.00
B Value
0.00
Average Period
0.5
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38 8:06:38
8:07:38 8:08:38 8:09:38 8:10:38
8:11:38 8:12:38 8:13:38
Hz
8:14:38
Not Used
8:15:38 8:16:38 8:17:38
8:18:38
0.0
8:19:38 8:20:38 8:21:38
003703
Monday, May 16, 2011
BA
Load
MyBA
60.08
30600.0
60.06
60.04
30500.0
60.02
60
30400.0
59.98
30300.0
59.94
MW
Frequency - Hz
59.96
59.92
30200.0
A Value
59.9
7651.305
59.88
B Value
30136.8
Average Period
20 to 52 second
30100.0
59.86
59.84
30000.0
59.82
59.8
29900.0
59.78
59.76
29800.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
003704
Monday, May 16, 2011
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
1000.0
60.06
60.04
800.0
60.02
60
600.0
59.98
400.0
59.94
59.92
59.9
200.0
59.88
59.86
0.0
59.84
59.82
-200.0
59.8
A Value
59.78
8.97
59.76
8:05:38 8:06:38
8:07:38 8:08:38
8:09:38 8:10:38 8:11:38
Hz
8:12:38 8:13:38
B Value
671.54
8:14:38 8:15:38 8:16:38
Average Period
20 to 52 second
8:17:38 8:18:38
Expected Primary Freq Response Based on Bias Setting
-400.0
8:19:38 8:20:38 8:21:38
MW
Frequency - Hz
59.96
Rows of
003705data to
Time (T)
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
05/16/11 07:41:16
05/16/11 07:41:18
05/16/11 07:41:20
05/16/11 07:41:22
05/16/11 07:41:24
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
59.98578
59.9874
59.98868
59.98999
59.99191
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
29782.73
29782.73
29782.73
29782.73
29782.82
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
0.001
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
0.001
0.002
shift to
align T(0)
1
Rows of
003706data to
Time (T)
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
05/16/11 07:42:40
05/16/11 07:42:42
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
Hz
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
60.0152
60.0152
60.01486
60.01422
60.01358
60.01227
60.01099
60.00873
60.00647
60.00485
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
29787.84
29813.39
29813.39
29813.39
29813.39
29813.39
29813.33
29813.33
29813.33
29813.33
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.002
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
shift to
align T(0)
1
Rows of
003707data to
Time (T)
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
Hz
60.00354
60.00195
60
59.99774
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
59.98514
59.98416
59.98352
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29813.33
29797.46
29797.46
29797.46
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.000
shift to
align T(0)
1
Rows of
003708data to
Time (T)
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
Hz
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
60.01227
60.01163
60.01065
60.0097
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
shift to
align T(0)
1
Rows of
003709data to
Time (T)
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
05/16/11 07:46:16
05/16/11 07:46:18
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
Hz
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
60.01422
60.01227
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
59.99646
59.99579
59.99417
59.99225
59.9903
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
29782.35
29782.35
29782.44
29782.44
29782.44
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
-0.001
-0.001
-0.002
-0.002
-0.002
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
0.001
0.001
0.002
0.002
0.002
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
shift to
align T(0)
1
Rows of
003710data to
Time (T)
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
Hz
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
60.02164
60.01971
60.01907
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
29794.69
29794.69
29794.69
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
-0.002
-0.001
-0.002
0.000
0.001
-0.001
-0.003
-0.001
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
0.002
0.001
0.002
0.000
0.001
0.001
0.003
0.001
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
shift to
align T(0)
1
Rows of
003711data to
Time (T)
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
05/16/11 07:49:32
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
Hz
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
60
60
60.00452
60.00583
60.00613
60.00583
60.00516
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
29795.55
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
shift to
align T(0)
1
Rows of
003712data to
Time (T)
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
05/16/11 07:51:24
05/16/11 07:51:26
Hz
59.99225
59.99484
59.99646
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
59.97189
59.97125
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
29756.18
29756.18
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.003
0.002
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.003
0.002
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.001
shift to
align T(0)
1
Rows of
003713data to
Time (T)
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
Hz
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
59.98868
59.98868
59.9874
59.98611
59.98611
59.98709
59.98837
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
29795.02
29795.02
29795.05
29795.05
29795.05
29795.05
29795.05
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
shift to
align T(0)
1
Rows of
003714data to
Time (T)
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
Hz
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
shift to
align T(0)
1
Rows of
003715data to
Time (T)
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
Hz
60.00064
60.00098
60.00064
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
59.98547
59.98547
59.98514
59.9845
59.9845
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29823.76
29823.76
29818.41
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
29826.47
29826.41
29826.41
29826.41
29826.41
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
shift to
align T(0)
1
Rows of
003716data to
Time (T)
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
05/16/11 07:56:00
05/16/11 07:56:02
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
05/16/11 07:56:24
05/16/11 07:56:26
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
Hz
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
59.97641
59.9761
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
59.97803
59.97867
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
29856.55
29856.55
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.004
0.002
0.002
0.002
0.003
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
shift to
align T(0)
1
Rows of
003717data to
Time (T)
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
05/16/11 07:57:42
05/16/11 07:57:44
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
Hz
60.01938
60.02036
60.02197
60.02423
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
60.02261
60.02164
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29873.15
29889.67
29889.67
29889.67
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
29891.67
29891.64
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
shift to
align T(0)
1
Rows of
003718data to
Time (T)
05/16/11 07:58:38
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
05/16/11 08:00:00
05/16/11 08:00:02
Hz
60.02069
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
59.99451
59.99127
59.98965
59.98868
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
59.97287
59.97287
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29887.14
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
29862.1
29862.1
29861.95
29861.95
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
29905.8
29905.8
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
-0.005
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.002
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
0.005
0.003
0.002
0.001
0.002
0.002
0.002
0.002
0.003
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.002
0.000
shift to
align T(0)
1
Rows of
003719data to
Time (T)
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
Hz
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
59.98709
59.98773
59.98965
59.99161
59.99255
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
29951.05
29951.05
29955.09
29955.09
29955.09
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
-0.001
-0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.000
0.001
0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
shift to
align T(0)
1
Rows of
003720data to
Time (T)
05/16/11 08:01:30
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
05/16/11 08:02:36
05/16/11 08:02:38
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
Hz
59.99323
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
59.96512
59.96512
59.96576
59.96704
59.96994
59.97253
59.97415
59.9761
59.97739
59.97931
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29955.09
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
30055.73
30055.73
30055.73
30055.73
30068.76
30068.76
30068.76
30068.76
30068.76
30068.21
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
shift to
align T(0)
1
Rows of
003721data to
Time (T)
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
05/16/11 08:04:00
05/16/11 08:04:02
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
Hz
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
59.98029
59.979
59.97867
59.97931
59.97998
59.97931
59.979
59.97803
59.97675
59.97739
59.979
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
30118.77
30118.77
30118.74
30118.74
30118.74
30118.74
30118.74
30106.93
30106.93
30106.93
30106.93
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
-0.001
0.000
-0.001
-0.001
0.001
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.002
shift to
align T(0)
1
Rows of
003722data to
Time (T)
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
Hz
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
shift to
align T(0)
1
Rows of
003723data to
Time (T)
05/16/11 08:05:48
05/16/11 08:05:50
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
05/16/11 08:06:36
05/16/11 08:06:38
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
Hz
Contingent
Resource
Lost
MW
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
471
471.3000183
471.3000183
471.3000183
471.3000183
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
470.8999939
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
0.000
-0.042
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
0.000
0.042
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
shift to
align T(0)
1
Rows of
003724data to
Time (T)
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
Hz
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
shift to
align T(0)
1
Rows of
003725data to
Time (T)
05/16/11 08:08:40
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
05/16/11 08:10:04
Hz
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30234.59
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
-0.001
-0.001
-0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
0.001
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
shift to
align T(0)
1
Rows of
003726data to
Time (T)
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
Hz
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
30300.1
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
-0.001
-0.004
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
0.001
0.004
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
shift to
align T(0)
1
Rows of
003727data to
Time (T)
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
05/16/11 08:12:56
Hz
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.1
30349.1
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.002
shift to
align T(0)
1
Rows of
003728data to
Time (T)
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
05/16/11 08:14:10
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
Hz
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.003
0.002
0.004
0.002
shift to
align T(0)
1
Rows of
003729data to
Time (T)
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
05/16/11 08:15:28
05/16/11 08:15:30
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
Hz
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
-0.001
0.004
0.002
0.000
0.001
-0.002
0.000
0.001
0.000
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.002
0.000
0.001
0.002
0.000
0.001
0.000
0.000
0.001
shift to
align T(0)
1
Rows of
003730data to
Time (T)
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
Hz
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.004
-0.001
0.000
-0.002
-0.002
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
-0.001
-0.003
-0.003
0.000
0.002
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.004
0.001
0.000
0.002
0.002
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.003
0.003
0.000
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
shift to
align T(0)
1
Rows of
003731data to
Time (T)
05/16/11 08:17:16
05/16/11 08:17:18
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
05/16/11 08:18:40
Hz
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30416.87
30416.87
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
0.003
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
0.003
shift to
align T(0)
1
Rows of
003732data to
Time (T)
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
Hz
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
0.000
-0.001
-0.003
-0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
0.000
0.001
0.003
0.002
shift to
align T(0)
1
Rows of
003733data to
Time (T)
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
05/16/11 08:20:32
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
Hz
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
shift to
align T(0)
1
Rows of
003734data to
Time (T)
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
Hz
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
60.03717
60.03781
60.03781
60.03748
60.0365
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
30452.43
30473.21
30473.21
30473.21
30473.21
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
shift to
align T(0)
1
Rows of
003735data to
Time (T)
05/16/11 08:23:00
05/16/11 08:23:02
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
Hz
60.03101
60.03232
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
60.03458
60.03488
60.0336
60.03326
60.03232
60.03134
60.03168
60.03326
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
60.03134
60.03168
60.03134
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30485.47
30505.49
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
30529.28
30529.08
30529.08
30529.08
30529.08
30529.52
30529.52
30529.52
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
30521.82
30533.64
30533.64
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.000
-0.001
0.000
-0.001
-0.001
0.000
0.002
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
shift to
align T(0)
1
Rows of
003736data to
Time (T)
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
Hz
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
60.0365
60.03488
60.0336
60.03232
60.03134
60.03101
60.03101
60.0307
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
30556.84
30557.42
30557.42
30557.43
30557.43
30557.43
30557.43
30566.39
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
shift to
align T(0)
1
Rows of
003737data to
Time (T)
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
Hz
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.001
-0.001
0.000
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.002
0.002
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.002
shift to
align T(0)
1
Rows of
003738data to
Time (T)
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
Hz
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
60.00388
60.00128
59.99936
59.99805
59.99741
59.9971
59.99677
59.9971
59.99646
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
30543.34
30543.34
30554.42
30554.42
30554.42
30554.42
30534.33
30534.33
30533.84
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
shift to
align T(0)
1
Rows of
003739data to
Time (T)
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
05/16/11 08:29:20
05/16/11 08:29:22
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
Hz
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
59.97675
59.9761
59.9761
59.97641
59.97705
59.97803
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
30570.97
30593.17
30593.17
30593.17
30593.17
30575.07
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
shift to
align T(0)
1
Rows of
003740data to
Time (T)
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
Hz
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
59.97479
59.97479
59.97641
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
30603.96
30603.96
30603.96
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
-0.002
0.000
0.002
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.002
0.002
0.006
0.000
0.004
0.001
0.002
0.001
0.000
0.003
0.003
0.003
0.002
0.000
0.002
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
shift to
align T(0)
1
Rows of
003741data to
Time (T)
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
05/16/11 08:31:56
05/16/11 08:31:58
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
Hz
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
60.0184
60.02069
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
30661.87
30661.87
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
0.000
0.002
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
shift to
align T(0)
1
Rows of
003742data to
Time (T)
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
05/16/11 08:33:18
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
Hz
60.0152
60.01648
60.01614
60.0152
60.01486
60.01453
60.01291
60.01099
60.00775
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30648.14
30648.29
30648.29
30648.29
30648.29
30648.29
30652.04
30652.04
30652.04
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.002
-0.003
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.002
0.003
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
shift to
align T(0)
1
Rows of
003743data to
Time (T)
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
Hz
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
59.99966
60.00064
60.00098
60.00064
60
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
30686.83
30686.83
30686.83
30686.83
30686.83
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
shift to
align T(0)
1
Rows of
003744data to
Time (T)
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
05/16/11 08:36:00
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
Hz
59.99936
59.99741
59.99484
59.99289
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
60.01227
60.01163
60.01132
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
-653 30678.05
-653 30678.05
30678.05
30678.05
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
30726.76
30726.76
30726.76
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.002
-0.003
-0.002
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.002
0.003
0.002
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
shift to
align T(0)
1
Rows of
003745data to
Time (T)
05/16/11 08:37:20
05/16/11 08:37:22
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
Hz
60.0126
60.01132
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
60.00388
60.00485
60.00549
60.00613
60.00647
60.00677
60.00677
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30720.93
30720.93
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
30757.92
30752.27
30752.27
30752.27
30752.27
30752.27
30752.33
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.000
0.001
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
shift to
align T(0)
1
Rows of
003746data to
Time (T)
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
05/16/11 08:40:00
Hz
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
60.02618
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
30803.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Lowest
Max Absolute Delta Hz Delta Hz
0.078
-0.078
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
Highest Delta
Hz
0.009
Absolute
Delta Hz
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
shift to
align T(0)
1
003747
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
MyBA_110516_0806_FRS_Form2.9.xlsm
58.500 Hz
61.500 Hz
Auto Event Detection
8:06:38
1245 Manually selected row number of the Event Starting Time.
8:10:30
1442 Manually selected row number of the Event Ending Time.
Auto
Manual
Event Frequency Data
8:06:38
60.1
8:06:38
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
60.05
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
8:10:30
-0.101
Delta Hz Event Detected
60
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00
7:45:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
7:50:00
7:55:00
8:00:00
8:05:00
8:10:00
Hz
8:15:00
8:20:00
8:25:00
8:30:00
8:35:00
8:40:00
003748
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
Frequency
Hz
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
Contingent
Resource
Lost
MW
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Value B
20 to 52 sec
Average
Frequency
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
662.51 MW
Yes
0.711 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
Balancing Authority MyBA
Grid Nominal Frequency
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
A Point
FPointA
A Value
C Value
Delta FC
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
8:06:36
60.00195313
59.99862671
59.87011337
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
Spare
Spare
Sum of Pre Perturbation Adjustments
45.057
69.880
83.086
86.509
85.036
82.615
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
708.959
705.229
702.804
696.067
685.829
675.477
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
325.933
321.849
315.567
307.788
301.197
295.448
288.014
275.789
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average
Ramp
MW/scan
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Period Recovery Recovery Period Recovery
Target
Period
Period
Ramp
Period
MW
MW
MW
MW
MW
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
509.957
501.609
491.064
479.021
468.166
458.153
446.456
429.967
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
872.238
866.943
861.649
856.335
851.017
845.708
840.385
834.985
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
420.514
416.250
411.986
407.723
403.459
399.195
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
186.012
181.748
177.484
173.221
168.957
164.693
160.430
156.166
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
446.096
443.964
441.832
439.700
437.568
435.437
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
328.845
326.713
324.581
322.449
320.317
318.186
316.054
313.922
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Frequency
Hz
Contingent
Resource
Lost
MW
59.980
59.982
59.984
59.986
59.987
59.988
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
59.893
59.893
59.893
59.895
59.898
59.900
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
59.952
59.952
59.953
59.955
59.956
59.956
59.958
59.961
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
Hz
Hz
Hz
Hz
Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
30202.7 MW
30136.8 MW
-65.973 MW
-65.020 MW/0.1 Hz
14.00%
Average Bias Setting when Hz is greater than +/-0.036 Hz
-653.00 MW/0.1 Hz
Actual
Primary
Freq Response
MW/0.1 Hz
-481.62
-561.31
-863.83
-1000.43
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
Load
Resources
Tripped
Adjustment
0.00
0.00
0.00
0.00
0.00
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
NonConforming
Load
Spare
Spare
Adjustment Adjustment Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
20 to 52 second Average Period Evaluation
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.738 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingency MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingency Delta MW Actual
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
Expected Primary
Freq Response
Based on Bias Setting
MW
T
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
Frequency
Hz
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonContingent
Load
Conforming
Resource
Resources
Load
Lost
Tripped
Load (-)
MW
MW
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.711 P.U.
0.711 P.U.
Not
Used
Not
Used
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Not
Used
Not
Used
MW/0.1 Hz
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
EPFR
MW
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
446.26
446.26
446.26
456.01
467.62
475.25
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
1000.43
1007.61
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
0.0197
0.0178
0.0165
0.0142
0.0126
0.0120
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
0.0485
0.0481
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
Adjusted
Spare
P.U.
Adjustment
Performance
0.00
0.738
0.00
0.860
0.00
1.323
0.00
1.532
0.00
2.309
003749
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
-67.789
-55.851
-46.626
-44.326
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
-88.422
-76.483
-67.258
-64.958
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
241.944
240.477
239.065
237.677
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
113.628
113.016
112.409
111.808
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
60.008
60.005
60.005
60.006
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
0.0078
0.0052
0.0045
0.0061
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
003750
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
-13.275
-13.790
-16.357
-20.257
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
-33.908
-34.423
-36.989
-40.890
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
147.518
147.032
146.542
146.058
145.591
145.147
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
139.601
139.146
138.686
138.218
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
59.915
59.699
59.483
59.269
59.057
58.845
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
56.194
55.997
55.802
55.608
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
60.003
60.004
60.003
60.001
59.999
59.997
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
60.002
60.002
60.003
60.004
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
81245.24
9243.47
7757.08
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
38591.49
25305.89
25305.89
30873.19
53229.64
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
0.0023
0.0023
0.0032
0.0042
003751
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
42.028
50.963
67.093
83.506
103.730
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
21.395
30.330
46.461
62.874
83.098
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
126.560
126.327
126.134
125.982
125.879
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
50.549
50.381
50.214
50.048
49.882
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
59.992
59.990
59.985
59.983
59.978
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
7385.93
5250.54
3492.44
2929.15
2324.79
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
0.0078
0.0103
0.0149
0.0175
0.0216
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
003752
Monday, May 16, 2011
Balancing Authority
MyBA
60.02
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
0.711
0.711
"Auto" Event Detection adjustment of T(0).
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
464.954
59.92
59.9
400.0
300.0
59.897
59.88
MW/0.1 Hz
Frequency - Hz
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
8:05:48
8:05:58
8:06:08
8:06:18
8:06:28
8:06:38
8:06:48
8:06:58
8:07:08
8:07:18
8:07:28
Hz
Average Frequency
Actual Primary Freq Response Beta
Actual Average Primary Freq Response
EPFR Adjusted
EPFR Unadjusted
0.0
8:07:38
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
003753
Monday, May 16, 2011
-653.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
8:05:38
0.0
8:06:38
8:07:38
8:08:38
8:09:38
Hz
8:10:38
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003754
Value A Data
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Frequency
Hz
59.870
59.999
Contingent
Resource
Lost
MW
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Value B
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
0.00
-653.00 30202.74
Bias
Setting
EPFR
Frequency
MW
Hz
8.97
59.897
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
0.00
Load
Resources
Tripped
MW
0.00
NonConforming
Load
Load (-)
MW
0.00
Spare
MW
0.00
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
BA
BA
Bias
Load
Setting
P.U.
MW/0.1 Hz
MW
0.738
-653.00 30136.77
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
671.54
-653.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
0.738
0.860
1.323
1.532
2.309
0.738
0.860
1.323
1.532
2.309
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz MW/0.1 Hz
-653.00
-653.00
003755
Steps
1
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
003756
Monday, May 16, 2011
MyBA
Load
Resources
Tripped
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
0.00
B Value
Average Period
20 to 52 second
0.00
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
8:13:38
8:14:38
8:15:38
Hz
Initial Load Resources
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003757
Monday, May 16, 2011
MyBA
NonConforming
60.08
1.0
Load
60.06
Load (-)
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
8:15:38
Non- Conforming Load
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003758
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
59.9
A Value
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003759
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.94
0.6
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
0.4
59.86
59.84
59.82
0.2
59.8
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
003760
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
003761
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
MW
Frequency - Hz
59.96
59.92
A Value
59.9
B Value
0.00
15.00
0.5
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
003762
Monday, May 16, 2011
BA
Load
MyBA
30600.0
60.08
60.06
30500.0
60.04
60.02
30400.0
60
59.98
30300.0
59.94
30200.0
59.92
A Value
59.9
7651.305
B Value
30136.8
Average Period
20 to 52 second
30100.0
59.88
59.86
30000.0
59.84
59.82
29900.0
59.8
59.78
29800.0
59.76
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
MW
Frequency - Hz
59.96
003763
Monday, May 16, 2011
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
1000.0
60.06
60.04
800.0
60.02
60
600.0
59.98
400.0
59.94
MW
Frequency - Hz
59.96
59.92
59.9
200.0
59.88
59.86
0.0
59.84
59.82
-200.0
59.8
A Value
59.78
8.97
59.76
8:05:38
8:06:38
8:07:38 8:08:38
B Value
671.54
Average Period
20 to 52 second
-400.0
8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Expected Primary Freq Response Based on Bias Setting
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003764
Standards Announcement
Project 2007-12 Frequency Response
Successive Ballot and Non-Binding Poll Open Through 8 p.m. Monday,
November 5, 2012
Now Available
A successive ballot of BAL-003-1 – Frequency Response and Frequency Bias Setting and a non-binding
poll of the associated VRFs/VSLs is open through 8 p.m. Eastern on Monday, November 5, 2012.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standard and opinion in the non-binding poll of the associated VRFs and VSLs by clicking here.
Please read carefully: All stakeholders with comments (both members of the ballot pool as well as
other stakeholders, including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter the comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information and
are not required to answer any other questions.
Next Steps
The drafting team will consider all comments received during the formal comment period and
successive ballot and, if needed, make revisions to the standards. If the comments do not show the
need for significant revisions, the standard will proceed to a recirculation ballot.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. The proposed standard’s intent is
to collect data needed to accurately analyze existing Frequency Response, set a minimum Frequency
Response obligation, provide a uniform calculation of Frequency Bias Settings that transition to values
closer to Frequency Response, and encourage coordinated AGC operation. There is evidence of
continuing decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be analyzed, and the reasons for the decline in Frequency Response
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003765
can be identified. Once Frequency Response has been analyzed and confirmed, requirements can be
modified to maintain reliability.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-12
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003766
Standards Announcement
Project 2007-12 Frequency Response
Formal Comment Period Open:
October 5, – November 5, 2012
Upcoming:
Successive Ballot and Non-binding Polls:
October 26 – November 5, 2012
Now Available
BAL-003-1 – Frequency Response and Frequency Bias Setting, an implementation plan and several
associated documents (listed below) have been posted for a parallel formal comment period and
successive ballot through 8 p.m. Eastern on Monday, November 5, 2012.
The following associated documents have been posted for stakeholder review and comment:
Frequency Response Standard Background Document – Provides an explanation of each of the
proposed requirements; identifies how the proposed standard proposes to address FERC
directives from Order 693; and describes the decision process for use of the median as the
measure for Frequency Response.
Attachment A – Provides methodology for calculating Interconnection Frequency Response
Obligation, Balancing Authority Frequency Response Obligation, Frequency Response Measure
and the Frequency Bias Setting.
Procedure – Assigns tasks to the ERO and provides instructions for the ERO to follow when
carrying them out to support the BAL-003-1 standard.
FRS Form 1 (three versions – multiple Balancing Authority Interconnection, ERCOT and
Quebec) and FRS Form 2 (three versions – multiple Balancing Authority Interconnection,
ERCOT and Quebec) used to determine each Balancing Authority’s Frequency Response
Measure and Frequency Bias Setting. Instructions are now on the first page of each FRS Form 1
and FRS Form 2.
Mapping Document – Identifies each requirement in the already approved BAL-003-0.1b and
identifies how that requirement has been treated in the revisions proposed in BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003767
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, November 5, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Wendy Kinnard at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page.
Please read carefully: All stakeholders with comments (both members of the ballot pool as well as
other stakeholders, including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter the comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information and
are not required to answer any other questions.
Next Steps
A successive ballot and non-binding polls of the associated VRFs and VSLs will be conducted Friday,
October 26, 2012 through 8 p.m. Monday, November 5, 2012.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. The proposed standard’s intent is
to collect data needed to accurately analyze existing Frequency Response, set a minimum Frequency
Response obligation, provide a uniform calculation of Frequency Bias Settings that transition to values
closer to Frequency Response, and encourage coordinated AGC operation. There is evidence of
continuing decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be analyzed, and the reasons for the decline in Frequency Response
can be identified. Once Frequency Response has been analyzed and confirmed, requirements can be
modified to maintain reliability.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Standards Announcement: Project 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003768
For more information or assistance, please contact Wendy Kinnard,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-12 Frequency Response
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003769
Standards Announcement
Project 2007-12 Frequency Response
Formal Comment Period Open:
October 5, – November 5, 2012
Upcoming:
Successive Ballot and Non-binding Polls:
October 26 – November 5, 2012
Now Available
BAL-003-1 – Frequency Response and Frequency Bias Setting, an implementation plan and several
associated documents (listed below) have been posted for a parallel formal comment period and
successive ballot through 8 p.m. Eastern on Monday, November 5, 2012.
The following associated documents have been posted for stakeholder review and comment:
Frequency Response Standard Background Document – Provides an explanation of each of the
proposed requirements; identifies how the proposed standard proposes to address FERC
directives from Order 693; and describes the decision process for use of the median as the
measure for Frequency Response.
Attachment A – Provides methodology for calculating Interconnection Frequency Response
Obligation, Balancing Authority Frequency Response Obligation, Frequency Response Measure
and the Frequency Bias Setting.
Procedure – Assigns tasks to the ERO and provides instructions for the ERO to follow when
carrying them out to support the BAL-003-1 standard.
FRS Form 1 (three versions – multiple Balancing Authority Interconnection, ERCOT and
Quebec) and FRS Form 2 (three versions – multiple Balancing Authority Interconnection,
ERCOT and Quebec) used to determine each Balancing Authority’s Frequency Response
Measure and Frequency Bias Setting. Instructions are now on the first page of each FRS Form 1
and FRS Form 2.
Mapping Document – Identifies each requirement in the already approved BAL-003-0.1b and
identifies how that requirement has been treated in the revisions proposed in BAL-003-1.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003770
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, November 5, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Wendy Kinnard at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page.
Please read carefully: All stakeholders with comments (both members of the ballot pool as well as
other stakeholders, including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter the comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information and
are not required to answer any other questions.
Next Steps
A successive ballot and non-binding polls of the associated VRFs and VSLs will be conducted Friday,
October 26, 2012 through 8 p.m. Monday, November 5, 2012.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. The proposed standard’s intent is
to collect data needed to accurately analyze existing Frequency Response, set a minimum Frequency
Response obligation, provide a uniform calculation of Frequency Bias Settings that transition to values
closer to Frequency Response, and encourage coordinated AGC operation. There is evidence of
continuing decline in Frequency Response over the past 10 years, but no confirmed reason for the
apparent decline. The proposed standard requires entities to provide data so that Frequency Response
in each of the Interconnections can be analyzed, and the reasons for the decline in Frequency Response
can be identified. Once Frequency Response has been analyzed and confirmed, requirements can be
modified to maintain reliability.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Standards Announcement: Project 2007-12 Frequency Response
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003771
For more information or assistance, please contact Wendy Kinnard,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-12 Frequency Response
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003772
Standards Announcement
Project 2007-12 Frequency Response
Successive Ballot and Non-Binding Poll Results
Now Available
A successive ballot of BAL-003-1 – Frequency Response and Frequency Bias Setting and a non-binding
poll of the associated VRFs/VSLs concluded on Tuesday, November 6, 2012.
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Approval
Non-binding Poll Results
Quorum: 82.04%
Quorum:
76.28%
Approval: 76.08%
Supportive Opinions: 76.30 %
Next Steps
The drafting team will consider all comments received during the formal comment period and
successive ballot and, if needed, make revisions to the standards. If the comments do not show the
need for significant revisions, the standard will proceed to a recirculation ballot.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. There is evidence of continuing
decline in Frequency Response over the past 10 years, but no confirmed reason for the apparent
decline. The proposed standard would set a minimum Frequency Response obligation for each
Balancing Authority, provide a uniform calculation of Frequency Response and Frequency Bias Settings
that transition to values closer to natural Frequency Response, and encourage coordinated AGC
operation.
Additional information is available on the project page.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003773
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-12
2
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003774
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-12 Successive Ballot Frequency Response Oct 2012_in
Password
Ballot Period: 10/26/2012 - 11/6/2012
Ballot Type: Initial
Log in
Total # Votes: 297
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 362
Quorum: 82.04 % The Quorum has been reached
Weighted Segment
76.08 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
92
11
79
28
80
48
0
9
6
9
362
#
Votes
1
1
1
1
1
1
0
0.8
0.2
0.7
7.7
#
Votes
Fraction
35
5
41
15
37
24
0
8
0
7
172
Negative
Fraction
0.603
0.5
0.788
0.938
0.755
0.774
0
0.8
0
0.7
5.858
Abstain
No
# Votes Vote
23
5
11
1
12
7
0
0
2
0
61
0.397
0.5
0.212
0.063
0.245
0.226
0
0
0.2
0
1.843
20
1
14
6
12
7
0
1
1
2
64
14
0
13
6
19
10
0
0
3
0
65
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Member
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
James Armke
Scott J Kinney
Kevin Smith
Gregory S Miller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
Ballot
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Comments
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Raj Rana
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Joseph Turano Jr.
Negative
Negative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Gordon Pietsch
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D Schellberg
Tino Zaragoza
Michael Moltane
Abstain 003775
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Cole C Brodine
Negative
Negative
Affirmative
Randy MacDonald
Negative
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brad Chase
Ryan Millard
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A. Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
Rajendrasinh D Rana
John C. Allen
Tim Kelley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Negative
Abstain
Negative
Negative
Abstain
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Kathryn Spence
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Angela L Summer
Noman Lee Williams
Beth Young
Larry G Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Patrick Woods
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Brian Glover
Paul C Caldwell
David Kiguel
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
003776
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
LaGen
Madison Gas and Electric Co.
Northern California Power Agency
Ohio Edison Company
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
David Anderson
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Richard Comeaux
Joseph DePoorter
Tracy R Bibb
Douglas Hohlbaugh
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
Abstain 003777
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Edison Mission Energy
Electric Power Supply Association
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Mike D Kukla
Affirmative003778
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Francis J. Halpin
Carla Bayer
Chifong Thomas
Jeanie Doty
Paul A. Cummings
Affirmative
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Ellen Oswald
John R Cashin
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
S N Fernando
David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Allen D Schriver
Hari Modi
William O. Thompson
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
Joseph O'Brien
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Abstain 003779
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
6
6
6
6
6
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Energy Mark, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F Lemmons
Edward C Stein
Robert Blohm
James A Maenner
Roger C Zaklukiewicz
Howard F. Illian
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
003780
Donald Nelson
Diane J. Barney
Negative
Thomas G. Dvorsky
Jerome Murray
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Negative
Abstain
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=382b433b-ea44-425e-bfdc-2a7d66e15634[11/7/2012 1:25:50 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003781
Non-binding Poll Results
Project 2007-12 Frequency Response
Non-binding Poll Results
Non-binding Poll
Project 2007-12 Non-binding Poll
Name:
Poll Period: 10/26/2012 - 11/6/2012
Total # Opinions: 254
Total Ballot Pool: 333
76.28% of those who registered to participate provided an opinion or an abstention;
Summary Results: 76.30% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
1
1
1
1
Ameren Services
American Electric Power
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern
California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
Clark Public Utilities
Colorado Springs Utilities
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Member
Kirit Shah
Paul B. Johnson
John Bussman
Scott J Kinney
Kevin Smith
Comments
Abstain
Affirmative
Abstain
Abstain
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Tony Kroskey
Joseph Turano Jr.
Negative
Negative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de
Consolidated Edison Co. of New York
Graffenried
CPS Energy
Richard Castrejana
Dairyland Power Coop.
Robert W. Roddy
Dayton Power & Light Co.
Hertzel Shamash
Deseret Power
James Tucker
Dominion Virginia Power
Michael S Crowley
Duke Energy Carolina
Douglas E. Hils
East Kentucky Power Coop.
George S. Carruba
Empire District Electric Co.
Ralph F Meyer
Entergy Services, Inc.
Edward J Davis
FirstEnergy Corp.
William J Smith
Florida Keys Electric Cooperative Assoc. Dennis Minton
Florida Power & Light Co.
Mike O'Neil
Non-Binding Poll Results: Project 2007-12
Opinions
Abstain
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Negative
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003782
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Gainesville Regional Utilities
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Non-Binding Poll Results: Project 2007-12
Luther E. Fair
Gordon Pietsch
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Cole C Brodine
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Randy MacDonald
Abstain
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Doug Peterchuck
Brad Chase
Ryan Millard
John C. Collins
John T Walker
Larry D Avery
Brenda L Truhe
Brett A. Koelsch
Laurie Williams
Kenneth D. Brown
Abstain
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Kathryn Spence
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Negative
Negative
Negative
Abstain
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003783
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Noman Lee Williams
Beth Young
Larry G Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Charles B Manning
Independent Electricity System
Barbara Constantinescu
Operator
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
Tom Bowe
Southwest Power Pool, Inc.
Charles Yeung
AEP
Michael E Deloach
Alabama Power Company
Richard J. Mandes
Ameren Services
Mark Peters
APS
Steven Norris
Atlantic City Electric Company
NICOLE BUCKMAN
BC Hydro and Power Authority
Pat G. Harrington
Bonneville Power Administration
Rebecca Berdahl
City of Bartow, Florida
Matt Culverhouse
City of Clewiston
Lynne Mila
City of Garland
Ronnie C Hoeinghaus
City of Green Cove Springs
Gregg R Griffin
City of Redding
Bill Hughes
Cleco Corporation
Michelle A Corley
Colorado Springs Utilities
Charles Morgan
Consolidated Edison Co. of New York
Peter T Yost
Constellation Energy
CJ Ingersoll
Consumers Energy
Richard Blumenstock
CPS Energy
Jose Escamilla
Detroit Edison Company
Kent Kujala
Dominion Resources Services
Michael F. Gildea
Duke Energy Carolina
Henry Ernst-Jr
Non-Binding Poll Results: Project 2007-12
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003784
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations
Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam
County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Non-Binding Poll Results: Project 2007-12
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
Abstain
Affirmative
Affirmative
Affirmative
William N. Phinney
Wesley W Gray
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Michael Schiavone
William SeDoris
David Anderson
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
David Proebstel
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Abstain
Affirmative
Affirmative
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003785
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
Seattle City Light
Dana Wheelock
Seminole Electric Cooperative, Inc.
James R Frauen
Snohomish County PUD No. 1
Mark Oens
South Carolina Electric & Gas Co.
Hubert C Young
Tacoma Public Utilities
Travis Metcalfe
Tampa Electric Co.
Ronald L Donahey
Tennessee Valley Authority
Ian S Grant
Tri-State G & T Association, Inc.
Janelle Marriott
Westar Energy
Bo Jones
Xcel Energy, Inc.
Michael Ibold
Alliant Energy Corp. Services, Inc.
Kenneth Goldsmith
American Municipal Power
Kevin Koloini
Blue Ridge Power Agency
Duane S Dahlquist
City of Austin dba Austin Energy
Reza Ebrahimian
City of Clewiston
Kevin McCarthy
City of New Smyrna Beach Utilities
Tim Beyrle
Commission
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri
John Allen
Consumers Energy
David Frank Ronk
Detroit Edison Company
Daniel Herring
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Thomas Richards
Georgia System Operations Corporation Guy Andrews
Imperial Irrigation District
Diana U Torres
Madison Gas and Electric Co.
Joseph DePoorter
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Public Utility District No. 1 of Douglas
Henry E. LuBean
County
Public Utility District No. 1 of Snohomish
John D Martinsen
County
Sacramento Municipal Utility District
Mike Ramirez
Seattle City Light
Hao Li
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
AEP Service Corp.
Brock Ondayko
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
Arizona Public Service Co.
Edward Cambridge
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Black Hills Corp
George Tatar
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Non-Binding Poll Results: Project 2007-12
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Abstain
Affirmative
Abstain
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003786
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Bonneville Power Administration
BrightSource Energy, Inc.
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Water, Light & Power of Springfield
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Edison Mission Energy
Electric Power Supply Association
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Non-Binding Poll Results: Project 2007-12
Francis J. Halpin
Chifong Thomas
Jeanie Doty
Paul A. Cummings
Negative
Affirmative
Affirmative
Affirmative
Max Emrick
Affirmative
Steve Rose
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Ellen Oswald
John R Cashin
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Affirmative
Kenneth Silver
Affirmative
Mike Laney
S N Fernando
Affirmative
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Allen D Schriver
Hari Modi
William O. Thompson
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003787
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities
Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Northern Indiana Public Service Co.
Non-Binding Poll Results: Project 2007-12
Wayne Lewis
Tim Kucey
Abstain
Steven Grega
Abstain
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
Abstain
Negative
Negative
Affirmative
Negative
Negative
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Brad Packer
Affirmative
Brad Jones
Daniel Prowse
Dennis Kimm
Joseph O'Brien
Affirmative
Affirmative
Affirmative
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003788
6
Omaha Public Power District
6
Orlando Utilities Commission
6
6
6
6
6
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
Xcel Energy, Inc.
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
10
10
10
10
10
10
10
10
10
Energy Mark, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Non-Binding Poll Results: Project 2007-12
David Ried
Claston Augustus
Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Affirmative
Affirmative
Abstain
Abstain
Abstain
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Howard F. Illian
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Donald Nelson
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003789
Name (33 Responses)
Organization (33 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
Contact Organization (17 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (8 Responses)
Comments (50 Responses)
Question 1 (32 Responses)
Question 1 Comments (42 Responses)
Question 2 (31 Responses)
Question 2 Comments (42 Responses)
Question 3 (27 Responses)
Question 3 Comments (42 Responses)
Question 4 (34 Responses)
Question 4 Comments (42 Responses)
Question 5 (23 Responses)
Question 5 Comments (42 Responses)
Question 6 (24 Responses)
Question 6 Comments (42 Responses)
Question 7 (25 Responses)
Question 7 Comments (42 Responses)
Question 8 (24 Responses)
Question 8 Comments (42 Responses)
Question 9 (0 Responses)
Question 9 Comments (42 Responses)
Individual
Richard Vine
California Independent System Operator
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
The ISO supports the development of BAL-003-1 and would like to offer the following
comments/suggestions: (1) Some BAs may have to develop a new Ancillary Service product to ensure
that its FRO can be met and believes that 12 months after FERC’s approval may not provide adequate
time to stakeholder and modify market software applications. The ISO suggest increasing the
implementation timeline by at least one more year. (2) If the implementation timeline cannot be
changed, then the ISO suggests that compliance should be waived for the first year of operation
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003790
under BAL-003-1. (3) Some BAs may elect to procure a portion of its FRO through bilateral
agreements for certain hours (e.g. off-peak) with a neighboring BA. Since a contingency could be in a
BA other than the two BAs under a bilateral agreement, the standard or background document needs
to clarify the duration of frequency response so that transmission reservation is not a requirement for
frequency response. The ISO believes that the BA experiencing the contingency should have adequate
arrangements in place to deal with internal contingencies.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
Yes
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service (supplying
actual interchange, frequency response, and schedules to another BA), then it can be assumed that
the BA is supplying regulation service. Was the intent of the requirement to simply state that all BA’s
must have a bias setting less than zero at all times? The intent of this requirement needs to be
clarified.
No
This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource contingency criteria (in
the attachment, this is called the “target contingency criteria”), etc. A sample calculation would be of
value to entities. “The largest category C (N-2) event is used for all interconnections except the
Eastern which uses the largest event in the last 10 years”. All interconnections should be using the
same design basis contingency. The NERC 2012 CPS2 bounds has an Eastern Interconnection
frequency bias of -6,360 MW/.1Hz. Why does this attachment refer to an Interconnection frequency
response obligation of -1,002MW/.1Hz.? This is a significant difference.
No
While the discussion of primary frequency response includes inertial energy, the term inertial energy
is missing from the definition of “primary frequency response”.
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in BAL-001. The
Standard is currently confusing to understand, and it is unclear how the bias is calculated. It is
recommended that efforts should be made to clarify the changes, especially in Attachment A.
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard, then
GO’s and GOP’s should be included in the applicability since they are the entities responding to the
AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s should be
updated.
Individual
Howard F. Illian
Energy Mark, Inc.
Yes
Yes
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003791
Yes
Yes
Yes
Yes
Yes
Although I am in favor of using linear regression to determine the FRM, the standard using Median is
better than not having a standard.
Group
Edison Electric Institute
Mark Gray
Edision Electric Institute (Trade Association)
Yes
No
EEI does not fully agree with the definition of a “Frequency Response Sharing Group” (FRSG). In the
definition offered in the new Standard, it states that the FRSG “collectively maintain, allocate, and
supply operating resources”. Of the three roles, a balancing authority only maintains loadinterchange-generation balance through the allocation of resources. Therefore, EEI suggests that the
definition be changed to more appropriately align with the role of a BA, which we believe would be to
allocate resources in a manner that effectively allows the sharing of resources necessary to achieve a
FRO within the defined sharing group, which might otherwise not be possible or practical by a BA on
its own.
Yes
Yes
Yes
EEI supports the ERO’s role as defined in the procedure but is concerned that the procedure, unlike
approved NERC standards, is unbounded by the current rules for developing standards. For that
reason, EEI recommends that the procedure become more formalized and integrated into the
standard as an addendum thereby avoiding any Industry concerns that future modification might
occur outside the approved processes
Yes
EEI finds the method to be acceptable but as mentioned in our response to question No. 5 (above),
we believe that the procedure should be more formally documented as an addendum. Such a change
would ensure that the document would remain unchanged outside of the approved standards making
process. Additionally, EEI does not support using 4500 MW loss as the basis for determining the FRO
for the Eastern Interconnection for future events. However, as the calculation also includes 59.5 Hz as
the basis for determining the FRO, the results is an allocation which we believe is acceptable. In the
future, should the SDT decide to use 59.7 Hz as the basis for the FRO, than it will need to follow a
methodology similar to the other interconnections for determining the credible multiple contingency to
cover.
Yes
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003792
EEI supports the efforts and improvements made by the Standards Drafting Team (SDT) in the latest
version of BAL-003 and believe those changes have been responsive to the directives in Order 693.
However, we recognizes that the Industry has struggled with this standard and remains split as to
how best to respond to those directives and in some cases there are those who question whether a
standard is even necessary. Given the many open issues and the concerns expressed by stakeholders
we anticipate that this standard will once again fail to achieve sufficient support to gain approval.
Should the Standard fail to achieve ballet approval, it is our hope that NERC Staff and the NERC Board
of Trustees will allow the SDT a little more time to resolve any final issues that have been identified in
this latest ballet. Although we recognize that May 31, 2013 does not leave the ERO with a lot of time
to comply with this FERC imposed deadline, we still remain confident that given the progress made by
the SDT a standard, which is acceptable to the Industry, is still possible. To the extent EEI can help,
we are committed to working with member companies to communicate the issues and exchange
insights from the SDT to help as we can to achieve a positive outcome.
Individual
Thad Ness
American Electric Power
As provided in question 2 below, AEP does not agree with the definition containing the Frequency
Response Sharing Group as this function does not exist at this point in time.
No
AEP does not necessarily disagree with the words of the definition. However, AEP does not believe it is
appropriate to define a new function that is not in the NERC Rules of Procedure, NERC Statement of
Registry Criteria, or the NERC Functional Model. It is premature to incorporate this entity without a
proposed change to these governing NERC documents.
No
AEP believes this question in the comment form is incorrect. It appears that R3 and R4 are
inadvertenly merged together.
No
AEP is under the impression that there are some requirements, which though not explicitly stated, are
implied in Attachment A. AEP feels strongly that these “sub-requirements” should be clarified and
contained within the body of the requirements of the standard.
There is no leverage for the BA to require the generator to carry their burden of addressing governor
settings or droop settings, yet the BA is obligated to meet some performance measures in that
regard. This revision adds new performance measure responsibilities on the BA who likely has no
direct control over every resource affecting their performance within their footprint. We are not
necessarily challenging the performance measures themselves, nor their underlying objectives,
however AEP views this as a gap in responsibilities which potentially effects reliability. AEP suggests
that GOPs be considered as part of this standard so that their performance can be factored into the
process to meet the performance objectives.
Group
NREL Transmission and Grid Integration Group
Erik Ela
National Renewable Energy Laboratory
Yes
Yes
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003793
Yes
Table 1: CB_r units should be unitless, CB'adj should be Hz.
Yes
Yes
Yes
Yes
We commend the drafting team for a rigorous approach to this new and important standard. Being
observers who have a strong interest in this standard as it applies to much of the research that we
do, but not stakeholders of the ultimate standard, we submit our overall comments as
recommendations here. We believe there are a few potential issues, that may at least need more
thought before going forward. The first is the credit for LR. (1) Overfrequency can be an issue: using
ERCOT as an example, with -282 MW/0.1Hz response and 1400 MW of LR all responsive at 59.7 Hz, if
just meeting FRO requirements, the 1400MW LR can all be triggered with a loss of (282*3=) 846MW,
causing (1400-846=)554MW of overgeneration. This can be exacerbated by further increases of LR
without recognition of the triggering frequency, and the disconnect between BA and interconnection in
the other interconnections. (2) With crediting LR toward the Interconnection, it will not give incentive
toward BAs to provide it. We believe the LR should contribute to the BA FRO rather than discount the
IFRO. (3) There is no requirement for frequency response capacity (ie MW) available to provide the
FR. This is a nonissue in today's world with the amount of spinning reserve already available, but the
issue could be apparent on future systems with increased reserve sharing, or reserve capacity from
resources that operate in modes which do not provide frequency response. The European
Interconnection requirement has two intentions: a 3,000 MW capacity requirement and a 1,500
MW/0.1Hz FRO requirement that is allocated out to its Transmission System Operators. This could
solve the issue with LR and generators, where LR is in MW and generation governing is in MW/0.1Hz.
(4) It is likely, and from our understanding is true in some areas like ERCOT, that the LR is selected
based on market solutions, and may not be available all times of the year. This is another reason why
the LR should contribute to the BA FRO rather than discount the IFRO. (5) It may be beneficial to
guide frequency settings for LR or even multiple settings to mimic a droop curve for LR. Other
potential issues not related to the LR. We think the SDT has done an outstanding job on reviewing the
data sets and determining statistically based values to better account for different factors that may
affect minimum frequency levels. We agree that there are current issues in the primary governing
response, but that there may be a disconnect in fixing those issues with the static values. We also
agree that there is not an easy solution. In specific: (6) The static CB ratio might not incentivize BAs
to improve response with increased inertia or faster responding governing response. (7) The static
withdrawal BC'adj may not incentivize BAs to improve their governing response and limit their
withdrawal. Improved technology may allow for better measurement to account for these issues
dynamically rather than using static numbers. Guidance on increasing inertia, increasing governing
speed, and reducing withdrawal should be considered by stakeholders. We thank NERC and the SDT
for the opportunity to provide comments on this important standard.
Individual
Jonathan Appelbaum
The United Illuminating Company
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003794
UI believes the VRF should be High. The VRF justification for Medium is that the prior year’s bias
setting would exist in the control system so the impact would not cause a Cascade. UI thinks that is
an adjustment factor that is applied after non-compliance is determined. Not having settings is likely
to cause cascade so the VRF is High.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
Yes
Yes
No
The supporting document on the standards page does not provide information on CB Ratio and why it
is used. It significantly increases FRO and should be justified based upon strong technical basis and
actual experience. (Please also see AZPS response to question 6, The Frequency Response Initiative
Report should be on the Standards page).
NO: 1. The Frequency Response initiative report should be added to the standard as an appendix. It is
not clear where to find this report. 2. The jusitification for dividing delta frequency with C to B ratio is
not adequate and not clear.
NO: 1. Either do not use C to B Ratio or provide adequate rational for using it. It appears to make
FRO unnecessarily too conservative and is not justified based upon experience. 2. The VRF is too
complicated and hard to understand. It must be either simplified or should be followed by example. 3.
The Frequency Response Obligation Methodology on Page 7 of “Procedure” does not show any formula
(it is blank).
As mentioned in Item 8 above, the VRF language is too complicated and hard to follow. Even though
the VRF poll is non binding, it needs to be clear and simple enough to be understood.
Individual
Travis Metcalfe
Tacoma Power
Yes
Yes
Yes
Yes
The addition to the Frequency Bias Setting definition of “and discourage response withdrawal through
secondary control systems” seems incomplete. Tacoma Power does not see anything in the standard
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003795
that addresses (or measures) how a frequency bias setting will discourage response withdrawal
through secondary systems. This should either be more fully addressed or removed.
Individual
Nazra Gladu
Manitoba Hydro
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
(1) Page 2, Balancing Authority Frequency Response Obligation (FRO) and Frequency Bias Setting:
States that the ERO is responsible for “annually assigning an FRO and Frequency Bias Setting to each
BA.” No mention is made of FRSGs. (2) Neither R1 nor the referenced Attachment A clarifies the FRM
requirements for an FRSG to comply versus a BA. In particular, compared to BAL-002-0 R1.1, which
clearly states that the BA may elect to fulfill its obligation through an FRSG and that in such cases the
FRSG has the same responsibilities as each BA (that is a participant in the FRSG). (3)Attachment A
refers to an FRSG calculating FRM, but the standard does not.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Purpose: Is the reference to ‘Interconnection Frequency’ supposed to be ‘Frequency Response’? This
would be consistent with later wording in the standard. R1: (1) The acronym ‘FRO’ is used
inconsistently within the document. (2) The phrase “to ensure that sufficient Frequency Response …”
should be separated from the requirement as it is (i) not descriptive of the required actions; (ii)
redundant with the stated purpose at the beginning of the standard. In general, such a drafting
technique should be avoided as it may allow Responsible Entities to argue that a violation has not
occurred where the specific action that is described has not been taken, but the purpose referenced in
the requirement has been met. M1: The reference to ‘documented formula’ is not clear. Does this
imply that the FRSG or BA have a record of their calculation? In addition, there is a typo, a random ‘)’
after FRM. M2: Should include the words ‘and uses a fixed Frequency Bias Setting…’ after overlap
Regulation Service to make the wording consistent within the Requirement. M3: The wording of this
measure switches tenses between ‘is’ and ‘was’. For consistency, we suggest that this be corrected.
NERC Glossary definition of an FRSG is a group of BAs that collectively maintain, allocate and supply
operating resources required to jointly meet the sum of the Frequency Response Obligations of its
members. No mention is made of the agreement including the sharing or delegation of responsibility
related to FRM. Accordingly, the standard should only reference a BA being able to delegate
responsibility to an FRSG if the RSG Agreement allows for such delegation. Data Retention 1.3.: (1)
As the standard is currently drafted, both the BA and the FRSG would be required to retain data or
evidence to show compliance with requirements R1 and M1. It is unclear whether this is the intention,
or whether it would be acceptable that just one or the other would maintain such records. (2) In the
third paragraph, it should be clarified who is required to keep information related to non compliance if
the BA belongs to an FRSG – the BA or the FRSG or both.
Individual
Alice Ireland
Xcel Energy
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003796
Yes
Yes
Yes
It is not clear however, as to if this is actually part of the standard or if it is a document that can be
revised without going through the standards development process. Also, the formatting of the
doucment should be modified to clearly identify where 'steps/actions' are needed from repsonsible
parties, whether that be the ERO or BA/FRSG.
YES. It is not clear however, as to if this is actually part of the standard or if it is a document that can
be revised without going through the standards development process. Also, the formatting of the
doucment should be modified to clearly identify where 'steps/actions' are needed from repsonsible
parties, whether that be the ERO or BA/FRSG.
Xcel Energy supports this proposed revision to the standard as a first step and suggests that after
operating for a couple of years under the revised standard, that NERC initiates a more complete study
to support any modifications to the standard.
Group
MRO NSRF
WILL SMITH
MIDWEST RELIABILITY ORGANIZATION
Yes
Yes
No
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing Authority
Interconnections from compliance with Requirement R3. To ensure a consistent approach in the
application of the standard, recommend R3 be revised as follows: (R3). Each Balancing Authority that
is not receiving Overlap Regulation Service and is utilizing a variable Frequency Bias Setting shall
maintain a Frequency Bias Setting that is: …
Yes
MRO NSRF AGREES
MRO NSRF AGREES
MRO NSRF AGREES
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing Authority
Interconnections from compliance with Requirement R2. To ensure a consistent approach in the
application of BAL-003-1, recommend R2 be revised as follows: (R2). Each Balancing Authority that is
a member of a multiple Balancing Authority Interconnection and is not receiving Overlap Regulation
Service and uses a fixed Frequency Bias Setting shall implement the Frequency Bias Setting
determined subject to Attachment A, as validated by the ERO, into its Area Control Error (ACE)
calculation …
Group
pacificorp
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003797
ryan millard
pacificorp
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
Bonneville Power Administration
Chris Higgins
Transmission Reliability Program
Yes
Yes
Yes
BPA is responding to 3.1 and 3.2 of R3. The bullets listed in question 3 on the original comment form
appear to be for Requirement R4. BPA is in support of R3.1 and R3.2.
No
BPA does not agree with the methodology in Attachment A. Please see BPA’s response to question 6
as well as BPA’s extensive comments submitted on 12/8/11 for Project 2007-12 Frequency Response
found at: http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
No
BPA does not agree with the methodologies outlined in Attachment B. Please see BPA’s response to
question 6 as well as BPA’s extensive comments submitted on 12/8/11 for Project 2007-12 Frequency
Response found at: http://www.nerc.com/docs/standards/sar/200712_comments_received_120911.pdf
No
BPA does not have specific changes to the methodology to suggest, however, a methodology that
arrives at a negative 840 MW per tenth Hz for WECC is obviously under-calculating the frequency bias
obligation. Currently WECC has an interconnection bias of over 2000 MW / 0.1Hz and with this bias
the frequency is steady state following point B on the frequency response curve. BPA would expect to
see frequency decline after point B if the FBO is lowered by almost 60%. BPA also must reiterate that
there is still a problem with the method used for modifying the FBO and frequency bias for Balancing
Authorities. A high-performing Balancing Authority will have its frequency bias increased each year
due to higher response during the events chosen by the ERO. Conversely, a low-performing Balancing
Authority will have its frequency bias reduced each year due to lower response during the events
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003798
chosen by the ERO.
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is developing into. Please
reference BPA’s extensive comments submitted on 12/8/11 for Project 2007-12 Frequency Response
found at: http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is developing into. Please
reference BPA’s extensive comments submitted on 12/8/11 for Project 2007-12 Frequency Response
found at: http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Individual
Shammara Hasty
Southern Company (Alabama Power Company, Georgia Power Company, Gulf Power Company,
Mississippi Power Company, Southern Company Services,Inc., Southern Company Generation,
Southern Company Energy Market)
Yes
Yes
Yes
Yes
No
Attachment A states that Form 1 is posted annually. The ERO support document selects events
annually. The timing for the two documents needs to be aligned so that the set of selected events
does not change from quarter to quarter. (If three events are selected for the first quarter those
same events will be a sub-set of the 20 events selected for the annual compliance calculations.)
No
The industry needs some assurance that the calculation of the Interconnection FRO described in the
report cannot be changed outside of the Standards Process for approval by the industry. We do not
support using a 4500 MW loss as the basis for determining the FRO for the Eastern Interconnection
for future events. However, as the calculation also includes 59.5 Hz as the basis for determining the
FRO, the result is an allocation which can be supported. To the extent that the standard drafting team
moves in the direction of using 59.7 Hz as the basis for the FRO, then it needs to follow a
methodology similar to the other Interconnections for determining the credible multiple contingency
to cover.
Yes
Yes
Please refer to comments for question 9.
The organization selecting events must ensure that the change in frequency is outside the normal
dead-band of generator governors. Many of the events selected in the past have not been outside the
dead-band and therefore, the frequency response was much less than expected. Southern Company
proposes .07 which is consistant with WECC.
Individual
Greg Travis
Idaho Power Company
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003799
Yes
Yes
Yes
Yes
Yes
Yes
Individual
John Seelke
Public Service Enterprise Group
PSEG entities will vote “Negative” on the standard until this Project 2007-12 achieves the following:
1. It coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls
Reserves, specifically BAL-012-1, regarding (a) definitions and (b) requirements that address
frequency response in both standards. a. Definitions that need to be coordinated: BAL-003-2 –
“Frequency Response Obligation” and BAL-012-1 – “Frequency Responsive Reserve.” b. Requirements
that need to be coordinated: i. BAL-003-1, per R1, states “Each Frequency Response Sharing Group
(FRSG) or Balancing Authority that is not a member of a FRSG shall achieve an annual Frequency
Response Measure (FRM) (as calculated and reported in accordance with Attachment A) that is equal
to or more negative than its Frequency Response Obligation (FRO) to ensure that sufficient Frequency
Response is provided by each FRSG or BA that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more negative than the Interconnection Frequency
Response Obligation.” ii. BAL-012 requires BAs to have sufficient Frequency Responsive Reserves per
R6, which requires BAs to “assess, on at least an hourly basis, that it has sufficient Regulating
Reserve, Contingency Reserve, and Frequency Responsive Reserve to meet its reserve plan(s) to
ensure reliable operation of the Bulk Electric System.” For Frequency Responsive Reserves, R3 in BAL012-1 requires BAs to develop an annual plan for these reserves. BAs should not be subject to
duplicative requirements for frequency response requirements in different standards that are
underdevelopment. Only one standard needs to define the frequency response requirements for BAs
(we suggest that be BAL-003-1), although other standards, such as BAL-012-1, may reference that
obligation. However, this decision should be made by consensus between the two SDTs. 2. It
coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls
Reserves, specifically BAL-012-1, to develop an application guide that would be attached to one of the
standards and that could be referenced by each standard. The application guide would include: a. A
hypothetical implementation plan for a BA that demonstrates how the BA may meet its Frequency
Response Obligation or Frequency Responsive Reserve prior to an event. This is a technical issue and
should not be confused with the institutional issue in #3 below. b. An explanation of the relationship
between Regulating Reserve, Contingency Reserve, and Frequency Responsive Reserve contained in
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003800
BAL-012-1 so that potential double counting (and whether that is proper of improper), is addressed.
3. Project 2007-12’s “Frequency Response Standard Background Document” dated October, 2012 lists
several methods of obtaining Frequency Response. Most of those are extracted below. We have
provided questions and commentary that we ask the team to address. a. “Regulation services.” This is
addressed in BAL-001-0.1a. The purpose of this standard is “To maintain Interconnection STEADYSTATE FREQUENCY within defined limits by balancing real power demand and supply in real-time.
How is this related to Frequency Response for a disturbance? (The team may answer this as part of
2.b above.) b. “Through a tariff (e.g. Frequency Response and regulation service). “ The team is
advised to review the actual pro-forma OATT schedule for Schedule 3 “Regulation and Frequency
Response Service” which is specifically limited to services providers that are “capable of providing this
service as necessary to follow the moment-by-moment changes in load.” Again, how is this related to
Frequency Response for a disturbance? (The team may answer this as part of 2.b above.) c. “From
generators through an interconnection agreement.” The FERC’s pro-forma Standard Large Generator
Interconnection Agreement (LGIA) per Order 2003 contains no requirement for generators to provide
Frequency Response service, and we are not aware on ANY interconnection agreement that does. We
ask that the team point to ANY interconnection agreement with such a requirement. Modification of an
interconnection agreement to incorporate such a requirement would require the consent of both
parties. d. “Contract with an internal resource or loads.” Since Frequency Response service would
likely be considered as a necessary service to provide Transmission Service under an OATT, it would
require a tariff. What existing tariff applies in the U.S.? The “methods” above that the team has listed
have the factual errors described. The standard BAL-003-1 cannot be implemented until the
necessary tariffs are developed that permit BAs and FRSGs to contract for Frequency Response
services. Once that is done, BAL-003-1 can dictate the performance requirements of a BA or FRSG. •
For context, FERC OATT schedules relevant to Frequency Response DO NOT set performance
requirements. Schedule 3 (Regulation and Frequency Response Service) sets forth a tariff for the
service, while BAL-001-0.1a sets forth performance requirements in aggregate for a BA or RSG.
Likewise, Schedule 5 (Operating Reserve - Spinning Reserve Service) and Schedule 6 (Operating
Reserve - Supplemental Reserve Service) set tariffs for both services, while BAL-002-1 sets
performance requirement. Without an OATT schedule for Frequency Response service, BAs and FRSGs
will have no means to contract with generators or loads to provide Frequency Response per BAL-0031. The team should address this concern.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Not Applicable
Not Applicable
No
As indicated in our previous comments, the status of Attachment A is unclear. It is a mixture of
requirements, criteria, process and guideline. Making a direct reference in the standard’s
requirements (R1 and R2) makes Attachment A as part of the requirement and hence is enforceable,
but it contains process and guideline information that is not subject to assessment. On the other
hand, the absence of a Measure to assess adherence to the criteria and process suggests that
Attachment A is not enforceable. It is this ambiguity that makes it difficult for the industry to assess
the extent to which they must follow the process. Again, we urge the SDT to keep only the
criteria/process parts that must be adhered to in Attachment A, and extract the remaining parts and
place them in a guideline document, or an appendix. In addition, the Responsible Entities are required
to submit Form 1 and Form 2, but such requirements are not written explicitly as “shall”, and are
imbedded in the Attachement whose mandatory status is unclear. This makes the standard very
confusing from an Responsible Entity’s obligation and compliance perspective.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003801
Yes
No
a. We do not support R2 as drafted, specifically the phrase “until directed to change by the ERO”. We
do not agree that the ERO has any authority to “direct” a BA or FRSG, or any responsible entities, to
make changes to the Frequency Bias Setting or take any operating or operations planning actions. We
suggest to replace the word “directed” with “requested”. b. In R2, the words “subject to” can be
interpreted differently. We suggest to replace them with “in accordance with” to parallel the intent as
conveyed in R1. c. We are still concerned with the status of Attachment A, as indicated in our
comments submitted under Q4 – that it is unclear if the materials in Attachment A must be adhered
to or not. A standard should not have an attachment whose enforcement status is unclear as part of a
requirement. d. FRS Forms 1 and 2 are referenced in Attachment 1, which itself has an unclear status
on measurability and enforceability. It is also unclear if FRS Forms 1 and 2 must be used to submit
the requested data. Collectively, Attachment 1, FRS Form 1 and Form 2 make the standard very
confusing as to which parts must be complied with. Much better clarity is needed to clearly convey the
standard ‘s requirements that are measurable, enforceable and must be complied with.
The proposed effective date for this standard conflicts with Ontario regulatory practice respecting the
effective date of implementing approved standards. It is suggested that this conflict be removed by
appending to each of Section A1.3 and A1.4, after “months after applicable regulatory approval”, of
the standard to the following effect: “, or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.” The same change should be made to the two bullets in the
proposed Implementation Plan.
Individual
Brian J Murphy
NextEra Energy
Yes
NextEra Energy does not support the changes made. It is concerned that certian changes were made
to help some large East coast entities that could not comply at the expense of the FRCC region.
Specifically, now on page 3 of Attachment A 4th paragraph from the bottom the statement is made “
sets its frequency bias to the greater of”. We believe that this must be changed to either Statement 1
“ Any number the BA chooses between 100% etc” Or Statement 2 “ Interconnection minimum as
determined by the ERO” Without this change, NextEra beleives the FRCC will be unfiarly treated
relative to others on the Eastern Interconnection. The technical reasons for this is concern was
explained during the Standard Drafting Team meetings. In addition, the ERO limit which is set at
0.9% of load should be changed to read within 0.8 or 0.9% of peak load based on the BA’s choice.
Also, see page 7 of the Procedure document and compare to page 1 of Attachment A. The formulae
abbreviations for the variables in the Procedure are not likewise abbreviated in Attachment A. For
example, “Credit for LR” on Attachment A is “CLR” in the Procedure, but it requires cross checking
each document to figure this out. Or CBr in Attachment A, Table 1 is represented as DFCBR in the
Procedure, Page 7. Since the same variables are being described, these should be represented the
same way in both documents throughout. 2. Similarly, is “IFRO” in Table 1 of Attachment A the same
as “FROInt” of the equation that follows on page 2? The same abbreviation should be used to
represent this variable. The documents should be revised in general along these lines for all terms. 3.
In Procedure document, page 5, paragraph 3 it should read “Table 2”, not “1”. 4. In the Procedure, it
would be good to show Table 1 and Table 2 as Table 1 of Attachment A (i.e. use table lines and
borders). 5. At least in the first usage, ERO in the Procedure document should be spelled out as
“Electric Reliability Organization (ERO)”. 6. In Table 1 of Attachment A, the two footnotes preceded by
asterisks (single and double on page 2) should be connected to the table by adding a single
superscripted asterisk to the Eastern UFLS value of 59.5, and a double superscripted asterisk to the
ERCOT LR value of 1,400.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003802
Individual
Don Jones
Texas Reliability Entity
Yes
Yes
Yes
It appears that R3.2 is based on the assumption that governor dead-band settings are 0.036 Hz for all
interconnections with multiple BAs. While the ERCOT region has a standard 0.036 Hz dead-band
specified in the ERCOT Protocols and Operating Guides, we are not sure if this is applicable to the
other regions.
Yes
1. The calculation for the FRO for ERCOT includes a credit of 1400 MW for load resources. 1400 MW is
currently the maximum amount of LR that can be procured through the ERCOT ancillary service
process. There can be periods during the day where 1400 MW was not procured or is not available (It
was noted during the summer of 2012 that on some days, only 900 MW of LR was available through
the ancillary service process). Should the calculated IFRO (-286 MW per 0.1 Hz) be modified to
account for this variation? 2. Background Document says: “Attachment A proposes the following
Interconnection event criteria as a basis to determine an Interconnection’s Frequency Response
Obligation: • Largest category C loss-of-resource (N-2) event • Largest total generating plant with
common voltage switchyard • Largest loss of generation in the interconnection in the last 10 years”
For ERCOT, the largest loss of generation in the last 10 years was over 3400 MW, and does not match
the 2750 MW (N-2) value used for the IFRO calculation.
Yes
1. Event Selection Criteria Item 2: Should certain events require mandatory inclusion for FRM
calculation (i.e. DCS events)? 2. Event Selection Criteria Item 6: We disagree with the way this is
worded. If a unit trips during this time, as it often can, measured frequency response needs to occur.
We understand that the results are impacted by the grid condition and perhaps that is why the SDT
decided to exclude the issue. Need to define what is intended by a “large” interchange ramp schedule
or load change. May also want to consider changing the language from “will be excluded from
consideration” to “MAY be excluded from consideration”.
Yes
Yes
Group
MEAG Power
Scott Miller
MEAG Powqer
Agree
Southern Company Services, Inc - Gen
Group
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003803
PPL NERC Registered Affiliates
Brent Ingebrigtson
LG&E and KU Services
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on this question.
Yes
PPL Affiliates suggest additional detail be added to the definition to ensure the members of the FRSG
are all within the same interconnection. The following definition includes the suggested changes: A
group whose members consist of two or more Balancing Authorities all within a single interconnection
that collectively operate resources required to jointly meet the sum of the Frequency Response
Obligations of its members.
No
The NERC posting did not include a redline to Attachment A, therefore, it is not clear what
modifications were made. However, there are several modifications that would add clarity to the
attachment. The PPL Affiliates support the comments of the SERC OC Standards Review Group on this
question, additionally, the following issues should be addressed: In Attachment A, page 3 and
elsewhere, clarify that temporary or small transfers of load or generation between BAs do not require
notification to the ERO or changes to the FBS or CPS limits. In Attachment A, page 4, a BA should be
allowed to be exempt from evaluation any single frequency event where non-conforming load
performs contrary to the performance of conventional load (ie. during a frequency decline, the nonconforming load simultaneously increases significantly). By nature, non-conforming load is totally
unpredictable, changes quickly, and fluctuates widely. Other than interruption, the BA has no control
over the actions of such loads nor can the BA predict or assume any “normal” action by a nonconforming load during a frequency disturbance event. Setting a limit on the number of events that a
BA could exempt (regardless of the reason) from FR evaluation in any given year would be more fair
and effective in evaluating a BA’s frequency response performance.
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on this question
Yes
The PPL Affiliates applaud the SDT for developing this technical justification document.
No
The PPL Affiliates are concerned that the document referred to “Attachment A” is directly referenced
in the proposed standard’s requirements but not actually attached to the standard itself as
Attachment A. Therefore, it is not clear how the proposed document could be modified in the future.
Having such material incorporated into a standard takes away from the open and transparent
stakeholder drive process.
Group
PJM Interconnection, LLC
Stephanie Monzon
PJM Interconnection
Yes
Yes
No
With what periodicity does a BA’s frequency bias setting have to change to be considered variable
bias? For example, if a BA changes it’s frequency bias setting monthly based on a percentage of each
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003804
month’s forecast or historic load, is this considered variable bias subject to compliance with R3 in lieu
of R4?
No
The target contingency protection criterion for the Eastern Interconnection is the largest event in the
last 10 years (believed to be a 2007 event) which is inconsistent with the other Interconnections. Is
periodic review required for this criteria? Will this criteria be revised after the referenced event is
older than 10 years? Are the other three interconnection’s target contingency protection criteria
subject to revision if they experience an event larger than a category C? This BA believes that future
periodic analysis should be defined and subsequent findings used to support changes via the standard
revision process. What are the procedural requirements for revising Attachment A? This BA is
concerned that the procedure for revising Attachment A is undefined and that, for example, the IFRO
could be increased absent the formal standard revision process, increasing a BA’s FRO and
subsequently increasing a BA’s compliance risk without providing BA’s the opportunity to review,
comment, and ballot. Related to the previous comment/question, how often are the statistically
derived values in Table 1 subject to a required update? For example, the Eastern Interconnection is
adjusted due to observed primary frequency response withdrawal (‘lazy L’ characteristic). The other
Interconnections are adjusted for observed differences between point C and point B. As the frequency
response characteristics of any Interconnection change, is Table 1 subject to required analysis and
revision? This BA believes that future periodic analysis should be defined and subsequent findings
used to support changes via the standard revision process. Attachment A indicates that a BA may
exclude an event from annual Form 1 FRM evaluation only if its tie-line or frequency data is corrupt or
unavailable. This exempts numerous scenarios that could result in a poor response score due to
system variations. These could include, but are not limited to, changing energy schedules, changes in
load, and AGC driving units up or down due to the ACE value at the time of the frequency event. This
subjects the BA to undue compliance risk even though the BA may have adequate frequency
responsive resources at the time. This BA suggests that the FRSDT adopt language (and Form 2
functionality) that allows the exclusion of events that are skewed by these types of situations.
Attachment A and Forms 1 & 2 specify that 20 to 52 seconds will be used as the post-event B point
average for FRM determination. The number of fast responding resources will increase as the
technology for batteries, flywheels, and frequency controlled demand side devices moves forward
over time. The 20 to 52 second interval does not adequately incentivize the devopment of these
technologies.
No
The Procedure indicates that events that occur when ‘large interchange schedule ramping or load
change is happening’ and ‘events occurring within 5 minutes of the top of the hour’ should be
excluded from consideration. Since interchange schedule ramping and load change occurs at the BA
level, this BA believes that the Procedure allows for the selection of events that occur when a BA is
experiencing these conditions but Attachment A does not allow for exemption of these events. Also,
the Procedure specifies that events that occur at the top of the hour be excluded, if other qualifying
events exist, but this does not take into consideration energy markets that allow for sub-hourly
schedule changes (e.g. 15 minutes) and the BA is not permitted to exempt these events on Form 1
subjecting the BA to undue compliance risks.
Yes
Yes
No
See previous comments. Also, this standard should be applicable to GOP’s as well as BA’s with, at a
minimum, the following requirements added: Each GOP shall follow all directives of it’s Balancing
Authority pertaining to frequency responsive operation, including but not limited to the status, droop
& deadband settings of their governors. Each GOP shall provide to their BA the status and droop &
deadband settings of their governors, and headroom available to respond to frequency deviations, as
requested.
Group
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003805
Duke Energy
Greg Rowland
Duke Energy
No
The definition reads as if the FRM is the median of all of the observations reported by the Balancing
Authorities and Frequency Response Sharing Groups. Duke Energy would suggest that the definition
read, “The median of all of the Frequency Response observations reported annually by a Frequency
Response Sharing Group, or Balancing Authority if not a participant in a Frequency Response Sharing
Group, for frequency events specified by the ERO. The Frequency Response Measure is calculated as
MW/0.1Hz.”
No
As a Balancing Authority may not be the entity maintaining or supplying resources, but would be
responsible for utilizing applicable resources within its BA Area, Duke Energy would suggest the
following definition, “A group whose members consist of two or more Balancing Authorities that
collectively utilize operating resources required to achieve a group FRM equal to or more negative
than the sum of the Frequency Response Obligations of its members.”
No
Duke Energy agrees with allowing single-BA Interconnections to utilize a variable Frequency Bias
Setting (FBS). Duke Energy disagrees with NERC allowing Balancing Authorities in a multiple-BA
Interconnection to change the ACE and bounds by which the Balancing Authorities are measured
under BAL-001 and BAL-002 by operating to a variable FBS. It is desired that a Balancing Authority
be capable of recognizing the amount of primary response available in real-time operation, such
information can be included among other information in the generation control algorithm; however,
the obligation to support the Interconnection frequency under the secondary control standards, and
the amount provided for any given frequency, should be based on the same criteria across all
Balancing Authorities of the same size. Nathan Cohn in his comments on Union Electric’s use of a
variable FBS expressed similar concern regarding the equitable sharing of the obligation to support
Interconnection frequency in a multiple-BA Interconnection. Take for example two Balancing
Authorities with equal total generation and load, but one operating under a fixed FBS and the other
operating under a variable FBS. To the extent that a Balancing Authority is not providing Frequency
Response comparable to its fixed Frequency Bias Setting, its ACE will reflect the difference to be
covered with secondary control and the Balancing Authority will be measured in a manner similar to
other BAs of its “size” based upon the FBS. To the extent that the other BA using a variable FBS is not
providing Frequency Response comparable to what it would be allocated using a fixed FBS, its ACE
will not reflect the difference or any further obligation to support Interconnection frequency at that
time with secondary control. Duke Energy’s concern regarding non-comparable treatment of all BAs is
further amplified by the lack of scrutiny placed on the BA algorithm used to determine the real-time
variable FBS, to ensure that compliance cannot be gamed by such use.
No
As indicated in our comments in the past, Duke Energy is certain that as the Interconnection
Frequency Bias Setting (FBS) is set closer to the actual Frequency Response in a multi-BA
Interconnection, most BAs will be challenged in meeting CPS2, while CPS1 and the proposed
Balancing Authority ACE Limit (BAAL) will be more achieveable bounds, and in some cases CPS1
performance will improve. Though probably most of the BAs may welcome a FBS set as high in
magnitude as allowed to address the potential compliance risk, there are some which may desire to
set their FBS closer to their required minimum allocation rather than have to take on a larger
obligation in frequency support under the secondary control measures. Duke Energy believes that this
proposed standard should incent BAs to provide more than their share of Frequency Response to the
Interconnection and allow that good performance to be recognized; however the requirements
described in Attachment A for determining the minimum Frequency Bias Setting (FBS), which requires
that the FBS be set no lower in magnitude than the FRM, will leave certain over-performing BAs with
no choice but to reduce their actual Frequency Response (still well-above their FRO) if they want to
operate with a FBS set closer to the Interconnection Minimum allocation and be relieved of the
associated increased obligation for frequency support under the secondary control measures. The FBS
is embedded within the secondary control measures of CPS1, CPS2 and the draft Balancing Authority
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003806
ACE Limit (BAAL). Comparable treatment of similarly-sized BAs (based upon the FRO allocation) is
only possible if all BAs are provided the same minimum FBS requirement. To the extent that a BA
provides more than its share of response to events, it’s over-performance will only be recognized if its
ACE is allowed to reflect a FBS comparable to its peers, allowing its over-performance to be reflected
in ACE in support of bringing frequency closer to 60 Hz. Generation control algorithms implemented
today to optimize CPS1 will allow non-zero ACE when in support Interconnection frequency within
bounds determined by the BA – there should be no concern of “response withdrawal” with such
algorithms in place, the BA will simply get credit for such performance. As depicted in the current
document, the over-performing BA would be required to set its minimum FBS at its FRM (or greater in
magnitude), taking away what should be considered over-performance, erasing it in ACE, and turning
it into an obligation under the secondary control measures. Based upon the draft, the only way that
the BA could be treated comparably to other similarly sized BAs held only to operating to the
Interconnection Minimum allocation, would be to reduce its actual response in FRM to a value less in
magnitude than its Interconnection Minimum allocation. Duke Energy believes that BAs should be
incented to provide more than their share of Frequency Response, and be given the opportunity to
report performance on a basis comparable to similar-sized BAs. Our opinion is that Attachment A
ensures that the Interconnection Frequency Bias Setting will remain at some margin above the actual
Interconnection Frequency Response in magnitude – the reliability of the Interconnection will not be
at risk by allowing over-performing BAs to operate and report performance on a comparable basis to
other similarly-sized BAs based upon the Interconnection Minimum allocation if they choose to do so –
to that extent, Duke Energy suggests that the language on page 3 be changed to: “A BA using a fixed
Frequency Bias Setting may set its Frequency Bias Setting to any number the BA chooses up to 125%
of its Frequency Response Measure as calculated on FRS Form 1, but no less in magnitude than its
Interconnection Minimum allocation as determined by the ERO.” Regarding the argument which could
be offered that a larger FBS in magnitude will also allow wider bounds for control performance, Duke
Energy agrees that a large portion of the BA operation will be around 60 Hz where such a benefit
could be realized, however it would also come at the cost of a larger obligation than other
comparably-sized BAs in sustained support of frequency during the more critical times of significant
deviation from 60 Hz where the BA’s compliance could be at risk. Below 59.95 Hz in the Eastern
Interconnection (the Frequency Trigger Limit under BAAL), the additional MWs needed to be
compliant for any given frequency are greater than the MWs of imbalance allowed by the larger BAAL
bound – comparably-sized BAs will not be comparably judged if the standard forces over-performing
BAs to assume a larger FBS (in magnitude) than their peers – that should be the decision of the BA.
We believe that the proposed language above will create the proper incentive for a Balancing
Authority to provide more than its minimum allocation of Frequency Response, and allow it to choose
if it wants to make that performance part of a larger FBS (in magnitude), knowing the associated
risks and benefits of that decision. Duke Energy supports this standard allowing for Frequency
Response Sharing Groups, however the requirements and supporting documents need to clearly allow
the FRSG to be treated no differently than if it was a Balancing Authority and shield the participating
BAs from compliance scrutiny when all scrutiny should be placed on the FRSG performance as a
whole. At the top of Page 3, the standard attachment allows the FRSG to “calculate a group NIA and
measure the group response to all events in the reporting year on a single FRS Form 1”, however at
the bottom of page 3, the standard attachment still requires the FRSG BAs to individually fill out Form
1 and Form 2 for the purposes of determining the minimum Frequency Bias Setting. Duke Energy
believes that the standard language in Attachment A, and the supporting form(s), should allow the
FRSG, if it chooses, to also report the split of the group FRM which the BAs will use to individually
determine their Frequency Bias Setting, rather than require each BA in an FRSG to still maintain Form
1 and Form 2 data. Form 1 could be modified for the FRSG to report the group’s FRM along with the
split of the FRM among the members, and another form could be developed for each FRSG BA to fill
out, replicating only the section of Form 1 (column S) where each BA could provide values for its FRM
allocation, its desired FBS, its minimum FBS allocation, and so on.
No
Duke Energy agrees with allowing the ERO to perform this function, however the industry needs some
assurance that this Procedure cannot be changed outside of the Standards Process for approval by the
industry. In the sixth line of the third paragraph on page 5, the statement should reference Table 2.
Page 5 reads as if the BAs will submit their data based upon Form 1 which includes an adjustment to
the Interconnection peak load (initially 0.9), and then the ERO will determine whether the
Interconnection minimum FBS is still more than 20% above the measured response – if so, the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003807
minimum FBS will be adjusted, requiring the BAs to reassess their new minimum FBS based upon a
different factor, and decide whether to use that value or choose a value up to 125% of their FRM,
resulting in another iteration of values being submitted to the ERO. If the ERO is going to do an
independent assessment of Interconnection Frequency Response to the events, on an annual basis
prior to gathering data from the BAs, the ERO could compare the total FBS being used by the BAs
against the estimated Frequency Response over that period to determine if an adjustment is
warranted, and then the ERO could include the appropriate adjustment factor (0.9, 0.8, etc..) in Form
1 for the BAs to use. If the ERO is not going to estimate the Frequency Response aside from the BAs,
multiple iterations will be likely. Duke Energy suggests the following language to cover the point
above: “On an annual basis, the ERO will review the Interconnection total minimum Frequency Bias
Setting for the prior period and compare it against the Interconnection’s total natural Frequency
Response determined for that period. If an Interconnection’s total minimum Frequency Bias Setting
exceeds (in absolute value) the Interconnection’s total natural Frequency Response by more (in
absolute value) than 0.2 percentage points of the Interconnection non-coincident peak load
(expressed in MW/0.1Hz), the minimum Frequency Bias Setting for BAs within that Interconnection
may be reduced (in absolute value) based on the technical evaluation and consultation with the
regions affected by 0.1 percentage point of Interconnection non-coincident peak load (expressed in
MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency Response. The ERO
will include the adjustment factor in the Interconnection Form 1 used by the Balancing Authorities for
the calculation of the new minimum Frequency Bias Setting. The Form 1 information from the
Balancing Authorities will be gathered by the ERO in coordination with the regions of each
Interconnection to determine the final Interconnection Frequency Bias Setting for the next period.”
No
Similar to our earlier concern, the industry needs some assurance that the calculation of the
Interconnection FRO described in the report cannot be changed outside of the Standards Process for
approval by the industry. Duke Energy does not support using a 4500 MW loss as the basis for
determining the FRO for the Eastern Interconnection for future events. However, as the calculation
also includes 59.5 Hz as the basis for determining the FRO, the result is an allocation which can be
supported. To the extent that the standard drafting team moves in the direction of using 59.7 Hz as
the basis for the FRO, then it needs to follow a methodology similar to the other Interconnections for
determining the credible multiple contingency to cover.
Yes
Though Duke Energy does not agree with some of the points in the Background Document, it does
justify the rationale used by the SDT. Additional comments: at the top of page 23, it states that the
basic Frequency Response Obligation is based on non-coincident peak load and generation data
reported in FERC Form 714, however the actual calculation is missing and should be based upon the
reported MWh, not the peak load as stated. At the bottom of page 23, it states that Attachment A
proposes the three options for event criteria, however doesn’t clarify why it was chosen that the
Eastern Interconnection would be held to the largest event over the last 10 years, while others will be
based upon the largest category C loss-of-resource (N-2) event.
No
Given the FERC deadline approaching for NERC to deliver a Frequency Response standard, Duke
Energy supports the adoption of this standard with some reservations. We believe that the proposed
standard addresses the FERC directive to NERC, however it also introduces some longer-term issues
related to secondary control and related costs that may have not been anticipated by the FERC. To
that point, Duke Energy believes that if this standard is adopted, the industry will have the time and
opportunity through the NERC standards development process to mitigate some of the concerns
presented in our comments.”
The concern raised in Duke Energy’s comments in item 4 will not be a factor for a few years, but will
be an issue as more and more BAs are in the position of their FRM being better than the
Interconnection Minimum allocation. We believe that the language that we proposed for calculating
the minimum FBS in a multiple-BA Interconnection allows for the proper incentives for BAs to
maintain FRM much better than required, and allows for comparable measurement of secondary
control performance between similarly-sized BAs, while presenting no risk to reliability.
Individual
Don Schmit
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003808
Nebraska Public Power District
Agree
MRO NSRF [Midwest Reliability Organization - NERC Standards Review Forum]
Group
ACES Power Marketing Standards Collaborators
Jason Marshall
ACES Power Marketing
Yes
We believe that refinements to the definition were needed.
No
We agree that a definition is needed and thank the drafting team for writing one. However, we believe
additional refinement of the definition is necessary. Although the definition appears to be written to
parallel the Reserve Sharing Group definition, we think the definition needs to be simplified. For one,
it encompasses actions that are not necessary. For instance, the proposed definition includes the
action to “maintain operating resources”. This could literally include generating plant maintenance.
We do not agree that a Frequency Response Sharing Group would jointly perform maintenance on
their plants. In fact, since the definition applies to BAs, it is entirely possible within the functional
model that the BAs do not even own the plants and could not perform joint maintenance. We assume
the purpose of including “maintain” was to recognize that maintenance of generating resources would
need to be coordinated to ensure that there was sufficient frequency response reserve. We do not
believe this needs to be explicitly identified in the definition. Furthermore, we find the use of
“operating resource” as a source of potential confusion. While we understand operating resource is
intended to mean a facility that provides the ability to increase or decrease MW output based on the
frequency deviation, resource has various meanings throughout the standards and its use here could
be confusing and contradictory. For instance, TOP-006-2 R1 discusses transmission resources.
Furthermore, if an “operating resource” is capable of increasing or decreasing MW output based on
frequency deviation, what is a “resource”? In other words, why is “operating” added to the term
“resource”? We think it is best to avoid use of the term operating resource and, thus, recommend
changing the definition to: “A group of two or more Balancing Authorities that share frequency
response reserves and are required to jointly meet the Frequency Response Obligations of its
members.”
Yes
No
(1) Frequency Response Obligation (FRO) is used inconsistently with the proposed definition in the
document. The document uses the term “Interconnection Frequency Response Obligation” in many
locations. However, FRO specifically is defined as the BA’s “share of the required Frequency
Response”. It does not apply to the Interconnection. How can the Interconnection have a share of the
required frequency response? A new term may need to be defined for the Interconnection required
Frequency Response. (2) On page 3 Attachment A states the ERO will post the Frequency Bias Setting
for each BA along with their Frequency Response Obligation. Later on the same page, the document
states that the BA shall set its Frequency Bias Setting to 100% to 125% of it Frequency Response
Measure or Interconnection Minimum. What is the purpose of the ERO determining Frequency Bias
Settings if the settings are not going to be used by the BA? What are we missing in the explanation?
(3) Late on page 3, the document states that BAs are encouraged to notify NERC if load or generation
is transferred. Section 4(a) on page 8 of the Rules of Procedure Appendix 5A – Organization
Registration and Certification Manual indicates that changes to a Registered Entity’s footprint actually
triggers a potential certification audit. Since BAs are required to be certified and moving generation or
load from the metered boundaries of one BA to another BA would represent a change in footprint, we
suggest removing the word “encouraged” and stating affirmatively that BAs must notify NERC of such
changes and referencing the appropriate section of the Rules of Procedure. Otherwise, BAs may not
realize notification is actually required.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003809
Overall, we agree. However, we suggest the document clarify that the ERO shall perform these tasks
in coordination with the Resources Subcommittee. It consists of industry experts that can be an extra
resource to NERC. Furthermore, NERC staff working with the Resources Subcommittee will provide
additional transparency to the process.
Yes
We agree that this method will provide sufficient frequency response. However, we believe
Interconnection Frequency Response Obligation is used inconsistentently with the definition of
Frequency Response Obligation as documented in our response to other comments.
No
(1) The formula for calculating Frequency Response Obligation appears to be missing on page 23. (2)
We are confused by the varying sample rates for the different scan rates in the Definitions of
Frequency Values for Frequency Response Calculation table on page 13. It would appear that the time
range of values for the average B value varies more than necessary by scan rate. For example, for 2second scan rates, sampling would start at 20 seconds and end at 52 seconds. However, for the 4second scan rates, sampling starts at 24 seconds and ends at 48 seconds. Why would it not also
cover 20 and 52 seconds for a 4-second scan rate?
No
(1) We believe that the drafting team work has demonstrated that the standard is unnecessary. The
data presented in the posting shows that all of the interconnections easily exceed the required
Frequency Response necessary to avoid actuating UFLS relays. Since one of the main purposes of the
standard is to provide sufficient Frequency Response, it would seem the purpose is already met
without implementing and enforceable standard. So why is a standard needed to compel required
Frequency Response if it is already provided? (2) Even though we believe the supporting data for the
posting demonstrates the standard is unnecessary, we understand NERC is required by a FERC
directive to provide a standard. Given this requirement, we do believe the drafting team has largely
provided a reasonable standard and supporting documents that only require a few additional
adjustments (see our comments in other questions for these adjustments) to finalize the standard. As
a result, we will likely end up supporting the standard once these final adjustments are made.
(1) Please strike “that is a member of a multiple BA Interconnection” in R2 and R3. The language
makes the requirements difficult to read. We understand this is trying to clarify that these
requirements should not apply to BAs such as ERCOT since changing its Frequency Bias Setting does
not need to be coordinated with other BAs among other issues, and we do not have an issue with this
intent. However, there is an easier way to address this issue without creating a confusing
requirement. The SDT should include seeking a variance for the ERCOT area in conjunction with
developing the standard. (2) Please strike “in order to represent the Frequency Bias Setting for the
combined Balancing Authority Area” in Requirement R4 as it is superfluous and incorrect. First, the
two bullets provide the necessary information making the statement unnecessary. Second, the BA
Areas are not combined into a single BA Area as implied with the statement “combined Balancing
Authority Area”. They are still in fact two distinct BA Areas. (3) The data retention period for R1, R2,
R3, and R4 is not consistent with the NERC Rules of Procedure. Section 3.1.4.2 of Appendix 4C –
Compliance Monitoring and Enforcement Program states that the compliance audit will cover the
period from the day after the last compliance audit to the end date of the current compliance audit.
The data retention section states that data shall be kept for the current calendar year plus the three
previous calendar years. This could be up to four years which exceeds the BA audit period of three
years. It is unnecessary for a BA to maintain evidence that was already verified in a prior audit. We
recommend changing the evidence retention period to three years. (4) Has the drafting team
coordinated the addition of the Frequency Response Sharing Group (FRSG) with the Functional Model
Working Group and the NERC staff responsible for organizational registration? If not, please do so as
NERC will need to be willing to register entities as a FRSG if it is to be utilized. Furthermore, the
Functional Model Working Group should document the purpose and intent of the FRSG. (5) We
disagree with the VSLs for R1. The VSLs are structured such that a BA’s or FRSG’s violation is
dependent upon the rest of the interconnection to determine the severity level of the violation. If the
BAs collectively fail to achieve the Interconnection Frequency Response obligation, a 2% violation of
the Frequency Response Measure jumps from a Lower VSL to a High VSL. This should never be the
case. No violation by a registered entity should become potentially more or less severe based on the
violation of another entity. We encourage the drafting team to work with NERC Legal department in
reviewing this VSL further as FERC has already allowed ISO/RTO violations investigation to draw in
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003810
third parties that potentially contributed to the ISO/RTO violation to ensure the appropriate party is
fined. The principal is similar here in ensuring the appropriate BA is fined for its violation not the
violations/failures of other BAs. The background document mentions on page 31 that the motivation
for structuring the VSL in this manner was to prevent BAs in multiple BA interconnections from being
sanctioned disproportionately. We appreciate the drafting team considering this issue but believe
there is a simpler solution. Four VSLs could simply be written based on the percentage the BA misses
its own Frequency Response Obligation. Furthermore, the compliance enforcement process already
considers if the violation impacted reliability when assessing a sanction. (6) The Frequency Response
Obligation (FRO) term is used inconsistently with the definition in the VSLs for R1. The first part of
each BA implies that the Interconnection has an FRO. However, the definition specifically states that
FRO is the BA’s “share of the required Frequency Response”. It does not apply to the Interconnection.
How can the Interconnection have a share of the required frequency response? A new term may need
to be defined for the Interconnection. (7) The implementation plan still references Requirement R5.
There is no such requirement. (8) Requirement R1 is not consistent with the recent direction NERC
has taken to refocus on reliability and looking forward during compliance audits rather than
backwards. For instance, NERC has proposed monitoring internal controls of registered entities
because this will provide a reasonable assurance that the registered entity is prepared to comply in
the future. Current compliance audits focus mostly on past performance and provide no indication of
future reliability. How does Requirement R1 support this forward looking vision when it is a lagging
indicator that looks at historical performance? (9) Requirement R4 appears to be inconsistent with
Requirement R1 and Attachment A. On page 3, Attachment A states the BA shall set its Frequency
Bias Setting to 100% to 125% of it Frequency Response Measure or Interconnection Minimum.
However, Requirement R4 states that the BA providing Overlap Regulation Service shall set its
Frequency Bias Setting to the sum of its Frequency Bias Settings on FRS Form 1 and FRS Form 2 of
its own BA and the BA to which its provides Overlap Regulation Service. For simplicity let’s call the BA
providing Overlap Regulation Service BA X and the BA receiving the service BA Y. Why would the BA X
not set its Frequency Bias Setting to 100% to 125% of the sum of BA X’s and BA Y’s Frequency
Response Measure? This would make Requirement R4 parallel with R2. (10) We do not understand
the difference between the two bullets in Requirement R4. They appear to say essentially the same
thing and the background document provides no discussion to distinguish their differences. Please
provide further explanation.
Group
SERC OC Standards Review Group
Gerry Beckerle
Ameren
No
The definition reads as if the FRM is the median of all of the observations reported by the Balancing
Authorities and Frequency Response Sharing Groups. We agree with the Duke Energy suggestion that
the definition read, “The median of all of the Frequency Response observations reported annually by a
Frequency Response Sharing Group, or Balancing Authority if not a participant in a Frequency
Response Sharing Group, for frequency events specified by the ERO. The Frequency Response
Measure is calculated as MW/0.1Hz.”
No
A Balancing Authority may not be the entity maintaining or supplying resources, but would be
responsible for utilizing applicable resources within its BA Area. We would modify the Duke Energy
suggestion to read as follows: “A group whose members consist of two or more Balancing Authorities
that collectively utilize operating resources with a goal to achieve a group FRM equal to or more
negative than the sum of the Frequency Response Obligations of its members.”
No
It is important for NERC to monitor the interaction between the deployment of this standard and its
impact on CPS1, CPS2, and BAAL. If performance in the CPS criteria is degraded, there should be a
halt in the reduction of the minimum bias setting allowed. There is also concern that we are providing
the correct incentives to the entities to provide the appropriate amount of frequency response. We
also suggest that clarification be made so that changes in the BA’s footprint that would necessitate
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003811
changes in the bias setting or the FRO be permanent changes, not just temporary. It is unclear how
performance would be measured for a BA versus a frequency response sharing group.
No
We believe the industry needs some assurance that the calculation of the interconnection FRO cannot
be changed without rigorous review and input from the industry. In addition the clarification should be
made how the one in ten year loss for the Eastern Interconnection (4500 MW) would change after 10
years. Would the same methodology be used or would the largest Category C (n-2) be used?
Yes
We agree with the Duke Energy comments on this question.
The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review Group only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.
Individual
Brett Holland
Kansas City Power & Light
Yes
Yes
Yes
No
The Standard proposes a calculation that overstates the frequency response obligation (FRO) for
Balancing Authorities.
No
Criteria 3 - Why are frequency thresholds different between regions when generator governor reaction
is supposed to be the same between regions? Criteria 5 - What is the reasoning that multiple events
that are not stabilized within 18 seconds not being considered? Criteria 6 - How are "changes in
scheduled interchange" or load change determined in regions with interconnections with multiple BAs
with different time zones?
Yes
Yes
No
The Standard does not consider instances for smaller BAs that operate generation for peak conditions
and acquire energy for most of the operating year.
Individual
Angela P Gaines
Portland General Electric Company
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003812
The issue with proposed Reliability Standard BAL-003-1, requirement R1, is that the Annual
Frequency Response Measure (FRM) is determined after the fact with an entity unable to identify or
monitor compliance (on non-compliance) along the way. Also, the requirement seems to go the
opposite direction of NERC’s risk based initiatives where collecting historic compliance information
become unsustainable.
Individual
Kathleen Goodman
ISO New England Inc.
Agree
Last submitted comments of ISO-NE which have not been addressed and, for efficiency sake, do not
believe we should be requested to re-submit.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC Standards Review Group
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
Agree
Entergy is in agreement with comments submitted by SERC on 11/5/0212.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery, NERC Reliability Compliance Coordinator
Associated Electric Cooperative, Inc. - NCR01177
Agree
SERC OC Standards Review Group
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
Yes
Yes
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service (supplying
actual interchange, frequency response, and schedules to another BA), then we can assume it is
supplying regulation service. Was the intent of the requirement to simply state that all BA’s must
have a bias setting less than zero at all times? Please clarify the intent of this requirement.
No
(1) This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource contingency criteria
(in the attachment, this is called the “target contingency criteria”), etc. (2) Of value to entities would
be a sample calculation. (3) “The largest category C (N-2) event is used for all interconnections
except the Eastern which uses the largest event in the last 10 years”. Why aren’t all interconnections
using the same design contingency design basis? (4) The NERC 2012 CPS2 bounds has an Eastern
Interconnection frequency bias of -6,360 MW/.1Hz. Can the DT explain why this attachment refers to
an Interconnection frequency response obligation of -1,002MW/.1Hz. This is a significant difference.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003813
No
While the discussion of primary frequency response includes inertial energy, the term inertial energy
is missing from the definition of “primary frequency response”.
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in BAL-001. The
Standard is currently confusing to understand and it is unclear how the bias is calculated. It is
recommended that efforts should be made to clarify the changes, especially Attachment A.
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard, then
GO’s and GOP’s should be included in the applicability since they are the entities responding to the
AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s should be
updated.
Individual
David Jendras
Ameren
Yes
Yes
The word "jointly" may add confusion and we believe it is unessassry.
Yes
No
We disagree on having different methodologies for determining the targets, and would like clarity
added for when those targets may change, such as what will happen after the largestest event in the
last 10 years rolls off the books for the EI?
Yes
Yes
Yes
While we support this draft, we believe that this might only be a starting point and as additional
knowledge and experience is gained through the implementation of this standard and other efforts
such as the FRI, that the improvements can be embraced by all parties, even if those improvements
result in relaxed requirements.
Individual
Maggy Powell
Exelon Corporation and its affiliates
Yes
Please see response to question 8. The FRM definition is acceptable within the context of the
attachment description; however, without clarifying the terms under which the ERO specifies which
events are to be measured, the FRM definition is too variable.
Yes
No
Please see response to question 8.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003814
No
Exelon is troubled by the approach of having requirements that rely so heavily on the attachment to
the standard. The use of both of the documents is required to be compliant and this makes it difficult
to determine what the obligations are and increases the chance for error in interpretation. The
suggested changes below in response to question 8 take information from the Attachment and
establish requirements so that an entity does not have to go back and forth between the two
documents to identify its obligations. Attachment A should then be modified to include examples of
Forms 1 and 2 and instructions for completing the form for Balancing Authorities and Frequency
Response Sharing Groups.
No
Please see response to question 8.
No
Exelon checked "no" because it does not support the current draft standard. Exelon’s position is that
efforts to modify frequency monitoring and control should be directed at the existing standards. Since
Frequency Bias is already a component of ACE, and ACE performance is tracked by both CPS 1 and
CPS 2, it seems evident that NERC already has in place mechanisms for evaluating frequency
response. NERC already has in place mechanisms for ensuring sustained frequency response during a
contingency, through the Disturbance Control Standard (DCS) and its requirement for the contingent
Balancing Authority to deploy resources. Under the current BAL-003-0.1b language, Balancing
Authorities are given a consistent means for determining frequency bias, via the minimum
requirement of 1% peak generation or 1% peak load. Together with the above references to existing
CPS 1 performance measurements, current standards meet the objectives outlined in BAL-003-1. This
proposed draft BAL-003-1 complicates the setting of Frequency Bias and attempts to go beyond that
purpose into frequency response performance, without clear rules for how to perform. Exelon is also
concerned with moving this standard forward while there is an ongoing field trial that could impact
whether this standard should be put into place. For example, waivers are in place for CPS 2 for
participating Balancing Authorities and there is ongoing effort with the BAAL field trial set of standards
that will establish performance metrics around frequency control. As an alternate approach to waiting
to move forward on the standard, Exelon recommends the following BAL-003-1 Requirement
language: R1. The ERO shall identify up to five [5] system frequency events in each Interconnection
that will be included in the Form 1 and 2 data requests for Balancing Authorities by April 30th each
year. R2. Each Balancing Authority shall submit the following data to the ERO annually by July 15:
R2.1 The total annual net output of generating plants inside the Balancing Authority Area. R2.2 The
total annual load with losses inside the Balancing Authority Area. R3. Each Balancing Authority shall
calculate its Frequency Response Measure using Forms 1 and 2 as posted by the ERO. (See
Attachment A_Form 1 and Form 2) R4. Each Balancing Authority or Frequency Response Sharing
Group shall submit Forms 1 and 2 to contacts designated by the ERO before the expiration of ERO
established deadlines, which shall be no earlier than 30 days after posting of Forms 1 and 2. R5. The
ERO shall post the following information: R5.1. Each Interconnection’s Frequency Response Obligation
R5.2 Each Balancing Authorities Frequency Response Obligation R5.3 Each Balancing Authorities
Frequency Bias Setting R6. Each Balancing Authority shall implement in its ACE equation its ERO
established Frequency Bias Setting during the ERO established three-day implementation period. No
further adjustments can be implemented outside of the parameters established below in the
upcoming year unless a Balancing Authority coordinates with the Regional Entity and the affected
Balancing Authorities. R6.1 A Balancing Authority using a fixed Frequency Bias Setting sets its
Frequency Bias Setting to the greater of (in absolute value): R6.1.1. The number the BA chooses
between 100% and 125% of its Frequency Response Measure as calculated on FRS Form 1. R6.1.2.
The Balancing Authorities share of the Interconnection Minimum as determined by the ERO. R6.2 A
Balancing Authority using a variable Frequency Bias Setting shall maintain a setting that is: R6.2.1
Less than zero at all times, and R6.2.2 Equal to or greater in magnitude than its Frequency Response
Obligations when Frequency varies from 60 Hz by more than +/-0.036 Hz. R7. Each Frequency
Response Sharing Group or Balancing Authority that is not a member of a FRSG shall monitor its
Frequency Response Obligation and work with generating facilities or demand response resources to
provide sufficient Frequency Response to meet the Frequency Response Obligation assigned by the
ERO. R8. Each Balancing Authority that adds or removes generation or load, including through the
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003815
use of dynamic transfers, shall notify the ERO to ensure that any needed adjustments to the
Interconnection Frequency Response Obligation or Balancing Authority Frequency Response Obligation
and Bias can be calculated. R8.1. The ERO shall notify all affected Balancing Authorities of
modifications to the Frequency Response Obligation due to the addition or removal of generation or
load. R9. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias Setting for the
combined Balancing Authority Area, to be equivalent of the sum of the Frequency Bias Setting as
communicated by the ERO for the participating Balancing Authorities.
Individual
Janelle Marriott Gill
Tri-State Generation and Transmission Assn., Inc.
No
It is our opinion that there has not been enough justification to merit creating a new standard. If
additional justification is provided then frequency responsive reserves should be a subset of spinning
reserves much like spinning reserves are a subset of operating reserves.
We are concerned with the tariff implictations associated with this standard. Will this standard create
the need for an additional ancillary service under the FERC pro forma OATT?
Individual
Denise M Lietz
Puget Sound Energy
In reviewing the Consideration of Comments document, it is clear that the standard drafting team
does not wish for the administrative elements of Attachment A to become items addressed during
compliance evaluations (“There is no intent to require filing on a certain date and to have the BA
prove to the auditor that a filing was made on that date.” This quote appears at several places in the
Consideration of Comments documents, but first at page 113). However, because Attachment A is
referenced in the standard, its provisions, including the timing table, are all mandatory and
enforceable. This result is emphasized by the language of requirement R1, which states that entities
“…shall achieve an annual Frequency Response Measure (FRM) as calculated and reported in
accordance with Attachment A….” This language means that a failure to file a document on a date
specified in the attachment would be a potential compliance violation. Because Attachment A is
mandatory and enforceable, the standard drafting team should carefully review its provisions and
clarify which elements are requirements and which elements are background statements or guidance.
In addition, the use of additional headings and section numbers would add in clarifying the document
(for example, at the top of page 3, there is a discussion of how an FRSG would calculate its FRM;
however, there is an entire section beginning on page 4 addressing FRM where that discussion should
instead appear).
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003816
No
See comment in response to question 4 above for a discussion of Attachment A concerns. Appendix 1
of the Frequency Response Standard Background Document contains a discussion about why the use
of net actual interchange to calculate an entity’s Frequency Response Measure might introduce
inaccuracies into that calculation. That discussion ends with the following statement: “The frequency
response is buried within the typical hour to hour operational cacophony superimposed on actual net
interchange values. The choice of metrics will be important to artfully extract frequency response
from the noise and other unrepresentative error.” Based on these statements, it is very difficult to
support the standard’s approach to calculating the Frequency Response Measure. At Puget Sound
Energy (PSE), though, we believe that there is another factor to add to the “operational cacophony”
listed in Appendix 1. PSE is a comparatively small BA with limited internal generation. We are
embedded between two of the largest energy exporters in the Western Interconnection and, when
there is a frequency event, their response flows through PSE’s system. As a result, PSE will
experience transmission losses associated with the two BAs’ frequency response as it flows through
our system. When PSE’s frequency response is measured using net actual interchange, these losses
obscure, at least in part, our system’s frequency response. As a result, we ask the standard drafting
team to consider specifying a process that would allow us to propose and use an equivalent measure
of frequency response. For example, while we understand the concerns and difficulties associated with
measuring frequency response at the generator as the default measure for all BAs, in our case, a
choice to use that measurement option might prove to be a more-feasible way to comply with the
standard.
The definition of “Frequency Response Obligation” applies only to a Balancing Authority. However,
requirement R1 applies to both FRSGs and BAs and includes a Frequency Response Obligation that
applies to each of those entities. As a result, the definition must also address an FRSG’s Frequency
Response Obligation. The acronym for Balancing Authority is not included following the first reference
to the term in requirement R1 (looks like an inadvertent deletion). Requirement R1 states that an
entity “… shall achieve an annual Frequency Response Measure (FRM)….” However, the definition of
Frequency Response Measure already includes the concept of annual. As a result, the word “annual”
should be removed from the requirement. Requirement R1 includes the language “… to ensure that
sufficient Frequency Response is provided by each FRSG or BA that is not a member of a FRSG to
maintain Interconnection Frequency Response equal to or more negative than the Interconnection
Frequency Response Obligation.” This language is a purpose statement rather than a requirement
applicable to a FRSG or a BA and should be excluded from the requirement. So long as an FRSG or BA
achieves the FRM calculated in accordance with Attachment A, it has done everything necessary to
comply with the standard. There are discrepancies between the implementation plan and the
proposed standard: - The definitions of “Frequency Response Measure” and “Frequency Response
Obligation” in the Implementation Plan are different from those proposed in the draft standard. - The
Implementation Plan references “Reserve Sharing Group” rather than “Frequency Response Sharing
Group”. - The Implementation Plan does not include a definition for the term “Frequency Response
Sharing Group”. - The Implementation Plan continues to reference R5 in the discussion of the
standard’s proposed effective date. The annual process dates listed on page 32 of the Background
document appear to be inconsistent with those listed in Attachment A.
Individual
Rich Salgo
NV Energy
Yes
Yes
Yes
Yes
This document is improved, and satisfactorily addresses comments from the prior posting.
Yes
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003817
Yes
Yes
No
While I support the concept of a Frequency Response Standard with minimum performance
obligations, this Standard places the entire obligation for performance on the Balancing Authority
(and Frequency Reserve Sharing Group). Requirements R2-R4 are properly assigned to the BA, as
this is the entity that is responsible for the configuration and parameters in the ACE equation,
including the provision of a frequency bias setting. Requirement 1, however, is a performance
requirement over which the BA in the Functional Model has virtually no control or ability to influence.
Only a Generator Owner or Generator Operator is in a position of control over the performance under
this requirement through the operational control and configuration of the responding generating units.
In most BA's, the host BA entity also owns a fair amount, even a vast majority in many cases, of the
generation within the BA. However, even in the event that the host BA owned 100% of the generation
within its metered boundary, it is the action of the entity exercising its GO/GOP function that impacts
the frequency response performance within the Balancing Area. Assignment of R1 to the BA is
inappropriate from the standpoint that reliability requirements are to be assigned to the Reliability
Functions who are capable of causing compliance to occur. A BA has limited ability to influence the
outcome of the R1 performance metric. This is unlike other BA-assigned requirements, such as those
related to DCS or CPS compliance. For those, the BA does have considerable influence regarding the
curtailment of transactions to restore ACE, the direction of plant loading so as to distribute operating
reserve, etc. In contrast, performance under this proposed R1 of BAL-003-1 is dependent upon the
actions of the GO/GOP in such things as governor settings, generator control system configuration
and other operatinal or maintenance activities conducted at the generating plant site. For this reason,
it is inappropriate to assign this performance requirement to the BA. Rather, the requirements should
be allocated among the GO/GOP's of the on-line generation in some fashion. In further support of this
notion, refer to the NERC Functional Model, where it is provided that one of the tasks for Generator
Operation is to support Interconnection frequency.
Individual
John Tolo
Tucson Electric Power
Yes
however, the number of observations to be used in calculating an entity's FRM is not clear.
Yes
Yes
N/A
Yes
No
I think it should be more clear or better defined that an interconnection does have some input into
what events are selected.
No
I believe that the frequency bias obligation of the Western Interconnection is understated.
Yes
No
I feel that a BA's frequency bias for the upcoming year should not be related to present performance.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003818
A BA may have a good response one year and not good response another year and therefore the
threshold keeps moving around. I feel it should be related to BA size and therefore somewhat
standardized. E.g. a high-performing Balancing Authority will have its frequency bias increased each
year due to higher response during the events chosen by the ERO. Conversely, a low-performing
Balancing Authority will have its frequency bias reduced each year due to lower response during the
events chosen by the ERO.
This is an important task and the efforts of the drafting team are appreciated.
Group
Avista
Scott Kinney
Avista Corp
Agree
Bonneville Power Administration
Individual
Ken Gardner
AESO
1. The AESO disagrees with using a non-authoritative background document that has
definitions/description of terms used in the reliability standard. It is the opinion of the AESO that
these definitions/descriptions need to be authoritative. 2. The AESO has previously submitted
comments to the SDT that for the purpose of the FRM calculation, BAs should be able to exclude or
include events based on specific conditions or consideration, such as data quality or event suitability
(e.g. BA separation from the Interconnection). The revisions made by the SDT do not enable the
inclusion of other relevant events in the FRM calcualtion by a BA. The AESO would like to to see these
type of events to be permitted in the FRM calculation by a BA.
Individual
Patricia Robertson
BC Hydro
Yes
Additionally, there should be language to clarify that this is a negative value (the same should apply
to the definitions of FRO and Frequency Bias). It is fairly obvious that these values should be negative
when reading elsewhere in the proposed Standard and its related document but not in their
definitions.
Yes
Additionally, there should be language to clarify that the BAs must belong to the same
Interconnections to form the FRSG
Yes
BC Hydro applauds the STD’s efforts to recognize a more suitable bound for Variable Frequency Bias
settings
No
BC Hydro agrees with the principles outlined in the Attachment A but has some concerns as follows:
1.Attachment A is no longer recognized as one of the associated document of the proposed Standard
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003819
in its currently posted version. We believe this was removed by mistake. 2.There is no clarity as to
how certain factors used in determining the Interconnection FRO such as CCADJ, CBR and BC’ADJ
were determined. There is no apparent provision to re-assess any potential changes to these factors
over the future years. If such provision is needed or has been provided then consideration should be
given to averaging the adjustment over a longer duration (i.e., using the average of the factor
observed over a number of years rather than just the year being assessed). 3.The method used for
the allocation of the Interconnection FRO to BAs seems to not recognize the fact that frequency
response from Load is much less than frequency response from Generation of an equal MW size. 4.If
this Attachment A is considered an integral part of the standard then there should be some
enforceable measures to ensure applicable entities adhering to the prescribed time line.
No
BC Hydro agrees in principle that the ERO should perform these tasks related to BAL-003-1 but has
the following concerns: 1.There is no clear indication whether the Interconnection FRO will be
calculated every year, and if yes, how each of the factors involved will be determined. 2.It is not clear
whether data gathered in these procedures are only for the determination of annual FRO and FBS, or
also to determine whether the BA or the FRSG was in compliance to BAL-003-1 for the assessed year.
Since the ERO in this Document seems to be the NERC Resources Subcommittee and its Frequency
Work Group, we think this fact should be made clear. The Background document should also be
reviewed to ensure its alignment in this regard.
No Comment
Yes
BC Hydro respectfully submits these additional comments/observations: 1.The proposed standard
seems to indicate that it is applicable to the identified responsible entities at all times. There might be
circumstances where a BA that belongs to a multiple-BA Interconnection became isolated and has to
operate in restorative mode which might require adjusting the frequency bias to a value less negative
than the minimum FBS setting value in order to follow the much reduced load/generation level in the
area. We suggest adding some language in either the Applicability section or in individual
Requirements to recognize these circumstances. 2.Effective Dates: the proposed standard specifies a
fixed period (12-month or 24-month) following Regulatory Approval which may fall in the middle of
the year while the calculation and implementation are performed on an annual basis. Does this
represent any conflicts? 3.The proposed standard does not clearly specify whether a BA must chose
between using fixed bias or variable bias for the entire year. Should BAs be allowed to switched back
and forth between the two methods? If yes, more details may be needed to account for the FRM and
minimum FBS. 4.The proposed standard does not clearly specify whether a BA can be part of a FRSG
for only part of the year or must be the whole year. 5.The definition of FRO, FRM, FBS, etc. should all
include language to indicate the “negative” nature of the value. 6.Measure M2 should have “and uses
a fixed bias” added for clarity purpose. 7.In the Additional Compliance Information section of the
proposed standard the following info still exists: For Interconnections that are also Balancing
Authorities, Tie Line Bias control and fFlat Ffrequency control are equivalent and either is acceptable.
Since all reference to AGC Modes have been removed from the Requirements, this additional info
should also be removed.
Individual
Grergory Campoli
New York Independent System Operator
Yes
Yes
With a new process we are concerned that the interconnection minimum will initially move from 1.0%
to 0.9%.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003820
Yes
No
The drafting team should consider some method for discounting outliers, that may not be explainable.
No
In general we support the work of the DT, and the proposal to measure the systems response to
frequency events, along with the method to determine the FRO. My outstanding concern is with
enforcement on an entity that does not own the resources that provides the frequency response or
the lack of obligation for the entity with the information to provide to the BA to make the assessment
of expected frequency response. BA’s should at a minimum be given assurance that resources will
provide data that BA’s could use to forecast frequency response and take corrective actions.
Individual
Robert Blohm
Keen Resources Asia Ltd.
Yes
Yes
Yes
Yes
No
As a professionally trained published statistical expert never compensated by any balloting
participant, I consider event selection criterion 7 to be unacceptable because it violates the
fundamental statistical procedure of sampling statistical data "as is" and not pre-selecting the data (to
fit some preferred even-distribution over time) and therefore biasing it before applying any statistical
procedure to the data. Event criterion 6 is also unacceptable for being an an "ad hoc" explicit
exclusion, from the definition of the frequency response being measured, of response to frequency
events that occur during a specific kind of scheduled generation and load changes. Said exclusion
needs to be written into the definition of the Frequency Response that is being measured. It is
procedurally improper and unacceptable to bias the sampling procedure by explicit exclusion of data
as an alternative to redefining the thing being sampled. In that case it's not generic Frequency
Response that is being sampled, but some specific Frequency-Response-less-Response-to-ExcludedEvents that is being measured. It is non-transparent and subterfuge to avoid instead accordingy
reworking/narrowing the definition of Frequency Response, especially as said reworking requires a
clear technical justification that is absent from this standard, and modifying the existing NERC
Glossary definition of Frequency Response which Criterion 6 therefore stands in flat violation of.
No
This question is falsely worded. The SDT is specifically NOT using the method detailed in the
Frequency Response Initiative Report dated September 30, 2012. So the term "this method" is
practically meaningless in this question because it is not clear if it means "the SDT's method" or "the
FRI's method". The Background Document specifically states on page 29: "The NERC Frequency
Response Initiative Report addressed the relative merits of using the median versus linear regression
for aggregating single event frequency response samples into a frequency response measurement
score for compliance evaluation. This report provided 11 evaluation criteria as a basis for
recommending the use of linear regression instead of the median for the frequency response
measurement aggregation technique. The FRSDT made its own assessment on the basis of these
evaluation criteria on September 20, 2012, but concluded that the median would be the best
aggregation technique to use initially when the relative importance of each criterion was considered."
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003821
What needs to be changed, besides properly wording this question? The FRI method of linear
regression should be adopted, and the SDT method of median should be rejected, in the standard to
change the first sentence of this question into a true statement from a false statement and to, in
answer to the question, provide for the proper amount of Frequency Response.
No
See reply to Question 6. Also, the Background Document is seriously deficient in the discussion of
inertial response and therefore how imbalances "cause" frequency deviation. The Background
Document is overflowing in discussion of how frequency deviation causes frequency response. In
other words, the Background Document is "reactive" and not "proactive". The Background Document
lacks any discussion of the internal dynamics of rotating machines, beginning with any definition of
what Inertial Response is. Inertial Response is the instantaneous power produced by the lag
("inertia") in the ability of the generator's rotor to slow down to the frequency of the magnetic field in
the generator's fixed stator whose frequency is instantaneously lowered by a change in phase angle
between voltage and current that is due to a sudden loss of interconnected generation to meet load.
Adjustments by voltage response within milliseconds and near the location of the loss are sometimes
possible to avert rapid spread of a loss to the frequency of the entire interconnection, and constitute
the ongoing work of the Phasor Project long ago initiated by the DOE in the persistent absence of
NERC interest or work in this area. NERC and drafting team members under advisement by NERC
staff studiously resisted so much as any mention of frequency deviation causation in discussions or in
the Background Document. An inexplicable technical Cold War and Berlin Wall built in the 1970s and
today separating the DOE Phasor Project from NERC Frequency Response standard development and
NERC's so-called Frequency Response "Initiative" needs to be ended and torn down. My document
http://www.robertblohm.com/Inertia.doc provides missing technical support and explanation for
graphs 1-7 on pages 4-10 of the Background Document, on the basis of an exact understanding of
Inertial Response.
A probabilistic/statistical basis needs to be developed for the FRM that assesses for usage of
frequency response (causation of frequency error) and not just for provision of it. This would also
overcome NERC’s singular focus on reaction, and NERC’s color-blindness to proaction, pointed out in
my reply to question 7.
Group
SPP Standards REview Group
Robert Rhodes
Southwest Power Pool
Yes
Yes
Yes
Yes
Delete the 2nd ‘that’ in the 2nd bullet at the top of page 3.
Yes
Yes
Yes
We like the document and feel that it provides a primer on the frequency response standard. The
following are typos in and suggested corrections to the document: -The blue lines referenced in the
paragraph under Figure 2 on page 14 are green (A) and red (B). -Insert an ‘a’ in the 3rd line of the
2nd paragraph in the Sustained Response section on page 19 between ‘provides’ and ‘greater’. -Insert
a ‘for’ in the 2nd line of the 1st paragraph on page 21 between ‘resource’ and ‘all’. -Change ‘provide’
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003822
to ‘provided’ in the 3rd line from the bottom line of the 1st paragraph in the Single Event Frequency
Response Data section on page 24. -Change the ‘east’ to ‘Eastern Interconnection’ in the 4th line of
the 1st paragraph in the Median as the Standard’s Measure of Balancing Authority Performance
section on page 27. -Delete the ‘put’ in the 3rd bullet on page 29. Also, replace the ‘put’ in the 5th
bullet with ‘gave’.
We support the standard as proposed.
Additional typos: Change the ‘)’ to a ‘(‘ in the 4th line of M1 of the standard. No further comment
Individual
Marie Knox
MISO
Yes
Yes
No
We agree with the general obligation but believe that the requirement should apply to single BA
Interconnections as well. This is supposed to be a North American standard. What other standards
shouldn’t apply to a single BA Interconnection? We have the same concern with Requirement 2.
Yes
Yes
The first hyperlink on page 3 of the Procedure for ERO Support does not work.
Yes
Yes
Yes
Group
JEA
Thomas McElhinney
JEA
R1 places the burden for compliance on the BA but the BA does not control generation assets and
should not be solely responsible for maintaining frequency response. While the standard can still
define the amount of Frequency Response for each BA, there needs to be an obligation on the
GO/GOP to provide that service as directed by the BA and they should also be held accountable for
compliance. Finally, we do not believe that a sufficient study has been conducted to determine the
impact of this standard. We are concerned that a substantial number of compliance issues could result
and that the resulting cost to maintain compliance could be excessive and we suggest it be put
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003823
through the Cost Effective Analysis Process (CEAP). We suggest that the proposed values be
evaluated on a sample size within each region to determine the number of compliance issues and for
those issues that are found determine what the BA would have to do be compliant.
Individual
Tony Kroskey
Brazos Electric Power Cooperative, Inc.
Agree
ACES Power Marketing
Individual
Mauricio Guardado
Los Angeles Department of Water and Power
Spinning reserves are intended to support the interconnection response to the loss of a resource. If
BAL-003-1 is adopted through this Project, the LADWP recommends that the spinning reserve
requirements of BAL-002-0.1b and BAL-STD-002-0 be removed, as the Spinning reserve requirement
would require utilities to reserve resources in excess of the reserves required in BAL-003-1. LADWP
recognizes that this recommendation may be handled through a separate NERC Project, but wanted
to submit this comment to bring light to this potential conflict in Reliability Standards.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003824
Consideration of Comments
Project 2007-12 Frequency Response
(BAL-003-1)
The Project 2007-12 Drafting Team thanks all commenters who submitted comments on the proposed
standard, BAL-003-1 which was posted for a 30-day formal comment period from October 5, 2012
through November 6, 2012. Stakeholders were asked to provide feedback on the standard and
associated documents through a special electronic comment form. There were 50 sets of comments,
including comments from approximately 144 different people from approximately 100 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
Based on industry comments the drafting team made the following clarifying modifications to the
proposed standard and associated documents.
•
•
•
•
Made clarifying changes to the proposed standard including replacing the term “…subject to…: with
“…in accordance with…” in Requirement R2.
Clarified the description of the calculation for the Interconnection IFRO in Attachment A.
Modified Attachment A and the Procedure to provide consistency with the use of the term
“resource contingency criteria”.
Corrected typographical errors in all documents.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003825
Index to Questions, Comments, and Responses
1.
The SDT has made minor modifications to the proposed definition for Frequency Response Measure
based on industry comments. Do you agree that these modifications provide sufficient clarity? If not,
please explain in the comment area. ....................................................................................................... 11
2.
The SDT has created a definition for Frequency Response Sharing Group. The definition is as follows: A
group whose members consist of two or more Balancing Authorities that collectively maintain,
allocate, and supply operating resources required to jointly meet the Frequency Response Obligations
of its members. Do you agree with this definition? If not, please explain in the comment area. .......... 16
3.
The SDT has added Requirement R3 for entities using variable Frequency Bias. R3. Each Balancing
Authority that is a member of a multiple Balancing Authority Interconnection, is not receiving Overlap
Regulation Service and utilizing a variable Frequency Bias Setting shall maintain a Frequency Bias
Setting that is: 3.1 Less than zero at all times, and 3.3 Equal to or more negative than its Frequency
Response Obligation when Frequency varies from 60 Hz by more than +/-0.036 Hz. ............................ 22
4.
Based on Industry comments the SDT has modified ”Attachment A- Supporting Document” to provide
additional clarity. Do you agree with the modifications? If not, what modifications do you disagree
with? ......................................................................................................................................................... 29
5.
The SDT has moved a portion of the material located in Attachment A and all of the material located in
”Attachment B- Process for Adjusting Bias Setting Floor” into a new document “Procedure for ERO
Support of Frequency Response and Frequency Bias Setting Standard”. The SDT created this document
to assign tasks to the ERO and provide instructions for the ERO to follow when carrying them out
under the BAL-003-1 standard. Do you agree that the ERO should perform these tasks and that this
document provides sufficient detail for the ERO to do it under the BAL-003-1 standard? If not, what
needs to be added to the document?”. ................................................................................................... 49
6.
The SDT is now using the method detailed in the Frequency Response Initiative Report dated
September 30, 2012 to calculate the Interconnection Frequency Response Obligation. Do you agree
that this method provides for the proper amount of Frequency Response? If not, what specifically
needs to be changed? .............................................................................................................................. 59
7.
Based on Industry comments received the SDT made significant clarifying modifications to the
Background Document. Do you agree that this document provides sufficient information to justify the
rationale used by the SDT in developing the draft standard an provides the industry with sufficient
understanding of the issues being addressed by the standard? ............................................................. 66
8.
If you are not in support of this draft standard, what modifications do you believe need to be made in
order for you to support the standard? Please list the issues and your proposed solution to the issue.
.................................................................................................................................................................. 72
9.
Please provide any other comments (that you have not already provided in response to the questions
above) that you have on the draft standard BAL-003-1. ......................................................................... 92
Consideration of Comments: Project 2007-12
2
003826
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
9.
Michael Jones
National Grid
NPCC 1
2
3
4
5
6
7
8
9
10
X
003827
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. David Kiguel
Hydro One Networks Inc.
NPCC 1
11. Michael Lombardi
Northeast Utilities
NPCC 1
12. Randy Macdonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
15. Lee Pedowcz
Northeast Power Coordinating Council
NPCC 10
16. Wayne Sipperly
New York Power Authority
NPCC 5
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
20. Brian Robinson
Utility Services
NPCC 8
21. Brian Shanahan
National Grid
NPCC 1
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Christina Koncz
PSEG Power LLC
2.
Group
Erik Ela
Additional Member Additional Organization
Region
5
6
7
Segment Selection
NA - Not Applicable NA
2. Brendan Kirby
Consultant
NA - Not Applicable NA
3. Yingchen Zhang
NREL
NA - Not Applicable
4. Mohit Singh
NREL
NA - Not Applicable
WILL SMITH
4
NPCC 5
NREL
Group
3
NREL Transmission and Grid Integration
Group
1. Vahan Gevorgian
3.
2
MRO NSRF
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM BREENE
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
Consideration of Comments: Project 2007-12
4
8
9
10
003828
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 5
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. DAN INMAN
MPC
4.
Group
Bonneville Power Administration
Additional Organization
Technical Operations
WECC 1
2. Kristy Humphrey
Technical Operations
WECC 1
3. Ayodele Idowu
Technical Operations
WECC 1
4. Rebecca Berdahl
Policy Development & Analysis WECC 3
Group
4
5
6
7
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Bart McManus
5.
3
1, 3, 5, 6
Chris Higgins
Additional Member
2
Scott Miller
MEAG Power
Additional Member Additional Organization Region Segment Selection
1. Steve Jackson
MEAG Power
SERC
3
2. Danny Dees
MEAG Power
SERC
1
3. Steve Grego
MEAG Power
SERC
5
6.
Group
Brent Ingebrigtson
Additional
Member
PPL NERC Registered Affiliates
Additional Organization
Region
Segment
Selection
1.
Brenda L. Truhe
PPL Electric Utilities Corporation`
RFC
1
2.
Annette M. Bannon
PPL Generation, LLC on behalf of Supply NERC Registered
Affiliates
RFC
5
Elizabeth A. Davis
PPL EnergyPlus, LLC
3.
4.
X
WECC 5
Consideration of Comments: Project 2007-12
MRO
6
5
8
9
10
003829
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
NPCC 6
6.
SERC
6
7.
SPP
6
8.
RFC
6
9.
WECC 6
10. Brent Ingebrigtson
LG&E and KU Services
7.
Greg Rowland
Group
SERC
2
3
4
5
6
7
3
Duke Energy
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Lee Schuster
Duke Energy
FRCC
3
3. Dale Goodwine
Duke Energy
SERC
5
4. Greg Cecil
Duke Energy
RFC
6
8.
Group
Jason Marshall
Additional
Member
ACES Power Marketing Standards
Collaborators
Additional Organization
X
Region
Segment
Selection
1. John Shaver
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.
WECC 1, 4, 5
2. Bill Hutchison
Southern Illinois Power Cooperative
SERC
1
3. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
9.
Group
Gerry Beckerle
SERC OC Standards Review Group
X
X
Additional Member Additional Organization Region Segment Selection
1.
Jeff Harrison
2.
Robert Thomasson Big Rivers Electric Corp. SERC
AECI
SERC
1, 3, 5, 6
1
3.
Dan Roethemeyer
Dynegy
SERC
5
4.
Adam Guinn
Duke Energy
SERC
1, 3, 5, 6
5.
Brad Young
LGE-KU
SERC
1, 3, 5, 6
6.
Wayne Van Liere
LGE-KU
SERC
1, 3, 5, 6
7.
Marie Knox
MISO
SERC
2
8.
Terry Bilke
MISO
SERC
2
Consideration of Comments: Project 2007-12
6
8
9
10
003830
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Troy Blalock
SCE&G
SERC
1, 3, 5, 6
10. Cindy Martin
Southern Co. Services
SERC
1, 5
11. Todd Lucas
Southern Co. Services
SERC
1, 5
12. Kelly Casteel
TVA
SERC
6, 1, 3, 5
13. Joel Wise
TVA
SERC
1, 3, 5, 6
14. Stuart Goza
TVA
SERC
1, 3, 5, 6
15. Steve Corbin
SERC Reliability Corp
SERC
10
10.
David Dockery, NERC
Reliability Compliance
Coordinator
Group
Additional Member
Associated Electric Cooperative, Inc. JRO00088
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
Group
3
4
5
X
X
X
X
X
X
6
7
X
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
11.
2
Scott Kinney
Avista
Additional Member Additional Organization Region Segment Selection
1. Scott
Kinney
WECC 1
2. Bob
Lafferty
WECC 3
3. Ed
Groce
WECC 5
12.
Group
Robert Rhodes
Additional Member
Additional Organization
SPP Standards REview Group
X
Region Segment Selection
1.
John Allen
City Utililties of Springfield
SPP
1, 4
2.
Lisa Duffey
Cleco Power
SPP
1, 3, 5
3.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
4.
Greg McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
5.
Stephen McGie
City of Coffeyville
SPP
NA
Consideration of Comments: Project 2007-12
7
8
9
10
003831
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6.
Terry Petzoldt
Kansas City Board of Public Utilities SPP
3
7.
Valerie Pinamonti
American Electric Power
SPP
1, 3, 5
8.
Randy Root
Grand River Dam Authority
SPP
1, 3, 5
9.
Katie Shea
Westar Energy
SPP
1, 3, 5, 6
10. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
13.
Thomas McElhinney
Group
JEA
2
3
4
5
X
X
X
6
7
8
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
FRCC
1
2. Garry Baker
FRCC
3
3. John Babik
FRCC
5
14.
Mark Gray
Janet Smith, Regulatory
Affairs Supervisor
Edison Electric Institute
X
X
X
X
Arizona Public Service Company
Individual
17. Individual
ryan millard
Stephanie Monzon
pacificorp
PJM Interconnection, LLC
X
X
X
X
X
X
X
X
18.
Individual
Richard Vine
California Independent System Operator
19.
Individual
Howard F. Illian
Energy Mark, Inc.
20.
Individual
Thad Ness
American Electric Power
X
21.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
22.
Individual
Travis Metcalfe
Tacoma Power
X
X
23.
Individual
Nazra Gladu
Manitoba Hydro
X
24.
Individual
Alice Ireland
Xcel Energy
25.
Individual
Shammara Hasty
26.
Individual
27.
15.
Individual
Individual
16.
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Southern Company
X
X
X
X
Greg Travis
Idaho Power Company
X
X
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
28.
Individual
Michael Falvo
Independent Electricity System Operator
29.
Individual
Brian J Murphy
NextEra Energy
X
X
X
Consideration of Comments: Project 2007-12
X
X
X
X
8
9
10
003832
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
30.
Individual
2
3
4
5
6
Texas Reliability Entity
Individual
32. Individual
Don Schmit
Brett Holland
Nebraska Public Power District
Kansas City Power & Light
X
X
X
X
X
X
X
33.
Individual
Angela P Gaines
Portland General Electric Company
X
X
X
X
34.
Individual
Kathleen Goodman
ISO New England Inc.
35.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
36.
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
X
37.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
X
X
X
X
38.
Individual
David Jendras
Ameren
X
X
X
X
39.
Individual
Maggy Powell
X
X
X
X
X
X
X
X
X
Individual
Janelle Marriott Gill
Exelon Corporation and its affiliates
Tri-State Generation and Transmission
Assn., Inc.
41.
Individual
Denise M Lietz
Puget Sound Energy
X
X
X
42.
Individual
Rich Salgo
NV Energy
X
X
X
43.
Individual
John Tolo
Tucson Electric Power
X
44.
Individual
Ken Gardner
AESO
45.
Individual
Patricia Robertson
BC Hydro
X
X
46.
Individual
Grergory Campoli
New York Independent System Operator
47.
Individual
Robert Blohm
Keen Resources Asia Ltd.
48.
Individual
Marie Knox
MISO
49.
Individual
Tony Kroskey
Individual
Mauricio Guardado
Brazos Electric Power Cooperative, Inc.
Los Angeles Department of Water and
Power
40.
50.
Consideration of Comments: Project 2007-12
8
9
10
X
Don Jones
31.
7
X
X
X
X
X
X
X
X
X
X
X
9
003833
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration:
Organization
Supporting Comments of “Entity Name”
MEAG Power
Southern Company Services, Inc - Gen
Associated Electric Cooperative, Inc. JRO00088
SERC OC Standards Review Group
Avista
Bonneville Power Administration
Nebraska Public Power District
MRO NSRF [Midwest Reliability Organization - NERC Standards Review Forum]
ISO New England Inc.
Last submitted comments of ISO-NE which have not been addressed and, for
efficiency sake, do not believe we should be requested to re-submit.
South Carolina Electric and Gas
SERC OC Standards Review Group
Entergy Services, Inc. (Transmission)
Entergy is in agreement with comments submitted by SERC on 11/5/0212.
Brazos Electric Power Cooperative, Inc.
ACES Power Marketing
Consideration of Comments: Project 2007-12
10
003834
1.
The SDT has made minor modifications to the proposed definition for Frequency Response Measure based on industry
comments. Do you agree that these modifications provide sufficient clarity? If not, please explain in the comment area.
Summary Consideration: A few of the commenters felt that the definition applied to all of the observations for both the BA and the
FRSG. The drafting team stated that although they understood their concern they did not agree with them. They felt
that the present definition provided sufficient clarity and decided to not make any modifications.
One commenter felt that the definition should state that it is a negative value. The drafting team explained that while the desired
value would be negative it is mathematically feasible for the actual value to be positive but that value would by
definition mean that the entity failed the measurement for Requirement R1.
Another commenter did not believe that there was sufficient clarity as to the number of observations that would be used to calculate
FRM. The drafting team stated that the number of observations would vary from year to year. The basis for
determining events is outlined in the Procedure attached to this standard.
Organization
Yes or No
Duke Energy
No
Question 1 Comment
The definition reads as if the FRM is the median of all of the observations reported by the
Balancing Authorities and Frequency Response Sharing Groups. Duke Energy would suggest
that the definition read, “The median of all of the Frequency Response observations
reported annually by a Frequency Response Sharing Group, or Balancing Authority if not a
participant in a Frequency Response Sharing Group, for frequency events specified by the
ERO. The Frequency Response Measure is calculated as MW/0.1Hz.”
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
SERC OC Standards
Review Group
No
The definition reads as if the FRM is the median of all of the observations reported by the
Balancing Authorities and Frequency Response Sharing Groups. We agree with the Duke
Energy suggestion that the definition read, “The median of all of the Frequency Response
observations reported annually by a Frequency Response Sharing Group, or Balancing
Consideration of Comments: Project 2007-12
11
003835
Organization
Yes or No
Question 1 Comment
Authority if not a participant in a Frequency Response Sharing Group, for frequency events
specified by the ERO. The Frequency Response Measure is calculated as MW/0.1Hz.”
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
PPL NERC Registered
Affiliates
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on this
question.
Response: The drafting team thanks you for your comment. However, the drafting team believes that the present definition
provides sufficient clarity and has decided to not make any changes.
BC Hydro
Yes
Additionally, there should be language to clarify that this is a negative value (the same
should apply to the definitions of FRO and Frequency Bias). It is fairly obvious that these
values should be negative when reading elsewhere in the proposed Standard and its related
document but not in their definitions.
Response: While the desired value would be negative it is mathematically feasible for the actual value to be positive but that
value would by definition mean that the entity failed the measurement for Requirement R1.
Tucson Electric Power
Yes
however, the number of observations to be used in calculating an entity's FRM is not clear.
Response: Thank you for your affirmative response and clarifying comment. The number of observations will vary from year to
year. The basis for determining events is outlined in the Procedure attached to this standard.
Exelon Corporation and
its affiliates
Yes
Please see response to question 8. The FRM definition is acceptable within the context of
the attachment description; however, without clarifying the terms under which the ERO
specifies which events are to be measured, the FRM definition is too variable.
Response: Thank you for your affirmative response and clarifying comment. The criteria used to determine the events to be used
are outlined in the Procedure attached to this standard. Please refer to our response to Question #8.
Consideration of Comments: Project 2007-12
12
003836
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
Yes
Question 1 Comment
We believe that refinements to the definition were needed.
Response: Thank you for your affirmative response and clarifying comment.
Manitoba Hydro
Yes
Northeast Power
Coordinating Council
Yes
NREL Transmission and
Grid Integration Group
Yes
MRO NSRF
Yes
Bonneville Power
Administration
Yes
SPP Standards REview
Group
Yes
Edison Electric Institute
Yes
Arizona Public Service
Company
Yes
pacificorp
Yes
No comment.
PJM Interconnection, LLC Yes
California Independent
Yes
Consideration of Comments: Project 2007-12
13
003837
Organization
Yes or No
Question 1 Comment
System Operator
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Xcel Energy
Yes
Southern Company
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
Texas Reliability Entity
Yes
Kansas City Power &
Light
Yes
Consolidated Edison Co.
of NY, Inc.
Yes
Ameren
Yes
NV Energy
Yes
New York Independent
System Operator
Yes
Keen Resources Asia Ltd.
Yes
Consideration of Comments: Project 2007-12
14
003838
Organization
Yes or No
MISO
Yes
American Electric Power
Question 1 Comment
As provided in question 2 below, AEP does not agree with the definition containing the
Frequency Response Sharing Group as this function does not exist at this point in time.
Response: Thank you for your comments. The term Frequency Response Sharing Group is defined at the beginning of the
standard. Once this standard is approved by the industry, NERC BOT and FERC the definition will be removed from the standard
and added to the NERC Glossary of Terms.
Consideration of Comments: Project 2007-12
15
003839
2.
The SDT has created a definition for Frequency Response Sharing Group. The definition is as follows: A group whose members
consist of two or more Balancing Authorities that collectively maintain, allocate, and supply operating resources required to
jointly meet the Frequency Response Obligations of its members. Do you agree with this definition? If not, please explain in the
comment area.
Summary Consideration: Almost all of the commenters wanted to modify the definition. The drafting team explained that they
believed that the proposed definition should remain unchanged. The drafting team developed the definition to be
essentially the same as that currently used for contingency Reserve Sharing Groups. This will help ensure that the
different types of reserve groups are comparable as we move forward with this new type of group.
One commenter did not agree believe it was appropriate to define a new function that was not in the NERC ROP, NERC Statement of
Registry Criteria or the NERC Functional Model. The drafting team stated that they had discussed this issue with NERC.
NERC staff will add this entity to the registered entity list in the same manner as the existing Reserve Sharing Group.
While this is not in the current version available online, NERC will have at least 24 months from the time of regulatory
approval to add the entity to the list of registered entities.
Organization
Yes or No
SERC OC Standards Review
Group
No
Question 2 Comment
A Balancing Authority may not be the entity maintaining or supplying resources, but
would be responsible for utilizing applicable resources within its BA Area. We would
modify the Duke Energy suggestion to read as follows: “A group whose members
consist of two or more Balancing Authorities that collectively utilize operating
resources with a goal to achieve a group FRM equal to or more negative than the sum
of the Frequency Response Obligations of its members.”
Response: Thank you for your comments. After review of suggested changes, the drafting team believes that the proposed definition
should remain unchanged. The drafting team developed the definition to be essentially the same as that currently used for
contingency Reserve Sharing Groups. This will help ensure that the different types of reserve groups are comparable as we move
forward with this new type of group.
American Electric Power
No
AEP does not necessarily disagree with the words of the definition. However, AEP does
Consideration of Comments: Project 2007-12
16
003840
Organization
Yes or No
Question 2 Comment
not believe it is appropriate to define a new function that is not in the NERC Rules of
Procedure, NERC Statement of Registry Criteria, or the NERC Functional Model. It is
premature to incorporate this entity without a proposed change to these governing
NERC documents.
Response: Thank you for your comments. The drafting team has discussed this issue with NERC. NERC staff will add this entity to
the registered entity list in the same manner as the existing Reserve Sharing Group. While not in the current version available online,
NERC will have at least 24 months from the time of regulatory approval to add the entity to the list of registered entities.
Duke Energy
No
As a Balancing Authority may not be the entity maintaining or supplying resources, but
would be responsible for utilizing applicable resources within its BA Area, Duke Energy
would suggest the following definition, “A group whose members consist of two or
more Balancing Authorities that collectively utilize operating resources required to
achieve a group FRM equal to or more negative than the sum of the Frequency
Response Obligations of its members.”
Response: Thank you for your comments. After review of suggested changes, the drafting team believes that the proposed
definition should remain unchanged. The drafting team developed the definition to be essentially the same as that currently used for
contingency Reserve Sharing Groups. This will help ensure that the different types of reserve groups are comparable as we move
forward with this new type of group.
Edison Electric Institute
No
EEI does not fully agree with the definition of a “Frequency Response Sharing Group”
(FRSG). In the definition offered in the new Standard, it states that the FRSG
“collectively maintain, allocate, and supply operating resources”. Of the three roles, a
balancing authority only maintains load-interchange-generation balance through the
allocation of resources. Therefore, EEI suggests that the definition be changed to more
appropriately align with the role of a BA, which we believe would be to allocate
resources in a manner that effectively allows the sharing of resources necessary to
achieve a FRO within the defined sharing group, which might otherwise not be possible
or practical by a BA on its own.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
Consideration of Comments: Project 2007-12
17
003841
Organization
Yes or No
Question 2 Comment
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
ACES Power Marketing
Standards Collaborators
No
We agree that a definition is needed and thank the drafting team for writing one.
However, we believe additional refinement of the definition is necessary. Although the
definition appears to be written to parallel the Reserve Sharing Group definition, we
think the definition needs to be simplified. For one, it encompasses actions that are not
necessary. For instance, the proposed definition includes the action to “maintain
operating resources”. This could literally include generating plant maintenance. We do
not agree that a Frequency Response Sharing Group would jointly perform
maintenance on their plants. In fact, since the definition applies to BAs, it is entirely
possible within the functional model that the BAs do not even own the plants and
could not perform joint maintenance. We assume the purpose of including “maintain”
was to recognize that maintenance of generating resources would need to be
coordinated to ensure that there was sufficient frequency response reserve. We do not
believe this needs to be explicitly identified in the definition. Furthermore, we find the
use of “operating resource” as a source of potential confusion. While we understand
operating resource is intended to mean a facility that provides the ability to increase or
decrease MW output based on the frequency deviation, resource has various meanings
throughout the standards and its use here could be confusing and contradictory. For
instance, TOP-006-2 R1 discusses transmission resources. Furthermore, if an “operating
resource” is capable of increasingor decreasing MW output based on frequency
deviation, what is a “resource”? In other words, why is “operating” added to the term
“resource”? We think it is best to avoid use of the term operating resource and, thus,
recommend changing the definition to: “A group of two or more Balancing Authorities
that share frequency response reserves and are required to jointly meet the Frequency
Response Obligations of its members.”
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
BC Hydro
Yes
Additionally, there should be language to clarify that the BAs must belong to the same
Consideration of Comments: Project 2007-12
18
003842
Organization
Yes or No
Question 2 Comment
Interconnections to form the FRSG
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
PPL NERC Registered
Affiliates
Yes
PPL Affiliates suggest additional detail be added to the definition to ensure the
members of the FRSG are all within the same interconnection. The following definition
includes the suggested changes: A group whose members consist of two or more
Balancing Authorities all within a single interconnection that collectively operate
resources required to jointly meet the sum of the Frequency Response Obligations of
its members.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
Ameren
Yes
The word "jointly" may add confusion and we believe it is unessassry.
Response: After review of suggested changes, the drafting team believes that the proposed definition should remain unchanged. The
drafting team developed the definition to be essentially the same as that currently used for contingency Reserve Sharing Groups. This
will help ensure that the different types of reserve groups are comparable as we move forward with this new type of group.
Manitoba Hydro
Yes
Northeast Power
Coordinating Council
Yes
NREL Transmission and Grid
Integration Group
Yes
MRO NSRF
Yes
Bonneville Power
Yes
No comment.
Consideration of Comments: Project 2007-12
19
003843
Organization
Yes or No
Question 2 Comment
Administration
SPP Standards REview
Group
Yes
Arizona Public Service
Company
Yes
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Xcel Energy
Yes
Southern Company
Yes
Idaho Power Company
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Consolidated Edison Co. of
NY, Inc.
Yes
Consideration of Comments: Project 2007-12
20
003844
Organization
Yes or No
Exelon Corporation and its
affiliates
Yes
NV Energy
Yes
Tucson Electric Power
Yes
Keen Resources Asia Ltd.
Yes
MISO
Yes
Independent Electricity
System Operator
Question 2 Comment
Not Applicable
Consideration of Comments: Project 2007-12
21
003845
3.
The SDT has added Requirement R3 for entities using variable Frequency Bias. R3. Each Balancing Authority that is a member of
a multiple Balancing Authority Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
3.1 Less than zero at all times, and
3.3 Equal to or more negative than its Frequency Response Obligation when Frequency varies from 60 Hz by more than +/-0.036
Hz.
Summary Consideration: A couple of commenters felt that the intent of the requirement needed to be clarified. The drafting team
explained that Requirement R3 is only applicable to a BA using a variable bias and does require a BA to maintain a bias
less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias have a bias at least equal to
the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are addressed in
Requirement R2.
A few commenters expressed concern with excluding a single BA interconnection from compliance with Requirement R3. The
drafting team stated that they had discussed the applicability of variable bias requirements to single BA
Interconnections extensively. The consensus of the drafting team was that single BA Interconnections inherently have
strong incentives to accurately represent their frequency response characteristic. Any adverse consequences of
misrepresenting the frequency response characteristic will be borne solely by that BA and cannot affect other BAs in
other Interconnections adversely.
One commenter disagreed with allowing the use of variable Frequency Bias in a multi-BA interconnection. The drafting team
believes that this concern may be better addressed within BAL-001. Variable frequency bias settings allow a Balancing
Authority to better match their frequency bias setting in use with the actual frequency response occurring at any
instant in time. If it is meeting its FRO for larger frequency deviations and the frequency bias setting in use at that time
meets or exceeds its FRO, then the BA is doing its part to support frequency and AGC will not be withdrawing that
frequency response.
Another commenter question the periodicity of a BA changing its Frequency Bias Setting to be considered using variable Frequency
Bias. They gave an example of an entity changing its FBS monthly. The drafting team stated that they had not defined
the periodicity for changing their bias to be variable. The example given would be a form of variable bias and would
trigger all rules related to variable bias. Requirement R3 is separate from Requirement R4. Requirement R4 is related
Consideration of Comments: Project 2007-12
22
003846
to those entities providing Overlap Regulation Service. It is possible for an entity to provide Overlap Regulation
Service and have a variable bias setting therefore an entity may be subject to compliance for both Requirement R3 and
Requirement R4.
Organization
Yes or No
American Electric Power
No
Question 3 Comment
AEP believes this question in the comment form is incorrect. It appears that R3 and R4
are inadvertenly merged together.
Response: The drafting team is not sure of the point you are trying to make. The question only contains the Requirement R3 from
the standard. The drafting team did notice that the numbering of the sub-bullets was incorrect.
Duke Energy
No
Duke Energy agrees with allowing single-BA Interconnections to utilize a variable
Frequency Bias Setting (FBS). Duke Energy disagrees with NERC allowing Balancing
Authorities in a multiple-BA Interconnection to change the ACE and bounds by which
the Balancing Authorities are measured under BAL-001 and BAL-002 by operating to a
variable FBS. It is desired that a Balancing Authority be capable of recognizing the
amount of primary response available in real-time operation, such information can be
included among other information in the generation control algorithm; however, the
obligation to support the Interconnection frequency under the secondary control
standards, and the amount provided for any given frequency, should be based on the
same criteria across all Balancing Authorities of the same size. Nathan Cohn in his
comments on Union Electric’s use of a variable FBS expressed similar concern regarding
the equitable sharing of the obligation to support Interconnection frequency in a
multiple-BA Interconnection. Take for example two Balancing Authorities with equal
total generation and load, but one operating under a fixed FBS and the other operating
under a variable FBS. To the extent that a Balancing Authority is not providing
Frequency Response comparable to its fixed Frequency Bias Setting, its ACE will reflect
the difference to be covered with secondary control and the Balancing Authority will be
measured in a manner similar to other BAs of its “size” based upon the FBS. To the
extent that the other BA using a variable FBS is not providing Frequency Response
Consideration of Comments: Project 2007-12
23
003847
Organization
Yes or No
Question 3 Comment
comparable to what it would be allocated using a fixed FBS, its ACE will not reflect the
difference or any further obligation to support Interconnection frequency at that time
with secondary control. Duke Energy’s concern regarding non-comparable treatment of
all BAs is further amplified by the lack of scrutiny placed on the BA algorithm used to
determine the real-time variable FBS, to ensure that compliance cannot be gamed by
such use.
Response: The drafting team believes that this concern may be better addressed within BAL-001. Variable frequency bias settings
allow a Balancing Authority to better match their frequency bias setting in use with the actual frequency response occurring at any
instant in time. If it is meeting its FRO for larger frequency deviations and the frequency bias setting in use at that time meets or
exceeds its FRO, then the BA is doing its part to support frequency and AGC will not be withdrawing that frequency response.
Northeast Power
Coordinating Council
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service
(supplying actual interchange, frequency response, and schedules to another BA), then
it can be assumed that the BA is supplying regulation service. Was the intent of the
requirement to simply state that all BA’s must have a bias setting less than zero at all
times? The intent of this requirement needs to be clarified.
Response: The drafting team is not sure if we understand your first comment. A BA not providing Overlap Regulation Service may
or may not be providing Supplemental Regulation Service. Requirement R3 is only applicable to a BA using a variable bias and
does require a BA to maintain a bias less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias
have a bias at least equal to the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are
addressed in Requirement R2.
Consolidated Edison Co. of
NY, Inc.
No
If a BA is using a frequency bias setting and is not providing Overlap Regulation Service
(supplying actual interchange, frequency response, and schedules to another BA), then
we can assume it is supplying regulation service. Was the intent of the requirement to
simply state that all BA’s must have a bias setting less than zero at all times? Please
clarify the intent of this requirement.
Response: The drafting team is not sure if we understand your first comment. A BA not providing Overlap Regulation Service may
or may not be providing Supplemental Regulation Service. Requirement R3 is only applicable to a BA using a variable bias and
Consideration of Comments: Project 2007-12
24
003848
Organization
Yes or No
Question 3 Comment
does require a BA to maintain a bias less than zero. Bullet R3.2 extends the requirement to ensure that BAs using variable bias
have a bias at least equal to the FRO when frequency is outside the bandwidth of +/- 0.036 Hz. The BAs using a fixed bias are
addressed in Requirement R2.
Exelon Corporation and its
affiliates
No
Please see response to question 8.
Response: Please refer to the drafting team response to Question #8.
MRO NSRF
No
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing
Authority Interconnections from compliance with Requirement R3. To ensure a
consistent approach in the application of the standard, recommend R3 be revised as
follows:(R3). Each Balancing Authority that is not receiving Overlap Regulation Service
and is utilizing a variable Frequency Bias Setting shall maintain a Frequency Bias Setting
that is: ...
Response: The drafting team discussed the applicability of variable bias requirements to single BA Interconnections extensively. The
consensus of the drafting team was that single BA Interconnections inherently have strong incentives to accurately represent their
frequency response characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will be borne
solely by that BA and cannot affect other BAs in other Interconnections adversely.
MISO
No
We agree with the general obligation but believe that the requirement should apply to
single BA Interconnections as well. This is supposed to be a North American standard.
What other standards shouldn’t apply to a single BA Interconnection? We have the
same concern with Requirement 2.
Response: The drafting team discussed the applicability of variable bias requirements to single BA Interconnections extensively.
The consensus of the drafting team was that single BA Interconnections inherently have strong incentives to accurately represent
their frequency response characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will
be borne solely by that BA and cannot affect other BAs in other Interconnections adversely.
PJM Interconnection, LLC
No
With what periodicity does a BA’s frequency bias setting have to change to be
Consideration of Comments: Project 2007-12
25
003849
Organization
Yes or No
Question 3 Comment
considered variable bias? For example, if a BA changes it’s frequency bias setting
monthly based on a percentage of each month’s forecast or historic load, is this
considered variable bias subject to compliance with R3 in lieu of R4?
Response: The drafting team has not defined the periodicity for changing their bias to be variable. The example given would be a
form of variable bias and would trigger all rules related to variable bias. Requirement R3 is separate from Requirement R4.
Requirement R4 is related to those entities providing Overlap Regulation Service. It is possible for an entity to provide Overlap
Regulation Service and have a variable bias setting therefore an entity may be subject to compliance for both Requirement R3 and
Requirement R4.
BC Hydro
Yes
BC Hydro applauds the STD’s efforts to recognize a more suitable bound for Variable
Frequency Bias settings
Response: Thank you for your affirmative response and clarifying comment.
Bonneville Power
Administration
Yes
BPA is responding to 3.1 and 3.2 of R3. The bullets listed in question 3 on the original
comment form appear to be for Requirement R4. BPA is in support of R3.1 and R3.2.
Response: Thank you for your affirmative response and clarifying comment.
Texas Reliability Entity
Yes
It appears that R3.2 is based on the assumption that governor dead-band settings are
0.036 Hz for all interconnections with multiple BAs. While the ERCOT region has a
standard 0.036 Hz dead-band specified in the ERCOT Protocols and Operating Guides,
we are not sure if this is applicable to the other regions.
Response: Thank you for your affirmative response and clarifying comment. In addition, as to the deadband setting, this number
was also considered to be within the frequency deviation range of the event determination criteria as defined in the Procedure
document.
Tucson Electric Power
Yes
N/A
Consideration of Comments: Project 2007-12
26
003850
Organization
Yes or No
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
ACES Power Marketing
Standards Collaborators
Yes
SPP Standards REview
Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Southern Company
Yes
Idaho Power Company
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
Question 3 Comment
No comment.
Consideration of Comments: Project 2007-12
27
003851
Organization
Yes or No
Keen Resources Asia Ltd.
Yes
Independent Electricity
System Operator
Question 3 Comment
Not Applicable
Consideration of Comments: Project 2007-12
28
003852
4.
Based on Industry comments the SDT has modified ”Attachment A- Supporting Document” to provide additional clarity. Do you
agree with the modifications? If not, what modifications do you disagree with?
Summary Consideration: A few commenters felt that there were requirements stated within Attachment A. The drafting team
explained that the requirement stated in the standard was the only requirement related to FRM. Attachment A is
there to provide uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability
objectives in the requirements and put procedural steps in the attachment and procedure.
Several commenters expressed concern over the use of the largest event in the last 10 years for the Eastern Interconnection while all
of the other Interconnections used the Category C (N-2). The drafting team stated that the results for the current
Eastern Interconnection model do not represent observed response adequately. The models for the other
Interconnections have a better match. For this reason the drafting team has recommended the largest event in the
last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are
provided on pages 52 through 55 of the Frequency Response Initiative paper.
A couple of commenters questioned the difference between the present frequency bias of -6,360 MW/0.1 Hz and the proposed of 1,002 MW/0.1 Hz. The drafting team explained that the -6,630 MW/0.1 Hz represents a summation of the Frequency
Bias Settings of all Balancing Authorities in the Eastern Interconnection, most of which use the 1% default minimum as
required in the current BAL-003-0 standard, which far exceeds their real response. The IFRO of -1002 MW/0.1 Hz is the
response determined to avoid the first step of Underfrequency load shedding in the Interconnection for a 4,500 MW
generation loss.
A few commenters felt that clarification was need concerning changes in a BAs footprint and changes to the bias setting or FRO. The
drafting team felt that this was a problem that would take care of itself. If two BAs change footprint but do not raise
the issue the impact is transparent to the Interconnection. If one BA believes that its limits need to be adjusted the
process will adjust the limits of both BAs accordingly.
A couple of commenters requested clarity as to how changes to the process in Attachment A would be handled. The drafting team
explained that any change to the methodology described in Attachment A would have to go through the Standards
Development Process prior to being implemented.
Two commenters felt that there should be an exemption for non-conforming load performing contrary to the performance of
conventional load. The drafting team stated that they did not agree that there should be an exemption but has
designed the forms to allow for adjustments for non-conforming load. However the BA may find that no adjustment
for non-conforming load may be needed due to the measurement over multiple events rather than individual events.
Consideration of Comments: Project 2007-12
29
003853
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 4 Comment
(1) Frequency Response Obligation (FRO) is used inconsistently with the proposed
definition in the document. The document uses the term “Interconnection Frequency
Response Obligation” in many locations. However, FRO specifically is defined as the
BA’s “share of the required Frequency Response”. It does not apply to the
Interconnection. How can the Interconnection have a share of the required frequency
response? A new term may need to be defined for the Interconnection required
Frequency Response.
(2) On page 3 Attachment A states the ERO will post the Frequency Bias Setting for
each BA along with their Frequency Response Obligation. Later on the same page, the
document states that the BA shall set its Frequency Bias Setting to 100% to 125% of it
Frequency Response Measure or Interconnection Minimum. What is the purpose of the
ERO determining Frequency Bias Settings if the settings are not going to be used by the
BA? What are we missing in the explanation?
(3) Late on page 3, the document states that BAs are encouraged to notify NERC if load
or generation is transferred. Section 4(a) on page 8 of the Rules of Procedure Appendix
5A - Organization Registration and Certification Manual indicates that changes to a
Registered Entity’s footprint actually triggers a potential certification audit. Since BAs
are required to be certified and moving generation or load from the metered
boundaries of one BA to another BA would represent a change in footprint, we suggest
removing the word “encouraged” and stating affirmatively that BAs must notify NERC
of such changes and referencing the appropriate section of the Rules of Procedure.
Otherwise, BAs may not realize notification is actually required.
Response: (1) The drafting team believes the IFRO and FRO terms are used appropriately in Attachment A. Interconnection
Frequency Response Obligation is not defined in the standard nor is it a performance obligation. The drafting team has clarified
Attachment A in instances when using the terms to address your comments.
Consideration of Comments: Project 2007-12
30
003854
Organization
Yes or No
Question 4 Comment
(2) The ERO is not determining the FBS but is only validating the FBS provided by the BA on FRS Form 1.
(3) The SDT believes these are two coordinated but separate processes. If the Rules of Procedure apply, as worded this document
provides the avenue to make the necessary changes to Frequency Bias Setting.
Consolidated Edison Co. of
NY, Inc.
No
(1) This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource
contingency criteria (in the attachment, this is called the “target contingency criteria”),
etc.
(2) Of value to entities would be a sample calculation.
(3) “The largest category C (N-2) event is used for all interconnections except the
Eastern which uses the largest event in the last 10 years”. Why aren’t all
interconnections using the same design contingency design basis?
(4) The NERC 2012 CPS2 bounds has an Eastern Interconnection frequency bias of 6,360 MW/.1Hz. Can the DT explain why this attachment refers to an Interconnection
frequency response obligation of -1,002MW/.1Hz. This is a significant difference.
Response: (1) As stated in Attachment A these terms are defined in the Procedure. The drafting team clarified the use of multiple
terms of “resource contingency criteria” throughout both Attachment A and the Procedure documents.
(2) The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
(3) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
pages 52 through 55 of the Frequency Response Initiative paper.
(4) The -6,630 MW/0.1 Hz represents a summation of the Frequency Bias Settings of all Balancing Authorities in the Eastern
Interconnection, most of which use the 1% default minimum as required in the current BAL-003-0 standard, which far exceeds
their real response. The IFRO of -1002 MW/0.1 Hz is the response determined to avoid the first step of Underfrequency load
shedding in the Interconnection for a 4,500 MW generation loss.
Consideration of Comments: Project 2007-12
31
003855
Organization
Yes or No
American Electric Power
No
Question 4 Comment
AEP is under the impression that there are some requirements, which though not
explicitly stated, are implied in Attachment A. AEP feels strongly that these “subrequirements” should be clarified and contained within the body of the requirements
of the standard.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM.
Duke Energy
No
As indicated in our comments in the past, Duke Energy is certain that as the
Interconnection Frequency Bias Setting (FBS) is set closer to the actual Frequency
Response in a multi-BA Interconnection, most BAs will be challenged in meeting CPS2,
while CPS1 and the proposed Balancing Authority ACE Limit (BAAL) will be more
achieveable bounds, and in some cases CPS1 performance will improve. Though
probably most of the BAs may welcome a FBS set as high in magnitude as allowed to
address the potential compliance risk, there are some which may desire to set their FBS
closer to their required minimum allocation rather than have to take on a larger
obligation in frequency support under the secondary control measures. Duke Energy
believes that this proposed standard should incent BAs to provide more than their
share of Frequency Response to the Interconnection and allow that good performance
to be recognized; however the requirements described in Attachment A for
determining the minimum Frequency Bias Setting (FBS), which requires that the FBS be
set no lower in magnitude than the FRM, will leave certain over-performing BAs with
no choice but to reduce their actual Frequency Response (still well-above their FRO) if
they want to operate with a FBS set closer to the Interconnection Minimum allocation
and be relieved of the associated increased obligation for frequency support under the
secondary control measures. The FBS is embedded within the secondary control
measures of CPS1, CPS2 and the draft Balancing Authority ACE Limit (BAAL).
Comparable treatment of similarly-sized BAs (based upon the FRO allocation) is only
possible if all BAs are provided the same minimum FBS requirement. To the extent that
a BA provides more than its share of response to events, it’s over-performance will only
Consideration of Comments: Project 2007-12
32
003856
Organization
Yes or No
Question 4 Comment
be recognized if its ACE is allowed to reflect a FBS comparable to its peers, allowing its
over-performance to be reflected in ACE in support of bringing frequency closer to 60
Hz. Generation control algorithms implemented today to optimize CPS1 will allow nonzero ACE when in support Interconnection frequency within bounds determined by the
BA - there should be no concern of “response withdrawal” with such algorithms in
place, the BA will simply get credit for such performance. As depicted in the current
document, the over-performing BA would be required to set its minimum FBS at its
FRM (or greater in magnitude), taking away what should be considered overperformance, erasing it in ACE, and turning it into an obligation under the secondary
control measures. Based upon the draft, the only way that the BA could be treated
comparably to other similarly sized BAs held only to operating to the Interconnection
Minimum allocation, would be to reduce its actual response in FRM to a value less in
magnitude than its Interconnection Minimum allocation. Duke Energy believes that
BAs should be incented to provide more than their share of Frequency Response, and
be given the opportunity to report performance on a basis comparable to similar-sized
BAs. Our opinion is that Attachment A ensures that the Interconnection Frequency
Bias Setting will remain at some margin above the actual Interconnection Frequency
Response in magnitude - the reliability of the Interconnection will not be at risk by
allowing over-performing BAs to operate and report performance on a comparable
basis to other similarly-sized BAs based upon the Interconnection Minimum allocation
if they choose to do so - to that extent, Duke Energy suggests that the language on
page 3 be changed to:”A BA using a fixed Frequency Bias Setting may set its Frequency
Bias Setting to any number the BA chooses up to 125% of its Frequency Response
Measure as calculated on FRS Form 1, but no less in magnitude than its Interconnection
Minimum allocation as determined by the ERO.”Regarding the argument which could
be offered that a larger FBS in magnitude will also allow wider bounds for control
performance, Duke Energy agrees that a large portion of the BA operation will be
around 60 Hz where such a benefit could be realized, however it would also come at
the cost of a larger obligation than other comparably-sized BAs in sustained support of
frequency during the more critical times of significant deviation from 60 Hz where the
BA’s compliance could be at risk. Below 59.95 Hz in the Eastern Interconnection (the
Consideration of Comments: Project 2007-12
33
003857
Organization
Yes or No
Question 4 Comment
Frequency Trigger Limit under BAAL), the additional MWs needed to be compliant for
any given frequency are greater than the MWs of imbalance allowed by the larger BAAL
bound - comparably-sized BAs will not be comparably judged if the standard forces
over-performing BAs to assume a larger FBS (in magnitude) than their peers - that
should be the decision of the BA. We believe that the proposed language above will
create the proper incentive for a Balancing Authority to provide more than its
minimum allocation of Frequency Response, and allow it to choose if it wants to make
that performance part of a larger FBS (in magnitude), knowing the associated risks and
benefits of that decision.Duke Energy supports this standard allowing for Frequency
Response Sharing Groups, however the requirements and supporting documents need
to clearly allow the FRSG to be treated no differently than if it was a Balancing
Authority and shield the participating BAs from compliance scrutiny when all scrutiny
should be placed on the FRSG performance as a whole.
At the top of Page 3, the standard attachment allows the FRSG to “calculate a group
NIA and measure the group response to all events in the reporting year on a single FRS
Form 1”, however at the bottom of page 3, the standard attachment still requires the
FRSG BAs to individually fill out Form 1 and Form 2 for the purposes of determining the
minimum Frequency Bias Setting. Duke Energy believes that the standard language in
Attachment A, and the supporting form(s), should allow the FRSG, if it chooses, to also
report the split of the group FRM which the BAs will use to individually determine their
Frequency Bias Setting, rather than require each BA in an FRSG to still maintain Form 1
and Form 2 data. Form 1 could be modified for the FRSG to report the group’s FRM
along with the split of the FRM among the members, and another form could be
developed for each FRSG BA to fill out, replicating only the section of Form 1 (column S)
where each BA could provide values for its FRM allocation, its desired FBS, its minimum
FBS allocation, and so on.
Response: The drafting team has chosen to reduce the minimum Frequency Bias Settings for individual BAs on a controlled basis
on each Interconnection. Your suggestion would eliminate the ability of the drafting team to coordinate the reduction of the
minimum Frequency Bias Settings for the BAs. Other commenters have stated that they disagree with reducing the minimum
Consideration of Comments: Project 2007-12
34
003858
Organization
Yes or No
Question 4 Comment
Frequency Bias Setting. The drafting team is attempting to balance between the two positions stated in previous postings.
The drafting team understands your concern regarding the treatment of FRSG and the minimum Frequency Bias Setting. However,
the drafting team believes that this allocation of Frequency Bias among the FRSG members on a basis different from the measured
response could be detrimental to reliability under system separation conditions. Future consideration of this issue may be
possible once additional information is available.
Independent Electricity
System Operator
No
As indicated in our previous comments, the status of Attachment A is unclear. It is a
mixture of requirements, criteria, process and guideline. Making a direct reference in
the standard’s requirements (R1 and R2) makes Attachment A as part of the
requirement and hence is enforceable, but it contains process and guideline
information that is not subject to assessment. On the other hand, the absence of a
Measure to assess adherence to the criteria and process suggests that Attachment A is
not enforceable. It is this ambiguity that makes it difficult for the industry to assess the
extent to which they must follow the process. Again, we urge the SDT to keep only the
criteria/process parts that must be adhered to in Attachment A, and extract the
remaining parts and place them in a guideline document, or an appendix.In addition,
the Responsible Entities are required to submit Form 1 and Form 2, but such
requirements are not written explicitly as “shall”, and are imbedded in the
Attachement whose mandatory status is unclear. This makes the standard very
confusing from an Responsible Entity’s obligation and compliance perspective.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
BC Hydro
No
BC Hydro agrees with the principles outlined in the Attachment A but has some
concerns as follows:
1.Attachment A is no longer recognized as one of the associated document of the
proposed Standard in its currently posted version. We believe this was removed by
mistake.
Consideration of Comments: Project 2007-12
35
003859
Organization
Yes or No
Question 4 Comment
2.There is no clarity as to how certain factors used in determining the Interconnection
FRO such as CCADJ, CBR and BC’ADJ were determined. There is no apparent provision
to re-assess any potential changes to these factors over the future years. If such
provision is needed or has been provided then consideration should be given to
averaging the adjustment over a longer duration (i.e., using the average of the factor
observed over a number of years rather than just the year being assessed).
3.The method used for the allocation of the Interconnection FRO to BAs seems to not
recognize the fact that frequency response from Load is much less than frequency
response from Generation of an equal MW size.
4.If this Attachment A is considered an integral part of the standard then there should
be some enforceable measures to ensure applicable entities adhering to the prescribed
time line.
Response:
(1) The drafting team disagrees that Attachment A is not one of the associated documents of the standard. It is included by
reference in Requirements R1 and R2 and will be attached to the standard upon final approval.
(2) If the data inputs change then the number will change but the methodology used to calculate the number cannot change
without going through the standards process.
(3) The drafting team agrees with your conclusion. The source of the Frequency Response is not related to the distribution of the
obligation.
(4) The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide uniformity
in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the requirements and
put procedural steps in the attachment and procedure.
Bonneville Power
Administration
No
BPA does not agree with the methodology in Attachment A. Please see BPA’s response
to question 6 as well as BPA’s extensive comments submitted on 12/8/11 for Project
2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Consideration of Comments: Project 2007-12
36
003860
Organization
Yes or No
Question 4 Comment
Response: Please refer to our response to Question #6 and our responses to your comments submitted on 12/8/11.
Exelon Corporation and its
affiliates
No
Exelon is troubled by the approach of having requirements that rely so heavily on the
attachment to the standard. The use of both of the documents is required to be
compliant and this makes it difficult to determine what the obligations are and
increases the chance for error in interpretation. The suggested changes below in
response to question 8 take information from the Attachment and establish
requirements so that an entity does not have to go back and forth between the two
documents to identify its obligations. Attachment A should then be modified to include
examples of Forms 1 and 2 and instructions for completing the form for Balancing
Authorities and Frequency Response Sharing Groups.
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
SERC OC Standards Review
Group
No
It is important for NERC to monitor the interaction between the deployment of this
standard and its impact on CPS1, CPS2, and BAAL. If performance in the CPS criteria is
degraded, there should be a halt in the reduction of the minimum bias setting allowed.
There is also concern that we are providing the correct incentives to the entities to
provide the appropriate amount of frequency response.
We also suggest that clarification be made so that changes in the BA’s footprint that
would necessitate changes in the bias setting or the FRO be permanent changes, not
just temporary.
It is unclear how performance would be measured for a BA versus a frequency
response sharing group.
Consideration of Comments: Project 2007-12
37
003861
Organization
Yes or No
Question 4 Comment
Response: The minimum is not required to be reduced but is allowed to be reduced if no significant impacts are seen on CPS1,
CPS2 and BAAL.
The drafting team agrees that temporary changes will not apply in this case. It is a problem that will take care of itself. If two BAs
change footprint but do not raise the issue the impact is transparent to the Interconnection. If one BA believes that its limits need
to be adjusted the process will adjust the limits of both BAs accordingly.
The Background Document and Attachment A explain how a FRSG would report. The FRS Forms allow BAs and RSGs to account
for contributions from either.
PPL NERC Registered
Affiliates
No
The NERC posting did not include a redline to Attachment A, therefore, it is not clear
what modifications were made. However, there are several modifications that would
add clarity to the attachment. The PPL Affiliates support the comments of the SERC OC
Standards Review Group on this question, additionally, the following issues should be
addressed:
In Attachment A, page 3 and elsewhere, clarify that temporary or small transfers of
load or generation between BAs do not require notification to the ERO or changes to
the FBS or CPS limits.
In Attachment A, page 4, a BA should be allowed to be exempt from evaluation any
single frequency event where non-conforming load performs contrary to the
performance of conventional load (ie. during a frequency decline, the non-conforming
load simultaneously increases significantly). By nature, non-conforming load is totally
unpredictable, changes quickly, and fluctuates widely. Other than interruption, the BA
has no control over the actions of such loads nor can the BA predict or assume any
“normal” action by a non-conforming load during a frequency disturbance event.
Setting a limit on the number of events that a BA could exempt (regardless of the
reason) from FR evaluation in any given year would be more fair and effective in
evaluating a BA’s frequency response performance.
Response: Please refer to our response to the SERC OC Standards Review Group.
Consideration of Comments: Project 2007-12
38
003862
Organization
Yes or No
Question 4 Comment
The drafting team does not agree that there should be an exemption but has designed the forms to allow for adjustments for nonconforming load. However the BA may find that no adjustment for non-conforming load may be needed due to the measurement
over multiple events rather than individual events.
Kansas City Power & Light
No
The Standard proposes a calculation that overstates the frequency response obligation
(FRO) for Balancing Authorities.
Response: The drafting team disagrees with your comment. However, the drafting team cannot provide any detail due to the lack
of details in your comment.
Arizona Public Service
Company
No
The supporting document on the standards page does not provide information on CB
Ratio and why it is used. It significantly increases FRO and should be justified based
upon strong technical basis and actual experience. (Please also see AZPS response to
question 6, The Frequency Response Initiative Report should be on the Standards
page).
Response: The rationale can be found beginning on page 14 of the Background document and page 49 of the FRI report.
Please refer to our response for Question #6.
PJM Interconnection, LLC
No
The target contingency protection criterion for the Eastern Interconnection is the
largest event in the last 10 years (believed to be a 2007 event) which is inconsistent
with the other Interconnections. Is periodic review required for this criteria?
Will this criteria be revised after the referenced event is older than 10 years?
Are the other three interconnection’s target contingency protection criteria subject to
revision if they experience an event larger than a category C?
This BA believes that future periodic analysis should be defined and subsequent
findings used to support changes via the standard revision process. What are the
procedural requirements for revising Attachment A?
This BA is concerned that the procedure for revising Attachment A is undefined and
Consideration of Comments: Project 2007-12
39
003863
Organization
Yes or No
Question 4 Comment
that, for example, the IFRO could be increased absent the formal standard revision
process, increasing a BA’s FRO and subsequently increasing a BA’s compliance risk
without providing BA’s the opportunity to review, comment, and ballot.Related to the
previous comment/question, how often are the statistically derived values in Table 1
subject to a required update? For example, the Eastern Interconnection is adjusted due
to observed primary frequency response withdrawal (‘lazy L’ characteristic). The other
Interconnections are adjusted for observed differences between point C and point B.
As the frequency response characteristics of any Interconnection change, is Table 1
subject to required analysis and revision? This BA believes that future periodic analysis
should be defined and subsequent findings used to support changes via the standard
revision process.
Attachment A indicates that a BA may exclude an event from annual Form 1 FRM
evaluation only if its tie-line or frequency data is corrupt or unavailable. This exempts
numerous scenarios that could result in a poor response score due to system
variations. These could include, but are not limited to, changing energy schedules,
changes in load, and AGC driving units up or down due to the ACE value at the time of
the frequency event. This subjects the BA to undue compliance risk even though the BA
may have adequate frequency responsive resources at the time. This BA suggests that
the FRSDT adopt language (and Form 2 functionality) that allows the exclusion of
events that are skewed by these types of situations.
Attachment A and Forms 1 & 2 specify that 20 to 52 seconds will be used as the postevent B point average for FRM determination. The number of fast responding
resources will increase as the technology for batteries, flywheels, and frequency
controlled demand side devices moves forward over time. The 20 to 52 second interval
does not adequately incentivize the devopment of these technologies.
Response: The results for the current Eastern Interconnection model do not represent observed response adequately. The
models for the other Interconnections have a better match. For this reason, the drafting team has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details
Consideration of Comments: Project 2007-12
40
003864
Organization
Yes or No
Question 4 Comment
are provided on pages 52 through 55 of the Frequency Response Initiative paper.
As the model for the EI is improved and information and experience is gained under this standard the answer to your question will
be determined through an open and inclusive process.
If it is determined that a change in any methodology used in the processes in this standard is needed it would have to go through
the standards process.
The drafting team does not agree that there should be an exemption but has designed the forms to allow for certain adjustments.
In addition, the methodology recommended utilizing the median addresses the concerns related to a single event occurrence.
Ultimately the BA may find that no adjustment may be needed due to the measurement over multiple events rather than
individual events.
This standard was not intended to provide incentives for the development of new technologies. It is intended to provide for the
reliable operation of the Bulk Electric System.
Northeast Power
Coordinating Council
No
This document lacks definitions of terms such as CCadj, DFcc, DFcbr, resource
contingency criteria (in the attachment, this is called the “target contingency criteria”),
etc. A sample calculation would be of value to entities. “The largest category C (N-2)
event is used for all interconnections except the Eastern which uses the largest event in
the last 10 years”. All interconnections should be using the same design basis
contingency. The NERC 2012 CPS2 bounds has an Eastern Interconnection frequency
bias of -6,360 MW/.1Hz. Why does this attachment refer to an Interconnection
frequency response obligation of -1,002MW/.1Hz.? This is a significant difference.
Response: As stated in Attachment A these terms are defined in the Procedure. The drafting team clarified the use of multiple
terms of “resource contingency criteria” throughout both Attachment A and the Procedure documents.
The drafting team will provide a sample calculation of the BA FRO and FRM and post this information on the NERC RS website.
The calculation of the IFRO is shown in the Attachment A with the formulas shown in the Procedure document.
The results for the current Eastern Interconnection model do not represent observed response adequately. The models for the
other Interconnections have a better match. For this reason, the drafting team has recommended the largest event in the last ten
years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on pages
Consideration of Comments: Project 2007-12
41
003865
Organization
Yes or No
Question 4 Comment
52 through 55 of the Frequency Response Initiative paper.
The -6,630 MW/0.1 Hz represents a summation of the Frequency Bias Settings of all Balancing Authorities in the Eastern
Interconnection, most of which use the 1% default minimum as required in the current BAL-003-0 standard, which far exceeds
their real response. The IFRO of -1002 MW/0.1 Hz is the response determined to avoid the first step of Underfrequency load
shedding in the Interconnection for a 4,500 MW generation loss.
Ameren
No
We disagree on having different methodologies for determining the targets, and would
like clarity added for when those targets may change, such as what will happen after
the largestest event in the last 10 years rolls off the books for the EI?
Response: The results for the current Eastern Interconnection model do not represent observed response adequately. The
models for the other Interconnections have a better match. For this reason, the drafting team has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details
are provided on pages 52 through 55 of the Frequency Response Initiative paper.
If it is determined that a change in any methodology used in the processes in this standard is needed it would have to go through
the standards process.
As the model for the EI is improved and information and experience is gained under this standard the answer to your question will
be determined through an open and inclusive process.
Manitoba Hydro
Yes
(1) Page 2, Balancing Authority Frequency Response Obligation (FRO) and Frequency
Bias Setting: States that the ERO is responsible for “annually assigning an FRO and
Frequency Bias Setting to each BA.” No mention is made of FRSGs.
(2) Neither R1 nor the referenced Attachment A clarifies the FRM requirements for an
FRSG to comply versus a BA. In particular, compared to BAL-002-0 R1.1, which clearly
states that the BA may elect to fulfill its obligation through an FRSG and that in such
cases the FRSG has the same responsibilities as each BA (that is a participant in the
FRSG).
(3)Attachment A refers to an FRSG calculating FRM, but the standard does not.
Consideration of Comments: Project 2007-12
42
003866
Organization
Yes or No
Question 4 Comment
Response: 1) - The FRSG FRO is a summation of its members’ FROs.
2) & 3) -The drafting team believes that it is clearly stated for a FRSG compliance with R1. The Requirement reads “Each
Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a member of a FRSG shall achieve an annual
Frequency Response Measure (FRM) (as calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided by each FRSG or
BA that is not a member of a FRSG to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation.”
Texas Reliability Entity
Yes
1. The calculation for the FRO for ERCOT includes a credit of 1400 MW for load
resources. 1400 MW is currently the maximum amount of LR that can be procured
through the ERCOT ancillary service process. There can be periods during the day
where 1400 MW was not procured or is not available (It was noted during the summer
of 2012 that on some days, only 900 MW of LR was available through the ancillary
service process). Should the calculated IFRO (-286 MW per 0.1 Hz) be modified to
account for this variation?
2. Background Document says: “Attachment A proposes the following Interconnection
event criteria as a basis to determine an Interconnection’s Frequency Response
Obligation: o Largest category C loss-of-resource (N-2) event o Largest total
generating plant with common voltage switchyard o Largest loss of generation in the
interconnection in the last 10 years” For ERCOT, the largest loss of generation in the
last 10 years was over 3400 MW, and does not match the 2750 MW (N-2) value used
for the IFRO calculation.
Response:
(1) The process used to determine the IFRO has been vetted through multiple forums. The drafting team feels that the proposed
calculation is appropriate for the standard at this time. As experience is gained through the implementation of this standard,
the calculation will be reviewed and any adjustments will be addressed through an open and inclusive process.
(2) The results for the current Texas Interconnection model represent observed response adequately so the recommended
Resource Contingency Criteria for ERCOT is the Category C N-2 event. For further details related to the full determination,
Consideration of Comments: Project 2007-12
43
003867
Organization
Yes or No
Question 4 Comment
please refer to the Frequency Response Initiative paper.
SPP Standards REview
Group
Yes
Delete the 2nd ‘that’ in the 2nd bullet at the top of page 3.
Response: Thank you for the comment. The drafting team has made the correction.
Xcel Energy
Yes
It is not clear however, as to if this is actually part of the standard or if it is a document
that can be revised without going through the standards development process.
Also, the formatting of the document should be modified to clearly identify where
'steps/actions' are needed from responsible parties, whether that be the ERO or
BA/FRSG.
Response: If it is determined that a change in any methodology used in the processes in this standard is needed it would have to
go through the standards process.
Please refer to the “timeline” on page #6 of Attachment A as this clearly provides for who has responsibility for each step in the
process.
NextEra Energy
Yes
NextEra Energy does not support the changes made. It is concerned that certian
changes were made to help some large East coast entities that could not comply at the
expense of the FRCC region. Specifically, now on page 3 of Attachment A 4th
paragraph from the bottom the statement is made “ sets its frequency bias to the
greater of”. We believe that this must be changed to either Statement 1 “ Any number
the BA chooses between 100% etc”Or Statement 2 “ Interconnection minimum as
determined by the ERO” Without this change, NextEra beleives the FRCC will be
unfiarly treated relative to others on the Eastern Interconnection. The technical
reasons for this is concern was explained during the Standard Drafting Team meetings.
In addition, the ERO limit which is set at 0.9% of load should be changed to read within
0.8 or 0.9% of peak load based on the BA’s choice.
Also, see page 7 of the Procedure document and compare to page 1 of Attachment A.
Consideration of Comments: Project 2007-12
44
003868
Organization
Yes or No
Question 4 Comment
The formulae abbreviations for the variables in the Procedure are not likewise
abbreviated in Attachment A. For example, “Credit for LR” on Attachment A is “CLR” in
the Procedure, but it requires cross checking each document to figure this out. Or CBr
in Attachment A, Table 1 is represented as DFCBR in the Procedure, Page 7. Since the
same variables are being described, these should be represented the same way in both
documents throughout.
2. Similarly, is “IFRO” in Table 1 of Attachment A the same as “FROInt” of the equation
that follows on page 2? The same abbreviation should be used to represent this
variable. The documents should be revised in general along these lines for all terms.
3. In Procedure document, page 5, paragraph 3 it should read “Table 2”, not “1”.
4. In the Procedure, it would be good to show Table 1 and Table 2 as Table 1 of
Attachment A (i.e. use table lines and borders).
5. At least in the first usage, ERO in the Procedure document should be spelled out as
“Electric Reliability Organization (ERO)”.
6. In Table 1 of Attachment A, the two footnotes preceded by asterisks (single and
double on page 2) should be connected to the table by adding a single superscripted
asterisk to the Eastern UFLS value of 59.5, and a double superscripted asterisk to the
ERCOT LR value of 1,400.
Response:
(1) The drafting team does not believe any BAs were favored over other BAs. However the drafting team is unclear as to your
expressed concerns related to FRCC. In direct communications with FRCC they concluded that the IFRO starting frequency of
the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS operation in FRCC
for an external resource loss event than for an internal FRCC event.
The drafting team does not agree with the recommended wording change for the bias setting because it would essentially
remove the Interconnection minimum FBS. The drafting team does not agree that we are mixing terms between the
Procedure and Attachment A. The drafting team uses CBR and DFCBR in both documents defining two different variables. The
drafting team clarified CLR.
Consideration of Comments: Project 2007-12
45
003869
Organization
Yes or No
Question 4 Comment
(2) The drafting team clarified IFRO/FRO in the documents.
(3) Thank you. The drafting team has corrected this in the document.
(4) The drafting team thanks you for your comment. However, the majority of the industry does not support your suggested
modification. Therefore, the drafting team will leave the tables as shown.
(5) The drafting team changed ERO to Electric Reliability Organization as per your suggestion.
(6) Thank you. The drafting team has made the changes.
NREL Transmission and Grid
Integration Group
Yes
Table 1: CB_r units should be unitless, CB'adj should be Hz.
Response: Thank you for the comment. The drafting team has made these changes.
NV Energy
Yes
This document is improved, and satisfactorily addresses comments from the prior
posting.
Response: Thank you for the comment.
New York Independent
System Operator
Yes
With a new process we are concerned that the interconnection minimum will initially
move from 1.0% to 0.9%.
Response: Thank you for your comment. The new process moves the minimum from 1.0% to 0.9%.
MRO NSRF
Yes
Edison Electric Institute
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Consideration of Comments: Project 2007-12
46
003870
Organization
Yes or No
Energy Mark, Inc.
Yes
Tacoma Power
Yes
Southern Company
Yes
Idaho Power Company
Yes
Tucson Electric Power
Yes
Keen Resources Asia Ltd.
Yes
MISO
Yes
Puget Sound Energy
Question 4 Comment
In reviewing the Consideration of Comments document, it is clear that the standard
drafting team does not wish for the administrative elements of Attachment A to
become items addressed during compliance evaluations (“There is no intent to require
filing on a certain date and to have the BA prove to the auditor that a filing was made
on that date.” This quote appears at several places in the Consideration of Comments
documents, but first at page 113). However, because Attachment A is referenced in
the standard, its provisions, including the timing table, are all mandatory and
enforceable. This result is emphasized by the language of requirement R1, which states
that entities “...shall achieve an annual Frequency Response Measure (FRM) as
calculated and reported in accordance with Attachment A....” This language means
that a failure to file a document on a date specified in the attachment would be a
potential compliance violation. Because Attachment A is mandatory and enforceable,
the standard drafting team should carefully review its provisions and clarify which
elements are requirements and which elements are background statements or
guidance. In addition, the use of additional headings and section numbers would add
in clarifying the document (for example, at the top of page 3, there is a discussion of
how an FRSG would calculate its FRM; however, there is an entire section beginning on
Consideration of Comments: Project 2007-12
47
003871
Organization
Yes or No
Question 4 Comment
page 4 addressing FRM where that discussion should instead appear).
Response: The requirement stated in the standard is the only requirement related to FRM. Attachment A is there to provide
uniformity in the calculation of the FRM. The drafting team conscientiously included only reliability objectives in the
requirements and put procedural steps in the attachment and procedure.
Consideration of Comments: Project 2007-12
48
003872
5.
The SDT has moved a portion of the material located in Attachment A and all of the material located in ”Attachment B- Process
for Adjusting Bias Setting Floor” into a new document “Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard”. The SDT created this document to assign tasks to the ERO and provide instructions for the ERO to follow
when carrying them out under the BAL-003-1 standard. Do you agree that the ERO should perform these tasks and that this
document provides sufficient detail for the ERO to do it under the BAL-003-1 standard? If not, what needs to be added to the
document?”.
Summary Consideration: Several commenters requested clarity on how modifications to the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard would be made. The drafting team explained that the
“Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard” was not incorporated into
the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure will not be developed
through the standard development process. Consistent with NERC’s commitment to an open and transparent process,
the procedure for modifying the event selection process for supporting the Frequency Response Standard is set forth in
the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and
will discuss the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in
addition, any modifications will be filed with FERC for informational purposes. This process provides the industry
assurance that changes will be properly vetted and that there is an opportunity for stakeholder input.
A couple of commenters questioned how events would be excluded, specifically with regards to during ramping periods. The drafting
team stated that all events are considered. Events that occur over known ramping periods are selected last. As an
example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used.
The benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
A few commenters did not understand why the frequency criteria are different for each Interconnection. The drafting team
explained that the frequency criteria was different for each interconnection because the frequency used to measure
frequency response is interconnection dependent and varies differently for each interconnection. Larger
interconnections have greater frequency response and as a consequence smaller frequency deviations for events of
the size typically experienced.
One or two commenters questioned whether certain events should always be included in the evaluation process. The drafting team
stated that based on event evaluation by this drafting team, it has been determined that it is impossible to require
certain events to be included. This is the reason that the drafting team has developed the Event Selection Criteria.
Consideration of Comments: Project 2007-12
49
003873
Organization
Yes or No
Keen Resources Asia Ltd.
No
Question 5 Comment
As a professionally trained published statistical expert never compensated by any
balloting participant, I consider event selection criterion 7 to be unacceptable because
it violates the fundamental statistical procedure of sampling statistical data "as is" and
not pre-selecting the data (to fit some preferred even-distribution over time) and
therefore biasing it before applying any statistical procedure to the data. Event
criterion 6 is also unacceptable for being an an "ad hoc" explicit exclusion, from the
definition of the frequency response being measured, of response to frequency events
that occur during a specific kind of scheduled generation and load changes. Said
exclusion needs to be written into the definition of the Frequency Response that is
being measured. It is procedurally improper and unacceptable to bias the sampling
procedure by explicit exclusion of data as an alternative to redefining the thing being
sampled. In that case it's not generic Frequency Response that is being sampled, but
some specific Frequency-Response-less-Response-to-Excluded-Events that is being
measured. It is non-transparent and subterfuge to avoid instead accordingy
reworking/narrowing the definition of Frequency Response, especially as said
reworking requires a clear technical justification that is absent from this standard, and
modifying the existing NERC Glossary definition of Frequency Response which Criterion
6 therefore stands in flat violation of.
Response: Criterion 7 is included in the Event Selection Criteria because the drafting team considers it very important to be able
to select and finalize events for analysis quarterly so that the BAs can evaluate their performance as the measurement year
unfolds. This necessarily requires minimal criteria to insure that this selection and finalization process can be completed
quarterly. The drafting team recognizes that this finalization may have some effect on the sampling, but values the quarterly
selection and finalization more than the pure statistical sampling theory. This is a trade-off that the drafting team has chosen to
make. Once several years of a regular disparity between seasons of the year were established in terms of number of events in a
season, the industry could propose modifying the Standard at that time to adjust Criterion 7 accordingly.
Criterion 6 is included because historic data indicate that the periods within 5 minutes of the top of the hour have shown to have
Consideration of Comments: Project 2007-12
50
003874
Organization
Yes or No
Question 5 Comment
higher frequency variability than other periods in the hour. Statistical analysis presented in the FRI Report indicates that predisturbance frequency is a significant contributor to the variability of frequency response. The drafting team has chosen to allow
the exclusion of events close to the top of the hour when other acceptable events are available until analysis is done of whether
these periods have a statistically different frequency response and therefore introduce bias. Meanwhile, as Balancing Authorities
are moving toward quarter-hourly scheduling, the higher top-of-the-hour frequency variability prompting the need and
application of Criterion 6 is expected to disappear. Therefore, while your recommended alternative of changing the NERC
definition of Frequency Response may be statistically correct, from a practical perspective it would likely prove to be a needless
chore and to yield a needlessly complicated definition only to have to be changed back again.
Southern Company
No
Attachment A states that Form 1 is posted annually. The ERO support document selects
events annually. The timing for the two documents needs to be aligned so that the set
of selected events does not change from quarter to quarter. (If three events are
selected for the first quarter those same events will be a sub-set of the 20 events
selected for the annual compliance calculations.)
Response: Attachment A indicates that Form 1 with the events from the previous quarter is posted on May 10th, August 10th,
November 10th and the second business day in February. It is the intent of the standard that events once posted will be included
in the FRM analysis.
BC Hydro
No
BC Hydro agrees in principle that the ERO should perform these tasks related to BAL003-1 but has the following concerns:
1. There is no clear indication whether the Interconnection FRO will be calculated every
year, and if yes, how each of the factors involved will be determined.
2. It is not clear whether data gathered in these procedures are only for the
determination of annual FRO and FBS, or also to determine whether the BA or the FRSG
was in compliance to BAL-003-1 for the assessed year. Since the ERO in this Document
seems to be the NERC Resources Subcommittee and its Frequency Work Group, we
think this fact should be made clear. The Background document should also be
reviewed to ensure its alignment in this regard.
Consideration of Comments: Project 2007-12
51
003875
Organization
Yes or No
Question 5 Comment
Response: The drafting team has chosen to use the methods presented in the FRI Report to determine the values presented in
Table 1 of Attachment A to determine the Interconnection FRO. If the method of calculation by the ERO or the base starting
values used to determine the IFRO change (i.e. Resource Contingency Criteria or Prevailing UFLS First Step), then those changes
will be subject to the standards process to accept those changes. If the statistical determinates used in the method change (i.e.
Starting Frequency, CCADJ, CBR, BC’ADJ, and Credit for LR) or the data used to allocate the IFRO among the BAs (i.e. FERC Form 714
data) changes, the new values will be implemented without being subject to the standards process.
The data gathered for the FRO calculation is not compliance related. The calculation of FBS is also not compliance related.
However, assuming the information is entered into FRS Form 1 correctly then the FBS number will be used by an auditor to
determine compliance with Requirement R2.
The drafting team has been instructed by NERC to refer to all NERC entities (i.e. Frequency Working Group, Resources
Subcommittee, etc) as the ERO.
Bonneville Power
Administration
No
BPA does not agree with the methodologies outlined in Attachment B. Please see
BPA’s response to question 6 as well as BPA’s extensive comments submitted on
12/8/11 for Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf
Response: Please refer to our response to your comment for Question #6 and our responses to your comments dated 12/8/11.
Kansas City Power & Light
No
Criteria 3 - Why are frequency thresholds different between regions when generator
governor reaction is supposed to be the same between regions?
Criteria 5 - What is the reasoning that multiple events that are not stabilized within 18
seconds not being considered?
Criteria 6 - How are "changes in scheduled interchange" or load change determined in
regions with interconnections with multiple BAs with different time zones?
Response: The frequency criteria is different for each interconnection because the frequency used to measure frequency response
is interconnection dependent and varies differently for each interconnection. Larger interconnections have greater frequency
response and as a consequence smaller frequency deviations for events of the size typically experienced.
Consideration of Comments: Project 2007-12
52
003876
Organization
Yes or No
Question 5 Comment
The standardized method used to measure frequency response will not work correctly for events that have not stabilized within
18 seconds.
This determination will be made by the ERO (presently the Frequency Working Group).
All events are considered. Events that occur over known ramping periods are selected last. As an example, the event reflected in
the right graph shown in the Procedure would be selected over the event reflected in the graph on the left. If an inadequate
number of events are available for that season, then these events may be used. The benefit of using the median of at least 20
events in a year helps minimize the impact of outliers.
Duke Energy
No
Duke Energy agrees with allowing the ERO to perform this function, however the
industry needs some assurance that this Procedure cannot be changed outside of the
Standards Process for approval by the industry. In the sixth line of the third paragraph
on page 5, the statement should reference Table 2. Page 5 reads as if the BAs will
submit their data based upon Form 1 which includes an adjustment to the
Interconnection peak load (initially 0.9), and then the ERO will determine whether the
Interconnection minimum FBS is still more than 20% above the measured response - if
so, the minimum FBS will be adjusted, requiring the BAs to reassess their new
minimum FBS based upon a different factor, and decide whether to use that value or
choose a value up to 125% of their FRM, resulting in another iteration of values being
submitted to the ERO. If the ERO is going to do an independent assessment of
Interconnection Frequency Response to the events, on an annual basis prior to
gathering data from the BAs, the ERO could compare the total FBS being used by the
BAs against the estimated Frequency Response over that period to determine if an
adjustment is warranted, and then the ERO could include the appropriate adjustment
factor (0.9, 0.8, etc..) in Form 1 for the BAs to use. If the ERO is not going to estimate
the Frequency Response aside from the BAs, multiple iterations will be likely. Duke
Energy suggests the following language to cover the point above: “On an annual basis,
the ERO will review the Interconnection total minimum Frequency Bias Setting for the
prior period and compare it against the Interconnection’s total natural Frequency
Response determined for that period. If an Interconnection’s total minimum
Frequency Bias Setting exceeds (in absolute value) the Interconnection’s total natural
Consideration of Comments: Project 2007-12
53
003877
Organization
Yes or No
Question 5 Comment
Frequency Response by more (in absolute value) than 0.2 percentage points of the
Interconnection non-coincident peak load (expressed in MW/0.1Hz), the minimum
Frequency Bias Setting for BAs within that Interconnection may be reduced (in absolute
value) based on the technical evaluation and consultation with the regions affected by
0.1 percentage point of Interconnection non-coincident peak load (expressed in
MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency
Response. The ERO will include the adjustment factor in the Interconnection Form 1
used by the Balancing Authorities for the calculation of the new minimum Frequency
Bias Setting. The Form 1 information from the Balancing Authorities will be gathered
by the ERO in coordination with the regions of each Interconnection to determine the
final Interconnection Frequency Bias Setting for the next period.”
Response: The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard” is not incorporated into
the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure will not be developed through the
standard development process. Consistent with NERC’s commitment to an open and transparent process, the procedure for
modifying the event selection process for supporting the Frequency Response Standard is set forth in the opening paragraph of
the Procedure for ERO Support of Frequency Response and Frequency Bias Setting document. NERC will post suggested
modifications for a 45-day formal comment period, respond to all comments and will discuss the revision request in a public
meeting. Revisions will be provided to the NERC BOT for approval and in addition, any modifications will be filed with FERC for
informational purposes. This process provides the industry assurance that changes will be properly vetted and that there is an
opportunity for stakeholder input.
The reference has been changed from Table 1 to Table 2. Thank you for your comment.
The review of the information provided by the BAs discussed in the Procedure document will take a significant amount of time.
Therefore, the change to the Interconnection Minimum Frequency Bias Setting will occur on the subsequent year’s Form 1. This
will eliminate the risk of multiple iterations and allow sufficient time for the ERO to consult with the regions as indicated in the
Procedure. The drafting team has included clarifying language in the document.
Tucson Electric Power
No
I think it should be more clear or better defined that an interconnection does have
some input into what events are selected.
Consideration of Comments: Project 2007-12
54
003878
Organization
Yes or No
Question 5 Comment
Response: Thank you for your comment. Each interconnection has a representative on the Frequency Working Group that
performs the selection of events.
Exelon Corporation and its
affiliates
No
Please see response to question 8.
Response: Thank you for your comment. Please see response to Question 8.
PJM Interconnection, LLC
No
The Procedure indicates that events that occur when ‘large interchange schedule
ramping or load change is happening’ and ‘events occurring within 5 minutes of the top
of the hour’ should be excluded from consideration. Since interchange schedule
ramping and load change occurs at the BA level, this BA believes that the Procedure
allows for the selection of events that occur when a BA is experiencing these conditions
but Attachment A does not allow for exemption of these events. Also, the Procedure
specifies that events that occur at the top of the hour be excluded, if other qualifying
events exist, but this does not take into consideration energy markets that allow for
sub-hourly schedule changes (e.g. 15 minutes) and the BA is not permitted to exempt
these events on Form 1 subjecting the BA to undue compliance risks.
Response: Thank you for your comment. All events are considered. Events that occur over known ramping periods are selected
last. As an example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used. The
benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
Texas Reliability Entity
Yes
1. Event Selection Criteria Item 2: Should certain events require mandatory inclusion
for FRM calculation (i.e. DCS events)?
2. Event Selection Criteria Item 6: We disagree with the way this is worded. If a unit
trips during this time, as it often can, measured frequency response needs to occur.
We understand that the results are impacted by the grid condition and perhaps that is
why the SDT decided to exclude the issue. Need to define what is intended by a “large”
Consideration of Comments: Project 2007-12
55
003879
Organization
Yes or No
Question 5 Comment
interchange ramp schedule or load change. May also want to consider changing the
language from “will be excluded from consideration” to “MAY be excluded from
consideration”.
Response: Thank you for your comment. Based on event evaluation by this drafting team, it has been determined that it is
impossible to require certain events to be included. This is the reason that the drafting team has developed the Event Selection
Criteria.
The drafting team wrote the criteria to allow flexibility for any change that significantly impacts frequency.
The drafting team looked at the language and determined that the present language provides greater clarity. The “will be
excluded” is followed by “…if other acceptable frequency excursion events from the same quarter are available.” Therefore, it is
not a mandatory exclusion.
Edison Electric Institute
Yes
EEI supports the ERO’s role as defined in the procedure but is concerned that the
procedure, unlike approved NERC standards, is unbounded by the current rules for
developing standards. For that reason, EEI recommends that the procedure become
more formalized and integrated into the standard as an addendum thereby avoiding
any Industry concerns that future modification might occur outside the approved
processes
Response: Thank you for your comment. The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard” is not incorporated into the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure
will not be developed through the standard development process. Consistent with NERC’s commitment to an open and
transparent process, the procedure for modifying the event selection process for supporting the Frequency Response Standard is
set forth in the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and will discuss
the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in addition, any
modifications will be filed with FERC for informational purposes. This process provides the industry assurance that changes will be
properly vetted and that there is an opportunity for stakeholder input.
ACES Power Marketing
Yes
Overall, we agree. However, we suggest the document clarify that the ERO shall
Consideration of Comments: Project 2007-12
56
003880
Organization
Yes or No
Standards Collaborators
Question 5 Comment
perform these tasks in coordination with the Resources Subcommittee. It consists of
industry experts that can be an extra resource to NERC. Furthermore, NERC staff
working with the Resources Subcommittee will provide additional transparency to the
process.
Response: Thank you for your comment. The drafting team has been instructed by NERC to refer to all NERC entities (i.e.
Frequency Working Group, Resources Subcommittee, etc) as the ERO.
MISO
Yes
The first hyperlink on page 3 of the Procedure for ERO Support does not work.
Response: Thank you for your comment. The drafting team has corrected this.
Xcel Energy
YES
It is not clear however, as to if this is actually part of the standard or if it is a document
that can be revised without going through the standards development process. Also,
the formatting of the doucment should be modified to clearly identify where
'steps/actions' are needed from repsonsible parties, whether that be the ERO or
BA/FRSG.
Response: Thank you for your comment. The “Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard” is not incorporated into the BAL-003 Frequency Response Reliability Standard. As such, modifications to the Procedure
will not be developed through the standard development process. Consistent with NERC’s commitment to an open and
transparent process, the procedure for modifying the event selection process for supporting the Frequency Response Standard is
set forth in the opening paragraph of the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
document. NERC will post suggested modifications for a 45-day formal comment period, respond to all comments and will discuss
the revision request in a public meeting. Revisions will be provided to the NERC BOT for approval and in addition, any
modifications will be filed with FERC for informational purposes. This process provides the industry assurance that changes will be
properly vetted and that there is an opportunity for stakeholder input.
Manitoba Hydro
Yes
NREL Transmission and Grid
Yes
No comment.
Consideration of Comments: Project 2007-12
57
003881
Organization
Yes or No
Question 5 Comment
Integration Group
SPP Standards REview
Group
Yes
pacificorp
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
NV Energy
Yes
New York Independent
System Operator
Yes
MRO NSRF
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
58
003882
6.
The SDT is now using the method detailed in the Frequency Response Initiative Report dated September 30, 2012 to calculate
the Interconnection Frequency Response Obligation. Do you agree that this method provides for the proper amount of
Frequency Response? If not, what specifically needs to be changed?
Summary Consideration: Many of the commenters requested clarification on how changes to the methodology defined in
Attachment A could be modified. The drafting team explained that Attachment A was part of the standard and as such
is subject to the NERC standards process for making any changes.
Several commenters questioned the use of the largest event in the last 10 years for the Eastern Interconnection. The drafting team
stated that the results for the current Eastern Interconnection model do not represent observed response adequately.
The models for the other Interconnections have a better match. For this reason the SDT has recommended the largest
event in the last ten years be used to provide for an increased reliability margin for the Eastern Interconnection. If the
largest event in the last 10 years falls below 4500 MW then the SDT believes that an N-2 event would be utilized.
One commenter wanted a method to discount outliers. The drafting team explained that this was one of the reasons that they had
chosen the median as the appropriate measure for FRM. The benefit of using the median of at least 20 events per year
helps to minimize the impact of outliers.
Organization
Yes or No
Bonneville Power
Administration
No
Question 6 Comment
BPA does not have specific changes to the methodology to suggest, however, a
methodology that arrives at a negative 840 MW per tenth Hz for WECC is obviously
under-calculating the frequency bias obligation. Currently WECC has an
interconnection bias of over 2000 MW / 0.1Hz and with this bias the frequency is
steady state following point B on the frequency response curve. BPA would expect to
see frequency decline after point B if the FBO is lowered by almost 60%. BPA also must
reiterate that there is still a problem with the method used for modifying the FBO and
frequency bias for Balancing Authorities. A high-performing Balancing Authority will
have its frequency bias increased each year due to higher response during the events
chosen by the ERO. Conversely, a low-performing Balancing Authority will have its
frequency bias reduced each year due to lower response during the events chosen by
Consideration of Comments: Project 2007-12
59
003883
Organization
Yes or No
Question 6 Comment
the ERO.
Response: After review of comments, the drafting team feels confident with the current method of calculating Frequency
Response Obligation as outlined in the Frequency Response Initiative report. This standard requires minimum bias setting not to
be less than 0.9% of the non-coincidental peak load for a multi-BA interconnection. This will ensure that minimum bias settings
will be based on Interconnection’s non-coincidental peak load rather than biased toward low-performer. The minimum Frequency
Bias settings requirement are outlined in Table 2 of “Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard”
The drafting team points out that there is not a Frequency Bias obligation and that the currently measured response for the
Western Interconnection is approximately -1200 MW/0.1 Hz. This number is above, but much closer to the required level of -840
MW/0.1 Hz under this standard.
Tucson Electric Power
No
I believe that the frequency bias obligation of the Western Interconnection is
understated.
Response: The drafting team points out that there is not a Frequency Bias obligation and that the currently measured response for
the Western Interconnection is approximately -1200 MW/0.1 Hz. This number is above, but much closer to the required level of 840 MW/0.1 Hz under this standard.
Duke Energy
No
Similar to our earlier concern, the industry needs some assurance that the calculation
of the Interconnection FRO described in the report cannot be changed outside of the
Standards Process for approval by the industry. Duke Energy does not support using a
4500 MW loss as the basis for determining the FRO for the Eastern Interconnection for
future events. However, as the calculation also includes 59.5 Hz as the basis for
determining the FRO, the result is an allocation which can be supported. To the extent
that the standard drafting team moves in the direction of using 59.7 Hz as the basis for
the FRO, then it needs to follow a methodology similar to the other Interconnections
for determining the credible multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
Consideration of Comments: Project 2007-12
60
003884
Organization
Yes or No
Question 6 Comment
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason the SDT has recommended the largest event in the last ten years be used to provide for an increased
reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the SDT
believes that an N-2 event would be utilized.
New York Independent
System Operator
No
The drafting team should consider some method for discounting outliers, that may not
be explainable.
Response: Thank you for your comment. All events are considered. Events that occur over known ramping periods are selected
last. As an example, the event reflected in the right graph shown in the Procedure would be selected over the event reflected in
the graph on the left. If an inadequate number of events are available for that season, then these events may be used. The
benefit of using the median of at least 20 events in a year helps minimize the impact of outliers.
Southern Company
No
The industry needs some assurance that the calculation of the Interconnection FRO
described in the report cannot be changed outside of the Standards Process for
approval by the industry. We do not support using a 4500 MW loss as the basis for
determining the FRO for the Eastern Interconnection for future events. However, as the
calculation also includes 59.5 Hz as the basis for determining the FRO, the result is an
allocation which can be supported. To the extent that the standard drafting team
moves in the direction of using 59.7 Hz as the basis for the FRO, then it needs to follow
a methodology similar to the other Interconnections for determining the credible
multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
Consideration of Comments: Project 2007-12
61
003885
Organization
Yes or No
Question 6 Comment
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
PPL NERC Registered
Affiliates
No
The PPL Affiliates support the comments of the SERC OC Standards Review Group on
this question
Response: The Attachment A is part of the standard and as such is subject to the NERC standards process for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
Keen Resources Asia Ltd.
No
This question is falsely worded. The SDT is specifically NOT using the method detailed
in the Frequency Response Initiative Report dated September 30, 2012. So the term
"this method" is practically meaningless in this question because it is not clear if it
means "the SDT's method" or "the FRI's method". The Background Document
specifically states on page 29: "The NERC Frequency Response Initiative Report
addressed the relative merits of using the median versus linear regression for
aggregating single event frequency response samples into a frequency response
measurement score for compliance evaluation. This report provided 11 evaluation
criteria as a basis for recommending the use of linear regression instead of the median
for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but
concluded that the median would be the best aggregation technique to use initially
when the relative importance of each criterion was considered." What needs to be
changed, besides properly wording this question? The FRI method of linear regression
should be adopted, and the SDT method of median should be rejected, in the standard
to change the first sentence of this question into a true statement from a false
statement and to, in answer to the question, provide for the proper amount of
Consideration of Comments: Project 2007-12
62
003886
Organization
Yes or No
Question 6 Comment
Frequency Response.
Response: Thank you for your comments. The drafting team disagrees that the methodology for calculating the IFRO used in this
standard is different than that detailed in the FRI Report. The drafting team considered replacing median with linear regression but
chose to use the median because of its better resiliency to data quality problems found in the Actual Net Interchange data used in
the frequency-response calculation.
SERC OC Standards Review
Group
No
We believe the industry needs some assurance that the calculation of the
interconnection FRO cannot be changed without rigorous review and input from the
industry. In addition the clarification should be made how the one in ten year loss for
the Eastern Interconnection (4500 MW) would change after 10 years. Would the same
methodology be used or would the largest Category C (n-2) be used?
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason, the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
Arizona Public Service
Company
NO
1. The Frequency Response initiative report should be added to the standard as an
appendix. It is not clear where to find this report.
2. The jusitification for dividing delta frequency with C to B ratio is not adequate and
not clear.
Response: Thank you for your comment. 1) The drafting team disagrees that the FRI Report should be attached to this standard
as an appendix. We do agree that it should be easier to locate.
2) Please refer to the FRI Report for the reasoning you request.
Edison Electric Institute
Yes
EEI finds the method to be acceptable but as mentioned in our response to question
Consideration of Comments: Project 2007-12
63
003887
Organization
Yes or No
Question 6 Comment
No. 5 (above), we believe that the procedure should be more formally documented as
an addendum. Such a change would ensure that the document would remain
unchanged outside of the approved standards making process. Additionally, EEI does
not support using 4500 MW loss as the basis for determining the FRO for the Eastern
Interconnection for future events. However, as the calculation also includes 59.5 Hz as
the basis for determining the FRO, the results is an allocation which we believe is
acceptable. In the future, should the SDT decide to use 59.7 Hz as the basis for the
FRO, than it will need to follow a methodology similar to the other interconnections for
determining the credible multiple contingency to cover.
Response: Thank you for your comment. The Attachment A is part of the standard and as such is subject to the NERC standards
process manual for making any changes.
The drafting team agrees with your concern regarding the use of 4500 MW. However, the results for the current Eastern
Interconnection model do not represent observed response adequately. The models for the other Interconnections have a better
match. For this reason the drafting team has recommended the largest event in the last ten years be used to provide for an
increased reliability margin for the Eastern Interconnection. If the largest event in the last 10 years falls below 4500 MW then the
SDT believes that an N-2 event would be utilized.
ACES Power Marketing
Standards Collaborators
Yes
We agree that this method will provide sufficient frequency response. However, we
believe Interconnection Frequency Response Obligation is used inconsistentently with
the definition of Frequency Response Obligation as documented in our response to
other comments.
Response: Please refer to our responses to your other comments.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
SPP Standards REview
Yes
No comment.
Consideration of Comments: Project 2007-12
64
003888
Organization
Yes or No
Question 6 Comment
Group
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
Idaho Power Company
Yes
Independent Electricity
System Operator
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
MISO
Yes
MRO NSRF
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
65
003889
7.
Based on Industry comments received the SDT made significant clarifying modifications to the Background Document. Do you
agree that this document provides sufficient information to justify the rationale used by the SDT in developing the draft
standard and provides the industry with sufficient understanding of the issues being addressed by the standard?
Summary Consideration: Several of the commenters questioned why the formula for FRO was missing. The drafting team explained
that this was a problem incurred during the conversion to a pdf file. Once the problem was recognized by NERC, it was
immediately fixed during the posting.
A couple of commenters felt that there should be discussion in the Background Document concerning “inertial response”. The
drafting team stated that they saw a limited role for inertial response in the context of this standard. The standard
inherently does not address inertial requirements. It is of interest herein because of its role in determining the postcontingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency nadir
(point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
A few of the commenters questioned the use of the largest event in the last 10 years as the criteria for the Eastern Interconnection.
The drafting team explained that the results for the current Eastern Interconnection model do not represent observed
response adequately. The models for the other Interconnections have a better match. For this reason the drafting
team has recommended the largest event in the last ten years be used to provide for an increased reliability margin for
the Eastern Interconnection. Further details are provided on pages 52 through 55 of the Frequency Response Initiative
paper.
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 7 Comment
(1) The formula for calculating Frequency Response Obligation appears to be missing
on page 23.
(2) We are confused by the varying sample rates for the different scan rates in the
Definitions of Frequency Values for Frequency Response Calculation table on page 13.
It would appear that the time range of values for the average B value varies more than
necessary by scan rate. For example, for 2-second scan rates, sampling would start at
20 seconds and end at 52 seconds. However, for the 4-second scan rates, sampling
Consideration of Comments: Project 2007-12
66
003890
Organization
Yes or No
Question 7 Comment
starts at 24 seconds and ends at 48 seconds. Why would it not also cover 20 and 52
seconds for a 4-second scan rate?
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The SDT has corrected the table.
Bonneville Power
Administration
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is
developing into. Please reference BPA’s extensive comments submitted on 12/8/11 for
Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Response: Thank you for your comment. Please refer to our response to your comments dated 12/8/11.
Keen Resources Asia Ltd.
No
See reply to Question 6. Also, the Background Document is seriously deficient in the
discussion of inertial response and therefore how imbalances "cause" frequency
deviation. The Background Document is overflowing in discussion of how frequency
deviation causes frequency response. In other words, the Background Document is
"reactive" and not "proactive". The Background Document lacks any discussion of the
internal dynamics of rotating machines, beginning with any definition of what Inertial
Response is. Inertial Response is the instantaneous power produced by the lag
("inertia") in the ability of the generator's rotor to slow down to the frequency of the
magnetic field in the generator's fixed stator whose frequency is instantaneously
lowered by a change in phase angle between voltage and current that is due to a
sudden loss of interconnected generation to meet load. Adjustments by voltage
response within milliseconds and near the location of the loss are sometimes possible
to avert rapid spread of a loss to the frequency of the entire interconnection, and
constitute the ongoing work of the Phasor Project long ago initiated by the DOE in the
persistent absence of NERC interest or work in this area. NERC and drafting team
members under advisement by NERC staff studiously resisted so much as any mention
of frequency deviation causation in discussions or in the Background Document. An
Consideration of Comments: Project 2007-12
67
003891
Organization
Yes or No
Question 7 Comment
inexplicable technical Cold War and Berlin Wall built in the 1970s and today separating
the DOE Phasor Project from NERC Frequency Response standard development and
NERC's so-called Frequency Response "Initiative" needs to be ended and torn down.
My document http://www.robertblohm.com/Inertia.doc provides missing technical
support and explanation for graphs 1-7 on pages 4-10 of the Background Document, on
the basis of an exact understanding of Inertial Response.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Northeast Power
Coordinating Council
No
While the discussion of primary frequency response includes inertial energy, the term
inertial energy is missing from the definition of “primary frequency response”.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Consolidated Edison Co. of
NY, Inc.
No
While the discussion of primary frequency response includes inertial energy, the term
inertial energy is missing from the definition of “primary frequency response”.
Response: Thank you for your comment. The drafting team sees a limited role for inertial response in the context of this
standard. The standard inherently does not address inertial requirements. It is of interest herein because of its role in
determining the post-contingency rate of decline of frequency, as it ultimately impacts the duration of time before the frequency
nadir (point C) occurs. The drafting team considered a more elaborate description of inertial response, but believes that it is
tangential to the main mission of this standard.
Consideration of Comments: Project 2007-12
68
003892
Organization
Yes or No
PPL NERC Registered
Affiliates
Yes
Question 7 Comment
The PPL Affiliates applaud the SDT for developing this technical justification document.
Response: Thank you for your comment.
Duke Energy
Yes
Though Duke Energy does not agree with some of the points in the Background
Document, it does justify the rationale used by the SDT. Additional comments: at the
top of page 23, it states that the basic Frequency Response Obligation is based on noncoincident peak load and generation data reported in FERC Form 714, however the
actual calculation is missing and should be based upon the reported MWh, not the
peak load as stated. At the bottom of page 23, it states that Attachment A proposes
the three options for event criteria, however doesn’t clarify why it was chosen that the
Eastern Interconnection would be held to the largest event over the last 10 years, while
others will be based upon the largest category C loss-of-resource (N-2) event.
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
pages 52 through 55 of the Frequency Response Initiative paper.
SERC OC Standards Review
Group
Yes
We agree with the Duke Energy comments on this question.
Response: Thank you for your comment. (1) This was corrected during the posting. The formula was lost when converting to a
pdf file.
(2) The results for the current Eastern Interconnection model do not represent observed response adequately. The models for
the other Interconnections have a better match. For this reason the drafting team has recommended the largest event in the last
ten years be used to provide for an increased reliability margin for the Eastern Interconnection. Further details are provided on
Consideration of Comments: Project 2007-12
69
003893
Organization
Yes or No
Question 7 Comment
pages 52 through 55 of the Frequency Response Initiative paper.
SPP Standards REview
Group
Yes
We like the document and feel that it provides a primer on the frequency response
standard.The following are typos in and suggested corrections to the document:-The
blue lines referenced in the paragraph under Figure 2 on page 14 are green (A) and red
(B).-Insert an ‘a’ in the 3rd line of the 2nd paragraph in the Sustained Response section
on page 19 between ‘provides’ and ‘greater’.-Insert a ‘for’ in the 2nd line of the 1st
paragraph on page 21 between ‘resource’ and ‘all’.-Change ‘provide’ to ‘provided’ in
the 3rd line from the bottom line of the 1st paragraph in the Single Event Frequency
Response Data section on page 24.-Change the ‘east’ to ‘Eastern Interconnection’ in
the 4th line of the 1st paragraph in the Median as the Standard’s Measure of Balancing
Authority Performance section on page 27. -Delete the ‘put’ in the 3rd bullet on page
29. Also, replace the ‘put’ in the 5th bullet with ‘gave’.
Response: Thank you for your affirmative response and clarifying comment. The errors you mentioned have been corrected.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
PJM Interconnection, LLC
Yes
California Independent
System Operator
Yes
Energy Mark, Inc.
Yes
No comment.
Consideration of Comments: Project 2007-12
70
003894
Organization
Yes or No
Southern Company
Yes
Idaho Power Company
Yes
Texas Reliability Entity
Yes
Kansas City Power & Light
Yes
Ameren
Yes
NV Energy
Yes
Tucson Electric Power
Yes
BC Hydro
Yes
MISO
Yes
MRO NSRF
Question 7 Comment
MRO NSRF AGREES
Consideration of Comments: Project 2007-12
71
003895
8.
If you are not in support of this draft standard, what modifications do you believe need to be made in order for you to support
the standard? Please list the issues and your proposed solution to the issue.
Summary Consideration: A couple of commenters expressed concern with the fact that the onus for Frequency Response was being
put on the BAs who do not own or operate the generators. The drafting team explained that they had heard some of
the same concerns, but there are quite a few good reasons why this standard is a good starting point to meet the FERC
directives in Order No. 693 (which NERC was given a specific date next year to deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still,
they are responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the
standards. Similarly a TOP is responsible for maintaining voltage even though they may own no capacitor banks or
generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency
response (or generator governor response if the standard was generator centric) to about 30 events per year. There
are about 140 BAs in North America. There are on the order of 4000 generators that would have to report under a
generator-centric standard. How do you verify performance of 120,000 observations annually?
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large
contingency. It is not intended to be difficult to meet. As proposed, the standard has a performance obligation about
half of what we see today in actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have
about -2200MW/0.1Hz on average. The standard allows the formation of frequency response sharing groups (similar
in concept to DCS' RSGs) and allows obtaining response from other BAs contractually. This means there should be no
BAs out of compliance once the standard is in place.
A couple of commenters stated that they thought the standard was confusing. The drafting team stated that they appreciated their
concern that the standard is confusing, but the drafting team believed that the proposed standard is as clear as
possible while covering all of the issues involved and that based on comments received the industry was not in
agreement.
Consideration of Comments: Project 2007-12
72
003896
One or two commenters requested clarity on how modifications to the Attachment A could be made and if the FRS Forms 1 and 2 had
to be used. The drafting team explained that Attachment A was part of the standard and would have to use the
Standard Development Process to make any modifications. The drafting team also stated that the FRS Forms were
required to be used in the reporting.
A couple of commenters questioned the use of the Background Document. The drafting team explained that the Background
Document was only intended to be used for education and training similar to other training references in the NERC
Operating Manual.
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 8 Comment
(1) We believe that the drafting team work has demonstrated that the standard is
unnecessary. The data presented in the posting shows that all of the interconnections
easily exceed the required Frequency Response necessary to avoid actuating UFLS
relays. Since one of the main purposes of the standard is to provide sufficient
Frequency Response, it would seem the purpose is already met without implementing
and enforceable standard. So why is a standard needed to compel required Frequency
Response if it is already provided?
(2) Even though we believe the supporting data for the posting demonstrates the
standard is unnecessary, we understand NERC is required by a FERC directive to
provide a standard. Given this requirement, we do believe the drafting team has largely
provided a reasonable standard and supporting documents that only require a few
additional adjustments (see our comments in other questions for these adjustments) to
finalize the standard. As a result, we will likely end up supporting the standard once
these final adjustments are made.
Response: Thank you for your comment. We agree that the standard meets the primary directive to provide Frequency
Response. This standard will set a backstop to assure that Frequency Response will not decline past a “point of no return”
For issues raised in other questions please refer to our response to those questions.
Independent Electricity
No
a. We do not support R2 as drafted, specifically the phrase “until directed to change by
the ERO”. We do not agree that the ERO has any authority to “direct” a BA or FRSG, or
Consideration of Comments: Project 2007-12
73
003897
Organization
Yes or No
System Operator
Question 8 Comment
any responsible entities, to make changes to the Frequency Bias Setting or take any
operating or operations planning actions. We suggest to replace the word “directed”
with “requested”.
b. In R2, the words “subject to” can be interpreted differently. We suggest to replace
them with “in accordance with” to parallel the intent as conveyed in R1.
c. We are still concerned with the status of Attachment A, as indicated in our
comments submitted under Q4 - that it is unclear if the materials in Attachment A must
be adhered to or not. A standard should not have an attachment whose enforcement
status is unclear as part of a requirement.
d. FRS Forms 1 and 2 are referenced in Attachment 1, which itself has an unclear status
on measurability and enforceability. It is also unclear if FRS Forms 1 and 2 must be used
to submit the requested data. Collectively, Attachment 1, FRS Form 1 and Form 2 make
the standard very confusing as to which parts must be complied with. Much better
clarity is needed to clearly convey the standard ‘s requirements that are measurable,
enforceable and must be complied with.
Response: Thank you for your comments,
a) The drafting team believes that the term “direct” is less ambiguous. The drafting team believes that using the term “request”
could leave the impression that the action is optional.
b) The drafting team has adopted your suggested language.
c) Please refer to the drafting team response to Question #4.
d) The Attachment is mentioned in the standard requirements and is therefore enforceable. Since the FRS Forms are discussed in
the Attachment then they must be used in the calculation process.
Bonneville Power
Administration
No
BPA continues to fundamentally disagree with the approach that BAL-003-1 is
developing into. Please reference BPA’s extensive comments submitted on 12/8/11 for
Project 2007-12 Frequency Response found at:
http://www.nerc.com/docs/standards/sar/2007-12_comments_received_120911.pdf.
Consideration of Comments: Project 2007-12
74
003898
Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment. Please refer to the drafting team response to your comments submitted on 12/8/11.
Exelon Corporation and its
affiliates
No
Exelon checked "no" because it does not support the current draft standard. Exelon’s
position is that efforts to modify frequency monitoring and control should be directed
at the existing standards. Since Frequency Bias is already a component of ACE, and ACE
performance is tracked by both CPS 1 and CPS 2, it seems evident that NERC already
has in place mechanisms for evaluating frequency response. NERC already has in place
mechanisms for ensuring sustained frequency response during a contingency, through
the Disturbance Control Standard (DCS) and its requirement for the contingent
Balancing Authority to deploy resources. Under the current BAL-003-0.1b language,
Balancing Authorities are given a consistent means for determining frequency bias, via
the minimum requirement of 1% peak generation or 1% peak load. Together with the
above references to existing CPS 1 performance measurements, current standards
meet the objectives outlined in BAL-003-1. This proposed draft BAL-003-1 complicates
the setting of Frequency Bias and attempts to go beyond that purpose into frequency
response performance, without clear rules for how to perform.
Exelon is also concerned with moving this standard forward while there is an ongoing
field trial that could impact whether this standard should be put into place. For
example, waivers are in place for CPS 2 for participating Balancing Authorities and
there is ongoing effort with the BAAL field trial set of standards that will establish
performance metrics around frequency control. As an alternate approach to waiting to
move forward on the standard, Exelon recommends the following BAL-003-1
Requirement language:
R1.
The ERO shall identify up to five [5] system frequency events in each
Interconnection that will be included in the Form 1 and 2 data requests for Balancing
Authorities by April 30th each year.
R2.
Each Balancing Authority shall submit the following data to the ERO annually
by July 15:
R2.1
Consideration of Comments: Project 2007-12
The total annual net output of generating plants inside the Balancing
75
003899
Organization
Yes or No
Question 8 Comment
Authority Area.
R2.2
The total annual load with losses inside the Balancing Authority Area.
R3.
Each Balancing Authority shall calculate its Frequency Response Measure using
Forms 1 and 2 as posted by the ERO. (See Attachment A_Form 1 and Form 2)
R4.
Each Balancing Authority or Frequency Response Sharing Group shall submit
Forms 1 and 2 to contacts designated by the ERO before the expiration of ERO
established deadlines, which shall be no earlier than 30 days after posting of Forms 1
and 2.
R5.
The ERO shall post the following information:
R5.1.
Each Interconnection’s Frequency Response Obligation
R5.2
Each Balancing Authorities Frequency Response Obligation
R5.3
Each Balancing Authorities Frequency Bias Setting
R6.
Each Balancing Authority shall implement in its ACE equation its ERO
established Frequency Bias Setting during the ERO established three-day
implementation period. No further adjustments can be implemented outside of the
parameters established below in the upcoming year unless a Balancing Authority
coordinates with the Regional Entity and the affected Balancing Authorities.
R6.1
A Balancing Authority using a fixed Frequency Bias Setting sets its
Frequency Bias Setting to the greater of (in absolute value):
R6.1.1. The number the BA chooses between 100% and 125% of its
Frequency Response Measure as calculated on FRS Form 1.
R6.1.2. The Balancing Authorities share of the Interconnection Minimum
as determined by the ERO.
R6.2 A Balancing Authority using a variable Frequency Bias Setting shall
maintain a setting that is:
Consideration of Comments: Project 2007-12
76
003900
Organization
Yes or No
Question 8 Comment
R6.2.1 Less than zero at all times, and
R6.2.2 Equal to or greater in magnitude than its Frequency Response
Obligations when Frequency varies from 60 Hz by more than +/-0.036
Hz.
R7.
Each Frequency Response Sharing Group or Balancing Authority that is not a
member of a FRSG shall monitor its Frequency Response Obligation and work with
generating facilities or demand response resources to provide sufficient Frequency
Response to meet the Frequency Response Obligation assigned by the ERO.
R8.
Each Balancing Authority that adds or removes generation or load, including
through the use of dynamic transfers, shall notify the ERO to ensure that any needed
adjustments to the Interconnection Frequency Response Obligation or Balancing
Authority Frequency Response Obligation and Bias can be calculated.
R8.1. The ERO shall notify all affected Balancing Authorities of modifications
to the Frequency Response Obligation due to the addition or removal of
generation or load.
R9.
Each Balancing Authority that is performing Overlap Regulation Service shall
modify its Frequency Bias Setting in its ACE calculation, in order to represent the
Frequency Bias Setting for the combined Balancing Authority Area, to be equivalent of
the sum of the Frequency Bias Setting as communicated by the ERO for the
participating Balancing Authorities.
Response: Thank you for your comment. ACE, CPS1, CPS2, BAAL and DCS are all standards that measure Secondary Control
actions. The inclusion of the Frequency Bias Setting in ACE and these standards make them blind to Primary Frequency Control
and thus incapable of helping with the evaluation of Frequency Response (Primary Frequency Control). R1 sets clear rules with
respect to how much Frequency Response is required from each BA through the Frequency Response Obligation (FRO) and
Frequency Response Measure (FRM). The BAAL Field Trial is investigating issues associated with Secondary Frequency Control
only and is not impacted by and has no impact on Primary Frequency Control and BAL-003. The drafting team has considered the
suggestions contained in the requirements suggested and has explained in the Background document the reasons for writing the
Consideration of Comments: Project 2007-12
77
003901
Organization
Yes or No
Question 8 Comment
requirements and measures as contained in the draft BAL-003-1.
Duke Energy
No
Given the FERC deadline approaching for NERC to deliver a Frequency Response
standard, Duke Energy supports the adoption of this standard with some reservations.
We believe that the proposed standard addresses the FERC directive to NERC, however
it also introduces some longer-term issues related to secondary control and related
costs that may have not been anticipated by the FERC. To that point, Duke Energy
believes that if this standard is adopted, the industry will have the time and
opportunity through the NERC standards development process to mitigate some of the
concerns presented in our comments.”
Response: Thank you for your affirmative response and clarifying comment. The drafting team agrees that there could be some
impact on other standards but the implementation period will allow for time to adjust and learn
Tucson Electric Power
No
I feel that a BA's frequency bias for the upcoming year should not be related to present
performance. A BA may have a good response one year and not good response
another year and therefore the threshold keeps moving around. I feel it should be
related to BA size and therefore somewhat standardized. E.g. a high-performing
Balancing Authority will have its frequency bias increased each year due to higher
response during the events chosen by the ERO. Conversely, a low-performing
Balancing Authority will have its frequency bias reduced each year due to lower
response during the events chosen by the ERO.
Response: Thank you for your comment. The drafting team believes that control and frequency performance improve if the Bias
Setting and the BA’s Frequency Response are as closely matched as possible. Low performing BAs will still have to provide the
Interconnection minimum Bias Setting. In an unlikely case where a high performing BA has an internal change that markedly
reduces their Frequency Response, there are provisions in the standard’s supporting document to accommodate an intra-year
change in its Bias Setting.
New York Independent
System Operator
No
In general we support the work of the DT, and the proposal to measure the systems
response to frequency events, along with the method to determine the FRO. My
Consideration of Comments: Project 2007-12
78
003902
Organization
Yes or No
Question 8 Comment
outstanding concern is with enforcement on an entity that does not own the resources
that provides the frequency response or the lack of obligation for the entity with the
information to provide to the BA to make the assessment of expected frequency
response. BA’s should at a minimum be given assurance that resources will provide
data that BA’s could use to forecast frequency response and take corrective actions.
Response: Thank you for your comment. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
Consideration of Comments: Project 2007-12
79
003903
Organization
Yes or No
Tri-State Generation and
Transmission Assn., Inc.
No
Question 8 Comment
It is our opinion that there has not been enough justification to merit creating a new
standard. If additional justification is provided then frequency responsive reserves
should be a subset of spinning reserves much like spinning reserves are a subset of
operating reserves.
Response: Thank you for your comment. This standard will set a backstop to assure that Frequency Response will not decline past
a “point of no return”
This standard does not prescribe a method to provide Frequency Response but does provide for measuring that Frequency
Response is delivered.
Spinning reserve is outside the scope of the industry approved SAR.
Puget Sound Energy
No
See comment in response to question 4 above for a discussion of Attachment A
concerns.
Appendix 1 of the Frequency Response Standard Background Document contains a
discussion about why the use of net actual interchange to calculate an entity’s
Frequency Response Measure might introduce inaccuracies into that calculation. That
discussion ends with the following statement: “The frequency response is buried within
the typical hour to hour operational cacophony superimposed on actual net
interchange values. The choice of metrics will be important to artfully extract
frequency response from the noise and other unrepresentative error.” Based on these
statements, it is very difficult to support the standard’s approach to calculating the
Frequency Response Measure.At Puget Sound Energy (PSE), though, we believe that
there is another factor to add to the “operational cacophony” listed in Appendix 1. PSE
is a comparatively small BA with limited internal generation. We are embedded
between two of the largest energy exporters in the Western Interconnection and,
when there is a frequency event, their response flows through PSE’s system. As a
result, PSE will experience transmission losses associated with the two BAs’ frequency
response as it flows through our system. When PSE’s frequency response is measured
using net actual interchange, these losses obscure, at least in part, our system’s
Consideration of Comments: Project 2007-12
80
003904
Organization
Yes or No
Question 8 Comment
frequency response. As a result, we ask the standard drafting team to consider
specifying a process that would allow us to propose and use an equivalent measure of
frequency response. For example, while we understand the concerns and difficulties
associated with measuring frequency response at the generator as the default measure
for all BAs, in our case, a choice to use that measurement option might prove to be a
more-feasible way to comply with the standard.
Response: Thank you for your comment. Please refer to our response to your comments on Question #4.
Analysis of Field trial data has not shown that this has been a problem.
The spreadsheets have been designed to allow for adjustment for dynamically scheduled resources located in another BA.
PJM Interconnection, LLC
No
See previous comments.
Also, this standard should be applicable to GOP’s as well as BA’s with, at a minimum,
the following requirements added:
Each GOP shall follow all directives of it’s Balancing Authority pertaining to
frequency responsive operation, including but not limited to the status, droop &
deadband settings of their governors.
Each GOP shall provide to their BA the status and droop & deadband settings of
their governors, and headroom available to respond to frequency deviations, as
requested.
Response: Thank you for your comment. MISO has done analysis to find all large frequency events over the past year and how the
generators in its footprint performed. It turns out that many of the generators aren't on line for any of the events and only a few of
the generators were on line for all large events. So what do you do with generators that are not frequently run? Even if a generator
ran 50% of the time, you wouldn't have enough events to do a quality measure in a year.
Generator verification standards (MOD 27) are scheduled to be revised. The drafting team believes that this will address your
second concern
PPL NERC Registered
No
The PPL Affiliates are concerned that the document referred to “Attachment A” is
Consideration of Comments: Project 2007-12
81
003905
Organization
Yes or No
Affiliates
Question 8 Comment
directly referenced in the proposed standard’s requirements but not actually attached
to the standard itself as Attachment A. Therefore, it is not clear how the proposed
document could be modified in the future. Having such material incorporated into a
standard takes away from the open and transparent stakeholder drive process.
Response: Thank you for your comment. The attachment is mentioned in the requirement within the standard and therefore
becomes a part of the standard. Any modifications needing to be made to the attachment will have to use the Standards Process.
Consolidated Edison Co. of
NY, Inc.
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in
BAL-001. The Standard is currently confusing to understand and it is unclear how the
bias is calculated. It is recommended that efforts should be made to clarify the
changes, especially Attachment A.
Response: Thank you for your comment. The drafting team appreciates your concern that the standard is confusing, but the
drafting team believes that the proposed standard is as clear as possible while covering all of the issues involved.
The drafting team will either develop training materials to provide better understanding for both the FRM and FBS calculations or
recommend to the NERC Resources Subcommittee to develop said materials.
Northeast Power
Coordinating Council
No
The purpose of BAL-003 was to calculate frequency bias in the ACE equation used in
BAL-001. The Standard is currently confusing to understand, and it is unclear how the
bias is calculated. It is recommended that efforts should be made to clarify the
changes, especially in Attachment A.
Response: Thank you for your comment. The drafting team appreciates your concern that the standard is confusing, but the
drafting team believes that the proposed standard is as clear as possible while covering all of the issues involved.
The drafting team will either develop training materials to provide better understanding for both the FRM and FBS calculations or
recommend to the NERC Resources Subcommittee to develop said materials.
Kansas City Power & Light
No
The Standard does not consider instances for smaller BAs that operate generation for
peak conditions and acquire energy for most of the operating year.
Consideration of Comments: Project 2007-12
82
003906
Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment. The drafting team is unsure of your precise question. However, if your question
concerns meeting your performance obligation year around, then the process does allow for mechanisms for a BA to obtain
Frequency Response from external resources
NV Energy
No
While I support the concept of a Frequency Response Standard with minimum
performance obligations, this Standard places the entire obligation for performance on
the Balancing Authority (and Frequency Reserve Sharing Group). Requirements R2-R4
are properly assigned to the BA, as this is the entity that is responsible for the
configuration and parameters in the ACE equation, including the provision of a
frequency bias setting. Requirement 1, however, is a performance requirement over
which the BA in the Functional Model has virtually no control or ability to influence.
Only a Generator Owner or Generator Operator is in a position of control over the
performance under this requirement through the operational control and configuration
of the responding generating units. In most BA's, the host BA entity also owns a fair
amount, even a vast majority in many cases, of the generation within the BA. However,
even in the event that the host BA owned 100% of the generation within its metered
boundary, it is the action of the entity exercising its GO/GOP function that impacts the
frequency response performance within the Balancing Area. Assignment of R1 to the
BA is inappropriate from the standpoint that reliability requirements are to be assigned
to the Reliability Functions who are capable of causing compliance to occur. A BA has
limited ability to influence the outcome of the R1 performance metric. This is unlike
other BA-assigned requirements, such as those related to DCS or CPS compliance. For
those, the BA does have considerable influence regarding the curtailment of
transactions to restore ACE, the direction of plant loading so as to distribute operating
reserve, etc. In contrast, performance under this proposed R1 of BAL-003-1 is
dependent upon the actions of the GO/GOP in such things as governor settings,
generator control system configuration and other operatinal or maintenance activities
conducted at the generating plant site. For this reason, it is inappropriate to assign this
performance requirement to the BA. Rather, the requirements should be allocated
among the GO/GOP's of the on-line generation in some fashion.In further support of
Consideration of Comments: Project 2007-12
83
003907
Organization
Yes or No
Question 8 Comment
this notion, refer to the NERC Functional Model, where it is provided that one of the
tasks for Generator Operation is to support Interconnection frequency.
Response: Thank you for your comment. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
Arizona Public Service
NO
1. Either do not use C to B Ratio or provide adequate rational for using it. It appears to
Consideration of Comments: Project 2007-12
84
003908
Organization
Yes or No
Company
Question 8 Comment
make FRO unnecessarily too conservative and is not justified based upon experience.
2. The VRF is too complicated and hard to understand. It must be either simplified or
should be followed by example.
3. The Frequency Response Obligation Methodology on Page 7 of “Procedure” does not
show any formula (it is blank).
Response: Thank you for your comment. 1) The rationale can be found beginning on page 14 of the Background document and
page 49 of the FRI report.
2) The drafting team is assuming you meant the VSLs. The VSL attempts to correct the VRF based on the BA’s size and its impact
on the interconnection.
3) This was corrected during the posting. The problem occurred when the Word document was translated to a pdf file.
Energy Mark, Inc.
Yes
Although I am in favor of using linear regression to determine the FRM, the standard
using Median is better than not having a standard.
Response: Thank you for your comment. The drafting team thanks you for your affirmative response and clarifying comment.
Southern Company
Yes
Please refer to comments for question 9.
Response: The drafting team thanks you for your affirmative response and clarifying comment. Please refer to our response for
Question #9.
Manitoba Hydro
Yes
NREL Transmission and Grid
Integration Group
Yes
Edison Electric Institute
Yes
pacificorp
Yes
No comment.
Consideration of Comments: Project 2007-12
85
003909
Organization
Yes or No
California Independent
System Operator
Yes
Ameren
Yes
MISO
Yes
AESO
Question 8 Comment
1. The AESO disagrees with using a non-authoritative background document that has
definitions/description of terms used in the reliability standard. It is the opinion of the
AESO that these definitions/descriptions need to be authoritative.
2. The AESO has previously submitted comments to the SDT that for the purpose of the
FRM calculation, BAs should be able to exclude or include events based on specific
conditions or consideration, such as data quality or event suitability (e.g. BA separation
from the Interconnection). The revisions made by the SDT do not enable the inclusion
of other relevant events in the FRM calcualtion by a BA. The AESO would like to to see
these type of events to be permitted in the FRM calculation by a BA.
Response: Thank you for your comment. 1) The Background Document is intended for education and training similar to the other
training references in the NERC Operating Manual.
The drafting team believes that any new definitions that are located in the standard will ultimately be placed in the NERC glossary.
2) The drafting team believes that your concern will be addressed through the process since:
a) separation events would not be selected,
b) the median will exclude the outlier situations, and
c) If the data is corrupted, the FRS Forms allows for exclusion of that event.
Public Service Enterprise
Group
PSEG entities will vote “Negative” on the standard until this Project 2007-12 achieves
the following:
1. It coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-
Consideration of Comments: Project 2007-12
86
003910
Organization
Yes or No
Question 8 Comment
based Controls Reserves, specifically BAL-012-1, regarding (a) definitions and (b)
requirements that address frequency response in both standards.
a. Definitions that need to be coordinated: BAL-003-2 - “Frequency Response
Obligation” and BAL-012-1 - “Frequency Responsive Reserve.”
b. Requirements that need to be coordinated:
i. BAL-003-1, per R1, states “Each Frequency Response Sharing Group
(FRSG) or Balancing Authority that is not a member of a FRSG shall
achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that
sufficient Frequency Response is provided by each FRSG or BA that is not
a member of a FRSG to maintain Interconnection Frequency Response
equal to or more negative than the Interconnection Frequency Response
Obligation.”
ii. BAL-012 requires BAs to have sufficient Frequency Responsive
Reserves per R6, which requires BAs to “assess, on at least an hourly
basis, that it has sufficient Regulating Reserve, Contingency Reserve, and
Frequency Responsive Reserve to meet its reserve plan(s) to ensure
reliable operation of the Bulk Electric System.” For Frequency
Responsive Reserves, R3 in BAL-012-1 requires BAs to develop an annual
plan for these reserves.BAs should not be subject to duplicative
requirements for frequency response requirements in different
standards that are underdevelopment. Only one standard needs to
define the frequency response requirements for BAs (we suggest that be
BAL-003-1), although other standards, such as BAL-012-1, may reference
that obligation. However, this decision should be made by consensus
between the two SDTs.
2. It coordinates with Project 2010-14.1 Phase 1 of Balancing Authority Reliability-
Consideration of Comments: Project 2007-12
87
003911
Organization
Yes or No
Question 8 Comment
based Controls Reserves, specifically BAL-012-1, to develop an application guide that
would be attached to one of the standards and that could be referenced by each
standard. The application guide would include:
a. A hypothetical implementation plan for a BA that demonstrates how the BA
may meet its Frequency Response Obligation or Frequency Responsive Reserve
prior to an event. This is a technical issue and should not be confused with the
institutional issue in #3 below.
b. An explanation of the relationship between Regulating Reserve, Contingency
Reserve, and Frequency Responsive Reserve contained in BAL-012-1 so that
potential double counting (and whether that is proper of improper), is
addressed.
3. Project 2007-12’s “Frequency Response Standard Background Document” dated
October, 2012 lists several methods of obtaining Frequency Response. Most of those
are extracted below. We have provided questions and commentary that we ask the
team to address.
a. “Regulation services.” This is addressed in BAL-001-0.1a. The purpose of this
standard is “To maintain Interconnection STEADY-STATE FREQUENCY within
defined limits by balancing real power demand and supply in real-time. How is
this related to Frequency Response for a disturbance? (The team may answer
this as part of 2.b above.)
b. “Through a tariff (e.g. Frequency Response and regulation service). “ The
team is advised to review the actual pro-forma OATT schedule for Schedule 3
“Regulation and Frequency Response Service” which is specifically limited to
services providers that are “capable of providing this service as necessary to
follow the moment-by-moment changes in load.” Again, how is this related to
Frequency Response for a disturbance? (The team may answer this as part of
2.b above.)
c. “From generators through an interconnection agreement.” The FERC’s pro-
Consideration of Comments: Project 2007-12
88
003912
Organization
Yes or No
Question 8 Comment
forma Standard Large Generator Interconnection Agreement (LGIA) per Order
2003 contains no requirement for generators to provide Frequency Response
service, and we are not aware on ANY interconnection agreement that does.
We ask that the team point to ANY interconnection agreement with such a
requirement. Modification of an interconnection agreement to incorporate
such a requirement would require the consent of both parties.
d. “Contract with an internal resource or loads.”Since Frequency Response
service would likely be considered as a necessary service to provide
Transmission Service under an OATT, it would require a tariff. What existing
tariff applies in the U.S.?The “methods” above that the team has listed have the
factual errors described. The standard BAL-003-1 cannot be implemented until
the necessary tariffs are developed that permit BAs and FRSGs to contract for
Frequency Response services. Once that is done, BAL-003-1 can dictate the
performance requirements of a BA or FRSG.
o For context, FERC OATT schedules relevant to Frequency Response DO NOT set
performance requirements. Schedule 3 (Regulation and Frequency Response Service)
sets forth a tariff for the service, while BAL-001-0.1a sets forth performance
requirements in aggregate for a BA or RSG. Likewise, Schedule 5 (Operating Reserve Spinning Reserve Service) and Schedule 6 (Operating Reserve - Supplemental Reserve
Service) set tariffs for both services, while BAL-002-1 sets performance requirement.
Without an OATT schedule for Frequency Response service, BAs and FRSGs will have no
means to contract with generators or loads to provide Frequency Response per BAL003-1. The team should address this concern.
Response: Thank you for your comment. There is significant coordination between the two drafting teams and this coordination
will continue as all standards referenced are posted for comment.
With regard to double jeopardy, both drafting teams have been coordinating to ensure this does not occur.
We believe it is important from a reliability perspective to have a performance based standard. The ultimate need for tariff
changes, interconnection agree, etc will be based on a BA’s need to meet the standard.
Consideration of Comments: Project 2007-12
89
003913
Organization
Yes or No
Question 8 Comment
Within the measures for R1 and the discussions in the Background document, the drafting team believes that FERC and the
industry will be able to develop the changes to tariffs to address your concerns with the BA contracting with sources of Frequency
Response to meet its FRO. The BA is also responsible for dispatch levels of resources that provide Frequency Response. Now that
Frequency Response has been clearly defined and is able to be measured, sources of Frequency Response for delivery of the
service can be developed by the industry.
Once both BAL-003-1 and BAL-012-1 have passed, the drafting team believes it would then be an appropriate time for the
members of the two drafting teams to develop an application guide.
American Electric Power
There is no leverage for the BA to require the generator to carry their burden of
addressing governor settings or droop settings, yet the BA is obligated to meet some
performance measures in that regard.This revision adds new performance measure
responsibilities on the BA who likely has no direct control over every resource affecting
their performance within their footprint. We are not necessarily challenging the
performance measures themselves, nor their underlying objectives, however AEP views
this as a gap in responsibilities which potentially effects reliability. AEP suggests that
GOPs be considered as part of this standard so that their performance can be factored
into the process to meet the performance objectives.
Response: Thank you for your comments. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VARs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
Consideration of Comments: Project 2007-12
90
003914
Organization
Yes or No
Question 8 Comment
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
SPP Standards REview
Group
We support the standard as proposed.
Response: The drafting team thanks you for your support.
Consideration of Comments: Project 2007-12
91
003915
9.
Please provide any other comments (that you have not already provided in response to the questions above) that you have on
the draft standard BAL-003-1.
Summary Consideration: A couple of commenter disagreed with the VSLs for Requirement R1. The drafting team explained that the
VSLs were a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a
violation’s impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide
resource. The proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA
Interconnections. Consider a small BA that whose performance is 70% of it’s FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability, yet would be
sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not rational to sanction
this BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would treat
multi-BA Interconnections tens of times more harshly than single BA Interconnections. However, the drafting team has
added language to the requirement to reference the Interconnection Frequency Response Obligation.
One commenter felt that there was an inconsistency between Requirement R4 and Requirement R1 and Attachment A concerning
how a BA providing Overlap Regulation Services would calculate its FBS. The drafting team disagreed with their
comment. Under the two options in R4 the BAs must still comply with the minimum setting requirements through the
calculations performed under R2. In your example, if both BAs turned in FRS Form 1 showing a FBS based on the 100%
- 125% minimum these two numbers would be added together for compliance with R4.
One commenter felt that the definition should state that it is a negative value. The drafting team explained that while the desired
value would be negative it is mathematically feasible for the actual value to be positive but that value would by
definition mean that the entity failed the measurement for Requirement R1.
One commenter disagreed with putting the onus on the BA for providing Frequency Response. The drafting team The drafting team
explained that they had heard some of the same concerns, but there are quite a few good reasons why this standard is
a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still,
they are responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the
standards. Similarly a TOP is responsible for maintaining voltage even though they may own no capacitor banks or
generators to control VArs.
Consideration of Comments: Project 2007-12
92
003916
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency
response (or generator governor response if the standard was generator centric) to about 30 events per year. There
are about 140 BAs in North America. There are on the order of 4000 generators that would have to report under a
generator-centric standard. How do you verify performance of 120,000 observations annually?
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large
contingency. It is not intended to be difficult to meet. As proposed, the standard has a performance obligation about
half of what we see today in actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have
about -2200MW/0.1Hz on average. The standard allows the formation of frequency response sharing groups (similar
in concept to DCS' RSGs) and allows obtaining response from other BAs contractually. This means there should be no
BAs out of compliance once the standard is in place.
One commenter questioned how the event selection process would work. The drafting team stated that the event selection process
was outline in the Procedure for ERO Support of the Frequency Response and Frequency Bias Setting Standard.
Organization
Question 9 Comment
ACES Power Marketing
Standards Collaborators
(1) Please strike “that is a member of a multiple BA Interconnection” in R2 and R3. The language
makes the requirements difficult to read. We understand this is trying to clarify that these
requirements should not apply to BAs such as ERCOT since changing its Frequency Bias Setting does
not need to be coordinated with other BAs among other issues, and we do not have an issue with
this intent. However, there is an easier way to address this issue without creating a confusing
requirement. The SDT should include seeking a variance for the ERCOT area in conjunction with
developing the standard.
(2) Please strike “in order to represent the Frequency Bias Setting for the combined Balancing
Authority Area” in Requirement R4 as it is superfluous and incorrect. First, the two bullets provide
the necessary information making the statement unnecessary. Second, the BA Areas are not
combined into a single BA Area as implied with the statement “combined Balancing Authority
Area”. They are still in fact two distinct BA Areas.
Consideration of Comments: Project 2007-12
93
003917
Organization
Question 9 Comment
(3) The data retention period for R1, R2, R3, and R4 is not consistent with the NERC Rules of
Procedure. Section 3.1.4.2 of Appendix 4C - Compliance Monitoring and Enforcement Program
states that the compliance audit will cover the period from the day after the last compliance audit
to the end date of the current compliance audit. The data retention section states that data shall
be kept for the current calendar year plus the three previous calendar years. This could be up to
four years which exceeds the BA audit period of three years. It is unnecessary for a BA to maintain
evidence that was already verified in a prior audit. We recommend changing the evidence
retention period to three years.
(4) Has the drafting team coordinated the addition of the Frequency Response Sharing Group
(FRSG) with the Functional Model Working Group and the NERC staff responsible for organizational
registration? If not, please do so as NERC will need to be willing to register entities as a FRSG if it is
to be utilized. Furthermore, the Functional Model Working Group should document the purpose
and intent of the FRSG
.(5) We disagree with the VSLs for R1. The VSLs are structured such that a BA’s or FRSG’s violation
is dependent upon the rest of the interconnection to determine the severity level of the violation.
If the BAs collectively fail to achieve the Interconnection Frequency Response obligation, a 2%
violation of the Frequency Response Measure jumps from a Lower VSL to a High VSL. This should
never be the case. No violation by a registered entity should become potentially more or less
severe based on the violation of another entity. We encourage the drafting team to work with
NERC Legal department in reviewing this VSL further as FERC has already allowed ISO/RTO
violations investigation to draw in third parties that potentially contributed to the ISO/RTO
violation to ensure the appropriate party is fined. The principal is similar here in ensuring the
appropriate BA is fined for its violation not the violations/failures of other BAs. The background
document mentions on page 31 that the motivation for structuring the VSL in this manner was to
prevent BAs in multiple BA interconnections from being sanctioned disproportionately. We
appreciate the draftingteam considering this issue but believe there is a simpler solution. Four VSLs
could simply be written based on the percentage the BA misses its own Frequency Response
Obligation. Furthermore, the compliance enforcement process already considers if the violation
impacted reliability when assessing a sanction
Consideration of Comments: Project 2007-12
94
003918
Organization
Question 9 Comment
.(6) The Frequency Response Obligation (FRO) term is used inconsistently with the definition in the
VSLs for R1. The first part of each BA implies that the Interconnection has an FRO. However, the
definition specifically states that FRO is the BA’s “share of the required Frequency Response”. It
does not apply to the Interconnection. How can the Interconnection have a share of the required
frequency response? A new term may need to be defined for the Interconnection.
(7) The implementation plan still references Requirement R5. There is no such requirement
.(8) Requirement R1 is not consistent with the recent direction NERC has taken to refocus on
reliability and looking forward during compliance audits rather than backwards. For instance, NERC
has proposed monitoring internal controls of registered entities because this will provide a
reasonable assurance that the registered entity is prepared to comply in the future. Current
compliance audits focus mostly on past performance and provide no indication of future reliability.
How does Requirement R1 support this forward looking vision when it is a lagging indicator that
looks at historical performance?
(9) Requirement R4 appears to be inconsistent with Requirement R1 and Attachment A. On page 3,
Attachment A states the BA shall set its Frequency Bias Setting to 100% to 125% of it Frequency
Response Measure or Interconnection Minimum. However, Requirement R4 states that the BA
providing Overlap Regulation Service shall set its Frequency Bias Setting to the sum of its
Frequency Bias Settings on FRS Form 1 and FRS Form 2 of its own BA and the BA to which its
provides Overlap Regulation Service. For simplicity let’s call the BA providing Overlap Regulation
Service BA X and the BA receiving the service BA Y. Why would the BA X not set its Frequency Bias
Setting to 100% to 125% of the sum of BA X’s and BA Y’s Frequency Response Measure? This would
make Requirement R4 parallel with R2.
(10) We do not understand the difference between the two bullets in Requirement R4. They
appear to say essentially the same thing and the background document provides no discussion to
distinguish their differences. Please provide further explanation.
Response: Thank you for your comments.
(1) The proposed variance alternative could create unnecessary work for different organizations.
(2) The proposed elimination of words could help but, the elimination could bring more questions than benefits.
Consideration of Comments: Project 2007-12
95
003919
Organization
Question 9 Comment
(3) The drafting team believes that the language proposed in the draft standard is typical of other standards and is not in violation
of anything.
(4) The drafting team is coordinating as you stated.
(5) VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is intended to measure a violation’s
impact on reliability and thus levy an appropriate sanction. Frequency Response is an interconnection-wide resource. The
proposed VSLs are intended to put multi-BA Interconnections on the same plain as single-BA Interconnections. Consider a
small BA that whose performance is 70% of it’s FRO. If all other BAs in the Interconnection are compliant, the small BA’s
performance has negligible impact on reliability, yet would be sanctioned at the same level as a BA who was responsible for its
entire Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection that had insufficient
Frequency Response. To do otherwise would treat multi-BA Interconnections tens of times more harshly than single BA
Interconnections. However, the drafting team has added language to the requirement to reference the Interconnection
Frequency Response Obligation.
(6) The drafting team has clarified the VSL.
(7) The drafting team has corrected the Implementation Plan.
(8) The drafting team disagrees. The drafting team believes that this is a performance based standard similar to BAL-001 CPS and
BAL-002 DCS requirements. With regards to “internal controls” the drafting team believes that this is an enforcement activity
not a standards activity.
(9) The drafting team disagrees with your comment. Under the two options in R4 the BAs must still comply with the minimum
setting requirements through the calculations performed under R2. In your example, if both BAs turned in FRS Form 1 showing
a FBS based on the 100% - 125% minimum these two numbers would be added together for compliance with R4.
(10) Under the first bullet, two BAs have submitted two FRS Form 1 document in accordance with R1. Under the second bullet,
one entity has turned in a single FRS Form 1 with all information for the two BAs combined.
Keen Resources Asia Ltd.
A probabilistic/statistical basis needs to be developed for the FRM that assesses for usage of
frequency response (causation of frequency error) and not just for provision of it. This would also
overcome NERC’s singular focus on reaction, and NERC’s color-blindness to proaction, pointed out
in my reply to question 7.
Response: Thank you for your comment. As part of the ongoing evaluation of Frequency Response this may be considered.
SPP Standards REview Group
Additional typos:Change the ‘)’ to a ‘(‘ in the 4th line of M1 of the standard.No further comment
Consideration of Comments: Project 2007-12
96
003920
Organization
Question 9 Comment
Response: Thank you for your comment. This has been corrected.
Arizona Public Service Company
As mentioned in Item 8 above, the VRF language is too complicated and hard to follow. Even
though the VRF poll is non binding, it needs to be clear and simple enough to be understood.
Response: Thank you for your comments. The drafting team is assuming you mean the VSL. VSLs are a starting point for the
enforcement process. The combination of the VSL and VRF is intended to measure a violation’s impact on reliability and thus levy
an appropriate sanction. Frequency Response is an interconnection-wide resource. The proposed VSLs are intended to put multiBA Interconnections on the same plain as single-BA Interconnections. Consider a small BA that whose performance is 70% of it’s
FRO. If all other BAs in the Interconnection are compliant, the small BA’s performance has negligible impact on reliability, yet
would be sanctioned at the same level as a BA who was responsible for its entire Interconnection. It is not rational to sanction this
BA the same as a single BA Interconnection that had insufficient Frequency Response. To do otherwise would treat multi-BA
Interconnections tens of times more harshly than single BA Interconnections. However, the drafting team has added language to
the requirement to reference the Interconnection Frequency Response Obligation.
BC Hydro
BC Hydro respectfully submits these additional comments/observations:
1.The proposed standard seems to indicate that it is applicable to the identified responsible
entities at all times. There might be circumstances where a BA that belongs to a multiple-BA
Interconnection became isolated and has to operate in restorative mode which might require
adjusting the frequency bias to a value less negative than the minimum FBS setting value in order
to follow the much reduced load/generation level in the area. We suggest adding some language in
either the Applicability section or in individual Requirements to recognize these circumstances.
2.Effective Dates: the proposed standard specifies a fixed period (12-month or 24-month) following
Regulatory Approval which may fall in the middle of the year while the calculation and
implementation are performed on an annual basis. Does this represent any conflicts?
3.The proposed standard does not clearly specify whether a BA must chose between using fixed
bias or variable bias for the entire year. Should BAs be allowed to switched back and forth between
the two methods? If yes, more details may be needed to account for the FRM and minimum FBS.
4.The proposed standard does not clearly specify whether a BA can be part of a FRSG for only part
Consideration of Comments: Project 2007-12
97
003921
Organization
Question 9 Comment
of the year or must be the whole year
5.The definition of FRO, FRM, FBS, etc. should all include language to indicate the “negative”
nature of the value.
6.Measure M2 should have “and uses a fixed bias” added for clarity purpose.
7.In the Additional Compliance Information section of the proposed standard the following info still
exists: For Interconnections that are also Balancing Authorities, Tie Line Bias control and fFlat
Ffrequency control are equivalent and either is acceptable. Since all reference to AGC Modes have
been removed from the Requirements, this additional info should also be removed.
Response: Thank you for your comments.
(1) The drafting team does not believe that there is any difference between adherence to the current standard and the proposed
standard. With regard to islanded operations, the drafting team believes that other standards prevail under those conditions.
(2) The timelines are not requirements and may be adjusted to meet the annual calculation process proposed by the standard.
(3) The drafting team believes the standard as drafted, allows for two types of bias, fixed and variable. A fixed bias is a single
number for the entire period. A number that changes within the period is a variable bias and is subject to Requirement R3.
(4) FRS Form 1 and 2 allows for the transfer of Frequency Response on a per event basis.
(5) While the desired value of the FRM would be negative it is mathematically feasible for the actual value to be positive but that
value would by definition mean that the entity failed the measurement for Requirement R1. The FBS definition states that it is
an inverse contribution to the interconnection frequency; therefore the definition does not need to reference a negative value.
The FRO will be an allocation of the IFRO whose calculation methodology will provide a negative number. The allocation of a
negative number will result in a negative number. For these reasons the SDT did not modify the definitions.
(6) Requirement R2 is only applicable to entity’s using a fixed bias therefore Measure M2 only applies to those utilizing a fixed
bias.
(7) The proposed elimination of words could help but, the elimination could bring up more questions than benefits.
Edison Electric Institute
EEI supports the efforts and improvements made by the Standards Drafting Team (SDT) in the
latest version of BAL-003 and believe those changes have been responsive to the directives in
Order 693. However, we recognizes that the Industry has struggled with this standard and remains
split as to how best to respond to those directives and in some cases there are those who question
Consideration of Comments: Project 2007-12
98
003922
Organization
Question 9 Comment
whether a standard is even necessary. Given the many open issues and the concerns expressed by
stakeholders we anticipate that this standard will once again fail to achieve sufficient support to
gain approval. Should the Standard fail to achieve ballet approval, it is our hope that NERC Staff
and the NERC Board of Trustees will allow the SDT a little more time to resolve any final issues that
have been identified in this latest ballet. Although we recognize that May 31, 2013 does not leave
the ERO with a lot of time to comply with this FERC imposed deadline, we still remain confident
that given the progress made by the SDT a standard, which is acceptable to the Industry, is still
possible. To the extent EEI can help, we are committed to working with member companies to
communicate the issues and exchange insights from the SDT to help as we can to achieve a positive
outcome.
Response: Thank you for your comment and support.
Manitoba Hydro
Purpose: Is the reference to ‘Interconnection Frequency’ supposed to be ‘Frequency Response’?
This would be consistent with later wording in the standard.
R1:
(1) The acronym ‘FRO’ is used inconsistently within the document.
(2) The phrase “to ensure that sufficient Frequency Response ...” should be separated from the
requirement as it is
(i) not descriptive of the required actions
(ii) redundant with the stated purpose at the beginning of the standard.
In general, such a drafting technique should be avoided as it may allow Responsible Entities to
argue that a violation has not occurred where the specific action that is described has not been
taken, but the purpose referenced in the requirement has been met.
M1: The reference to ‘documented formula’ is not clear. Does this imply that the FRSG or BA have
a record of their calculation? In addition, there is a typo, a random ‘)’ after FRM.
M2: Should include the words ‘and uses a fixed Frequency Bias Setting...’ after overlap Regulation
Consideration of Comments: Project 2007-12
99
003923
Organization
Question 9 Comment
Service to make the wording consistent within the Requirement.
M3: The wording of this measure switches tenses between ‘is’ and ‘was’. For consistency, we
suggest that this be corrected.
NERC Glossary definition of an FRSG is a group of BAs that collectively maintain, allocate and supply
operating resources required to jointly meet the sum of the Frequency Response Obligations of its
members.
No mention is made of the agreement including the sharing or delegation of responsibility related
to FRM. Accordingly, the standard should only reference a BA being able to delegate responsibility
to an FRSG if the RSG Agreement allows for such delegation.
Data Retention 1.3.
(1) As the standard is currently drafted, both the BA and the FRSG would be required to retain
data or evidence to show compliance with requirements R1 and M1. It is unclear whether
this is the intention, or whether it would be acceptable that just one or the other would
maintain such records
.(2) In the third paragraph, it should be clarified who is required to keep information related to
non compliance if the BA belongs to an FRSG - the BA or the FRSG or both.
Response: Thank you for your comments. The drafting team believes that the purpose statement is correct as written. The
standard is for both Frequency Response and Frequency Bias Setting both of which support Interconnection Frequency.
(1) The drafting team corrected the identified FRO inconsistencies within the documents.
(2) The drafting team was advised by NERC staff to include the language you are referencing.
(3) M1 – Yes the entity must have a record of their calculation. The typo has been fixed.
M2 - Requirement R2 is only applicable to entity’s using a fixed bias therefore Measure M2 only applies to those utilizing a
fixed bias.
M3 – The drafting team corrected the use of “is” in the last line of the measure.
(4) The drafting team believes that any agreement between members of a RSG is an issue that the RSG would handle. We have a
created the FRSG to address the concerns that an existing RSG may or may not be a FRSG.
Consideration of Comments: Project 2007-12
100
003924
Organization
Question 9 Comment
Data Retention
(1) Both the BA and FRSG must maintain data. At a minimum the BA needs data to document its bias setting obligation. In
addition, the BAs data may be needed to demonstrate FRSG performance.
(2) The drafting team believes that the language is clear; the entity that is found non-compliant would be the entity that would be
required to keep the data.
JEA
R1 places the burden for compliance on the BA but the BA does not control generation assets and
should not be solely responsible for maintaining frequency response. While the standard can still
define the amount of Frequency Response for each BA, there needs to be an obligation on the
GO/GOP to provide that service as directed by the BA and they should also be held accountable for
compliance.
Finally, we do not believe that a sufficient study has been conducted to determine the impact of
this standard. We are concerned that a substantial number of compliance issues could result and
that the resulting cost to maintain compliance could be excessive and we suggest it be put through
the Cost Effective Analysis Process (CEAP). We suggest that the proposed values be evaluated on a
sample size within each region to determine the number of compliance issues and for those issues
that are found determine what the BA would have to do be compliant.
Response: Thank you for your comments. We've heard some of the same concerns, but there are quite a few good reasons why this
standard is a good starting point to meet the FERC directives in Order No. 693 (which NERC was given a specific date next year to
deliver).
There are several other standards where a similar situation occurs. As you note, many BAs don't own generators. Still, they are
responsible for meeting DCS and CPS. The BAs control regulating and contingency reserves to meet the standards. Similarly a TOP is
responsible for maintaining voltage even though they may own no capacitor banks or generators to control VArs.
To measure frequency response fairly accurately (one of the 693 directives), you have to monitor the BAs' frequency response (or
generator governor response if the standard was generator centric) to about 30 events per year. There are about 140 BAs in North
America. There are on the order of 4000 generators that would have to report under a generator-centric standard. How do you
verify performance of 120,000 observations annually?
Consideration of Comments: Project 2007-12
101
003925
Organization
Question 9 Comment
MISO has done analysis to find all large frequency events over the past year and how the generators in its footprint performed. It
turns out that many of the generators aren't on line for any of the events and only a few of the generators were on line for all large
events. So what do you do with generators that are not frequently run? Even if a generator ran 50% of the time, you wouldn't have
enough events to do a quality measure in a year.
The standard is a backstop standard beyond which we could expect problems during light load conditions for a large contingency. It
is not intended to be difficult to meet. As proposed, the standard has a performance obligation about half of what we see today in
actual operation. The obligation for the East is on the order of -1000MW/0.1Hz. We have about -2200MW/0.1Hz on average. The
standard allows the formation of frequency response sharing groups (similar in concept to DCS' RSGs) and allows obtaining response
from other BAs contractually. This means there should be no BAs out of compliance once the standard is in place.
Finally, to make it a generator standard precluded other solutions (load management, flywheels, market solution, etc.).
The SDT does not believe that there is a need to perform a “cost analysis”. The numbers are lower than the numbers we are
presently seeing.
Los Angeles Department of
Water and Power
Spinning reserves are intended to support the interconnection response to the loss of a resource. If
BAL-003-1 is adopted through this Project, the LADWP recommends that the spinning reserve
requirements of BAL-002-0.1b and BAL-STD-002-0 be removed, as the Spinning reserve
requirement would require utilities to reserve resources in excess of the reserves required in BAL003-1. LADWP recognizes that this recommendation may be handled through a separate NERC
Project, but wanted to submit this comment to bring light to this potential conflict in Reliability
Standards.
Response: Thank you for the observation.
Tacoma Power
The addition to the Frequency Bias Setting definition of “and discourage response withdrawal
through secondary control systems” seems incomplete. Tacoma Power does not see anything in
the standard that addresses (or measures) how a frequency bias setting will discourage response
withdrawal through secondary systems. This should either be more fully addressed or removed.
Consideration of Comments: Project 2007-12
102
003926
Organization
Question 9 Comment
Response: The FRI Report and the Background Documents contain explanations on this issue.
SERC OC Standards Review
Group
The comments expressed herein represent a consensus of the views of the above namedmembers
of the SERC OC Standards Review Group only and should not be construed as theposition of SERC
Reliability Corporation, its board, or its officers.
Response: Thank you for the clarification
Duke Energy
The concern raised in Duke Energy’s comments in item 4 will not be a factor for a few years, but
will be an issue as more and more BAs are in the position of their FRM being better than the
Interconnection Minimum allocation.
We believe that the language that we proposed for calculating the minimum FBS in a multiple-BA
Interconnection allows for the proper incentives for BAs to maintain FRM much better than
required, and allows for comparable measurement of secondary control performance between
similarly-sized BAs, while presenting no risk to reliability.
Response: Thank you for your comment. The industry will utilize information from the process related to this standard to make
future decisions. Also, please refer to our response to your Question #4 comment.
Puget Sound Energy
The definition of “Frequency Response Obligation” applies only to a Balancing Authority. However,
requirement R1 applies to both FRSGs and BAs and includes a Frequency Response Obligation that
applies to each of those entities. As a result, the definition must also address an FRSG’s Frequency
Response Obligation.
The acronym for Balancing Authority is not included following the first reference to the term in
requirement R1 (looks like an inadvertent deletion).
Requirement R1 states that an entity “... shall achieve an annual Frequency Response Measure
(FRM)....” However, the definition of Frequency Response Measure already includes the concept of
annual. As a result, the word “annual” should be removed from the requirement.
Requirement R1 includes the language “... to ensure that sufficient Frequency Response is provided
Consideration of Comments: Project 2007-12
103
003927
Organization
Question 9 Comment
by each FRSG or BA that is not a member of a FRSG to maintain Interconnection Frequency
Response equal to or more negative than the Interconnection Frequency Response Obligation.”
This language is a purpose statement rather than a requirement applicable to a FRSG or a BA and
should be excluded from the requirement. So long as an FRSG or BA achieves the FRM calculated
in accordance with Attachment A, it has done everything necessary to comply with the standard.
There are discrepancies between the implementation plan and the proposed standard:- The
definitions of “Frequency Response Measure” and “Frequency Response Obligation” in the
Implementation Plan are different from those proposed in the draft standard.- The Implementation
Plan references “Reserve Sharing Group” rather than “Frequency Response Sharing Group”.- The
Implementation Plan does not include a definition for the term “Frequency Response Sharing
Group”.The Implementation Plan continues to reference R5 in the discussion of the standard’s proposed
effective date.
The annual process dates listed on page 32 of the Background document appear to be inconsistent
with those listed in Attachment A.
Responses: Thank you for your comments.
The calculation of FRO is done at the individual BA level. Those BAs that are part of a FRSG must sum their individual FROs to
determine the FRSG FRO. This is clearly stated in Attachment A.
The drafting team corrected this oversight.
The drafting team disagrees that the term “annual” should be removed as it provides greater clarity as written.
The drafting team was advised by NERC staff to include the language you are referencing.
The drafting team has corrected the Implementation Plan.
The dates are not firm dates but are examples for the process.
California Independent System
Operator
The ISO supports the development of BAL-003-1 and would like to offer the following
comments/suggestions:
(1) Some BAs may have to develop a new Ancillary Service product to ensure that its FRO can be
met and believes that 12 months after FERC’s approval may not provide adequate time to
Consideration of Comments: Project 2007-12
104
003928
Organization
Question 9 Comment
stakeholder and modify market software applications. The ISO suggest increasing the
implementation timeline by at least one more year.
(2) If the implementation timeline cannot be changed, then the ISO suggests that compliance
should be waived for the first year of operation under BAL-003-1.
(3) Some BAs may elect to procure a portion of its FRO through bilateral agreements for certain
hours (e.g. off-peak) with a neighboring BA. Since a contingency could be in a BA other than the
two BAs under a bilateral agreement, the standard or background document needs to clarify the
duration of frequency response so that transmission reservation is not a requirement for frequency
response. The ISO believes that the BA experiencing the contingency should have adequate
arrangements in place to deal with internal contingencies.
Response: Thank you for your comments.
(1) The implementation date for Requirement R1 is 24 months after FERC approval, not 12 months. We believe that this would
provide ample time.
(2) See (1) above.
(3) The measurement period is 20 to 52 seconds after the beginning of the event. Additionally, there is no mention of
transmission requirements for purchase or delivery of Frequency Response.
Portland General Electric
Company
The issue with proposed Reliability Standard BAL-003-1, requirement R1, is that the Annual
Frequency Response Measure (FRM) is determined after the fact with an entity unable to identify
or monitor compliance (on non-compliance) along the way.
Also, the requirement seems to go the opposite direction of NERC’s risk based initiatives where
collecting historic compliance information become unsustainable.
Response: Thank you for your comments.
(1) The identification and posting of events will occur on a quarterly basis as stated in the Procedure Document. This will allow
BAs to monitor their compliance.
(2) The SDT believes that this is a performance based standard similar to BAL-001 CPS and BAL-002 DCS requirements.
Consideration of Comments: Project 2007-12
105
003929
Organization
Question 9 Comment
MRO NSRF
The MRO NSRF is concerned with the drafting team’s exclusion of single Balancing Authority
Interconnections from compliance with Requirement R2. To ensure a consistent approach in the
application of BAL-003-1, recommend R2 be revised as follows:
R2). Each Balancing Authority that is a member of a multiple Balancing Authority Interconnection
and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias Setting shall
implement the Frequency Bias Setting determined subject to Attachment A, as validated by the
ERO, into its Area Control Error (ACE) calculation ...
Response: Based on the comment rather than the proposed language the drafting team is providing the following response. The
drafting team discussed the applicability of bias requirements to single BA Interconnections extensively. The consensus of the
FRSDT was that single BA Interconnections inherently have strong incentives to accurately represent their frequency response
characteristic. Any adverse consequences of misrepresenting the frequency response characteristic will be borne solely by that BA
and cannot affect other BAs in other Interconnections adversely.
Southern Company
The organization selecting events must ensure that the change in frequency is outside the normal
dead-band of generator governors. Many of the events selected in the past have not been outside
the dead-band and therefore, the frequency response was much less than expected. Southern
Company proposes .07 which is consistant with WECC.
Response: Thank you for your comments. The drafting team has created a Procedure Document that details the event selection
criteria for each Interconnection. This should alleviate the concern of smaller events being selected.
Independent Electricity System
Operator
The proposed effective date for this standard conflicts with Ontario regulatory practice respecting
the effective date of implementing approved standards. It is suggested that this conflict be
removed by appending to each of Section A1.3 and A1.4, after “months after applicable regulatory
approval”, of the standard to the following effect:”, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.”The same change should be made to the
two bullets in the proposed Implementation Plan.
Response: The drafting team appreciates your comment. However, this language is required to be used by the drafting team with
Consideration of Comments: Project 2007-12
106
003930
Organization
Question 9 Comment
the only modification allowed to be the number of months prior to implementation.
Northeast Power Coordinating
Council
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard,
then GO’s and GOP’s should be included in the applicability since they are the entities responding
to the AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s
should be updated.
Response: The FRM is not intended to measure response to AGC signals but is intended to measure response to frequency
changes. Therefore, the drafting team does not believe that any modification is warranted.
Consolidated Edison Co. of NY,
Inc.
The VSL’s refer to the FRM (Frequency Response Measure). If that is the intent of the Standard,
then GO’s and GOP’s should be included in the applicability since they are the entities responding
to the AGC signals. If the intent is the FRO (Frequency Response Obligation) only, then the VSL’s
should be updated.
Response: The FRM is not intended to measure response to AGC signals but is intended to measure response to frequency
changes. Therefore, the SDT does not believe that any modification is warranted.
Tucson Electric Power
This is an important task and the efforts of the drafting team are appreciated.
Response: Thank you for the recognition.
The United Illuminating
Company
UI believes the VRF should be High. The VRF justification for Medium is that the prior year’s bias
setting would exist in the control system so the impact would not cause a Cascade. UI thinks that is
an adjustment factor that is applied after non-compliance is determined. Not having settings is
likely to cause cascade so the VRF is High.
Response: The drafting team reviewed the definition for the VRF levels and believes that the appropriate levels were used for
each requirement.
Tri-State Generation and
We are concerned with the tariff implictations associated with this standard. Will this standard
Consideration of Comments: Project 2007-12
107
003931
Organization
Question 9 Comment
Transmission Assn., Inc.
create the need for an additional ancillary service under the FERC pro forma OATT?
Response: The drafting team believes that your comment is possible but does not think that it is in the scope of NERC to make
changes to the FERC pro forma OATT.
NREL Transmission and Grid
Integration Group
We commend the drafting team for a rigorous approach to this new and important standard. Being
observers who have a strong interest in this standard as it applies to much of the research that we
do, but not stakeholders of the ultimate standard, we submit our overall comments as
recommendations here. We believe there are a few potential issues, that may at least need more
thought before going forward. The first is the credit for LR.
(1) Overfrequency can be an issue: using ERCOT as an example, with -282 MW/0.1Hz response and
1400 MW of LR all responsive at 59.7 Hz, if just meeting FRO requirements, the 1400MW LR can all
be triggered with a loss of (282*3=) 846MW, causing (1400-846=)554MW of overgeneration. This
can be exacerbated by further increases of LR without recognition of the triggering frequency, and
the disconnect between BA and interconnection in the other interconnections.
(2) With crediting LR toward the Interconnection, it will not give incentive toward BAs to provide
it. We believe the LR should contribute to the BA FRO rather than discount the IFRO.
(3) There is no requirement for frequency response capacity (ie MW) available to provide the FR.
This is a nonissue in today's world with the amount of spinning reserve already available, but the
issue could be apparent on future systems with increased reserve sharing, or reserve capacity from
resources that operate in modes which do not provide frequency response. The European
Interconnection requirement has two intentions: a 3,000 MW capacity requirement and a 1,500
MW/0.1Hz FRO requirement that is allocated out to its Transmission System Operators. This could
solve the issue with LR and generators, where LR is in MW and generation governing is in
MW/0.1Hz.
(4) It is likely, and from our understanding is true in some areas like ERCOT, that the LR is selected
based on market solutions, and may not be available all times of the year. This is another reason
why the LR should contribute to the BA FRO rather than discount the IFRO.
(5) It may be beneficial to guide frequency settings for LR or even multiple settings to mimic a
Consideration of Comments: Project 2007-12
108
003932
Organization
Question 9 Comment
droop curve for LR. Other potential issues not related to the LR. We think the SDT has done an
outstanding job on reviewing the data sets and determining statistically based values to better
account for different factors that may affect minimum frequency levels. We agree that there are
current issues in the primary governing response, but that there may be a disconnect in fixing
those issues with the static values. We also agree that there is not an easy solution. In specific:
(a) The static CB ratio might not incentivize BAs to improve response with increased inertia
or faster responding governing response.
(b) The static withdrawal BC'adj may not incentivize BAs to improve their governing
response and limit their withdrawal. Improved technology may allow for better
measurement to account for these issues dynamically rather than using static numbers.
Guidance on increasing inertia, increasing governing speed, and reducing withdrawal should
be considered by stakeholders. We thank NERC and the SDT for the opportunity to provide
comments on this important standard.
Response: Thank you for your comments.
(1) The standard as presently written addresses both over and under frequency events.
(2) The credit given for LCR is based on numbers provided by the interconnection. The utilization of load by any individual BA will
be included in the calculation of their FRM through the Net Actual Interchange term rather than the IFRO.
(3) Thank you for your comment.
(4) Please refer to our response to (2) above.
(5) Thank you for your comment. As more information is gained through implementation of this standard modifications based on
this information will be possible.
Ameren
While we support this draft, we believe that this might only be a starting point and as additional
knowledge and experience is gained through the implementation of this standard and other efforts
such as the FRI, that the improvements can be embraced by all parties, even if those improvements
result in relaxed requirements.
Response: Thank you for your comments. The NERC process allows for adjustments and improvements for both its thresholds and
Consideration of Comments: Project 2007-12
109
003933
Organization
Question 9 Comment
methodologies when operational experience has been gained.
Xcel Energy
Xcel Energy supports this proposed revision to the standard as a first step and suggests that after
operating for a couple of years under the revised standard, that NERC initiates a more complete
study to support any modifications to the standard.
Response: Thank you for your comment. The drafting team agrees.
END OF REPORT
Consideration of Comments: Project 2007-12
110
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003934
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
8. The draft standard was posted for a 45-day formal comment period and a 10 day initial
ballot from October 25, 2011 through December 8, 2011.
Proposed Action Plan and Description of Current Draft:
This is the third posting of the proposed standard and its associated documents for a 30 day
formal comment period and a successive 10 day ballot, from October 5, 2012 through November
5, 2012.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments submitted within the comment period
and with the successive ballot.
December, 2012
2. Conduct a recirculation ballot for ten days.
December, 2012
3. BOT adoption.
February, 2013
BAL-003-1
No ve m b e r 30, 2012
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003935
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Definitions of Terms used in the Standard
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s inverse Frequency Response contribution to the Interconnection, and
discourage response withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG) 1
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to jointly
meet the sum of the Frequency Response Obligations of its members.
1
This term and definition is identical to the definition in BAL-012-1 proposed standard.
BAL-003-1
No ve m b e r 30, 2012
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003936
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority (BA) to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to its scheduled
value. To provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.1.1
The Balancing Authority is the responsible entity unless the Balancing
Authority is a member of a Frequency Response Sharing Group, in which
case, the Frequency Response Sharing Group becomes the responsible
entity.
1.2. Frequency Response Sharing Group
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, R3 and
R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as
calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a FRSG
to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time
Horizon: Real-time Operations]
BAL-003-1
No ve m b e r 30, 2012
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003937
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency Bias Setting determined in
accordance with Attachment A, as validated by the ERO, into its Area Control Error
(ACE) calculation during the implementation period specified by the ERO and shall
use this Frequency Bias Setting until directed to change by the ERO. [Risk Factor:
Medium ][Time Horizon: Operations Planning]
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/- 0.036 Hz.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation, in order to represent the Frequency
Bias Setting for the combined Balancing Authority Area, to be equivalent to either:
[Risk Factor: Medium ][Time Horizon: Operations Planning]
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS
Form 2 for the participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
C. Measures
M1. Each Frequency Response Sharing Group or Balancing Authority that is not a member
of a Frequency Response Sharing Group shall have evidence such as dated data plus
documented formula in either hardcopy or electronic format that it achieved an annual
FRM (in accordance with the methods specified by the ERO in Attachment A with data
from FRS Form 1 reported to the ERO as specified in Attachment A) that is equal to or
more negative than its FRO to demonstrate compliance with Requirement R1.
M2. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service shall have evidence
such as a dated document in hard copy or electronic format showing the ERO validated
Frequency Bias Setting was implemented into its ACE calculation within the
implementation period specified or other evidence to demonstrate compliance with
Requirement R2.
M3. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and is utilizing variable
Frequency Bias shall have evidence such as a dated report in hard copy or electronic
format showing the average clock-minute average Frequency Bias Setting was less
than zero and during periods when the clock-minute average frequency was outside of
BAL-003-1
No ve m b e r 30, 2012
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003938
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
the range 59.964 Hz to 60.036 Hz was equal to or more negative than its Frequency
Response Obligation to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation as
specified in Requirement R4 to demonstrate compliance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3 and R4, Measures M1, M2, M3 and M4 for the current
year plus the previous three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Frequency Response Sharing Group shall retain data or evidence to show
compliance with Requirement R1 and Measure M1 for the current year plus the
previous three calendar years unless directed by its Compliance Enforcement
BAL-003-1
No ve m b e r 30, 2012
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003939
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority or Frequency Response Sharing Group is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and flat frequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
BAL-003-1
No ve m b e r 30, 2012
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003940
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R3
R4
Service and uses a
fixed Frequency
Bias Setting failed to
implement the
validated Frequency
Bias Setting value
into its ACE
calculation within
the implementation
period specified but
did so within 5
calendar days from
the implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting did not
implement the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 25 calendar
days from the
implementation
period specified by
the ERO.
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
is not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 1% but by at
most 10%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 10% but by at
most 20%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 20% but by at
most 30%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
obligation by more
than 30%..
BAL-003-1
No ve m b e r 30, 2012
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003941
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Overlap Regulation
Services with
combined footprint
setting-error less
than or equal to 10%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 10% but less
than or equal to 20%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 20% but less
than or equal to 30%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 30% of the
validated or
calculated value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
E. Regional Variance
None
F. Associated Documents
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
0
1
BAL-003-1
No ve m b e r 30, 2012
Date
April 1, 2005
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003942
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee approved the SAR for posting on January 13, 2005.
2. The SAR was posted for industry comment from January 17, 2005 through February 17,
2005.
3. Reply comments and a revised SAR were posted for a second industry comment period
from April 4, 2006 through May 3, 2006.
4. Reply comments and a revised SAR were posted for a third industry comment period
from February 8, 2007 through March 9, 2007.
5. Standards Committee approved moving the project into the standards development phase
on July 12, 2007.
6. The Standards Committee appointed the Standard Drafting Team on August 13, 2007.
7. The draft standard was posted for a 30 day formal comment period from February 4,
2011 through March 7, 2011.
8. The draft standard was posted for a 45-day formal comment period and a 10 day initial
ballot from October 25, 2011 through December 8, 2011.
Proposed Action Plan and Description of Current Draft:
This is the third posting of the proposed standard and its associated documents for a 30 day
formal comment period and a successive 10 day ballot, from October 5, 2012 through November
5, 2012.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments submitted within the comment period
and with the successive ballot.
December, 2012
2. Conduct a recirculation ballot for ten days.
December, 2012
3. BOT adoption.
February, 2013
BAL-003-1
No ve m b e r 30, 2012
Page 1 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003943
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Definitions of Terms used in the Standard
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s inverse Frequency Response contribution to the Interconnection, and
discourage response withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG) 1
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to jointly
meet the sum of the Frequency Response Obligations of its members.
1
This term and definition is identical to the definition in BAL-012-1 proposed standard.
BAL-003-1
No ve m b e r 30, 2012
Page 2 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003944
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
A. Introduction
Title: Frequency Response and Frequency Bias Setting
Number: BAL-003-1
Purpose: To require sufficient Frequency Response from the Balancing Authority (BA) to
maintain Interconnection Frequency within predefined bounds by arresting frequency
deviations and supporting frequency until the frequency is restored to its scheduled
value. To provide consistent methods for measuring Frequency Response and
determining the Frequency Bias Setting.
Applicability:
1.1. Balancing Authority
1.1.1
The Balancing Authority is the responsible entity unless the Balancing
Authority is a member of a Frequency Response Sharing Group, in which
case, the Frequency Response Sharing Group becomes the responsible
entity.
1.2. Frequency Response Sharing Group
Effective Date:
1.3. In those jurisdictions where regulatory approval is required, Requirements R2, R3
and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, Requirements R2, R3 and
R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
1.4. In those jurisdictions where regulatory approval is required, Requirements R1 of
this standard shall become effective the first calendar day of the first calendar
quarter 24 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, Requirements R1 of this standard shall
become effective the first calendar day of the first calendar quarter 24 months
after Board of Trustees adoption.
B. Requirements
R1.
Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as
calculated and reported in accordance with Attachment A) that is equal to or more
negative than its Frequency Response Obligation (FRO) to ensure that sufficient
Frequency Response is provided by each FRSG or BA that is not a member of a FRSG
to maintain Interconnection Frequency Response equal to or more negative than the
Interconnection Frequency Response Obligation. [Risk Factor: Medium ][Time
Horizon: Real-time Operations]
BAL-003-1
No ve m b e r 30, 2012
Page 3 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003945
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R2.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency Bias Setting determined in
accordance withsubject to Attachment A, as validated by the ERO, into its Area
Control Error (ACE) calculation during the implementation period specified by the
ERO and shall use this Frequency Bias Setting until directed to change by the ERO.
[Risk Factor: Medium ][Time Horizon: Operations Planning]
R3.
Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a Frequency Bias Setting that is: [Risk
Factor: Medium ][Time Horizon: Operations Planning]
3.1 Less than zero at all times, and
3.2 Equal to or more negative than its Frequency Response Obligation when
Frequency varies from 60 Hz by more than +/- 0.036 Hz.
R4.
Each Balancing Authority that is performing Overlap Regulation Service shall modify
its Frequency Bias Setting in its ACE calculation, in order to represent the Frequency
Bias Setting for the combined Balancing Authority Area, to be equivalent to either:
[Risk Factor: Medium ][Time Horizon: Operations Planning]
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS
Form 2 for the participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting shown on FRS Form 1 and FRS Form 2 for the
entirety of the participating Balancing Authorities’ Areas.
C. Measures
M1. Each Frequency Response Sharing Group or Balancing Authority that is not a member
of a Frequency Response Sharing Group shall have evidence such as dated data plus
documented formula in either hardcopy or electronic format that it achieved an annual
FRM )(in accordance with the methods specified by the ERO in Attachment A with
data from FRS Form 1 reported to the ERO as specified in Attachment A) that is equal
to or more negative than its FRO to demonstrate compliance with Requirement R1.
M2. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service shall have evidence
such as a dated document in hard copy or electronic format showing the ERO validated
Frequency Bias Setting was implemented into its ACE calculation within the
implementation period specified or other evidence to demonstrate compliance with
Requirement R2.
M3. The Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and is utilizing variable
Frequency Bias shall have evidence such as a dated report in hard copy or electronic
format showing the average clock-minute average Frequency Bias Setting was less
than zero and during periods when the clock-minute average frequency wasis outside
BAL-003-1
No ve m b e r 30, 2012
Page 4 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003946
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
of the range 59.964 Hz to 60.036 Hz was equal to or more negative than its Frequency
Response Obligation to demonstrate compliance with Requirement R3.
M4. The Balancing Authority shall have evidence such as a dated operating log, database or
list in hard copy or electronic format showing that when it performed Overlap
Regulation Service, it modified its Frequency Bias Setting in its ACE calculation as
specified in Requirement R4 to demonstrate compliance with Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity is the Compliance Enforcement Authority except where the
responsible entity works for the Regional Entity. Where the responsible entity
works for the Regional Entity, the Regional Entity will establish an agreement
with the ERO or another entity approved by the ERO and FERC (i.e. another
Regional Entity), to be responsible for compliance enforcement.
1.2. Compliance Monitoring and Assessment Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Balancing Authority shall retain data or evidence to show compliance with
Requirements R1, R2, R3 and R4, Measures M1, M2, M3 and M4 for the current
year plus the previous three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The Frequency Response Sharing Group shall retain data or evidence to show
compliance with Requirement R1 and Measure M1 for the current year plus the
previous three calendar years unless directed by its Compliance Enforcement
BAL-003-1
No ve m b e r 30, 2012
Page 5 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003947
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority or Frequency Response Sharing Group is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.4. Additional Compliance Information
For Interconnections that are also Balancing Authorities, Tie Line Bias control
and flat frequency control are equivalent and either is acceptable.
2.0 Violation Severity Levels
R#
Lower VSL
Medium VSL
High VSL
Severe VSL
R1
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one
is the greater
deviation from its
FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection was
equal to or more
negative than the
Interconnection’s
IFRO, and the
Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
1% but by at most
30% or 15 MW/0.1
Hz, whichever one is
the greater deviation
from its FRO
The summation of
the Balancing
Authorities’ FRM
within an
Interconnection did
not meet its IFRO,
and the Balancing
Authority’s, or
Frequency Response
Sharing Group’s,
FRM was less
negative than its
FRO by more than
30% or by more
than 15 MW/0.1 Hz,
whichever is the
greater deviation
from its FRO
R2
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
The Balancing
Authority in a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
BAL-003-1
No ve m b e r 30, 2012
Page 6 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003948
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
R3
R4
Service and uses a
fixed Frequency
Bias Setting failed to
implement the
validated Frequency
Bias Setting value
into its ACE
calculation within
the implementation
period specified but
did so within 5
calendar days from
the implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 5 calendar days
but less than or
equal to 15 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting
implemented the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 15 calendar
days but less than or
equal to 25 calendar
days from the
implementation
period specified by
the ERO.
Service and uses a
fixed Frequency
Bias Setting did not
implement the
validated Frequency
Bias Setting value
into its ACE
calculation in more
than 25 calendar
days from the
implementation
period specified by
the ERO.
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
is not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 1% but by at
most 10%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 10% but by at
most 20%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
member of a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
Obligation by more
than 20% but by at
most 30%.
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
The Balancing
Authority that is a
multiple Balancing
Authority
Interconnection and
not receiving
Overlap Regulation
Service and uses a
variable Frequency
Bias Setting average
Frequency Bias
Setting during
periods when the
clock-minute
average frequency
was outside of the
range 59.964 Hz to
60.036 Hz was less
negative than its
Frequency Response
obligation by more
than 30%..
BAL-003-1
No ve m b e r 30, 2012
The Balancing
Authority
incorrectly changed
the Frequency Bias
Setting value used in
its ACE calculation
when providing
Page 7 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003949
S ta n d a rd BAL-003-1 — Fre q u e n c y Re s p o n s e a n d Fre q u e n c y Bia s S e ttin g
Overlap Regulation
Services with
combined footprint
setting-error less
than or equal to 10%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 10% but less
than or equal to 20%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 20% but less
than or equal to 30%
of the validated or
calculated value.
Overlap Regulation
Services with
combined footprint
setting-error more
than 30% of the
validated or
calculated value.
OR
The Balancing
Authority failed to
change the
Frequency Bias
Setting value used in
its ACE calculation
when providing
Overlap Regulation
Services.
E. Regional Variance
None
F. Associated Documents
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
FRS Form 1
FRS Form 2
Frequency Response Standard Background Document
G. Version History
Version
0
1
BAL-003-1
No ve m b e r 30, 2012
Date
April 1, 2005
Action
Change Tracking
Effective Date
New
Complete Revision under
Project 2007-12
Revision
Page 8 of 8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003950
Attachment A
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Supporting Document
Interconnection Frequency Response Obligation (IFRO)
The ERO, in consultation with regional representatives, has established a target contingency protection
criterion for each Interconnection called the Interconnection Frequency Response Obligation (IFRO).
The default IFRO listed in Table 1 is based on the resource contingency criteria (RCC), which is the largest
category C (N-2) event identified except for the Eastern Interconnection, which uses the largest event in
the last 10 years. A maximum delta frequency (MDF) is calculated by adjusting a starting frequency for
each Interconnection by the following:
•
•
•
•
Prevailing UFLS first step
CCAdj which is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data
CBR which is the statistically determined ratio of the Point C to Value B
BC’Adj which is the statistically determined adjustment for the event nadir being below the Value
B (Eastern Interconnection only) during primary frequency response withdrawal.
The IFRO for each Interconnection in Table 1 is then calculated by dividing the RCC MWs by 10 times the
MDF. In the Eastern Interconnection there is an additional adjustment (BC’Adj) for the event nadir being
below the Value B due to primary frequency response withdrawal. This IFRO includes uncertainty
adjustments at a 95 % confidence level. Detailed descriptions of the calculations used in Table 1 below
are defined in the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard.
Interconnection
Starting Frequency (FStart)
Prevailing UFLS First Step
Base Delta Frequency (DFBase)
CCADJ
Delta Frequency (DFCC)
CBR
November 30, 2012
Eastern
59.974
59.5*
0.474
0.007
0.467
1.000
Western
59.976
59.5
0.476
0.004
0.472
1.625
ERCOT
59.963
59.3
0.663
0.012
0.651
1.377
HQ
59.972
58.5
1.472
N/A
1.472
1.550
Units
Hz
Hz
Hz
Hz
Hz
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
Delta Frequency (DFCBR)
0.467
0.291
0.473
0.949
BC’ADJ
0.018
N/A
N/A
N/A
Max. Delta Frequency (MDF)
0.449
0.291
0.473
0.949
Resource Contingency Criteria
(RCC)
4,500
2,740
2,750
1,700
Credit for Load Resources
(CLR)
300
1,400**
IFRO
-1,002
-840
-286
-179
Table 1: Interconnection Frequency Response Obligations
003951
Hz
Hz
MW
MW
MW/0.1 Hz
*The Eastern Interconnection UFLS set point listed is a compromise value set midway between
the stable frequency minimum established in PRC-006-1 (59.3 Hz) and the local protection UFLS
setting of 59.7 Hz used in Florida and Manitoba.
**In the Base Obligation measure for ERCOT, 1400 MW (Load Resources triggered by Under Frequency
Relays at 59.70 Hz) was reduced from its Resource Contingency Criteria level of 2750 MW to get 239
MW/0.1 Hz. This was reduced to accurately account for designed response from Load Resources within 30
cycles.
An Interconnection may propose alternate IFRO protection criteria to the ERO by submitting a SAR with
supporting technical documentation.
Balancing Authority Frequency Response Obligation (FRO) and
Frequency Bias Setting
The ERO will manage the administrative procedure for annually assigning an FRO and implementation of
the Frequency Bias Setting for each Balancing Authority. The annual timeline for all activities described
in this section are shown below.
For a multiple Balancing Authority interconnection, the Interconnection Frequency Response Obligation
shown in Table 1 is allocated based on the Balancing Authority annual load and annual generation. The
FRO allocation will be based on the following method:
FRO IFRO
Annual Gen Annual Load
Annual Gen Annual Load
Where:
• Annual GenBA is the total annual “Output of Generating Plants” within the Balancing Authority
Area (BAA), on FERC Form 714, column c of Part II - Schedule 3.
• Annual LoadBA is total annual Load within the BAA, on FERC Form 714, column e of Part II Schedule 3.
• Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
• Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
November 30, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003952
The data used for this calculation is from the most recently filed Form 714. As an example, a report to
NERC in January 2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to assemble
and submit equivalent data to the ERO for use in the FRO Allocation process.
Balancing Authorities that elect to form a FRSG will calculate a FRSG FRO by adding together the
individual BA FRO’s.
Balancing Authorities that elect to form a FRSG as a means to jointly meet the FRO will calculate their
FRM performance one of two ways:
•
•
Calculate a group NIA and measure the group response to all events in the reporting year on a
single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that contains the sum
of each participant’s individual event performance.
Balancing Authorities that merge or that transfer load or generation are encouraged to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation to the
Interconnection remains the same and so that CPS limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM), Frequency
Bias Setting and Frequency Bias type (fixed or variable) to the ERO each year to allow the ERO to validate
the revised Frequency Bias Settings on FRS Form 1. If the ERO posts the official list of events after the
date specified in the timeline below, Balancing Authorities will be given 30 days from the date the ERO
posts the official list of events to submit their FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing Authorities,
the ERO will use FRS Form 1 data to post the following information for each Balancing Authority for the
upcoming year:
•
•
Frequency Bias Setting
Frequency Response Obligation (FRO)
Once the data listed above is fully posted, the ERO will announce the three-day implementation period
for changing the Frequency Bias Setting if it differs from that shown in the timeline below.
A BA using a fixed Frequency Bias Setting sets its Frequency Bias Setting to the greater of (in absolute
value):
•
•
Any number the BA chooses between 100% and 125% of its Frequency Response Measure as
calculated on FRS Form 1
Interconnection Minimum as determined by the ERO
November 30, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003953
For purposes of calculating the minimum Frequency Bias Setting, a Balancing Authority participating in a
Frequency Response Sharing Group will need to calculate its stand-alone Frequency Response Measure
using FRS Form 1 and FRS Form 2 to determine its minimum Frequency Bias Setting.
A Balancing Authority providing Overlap Regulation will report the historic peak demand and generation
of its combined BAs’ areas on FRS Form 1 as described in Requirement R4.
There are occasions when changes are needed to Bias Settings outside of the normal schedule.
Examples are footprint changes between Balancing Authorities and major changes in load or generation
or the formation of new Balancing Authorities. In such cases the changing Balancing Authorities will
work with their Regions, NERC and the Resources Subcommittee to confirm appropriate changes to Bias
Settings, FRO, CPS limits and Inadvertent Interchange balances.
If there is no net change to the Interconnection total Bias, the Balancing Authorities involved will agree
on a date to implement their respective change in Bias Settings. The Balancing Authorities and ERO will
also agree to the allocation of FRO such that the sum remains the same.
If there is a net change to the Interconnection total Bias, this will cause a change in CPS2 limits and FRO
for other Balancing Authorities in the Interconnection. In this case, the ERO will notify the impacted
Balancing Authorities of their respective changes and provide an implementation window for making
the Bias Setting changes.
Frequency Response Measure (FRM)
The Balancing Authority will calculate its FRM from Single Event Frequency Response Data (SEFRD),
defined as: “the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz” as calculated on FRS Form 2 for each event shown on FRS
Form 1. The events in FRS Form 1 are selected by the ERO using the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change in its Net Actual
Interchange on its tie lines with its adjacent Balancing Authorities divided by the change in
Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to their Net
Actual Interchange (NAI) values to account for factors such as nonconforming loads. FRS Form 1 and 2
shows the types of adjustments that are allowed. Note that with the exception of the Contingent BA
column, any adjustments made must be made for all events in an evaluation year. As an example, if an
entity has non-conforming loads and makes an adjustment for one event, all events must show the nonconforming load, even if the non-conforming load does not impact the calculation. This ensures that the
reports are not utilizing the adjustments only when they are favorable to the BA.) The ERO will use a
standardized sampling interval of approximately 16 seconds before the event up to the time of the
event for the pre-event NAI, and frequency (A values) and approximately 20 to 52 seconds after the
event for the post-event NAI (B values) in the computation of SEFRD values, dependent on the data scan
rate of the Balancing Authority’s Energy Management System (EMS).
November 30, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003954
All events listed on FRS Form 1 need to be included in the annual submission of FRS Forms 1 and 2. The
only time a Balancing Authority should exclude an event is if its tie-line data or its Frequency data is
corrupt or its EMS was unavailable. FRS Form 2 has instructions on how to correct the BA’s data if the
given event is internal to the BA or if other authorized adjustments are used.
Assuming data entry is correct FRS Form 1 will automatically calculate the Balancing Authority’s FRM for
the past 12 months as the median of the SEFRD values. A Balancing Authority electing to report as an
FRSG or a provider of Overlap Regulation Service will provide an FRS Form 1 for the aggregate of its
participants.
To allow Balancing authorities to plan its operations, events with a “Point C” that cause the
Interconnection Frequency to be lower than that shown in Table 1 above (for example, an event in the
Eastern Interconnection that causes the Interconnection Frequency to go to 59.4 Hz) or higher than an
equal change in frequency going above 60 Hz may be included in the list of events for that
interconnection. However, the calculation of the BA response to such an event will be adjusted to show
a frequency change only to the Target Minimum Frequency shown in Table 1 above (in the previous
example this adjustment would cause Frequency to be shown as 59.5 Hz rather than 59.4 HZ) or a high
frequency amount of an equal quantity. Should such an event happen, the ERO will provide additional
guidance.
November 30, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003955
Timeline for Balancing Authority Frequency Response and Frequency
Bias Setting Activities
Described below is the timeline for the exchange of information between the ERO and Balancing
Authorities (BA) to:
•
•
•
Facilitate the assignment of BA Frequency Response Obligations (FRO)
Calculate BA Frequency Response Measures (FRM)
Determine BA Frequency Bias Settings (FBS)
Target Date
Activity
April 30
The ERO reviews candidate frequency events and selects frequency events for the
first quarter (December to February).
May 10
Form1 is posted with selected events from the first quarter for BA usage by the
ERO.
May 15
The BAs receive a request to provide load and generation data as described in
Attachment A to support FRO assignments and determining minimum FBS for
BAs.
July 15
The BAs provide load and generation data as described in Attachment A to the
ERO.
July 30
The ERO reviews candidate frequency events and selects frequency events for the
second quarter (March to May).
August 10
Form1 is posted with selected events from the first and second quarters for BA
usage by the ERO.
October 30
The ERO reviews candidate frequency events and selects frequency events for the
third quarter (June to August)
November 10
Form1 is posted with selected events from the first, second, and third quarters for
BA usage by the ERO.
November 20
If necessary, the ERO provides any updates to the necessary Frequency Response.
November 20
The ERO provides the fractional responsibility of each BA for the Interconnection’s
FRO and Minimum FBS to the BAs.
January 30
The ERO reviews candidate frequency events and selects frequency events for the
fourth quarter (September to November).
November 30, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003956
2nd business day in
February
Form1 is posted with all selected events for the year for BA usage by the ERO.
February 10
The ERO assigns FRO values to the BAs for the upcoming year.
March 7
BAs complete their frequency response sampling for all four quarters and their
FBS calculation, returning the results to the ERO.
March 24
The ERO validates FBS values, computes the sum of all FBS values for each
Interconnection, and determines L10 values for the CPS 2 criterion for each BA as
applicable.
Any time during
first 3 business
days of April
(unless specified
otherwise by the
ERO)
The BA implements any changes to their FBS and L10 value.
November 30, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003957
Attachment A
BAL-003-1 Frequency Response & Frequency Bias Setting Standard
Supporting Document
Interconnection Frequency Response Obligation (IFRO) for the
Interconnection
The ERO, in consultation with regional representatives, has established a target contingency protection
criterion for each Interconnection called the Interconnection Frequency Response Obligation (IFRO).
The default IFROtarget listed in Table 1 is based on the resource contingency criteria (RCC), which is the
largest category C (N-2) event identified except for the Eastern Interconnection, which uses the largest
event in the last 10 years. A maximum delta frequency (MDF) is calculated by adjusting a starting
frequency for each Interconnection by the following:
•
•
•
•
Prevailing UFLS first step
CCAdj which is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data
CBR which is the statistically determined ratio of the Point C to Value B
BC’Adj which is the statistically determined adjustment for the event nadir being below the Value
B (Eastern Interconnection only) during primary frequency response withdrawal.
Additionally, this contingency protection criterion includes uncertainty adjustments at a 95 %
confidence level to prevent Point C from encroaching on the interconnection’s highest Under Frequency
Load Shed (UFLS) step for credible contingencies. The IFROObligation for each Interconnection in Table
1 is then calculated by dividing the RCTarget Protection Criteria MWs by 10 times the MDFdifference
between the starting frequency and the Prevailing UFLS First Step. This number is then multiplied by the
C to B Ratio to arrive at a MW/0.1 Hz number. In the Eastern Interconnection there is an additional
adjustment (BC’Adj) for the event nadir being below the Value B due to primary frequency response
withdrawal. This Interconnection Frequency Response Obligation (IFRO) includes uncertainty
adjustments at a 95 % confidence level. Detailed descriptions of the calculations used in Table 1 below
are defined in the Procedure for ERO Support of Frequency Response and Frequency Bias Setting
Standard.
Interconnection
November 30, 2012
Eastern
Western
ERCOT
HQ
Units
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
Starting Frequency (FStart)
59.974
59.976
59.963
59.972
Prevailing UFLS First Step
59.5*
59.5
59.3
58.5
Base Delta Frequency (DFBase)
0.474
0.476
0.663
1.472
CCADJ
0.007
0.004
0.012
N/A
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
CBR
1.000
1.625
1.377
1.550
Delta Frequency (DFCBR)
0.467
0.291
0.473
0.949
BC’ADJ
0.018
N/A
N/A
N/A
Max. Delta Frequency (MDF)
0.449
0.291
0.473
0.949
Resource Contingency Criteria
(RCC)
4,500
2,740
2,750
1,700
Credit for Load Resources
(CLR)
300
1,400**
IFRO
-1,002
-840
-286
-179
Table 1: Interconnection Frequency Response Obligations
003958
Hz
Hz
Hz
Hz
Hz
Hz
Hz
Hz
MW
MW
MW/0.1 Hz
*The Eastern Interconnection UFLS set point listed is a compromise value set midway between
the stable frequency minimum established in PRC-006-1 (59.3 Hz) and the local protection UFLS
setting of 59.7 Hz used in Florida and Manitoba.
**In the Base Obligation measure for ERCOT, 1400 MW (Load Resources triggered by Under Frequency
Relays at 59.70 Hz) was reduced from its Resource Contingency Protection Criteria level of 2750 MW to get
239 MW/0.1 Hz. This was reduced to accurately account for designed response from Load Resources
within 30 cycles.
An Interconnection may propose alternate IFRO protection criteria to the ERO by submitting a SAR with
supporting technical documentation.
Balancing Authority Frequency Response Obligation (FRO) and
Frequency Bias Setting
The ERO will manage the administrative procedure for annually assigning an FRO and implementation of
the Frequency Bias Setting for each Balancing Authority. The annual timeline for all activities described
in this section are shown below.
For a multiple Balancing Authority interconnection, the Interconnection Frequency Response Obligation
shown in Table 1 is allocated based on the Balancing Authority annual load and annual generation. The
FRO allocation will be based on the following method:
FRO IFRO
Annual Gen Annual Load
Annual Gen
Annual Load
Where:
November 30, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
•
•
•
•
003959
Annual GenBA is the total annual “Output of Generating Plants” within the Balancing Authority
Area (BAA), on FERC Form 714, column c of Part II - Schedule 3.
Annual LoadBA is total annual Load within the BAA, on FERC Form 714, column e of Part II Schedule 3.
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
The data used for this calculation is from the most recently filed Form 714. As an example, a report to
NERC in January 2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to assemble
and submit equivalent data to the ERO for use in the FRO Allocation process.
Balancing Authorities that elect to form a FRSG will calculate a FRSG FRO by adding together the
individual BA FRO’s.
Balancing Authorities that elect to form a FRSG as a means to jointly meet the FRO will calculate their
FRM performance one of two ways:
•
•
Calculate a group NIA and measure the group response to all events in the reporting year on a
single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that that contains the
sum of each participant’s individual event performance.
Balancing Authorities that merge or that transfer load or generation are encouraged to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation to the
Interconnection remains the same and so that CPS limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM), Frequency
Bias Setting and Frequency Bias type (fixed or variable) to the ERO each year to allow the ERO to validate
the revised Frequency Bias Settings on FRS Form 1. If the ERO posts the official list of events after the
date specified in the timeline below, Balancing Authorities will be given 30 days from the date the ERO
posts the official list of events to submit their FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing Authorities,
the ERO will use FRS Form 1 data to post the following information for each Balancing Authority for the
upcoming year:
•
•
Frequency Bias Setting
Frequency Response Obligation (FRO)
Once the data listed above is fully posted, the ERO will announce the three-day implementation period
for changing the Frequency Bias Setting if it differs from that shown in the timeline below.
November 30, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003960
A BA using a fixed Frequency Bias Setting sets its Frequency Bias Setting to the greater of (in absolute
value):
•
•
Any number the BA chooses between 100% and 125% of its Frequency Response Measure as
calculated on FRS Form 1
Interconnection Minimum as determined by the ERO
For purposes of calculating the minimum Frequency Bias Setting, a Balancing Authority participating in a
Frequency Response Sharing Group will need to calculate its stand-alone Frequency Response Measure
using FRS Form 1 and FRS Form 2 to determine its minimum Frequency Bias Setting.
A Balancing Authority providing Overlap Regulation will report the historic peak demand and generation
of its combined BAs’ areas on FRS Form 1 as described in Requirement R4.
There are occasions when changes are needed to Bias Settings outside of the normal schedule.
Examples are footprint changes between Balancing Authorities and major changes in load or generation
or the formation of new Balancing Authorities. In such cases the changing Balancing Authorities will
work with their Regions, NERC and the Resources Subcommittee to confirm appropriate changes to Bias
Settings, FRO, CPS limits and Inadvertent Interchange balances.
If there is no net change to the Interconnection total Bias, the Balancing Authorities involved will agree
on a date to implement their respective change in Bias Settings. The Balancing Authorities and ERO will
also agree to the allocation of FRO such that the sum remains the same.
If there is a net change to the Interconnection total Bias, this will cause a change in CPS2 limits and FRO
for other Balancing Authorities in the Interconnection. In this case, the ERO will notify the impacted
Balancing Authorities of their respective changes and provide an implementation window for making
the Bias Setting changes.
Frequency Response Measure (FRM)
The Balancing Authority will calculate its FRM from Single Event Frequency Response Data (SEFRD),
defined as: “the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz” as calculated on FRS Form 2 for each event shown on FRS
Form 1. The events in FRS Form 1 are selected by the ERO using the Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change in its Net Actual
Interchange on its tie lines with its adjacent Balancing Authorities divided by the change in
Interconnection frequency. (Some Balancing Authorities may choose to apply corrections to their Net
Actual Interchange (NAI) values to account for factors such as nonconforming loads. FRS Form 1 and 2
shows the types of adjustments that are allowed. Note that with the exception of the Contingent BA
column, any adjustments made must be made for all events in an evaluation year. As an example, if an
entity has non-conforming loads and makes an adjustment for one event, all events must show the nonconforming load, even if the non-conforming load does not impact the calculation. This ensures that the
November 30, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003961
reports are not utilizing the adjustments only when they are favorable to the BA.) The ERO will use a
standardized sampling interval of approximately 16 seconds before the event up to the time of the
event for the pre-event NAI, and frequency (A values) and approximately 20 to 52 seconds after the
event for the post-event NAI (B values) in the computation of SEFRD values, dependent on the data scan
rate of the Balancing Authority’s Energy Management System (EMS).
All events listed on FRS Form 1 need to be included in the annual submission of FRS Forms 1 and 2. The
only time a Balancing Authority should exclude an event is if its tie-line data or its Frequency data is
corrupt or its EMS was unavailable. FRS Form 2 has instructions on how to correct the BA’s data if the
given event is internal to the BA or if other authorized adjustments are used.
Assuming data entry is correct FRS Form 1 will automatically calculate the Balancing Authority’s FRM for
the past 12 months as the median of the SEFRD values. A Balancing Authority electing to report as an
FRSG or a provider of Overlap Regulation Service will provide an FRS Form 1 for the aggregate of its
participants.
To allow Balancing authorities to plan its operations, events with a “Point C” that cause the
Interconnection Frequency to be lower than that shown in Table 1 above (for example, an event in the
Eastern Interconnection that causes the Interconnection Frequency to go to 59.4 Hz) or higher than an
equal change in frequency going above 60 Hz may be included in the list of events for that
interconnection. However, the calculation of the BA response to such an event will be adjusted to show
a frequency change only to the Target Minimum Frequency shown in Table 1 above (in the previous
example this adjustment would cause Frequency to be shown as 59.5 Hz rather than 59.4 HZ) or a high
frequency amount of an equal quantity. Should such an event happen, the ERO will provide additional
guidance.
November 30, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003962
Timeline for Balancing Authority Frequency Response and Frequency
Bias Setting Activities
Described below is the timeline for the exchange of information between the ERO and Balancing
Authorities (BA) to:
•
•
•
Facilitate the assignment of BA Frequency Response Obligations (FRO)
Calculate BA Frequency Response Measures (FRM)
Determine BA Frequency Bias Settings (FBS)
Target Date
Activity
April 30
The ERO reviews candidate frequency events and selects frequency events for the
first quarter (December to February).
May 10
Form1 is posted with selected events from the first quarter for BA usage by the
ERO.
May 15
The BAs receive a request to provide load and generation data as described in
Attachment A to support FRO assignments and determining minimum FBS for
BAs.
July 15
The BAs provide load and generation data as described in Attachment A to the
ERO.
July 30
The ERO reviews candidate frequency events and selects frequency events for the
second quarter (March to May).
August 10
Form1 is posted with selected events from the first and second quarters for BA
usage by the ERO.
October 30
The ERO reviews candidate frequency events and selects frequency events for the
third quarter (June to August)
November 10
Form1 is posted with selected events from the first, second, and third quarters for
BA usage by the ERO.
November 20
If necessary, the ERO provides any updates to the necessary Frequency Response.
November 20
The ERO provides the fractional responsibility of each BA for the Interconnection’s
FRO and Minimum FBS to the BAs.
January 30
The ERO reviews candidate frequency events and selects frequency events for the
fourth quarter (September to November).
November 30, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Attachment A
BAL-003-1 Frequency Response and Frequency Bias Setting
Supporting Document
003963
2nd business day in
February
Form1 is posted with all selected events for the year for BA usage by the ERO.
February 10
The ERO assigns FRO values to the BAs for the upcoming year.
March 7
BAs complete their frequency response sampling for all four quarters and their
FBS calculation, returning the results to the ERO.
March 24
The ERO validates FBS values, computes the sum of all FBS values for each
Interconnection, and determines L10 values for the CPS 2 criterion for each BA as
applicable.
Any time during
first 3 business
days of April
(unless specified
otherwise by the
ERO)
The BA implements any changes to their FBS and L10 value.
November 30, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003964
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b should be retired midnight of the day immediately prior to the Effective Date of BAL-0031 in the Jurisdiction in which the new standard is becoming effective.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4
and R5 become effective:
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually by Balancing Authorities for frequency events specified
by the ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
This will be calculated as MW/0.1Hz.
Frequency Bias Setting: A number, either fixed or variable, , usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s inverse Frequency Response contribution to the
Interconnection, and discourage withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG) 1: A group, whose members consist
of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of
its members.
The existing definition of Frequency Bias Setting should be retired midnight of the day immediately prior
to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming effective.
1
This term and definition is identical to the definition in BAL-012-1 proposed standard.
November, 2012
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003965
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved standards:
•
BAL-001-0.1a Real Power Balancing Control Performance
•
BAL-004-0 Time Error Correction
•
BAL-004-1 Time Error Correction
•
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
•
Frequency Response Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R2, R3 and R4 of this
standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R2, R3 and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter 24 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, Requirements R1 of this standard shall become effective the first calendar day of
the first calendar quarter 24 months after Board of Trustees adoption.
•
Requirement R1 cannot be implemented prior to the addition of Frequency Response Sharing
Group to the Compliance Registry.
November, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003966
Implementation Plan for BAL-003-1 – Frequency Response & Frequency Bias
Setting Standard
Prerequisite Approvals
There are no other reliability standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Modified Standards
BAL-003-0.1b should be retired midnight of the day immediately prior to the Effective Date of BAL-0031 in the Jurisdiction in which the new standard is becoming effective.
New or Modified Definitions
The following definitions shall become effective when BAL-003-1 Requirements R2, R3, R4
and R5 become effective:
Frequency Response Measure (FRM): The median of all the Frequency Response
observations reported annually by Balancing Authorities for frequency events specified
by the ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO): The Balancing Authority’s share of the
required Frequency Response needed for the reliable operation of an Interconnection.
This will be calculated as MW/0.1Hz.
Frequency Bias Setting: A number, either fixed or variable, , usually expressed in
MW/0.1 Hz, included in a Balancing Authority’s Area Control Error equation to account
for the Balancing Authority’s inverse Frequency Response contribution to the
Interconnection, and discourage withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG) 1: A group, whose members consist
of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating resources required to jointly meet the Frequency Response Obligations of
its members.
The existing definition of Frequency Bias Setting should be retired midnight of the day immediately prior
to the Effective Date of BAL-003-1 in the Jurisdiction in which the new standard is becoming effective.
1
This term and definition is identical to the definition in BAL-012-1 proposed standard.
November, 2012
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003967
Implementation Plan for BAL-003-1 – Frequency Response and Frequency Bias
The proposed revised definition for “Frequency Bias Setting” is incorporated in the following
NERC approved standards:
•
BAL-001-0.1a Real Power Balancing Control Performance
•
BAL-004-0 Time Error Correction
•
BAL-004-1 Time Error Correction
•
BAL-005-0.1b Automatic Generation Control
Compliance with Standards
Once this standard becomes effective, the responsible entities identified in the applicability section of the
standard must comply with the requirements. These include:
•
Balancing Authorities
•
Frequency Response Sharing Groups
Proposed Effective Date
Compliance with BAL-003-1 shall be implemented over a two-year period, as follows:
•
In those jurisdictions where regulatory approval is required, Requirements R2, R3 and R4 of this
standard shall become effective the first calendar day of the first calendar quarter 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
Requirements R2, R3 and R4 of this standard shall become effective the first calendar day of the first
calendar quarter 12 months after Board of Trustees adoption.
•
In those jurisdictions where regulatory approval is required, Requirements R1 of this
standard shall become effective the first calendar day of the first calendar quarter 24 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, Requirements R1 of this standard shall become effective the first calendar day of
the first calendar quarter 24 months after Board of Trustees adoption.
•
Requirement R1 cannot be implemented prior to the addition of Frequency Response Sharing
Group to the Compliance Registry.
November, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003968
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
This procedure outlines the Electric Reliability Organization (ERO) process for supporting the Frequency
Response Standard (FRS). A Procedure revision request may be submitted to the ERO for consideration.
The revision request must provide a technical justification for the suggested modification. The ERO shall
post the suggested modification for a 45-day formal comment period and discuss the revision request in
a public meeting. The ERO will make a recommendation to the NERC BOT, which may adopt the revision
request, reject it, or adopt it with modifications. Any approved revision to this Procedure shall be filed
with FERC for informational purposes.
Event Selection Process
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of
frequency events to be used by Balancing Authorities (BA) to calculate their Frequency Response to
determine:
•
•
Whether the BA met its Frequency Response Obligation, and
An appropriate fixed Bias Setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for analysis. The
events that best fit the criteria will be used to support the FRS. The evaluation period for
performing the annual Frequency Bias Setting and the Frequency Response Measure (FRM)
calculation is December 1 of the prior year through November 30 of the current year.
2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating
the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion
events in a 12 month evaluation period satisfying the criteria below, then similar acceptable
events from the subsequent year’s evaluation period will be included with the data set by the
ERO for determining FRS compliance. This is described later.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the
FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C and
the arrested frequency Point C exceeds the excursion threshold values specified for the
Interconnection in Table 1 below.
i. The A Value is computed as an average over the period from -16 seconds to 0
seconds before the frequency transient begins to decline.
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
November 30, 2012
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003969
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection
East
West
ERCOT
HQ
A Value
to Pt C
0.04Hz
0.07Hz
0.15Hz
0.30Hz
Point C (Low)
< 59.96
< 59.95
< 59.90
< 59.85
Point C (High)
> 60.04
> 60.05
> 60.10
> 60.15
Table 1: Interconnection Frequency Excursion Threshold Values
b. The time from the start of the rapid change in frequency until the point at which
Frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not be
included.
4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The
A Value is computed as an average over the period from -16 seconds to 0 seconds before the
frequency transient begins to decline. For example, given the choice of the two events below,
the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60
Hz.
5. Excursions that include 2 or more events that do not stabilize within 18 seconds will not be
considered.
6. Frequency excursion events occurring during periods:
(i) when large interchange schedule ramping or load change is happening, or
(ii) within 5 minutes of the top of the hour,
November 30, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003970
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
will be excluded from consideration if other acceptable frequency excursion events from the
same quarter are available.
7. The ERO will select the largest (A Value to Point C) 2 or 3 frequency excursion events occurring
each month. If there are not 2 frequency excursion events satisfying the selection criteria in a
month, then other frequency excursion events should be picked in the following sequence:
a. From the same event quarter of the year.
b. From an adjacent month.
c. From a similar load season in the year (shoulder vs. summer/winter)
d. The largest unused event.
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable
events from the next year’s evaluation period will be included with the data set by the ERO for
determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be
reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a
24 month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation. The
ERO will post the final list of frequency excursion events used for standard compliance as specified in
Attachment A of BAL-003-1. The following is a general description of the process that the ERO will use
to ensure that BAs can evaluate events during the year in order to monitor their performance
throughout the year.
Monthly
Candidate events will be initially screened by the "Frequency Event Detection Methodology" shown on
the following link located on the NERC Resources Subcommittee area of the NERC website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oct_2011.p
df. Each month's list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under "Candidate Frequency Events".
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
•
•
•
•
December through February
March through May
June through August
September through November
November 30, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003971
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Based on criteria established in the "Procedure for ERO Support of Frequency Response and Frequency
Bias Setting Standard", events will be selected to populate the FRS Form 1 for each Interconnection.
The Form 1's will be posted on the NERC website, in the Resources Subcommittee area under the title
"Frequency Response Standard Resources". Updated Form 1's will be posted at the end of each quarter
listed above after a review by the NERC RS' Frequency Working Group. While the events on this list are
expected to be final, as outlined in the selection criteria, additional events may be considered, if the
number of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the
year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters
listed above, will be posted as specified in Attachment A. Each Balancing Authority reports its previous
year’s Frequency Response Measure (FRM), Frequency Bias Setting and Frequency Bias type (fixed or
variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for
errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in
Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility in when
each BA implements its settings.
November 30, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003972
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Process for Adjusting Interconnection Minimum Frequency Bias Setting
This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to
better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance
with this procedure.
The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other
balancing standard limits.
Under BAL-003-1, the minimum Frequency Bias Settings will be moved toward the natural Frequency
Response in each interconnection. In the first year, the minimum Frequency Bias Setting for each
interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is
based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714
Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table
2 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum
Frequency Bias Setting is allocated among the BAs on an interconnection using the same allocation
method as is used for the allocation of the Frequency Response Obligation (FRO).
Interconnection
Eastern
Western
ERCOT*
HQ*
Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)
0.9% of non-coincident peak load
0.9% of non-coincident peak load
N/A
N/A
Table 2. Frequency Bias Setting Minimums
*The minimum Frequency Bias Setting requirement does not apply to a Balancing Authority that
is the only Balancing Authority in its Interconnection. These Balancing Authorities are solely
responsible for providing reliable frequency control of their Interconnection. These Balancing
Authorities are responsible for converting frequency error into a megawatt error to provide
reliable frequency control, and the imposition of a minimum bias setting greater than the
magnitude the Frequency Response Obligation may have the potential to cause control system
hunting, and instability in the extreme.
The ERO, in coordination with the regions of each interconnection, will annually review Frequency Bias
Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds
(in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value)
than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting
for BAs within that Interconnection may be reduced (in absolute value) in the subsequent years FRS
Form 1 based on the technical evaluation and consultation with the regions affected by 0.1 percentage
point of peak load (expressed in MW/0.1Hz) to better match that Frequency Bias Setting and natural
Frequency Response.
November 30, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003973
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
The ERO, in coordination with the regions of each Interconnection, will monitor the impact of the
reduction of minimum frequency bias settings, if any, on frequency performance, control performance,
and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish postcontingency restoration of frequency to schedule or control performance problems occur, then the prior
reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction
based on the criterion stated above may not be implemented.
November 30, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003974
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection Frequency Response Obligation Methodology
This procedure outlines the process the ERO is to use for determining the Interconnection Frequency
Response Obligation (IFRO).
The following are the formulae that comprise the calculation of the IFROs.
10
Where:
•
•
•
•
•
•
•
•
•
•
•
•
•
DFBase is the base delta frequency.
FStart is the starting frequency determined by the statistical analysis.
UFLS is the highest UFLS trip setpoint for the interconnection.
CCAdj is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data.
DFCC is the delta frequency adjusted for the differences between 1-second and sub-second Point
C observations for frequency events.
CBR is the statistically determined ratio of the Point C to Value B.
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
BC’ADJ is the statistically determined adjustment for the event nadir being below the Value B
(Eastern Interconnection only) during primary frequency response withdrawal.
MDF is the maximum allowable delta frequency.
RCC is the resource contingency criteria.
CLR is the credit for load resources.
ARCC is the adjusted resource contingency criteria adjusted for the credit for load resources.
IFRO is the interconnection frequency response obligation.
November 30, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003975
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Event Selection Process
This procedure outlines the Electric Reliability Organization (ERO) process for supporting the Frequency
Response Standard (FRS). A Procedure revision request may be submitted to the ERO for consideration.
The revision request must provide a technical justification for the suggested modification. The ERO shall
post the suggested modification for a 45-day formal comment period and discuss the revision request in
a public meeting. The ERO will make a recommendation to the NERC BOT, which may adopt the revision
request, reject it, or adopt it with modifications. Any approved revision to this Procedure shall be filed
with FERC for informational purposes.
Event Selection Process
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of
frequency events to be used by Balancing Authorities (BA) to calculate their Frequency Response to
determine:
•
•
Whether the BA met its Frequency Response Obligation, and
An appropriate fixed Bias Setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for analysis. The
events that best fit the criteria will be used to support the FRS. The evaluation period for
performing the annual Frequency Bias Setting and the Frequency Response Measure (FRM)
calculation is December 1 of the prior year through November 30 of the current year.
2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating
the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion
events in a 12 month evaluation period satisfying the criteria below, then similar acceptable
events from the subsequent year’s evaluation period will be included with the data set by the
ERO for determining FRS compliance. This is described later.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the
FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C and
the arrested frequency Point C exceeds the excursion threshold values specified for the
Interconnection in Table 1 below.
i. The A Value is computed as an average over the period from -16 seconds to 0
seconds before the frequency transient begins to decline.
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
November 30, 2012
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003976
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection
East
West
ERCOT
HQ
A Value
to Pt C
0.04Hz
0.07Hz
0.15Hz
0.30Hz
Point C (Low)
< 59.96
< 59.95
< 59.90
< 59.85
Point C (High)
> 60.04
> 60.05
> 60.10
> 60.15
Table 1: Interconnection Frequency Excursion Threshold Values
b. The time from the start of the rapid change in frequency until the point at which
Frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not be
included.
4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The
A Value is computed as an average over the period from -16 seconds to 0 seconds before the
frequency transient begins to decline. For example, given the choice of the two events below,
the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60
Hz.
5. Excursions that include 2 or more events that do not stabilize within 18 seconds will not be
considered.
6. Frequency excursion events occurring during periods:
(i) when large interchange schedule ramping or load change is happening, or
and frequency excursion events occurring (ii) within 5 minutes of the top of the hour,
November 30, 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003977
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
will be excluded from consideration if other acceptable frequency excursion events from the
same quarter are available.
6.7. The ERO will select the largest (A Value to Point C) 2 or 3 frequency excursion events occurring
each month. If there are not 2 frequency excursion events satisfying the selection criteria in a
month, then other frequency excursion events should be picked in the following sequence:
a. From the same event quarter of the year.
b. From an adjacent month.
c. From a similar load season in the year (shoulder vs. summer/winter)
d. The largest unused event.
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable
events from the next year’s evaluation period will be included with the data set by the ERO for
determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be
reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a
24 month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation. The
ERO will post the final list of frequency excursion events used for standard compliance as specified in
Attachment A of BAL-003-1. The following is a general description of the process that the ERO will use
to ensure that BAs can evaluate events during the year in order to monitor their performance
throughout the year.
Monthly
Candidate events will be initially screened by the "Frequency Event Detection Methodology" shown on
the following link located on the NERC Resources Subcommittee area of the NERC website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oct_2011.p
df. Each month's list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under "Candidate Frequency Events".
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
•
•
•
•
December through February
March through May
June through August
September through November
November 30, 2012
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003978
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Based on criteria established in the "Procedure for ERO Support of Frequency Response and Frequency
Bias Setting Standard", events will be selected to populate the FRS Form 1 for each Interconnection.
The Form 1's will be posted on the NERC website, in the Resources Subcommittee area under the title
"Frequency Response Standard Resources". Updated Form 1's will be posted at the end of each quarter
listed above after a review by the NERC RS' Frequency Working Group. While the events on this list are
expected to be final, as outlined in the selection criteria, additional events may be considered, if the
number of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the
year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters
listed above, will be posted as specified in Attachment A. Each Balancing Authority reports its previous
year’s Frequency Response Measure (FRM), Frequency Bias Setting and Frequency Bias type (fixed or
variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for
errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in
Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility in when
each BA implements its settings.
November 30, 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003979
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Process for Adjusting Interconnection Minimum Frequency Bias Setting
This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to
better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance
with this procedure.
The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other
balancing standard limits.
Under BAL-003-1, the minimum Frequency Bias Settings will be moved toward the natural Frequency
Response in each interconnection. In the first year, the minimum Frequency Bias Setting for each
interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is
based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714
Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table
21 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum
Frequency Bias Setting is allocated among the BAs on an interconnection using the same allocation
method as is used for the allocation of the Frequency Response Obligation (FRO).
Interconnection
Eastern
Western
ERCOT*
HQ*
Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)
0.9% of non-coincident peak load
0.9% of non-coincident peak load
N/A
N/A
Table 2. Frequency Bias Setting Minimums
*The minimum Frequency Bias Setting requirement does not apply to a Balancing Authority that
is the only Balancing Authority in its Interconnection. These Balancing Authorities are solely
responsible for providing reliable frequency control of their Interconnection. These Balancing
Authorities are responsible for converting frequency error into a megawatt error to provide
reliable frequency control, and the imposition of a minimum bias setting greater than the
magnitude the Frequency Response Obligation may have the potential to cause control system
hunting, and instability in the extreme.
The ERO, in coordination with the regions of each interconnection, will annually review Frequency Bias
Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds
(in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value)
than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting
for BAs within that Interconnection may be reduced (in absolute value) in the subsequent years FRS
Form 1 based on the technical evaluation and consultation with the regions affected by 0.1 percentage
point of peak load (expressed in MW/0.1Hz) to better match that Frequency Bias Setting and natural
Frequency Response.
November 30, 2012
5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003980
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
The ERO, in coordination with the regions of each Interconnection, will monitor the impact of the
reduction of minimum frequency bias settings, if any, on frequency performance, control performance,
and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish postcontingency restoration of frequency to schedule or control performance problems occur, then the prior
reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction
based on the criterion stated above may not be implemented.
November 30, 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003981
Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard
Interconnection Frequency Response Obligation Methodology
This procedure outlines the process the ERO is to use for determining the Interconnection Frequency
Response Obligation (IFRO).
The following are the formulae that comprise the calculation of the IFROs.
10
Where:
•
•
•
•
•
•
•
•
•
•
•
•
•
DFBase is the base delta frequency.
FStart is the starting frequency determined by the statistical analysis.
UFLS is the highest UFLS trip setpoint for the interconnection.
CCAdj is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C data is
lower than the 1-second data.
DFCC is the delta frequency adjusted for the differences between 1-second and sub-second Point
C observations for frequency events.
CBR is the statistically determined ratio of the Point C to Value B.
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
BC’ADJ is the statistically determined adjustment for the event nadir being below the Value B
(Eastern Interconnection only) during primary frequency response withdrawal.
MDF is the maximum allowable delta frequency.
RCC is the resource contingency criteria.
CLR is the credit for load resources.
ARCC is the adjusted resource continegency criteria adjusted for the credit for load resources.
IFRO is the interconnection frequency response obligation.
November 30, 2012
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003982
Frequency Response
Standard Background
Document
November, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003983
Table of Contents
Table of Contents ............................................................................................................................ 1
Introduction .................................................................................................................................... 2
Background ..................................................................................................................................... 2
Rationale by Requirement ............................................................................................................ 22
Requirement 1 ...................................................................................................................... 22
Background and Rationale .................................................................................................... 22
Requirement 2 ...................................................................................................................... 32
Background and Rationale .................................................................................................... 32
Requirement 3 ...................................................................................................................... 34
Requirement 4 ...................................................................................................................... 34
Background and Rationale .................................................................................................... 35
Requirement 5 ...................................................................................................................... 35
Background and Rationale ....................................................... Error! Bookmark not defined.
How this Standard Meets the FERC Order 693 Directives............................................................ 36
FERC Directive ........................................................................................................................... 36
1. Levels of Non-Compliance ................................................................................................. 36
2. Determine the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other Requirements of the Reliability Standard are met ... 36
3. Define the necessary amount of Frequency Response needed for Reliable Operation for
each Balancing Authority with methods of obtaining and measuring that the frequency
response is achieved ................................................................................................................. 36
Necessary Amount of Frequency Response ......................................................................... 36
Methods of Obtaining Frequency Response ........................................................................ 37
Measuring that the Frequency Response is Achieved .......................................................... 37
Going Beyond the Directive ...................................................................................................... 38
Future Work ................................................................................. Error! Bookmark not defined.
Good Practices and Tools.............................................................................................................. 39
Background ............................................................................................................................... 39
Identifying and Estimating Frequency Responsive Reserves ................................................... 39
Using FRS Form 1 Data .............................................................................................................. 40
Tools .......................................................................................................................................... 40
Field Trial .......................................................................................... Error! Bookmark not defined.
1
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003984
Introduction
This document provides background on the development, testing and implementation of BAL003-1 - Frequency Response Standard (FRS).1 The intent is to explain the rationale and
considerations for the Requirements of this standard and their associated compliance
information. The document also provides good practices and tips for Balancing Authorities
(“BAs”) with regard to Frequency Response.
In Order No. 693, the Federal Energy Regulatory Commission (“FERC” or the “Commission”)
directed additional changes to BAL-003.2 This document explains how compliance with those
directives are met by BAL-003-1.
The original Standards Authorization Request (“SAR”), finalized on June 30, 2007, assumed
there was adequate Frequency Response in all the North American Interconnections. The goal
of the SAR was to update the Standard to make the measurement process of frequency
response more objective and to provide this objective data to Planners and Operators for
improved modeling. The updated models will improve understanding of the trends in
Frequency Response to determine if reliability limits are being approached. The Standard
would also lay the process groundwork for a transition to a performance-based Standard if
reliability limits are approached.
This document will be periodically updated by the FRS Drafting Team (FRSDT) until the Standard
is approved. Once approved, this document will then be maintained and updated by the ERO
and the NERC Resources Subcommittee to be used as a reference and training resource.
Background
This section discusses the different components of frequency control and the individual
components of Primary Frequency Control also known as Frequency Response.
Frequency Control
Most system operators generally have a good understanding of frequency control and Bias
Setting as outlined in the balancing standards and the references to them in the NERC
Operating Manual. Frequency control can be divided into four overlapping windows of time as
outlined below.
Primary Frequency Control (Frequency Response) – Actions provided by the
Interconnection to arrest and stabilize frequency in response to frequency deviations.
Primary Control comes from automatic generator governor response (also known as speed
1
2
2
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of Terms Used in NERC Reliability
Standards, available here: http://www.nerc.com/files/Glossary_of_Terms.pdf.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 368-375, order on reh’g, Order
No. 693-A, 120 FERC ¶ 61,053 (2007).
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003985
regulation), load response (typically from motors), and other devices that provide an
immediate response based on local (device-level) control systems.
Secondary Frequency Control – Actions provided by an individual BA or its Reserve Sharing
Group to correct the resource – load unbalance that created the original frequency
deviation, which will restore both Scheduled Frequency and Primary Frequency Response.
Secondary Control comes from either manual or automated dispatch from a centralized
control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced basis
that are coordinated so there is a net zero effect on Area Control Error (ACE). Examples of
Tertiary Control include dispatching generation to serve native load; economic dispatch;
dispatching generation to affect Interchange; and re-dispatching generation. Tertiary
Control actions are intended to replace Secondary Control Response by reconfiguring
reserves.
Time Control includes small offsets to scheduled frequency to keep long term average
frequency at 60 Hz.
Primary Frequency Control – Frequency Response
Primary Frequency Control, also known generally as Frequency Response, is the first stage of
overall frequency control and is the response of resources and load to a locally sensed change
in frequency in order to arrest that change in frequency. Frequency Response is automatic, not
driven by any centralized system, and begins within seconds rather than minutes. Different
resources, loads, and systems provide Frequency Response with different response times,
based on current system conditions such as total resource/load and their respective mix.
The proposed NERC Glossary of Terms defines Frequency Response as:
•
•
(Equipment) The immediate and automatic reaction or response of power from a
system or power from elements of the system to a change in locally sensed system
frequency.
(System) The sum of the change in demand, and the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).
As noted above, Frequency Response is the characteristic of load and generation within
Balancing Authorities and Interconnections. It reacts or responds with changes in power to
attempted changes in load-resource balance that result in changes to system frequency.
Because the loss of a large generator is much more likely than a sudden loss of an equivalent
amount of load, Frequency Response is typically discussed in the context of a loss of a large
generator. Included within Frequency Response are many components of that response.
Understanding Frequency Response and the FRS requires an understanding of each of these
components and how they relate to each other.
Frequency Response Illustration
The following simple example is presented to illustrate the components of Frequency Response
in graphical form. It includes a series of seven graphs that illustrate the various components of
3
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003986
Frequency Response and a brief discussion of each describing how these components react to
attempted changes in the load-resource balance and resulting changes in system frequency.
The illustration is based on an assumed Disturbance event of the sudden loss of 1000 MW of
generation. Although a large event is used to illustrate the response components, even small
frequently occurring events will result in similar reactions or responses. The magnitude of the
event only affects the shape of the curves on the graph; it does not obviate the need for
Frequency Response.
Primary Frequency Control - Frequency Response - Graph 1
3000
60.100
Power Deficit
2500
60.000
2000
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Change in Power (MW)
Frequency
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The first graph, Primary Frequency Control – Frequency Response – Graph 1, presents a sudden
loss of generation of 1000 MW. The components are presented relative to time as shown on
the horizontal Time axis in seconds. This simplified example assumes a Disturbance event of
the sudden loss of generation resulting from a breaker trip that instantaneously removes 1000
MW of generation from the interconnection. This sudden loss is illustrated by the power deficit
line shown in black using the MW scale on the left. Interconnection frequency is illustrated by
the frequency line shown in red using the Hertz scale on the right. Since the Scheduled
Frequency is normally 60 Hz, it is assumed that this is the frequency when the Disturbance
event occurs.
Even though the generation has tripped and power injected by the generator has been
removed from the interconnection, the loads continue to use the same amount of power. The
4
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003987
“Law of Conservation of Energy”3 requires that the 1000 MW must be supplied to the
interconnection if energy balance is to be “conserved”. This additional 1000 MW of power is
produced by extracting kinetic energy that was stored in the rotating mass of all of the
synchronized generators and motors on the interconnection – essentially using this equipment
as a giant flywheel. The extracted energy supplies the “balancing inertia”4 power required to
maintain the power and energy balance on the interconnection. This balancing inertia power is
produced by the generators’ spinning inertial mass’ resistance to the slowdown in speed of the
rotating equipment on the interconnection that both provides the stored kinetic energy and
reduces the frequency of the interconnection. This is illustrated in the second graph, Primary
Frequency Control – Frequency Response – Graph 2, by the orange dots representing the
balancing inertia power that exactly overlay and offset the power deficit.
Primary Frequency Control - Frequency Response - Graph 2
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
As the frequency decreases, synchronized motors slow, as does the work they are providing,
resulting in a decrease in load called “load damping.” This load damping is the reason that the
power deficit initially declines. Synchronously operated motors will contribute to load
damping. Variable speed drives that are decoupled from the interconnection frequency do not
3
4
5
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power which is the first
derivative of energy with respect to time, must also be conserved.
The term “balancing Inertia” is coined here from the terms “inertial frequency response” and “balancing energy”. Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003988
contribute to load damping. In general, any load that does not change with interconnection
frequency including resistive load will not contribute to load damping or Frequency Response.
It is important to note that the power deficit equals exactly the balancing inertia, indicating that
there is no power or energy imbalance at any time during this process. What is normally
considered as “balancing power or energy” is actually power or energy required to correct the
frequency error from scheduled frequency. Any apparent power or energy imbalance is
corrected instantaneously by the balancing inertia power and energy extracted from the
interconnection. Thus the balancing function is really a frequency control function described as
a balancing function because ACE is calculated in MWs instead of Hertz, frequency error.
During the initial seconds of the Disturbance event, the governors have yet to respond to the
frequency decline. This is illustrated with the Blue line on the third graph, Primary Frequency
Control – Frequency Response – Graph 3, showing Governor Response. This time delay results
from the time that it takes the controller to adjust the equipment and the time it takes the
mass to flow from the source of the energy (main steam control valve for steam turbines, the
combustor for gas turbines, or the gate valve for hydro turbines) to the turbine-generator
blades where the power is converted to electrical energy.
Primary Frequency Control - Frequency Response - Graph 3
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Note that the frequency continues to decline due to the ongoing extraction by balancing inertia
power of energy from the rotating turbine-generators and synchronous motors on the
interconnection. The reduction in load also continues as the effect of load damping continues
6
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003989
to reduce the load while frequency declines. During this time delay (before the governor
response begins) the balancing inertia limits the rate of change of frequency.
After a short time delay, the governor response begins to increase rapidly in response to the
initial rapid decline in frequency, as illustrated on the fourth graph, Primary Frequency Control
– Frequency Response – Graph 4. Governor response exactly offsets the power deficit at the
point in time that the frequency decline is arrested. At this point in time, the balancing inertia
has provided its contribution to reliability and its power contribution is reduced to zero as it is
replaced by the governor response. If the time delay associated with the delivery of governor
response is reduced, the amount of balancing inertia required to limit the change in frequency
by the Disturbance event can also be reduced. This supports the conclusion that balancing
inertia is required to manage the time delays associated with the delivery of Frequency
Response. Not only is the rapid delivery of Frequency Response important, but the shortening
of the time delay associated with its delivery is also important. Therefore, two important
components of Frequency Response are 1) how long the time delay is before the initial delivery
of response begins; and 2) how much of the response is delivered before the frequency change
is arrested.
Primary Frequency Control - Frequency Response - Graph 4
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
This point, at which the frequency is first arrested, is defined as “Point C” and Frequency
Response calculated at this point is called the “arrested frequency response.” The arrested
frequency is normally the minimum (maximum for load loss events) frequency that will be
7
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003990
experienced during a Disturbance event. From a reliability perspective, this minimum
frequency is the frequency that is of concern. Adequate reliability requires that frequency at
the time frequency is arrested remain above the under-frequency relay settings so as not to trip
these relays and the firm load interrupted by them. Frequency Response delivered after
frequency is arrested at this minimum level provides less reliability value than Frequency
Response delivered before Point C, but greater value than Secondary Frequency Control power
and energy which is delivered minutes later.
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with their Governor Response. This results in the frequency partially
recovering from the minimum arrested value and results in an oscillating transient that follows
the minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period that ends roughly 20 seconds after the Disturbance event. This postdisturbance transient period is included on the fifth illustrative graph, Primary Frequency
Control – Frequency Response – Graph 5.
Primary Frequency Control - Frequency Response - Graph 5
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The total Disturbance event illustration is presented on the sixth graph, Primary Frequency
Control – Frequency Response – Graph 6. Frequency and power contributions stabilize at the
end of the transient period. Frequency Response calculated from data measured during this
settled period is called the “Settled Frequency Response.” The Settled Frequency Response is
the best measure to use as an estimator for the “Frequency Bias Setting” discussed later.
8
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003991
Primary Frequency Control - Frequency Response - Graph 6
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The final Disturbance event illustration is presented on the seventh graph, Primary Frequency
Control – Frequency Response – Graph 7. This graph shows the averaging periods used to
estimate the pre-disturbance A-Value averaging period and the post-disturbance B-Value
averaging period used to calculate the settled frequency response. A discussion of the
measurement of Frequency Response immediately follows these graphs. That discussion
includes consideration of the factors that affect the methods chosen to measure Frequency
Response for implementation in a reliability standard.
9
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003992
Primary Frequency Control - Frequency Response - Graph 7
3000
60.100
Power Deficit
Balancing Inertia
Load Damping
Governor Response
A-value
B-value
2500
60.000
Frequency
59.900
1500
59.800
B-Value Averaging Period
A-Value Averaging Period
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
2000
59.400
-20
-15
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Frequency Response Measurement (FRM)
The classic Frequency Response points A, C, and B, shown below in Fig. 1 Frequency Response
Characteristic, are used for measurement as found in the Frequency Response Characteristic
Survey Training Document within the NERC operating manual, found at
http://www.nerc.com/files/opman_7-1-11.pdf. This traditional Frequency Response Measure
has recently been more specifically termed “settled frequency response.” This term has been
used because it provides the best Frequency Response Measure to estimate the Frequency Bias
Setting in Tie-line Bias Control based Automatic Generation Control Systems. However, the
industry has recognized that there is considerable variability in measurement resulting from the
selection of Point A and Point B in the traditional measure making the traditional measurement
method unsuitable as the basis for an enforceable reliability standard in a real world setting of
multiple Balancing Authority interconnections.
10
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003993
Frequency Response
60.050
60.025
A = 60.000
60.000
Frequency (Hz)
59.975
59.950
59.925
59.900
B = 59.874
59.875
59.850
59.825
C = 59.812
59.800
59.775
59.750
-30
-20
-10
0
10
20
30
40
50
60
Time (Seconds)
Figure 1. Frequency Response Characteristic
By contrast, measuring an Interconnection’s settled frequency response is straightforward and
fairly accurate. All that’s needed to make the calculation is to know the size of a given
contingency (MW), divide this value by the change in frequency and multiply the results by 10
since frequency response is expressed in MW/0.1Hz.
Measuring a BA’s frequency response is more challenging. Prior to BAL-003-1, NERC’s
Frequency Response Characteristic Survey Training Document provided guidance to calculate
Frequency Response. In short, it told the reader to identify the BA’s interchange values
“immediately before” and “immediately after” the Disturbance event and use the difference to
calculate the MWs the BA deployed for the event. There are two challenges with this
approach:
•
•
Two people looking at the same data would come up with different values when
assessing which exact points were immediately before and after the event.
In practice, the actual response provided by the BA can change significantly in the
window of time between point B and when secondary and tertiary control can assist in
recovery.
Therefore, the measurement of settled frequency response has been standardized in a number
of ways to limit the variability in measurement resulting from the poorly specified selection of
Point A and Point B. It should be noted that t-0 has been defined as the first scan value that
11
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003994
shows a deviation in frequency of some significance, usually approaching about 10 mHz. The
goal is such that the first scan prior to t-0 was unaffected by the deviation and appropriate for
one of the averaging points.
•
•
The A-value averaging period of approximately the previous 16 seconds prior to t-0 was
selected to allow for an averaging of at least 2 scans for entities utilizing 6 second scan
rates. (All time average period references in this document are for 2 second scan rates
unless noted otherwise.)
The B-value averaging period of approximately (t+20 to t+52 seconds) was selected to
attempt to obtain the average of the data after primary frequency response was
deployed and the transient completed(settled), but before significance influence of
secondary control. Multiple periods were considered for averaging the B-value:
o 12 to 24 sec
o 18 to 30 sec
o 20 to 40 sec
o 18 to 52 sec
o 20 to 52 sec
It is necessary for all BAs from an interconnection to use the same averaging periods to
provide consistent results. In addition, the SDT decided that until more experience is
gained, it is also desirable for all interconnections to use the same averaging periods to
allow comparison between interconnections.
The methods presented in this document only address the values required to calculate the
frequency response associated with the frequency change between the initial frequency, AValue, and the settling frequency, B-Value. No reasonable or consistent calculations can be
made relating to the arresting frequency, C-Value, using Energy Management System (EMS)
scan rate data as long as 6-seconds or tie-line flow values associated with the minimum value of
the frequency response characteristic (C-value) as measured at the BA level.
Both the calculation of the frequency at Point A and the frequency at Point B began with the
assumption that a 6-second scan rate was the source of the data. Once the averaging periods
for a 6-second scan rate were selected, the averaging periods for the other scan rates were
selected to provide as much consistency as possible between BAs with different scan rates.
The Frequency at Point A was initially defined as the average of the two scans immediately
prior to the frequency event. All other averaging periods were selected to be as consistent as
possible with this 12 second average scan from the 6-second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” is defined as the average of the
same scans as used for the Point A frequency average.
The Frequency at Point B was then selected to be an average as long as the average of 6-second
scan data as possible that would not begin until most of the hydro governor response had been
delivered and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” is defined as the average of the same
scans as used for the Point B frequency average.
12
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003995
B Averaging Period Selection:
Experience from the Electric Reliability Council of Texas (“ERCOT”) and the field trail on
other interconnections indicated that the 12 to 24 second and 18 to 30 second
averaging periods were not suitable because they did not provide the consistency in
results that the other averaging periods provided, and that the remaining measuring
periods do not provide significantly different results from each other. The team
believed that this was observed because the transients were not complete in all of the
samples using these averaging periods.
The 18 to 52 second and 20 to 52 second averaging periods were compared to each
other, with the 20 to 52 second period providing more consistent values, believed to
result from the incomplete transient in some of the 18 to 52 second samples.
This left a choice between the 20 to 40 second and the 20 to 52 second averaging
periods. The team recognized that there would be more AGC response in the 20 to 52
second period, but the team also recognized that the 20 to 52 second period would
provide a better measure of squelched response from outer loop control action. The 20
to 52 second period was selected because it would indicate squelched response from
outer-loop control and provide incentive to reduce response withdrawal. The final
selections for the data averaging periods used in FRS Form 1 are shown in the table
below.
Definitions of Frequency Values for Frequency Response Calculation
Scan Rate
T 0 Scan
6-Seconds
5-Seconds
4-Seconds
3-Seconds
2-Seconds
Identify first
significant
change in
frequency as
the T 0 scan
A Value (average)
B Value (average)
Average of T-1 through T-2 scans
Average of T+4 through T+8 scans
Average of T-1 through T-2 scans
Average of T+5 through T+10 scans
Average of T-1 through T-3 scans
Average of T+6 through T+12 scans
Average of T-1 through T-5 scans
Average of T+7 through T+17 scans
Average of T-1 through T-8 scans
Average of T+10 through T+26 scans
Consistent measurement of Primary Frequency Response is achievable for a selected number of
events and can produce representative frequency response values, provided an appropriate
sample size is used in the analysis. Available research investigating the minimum sample size to
provide consistent measurements of Frequency Response has shown that a minimum sample
size of 20 events should be adequate.
Measurement of Primary Frequency Response on an individual resource or load basis requires
analysis of energy amounts that are often small and difficult to measure using current methods.
In addition, the number of an interconnection's resources and loads providing their response
could be problematic when compiling results for multiple events.
Measurement of Primary Frequency Response on an interconnection (System) basis is straight
forward provided that an accurate frequency metering source is available and the magnitude of
the resource/load imbalance is known in MWs.
13
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003996
Measurement on a Balancing Authority basis can be a challenge, since the determination of
change in MWs is determined by the change in the individual BA's metered tie lines.
Summation of tie lines is accomplished by summing the results of values obtained by the digital
scanning of meters at intervals up to six seconds, resulting in a non-coincidental summing of
values. Until the technology to GPS time stamp tie line values at the meter and the summing of
those values for coincidental times is in use throughout the industry, it is necessary to use
averaging of values described above to obtain consistent results.
Figure 2. Frequency Response Measurement
The standardized measure is shown graphically in Fig. 2 Frequency Response Measurement
with the averaging periods shown by the solid green and red lines on the graph. Since FERC
directed a performance obligation for BAL-003-1, it is important to be more objective in the
measurement process. The standardized calculation is available on FRS Form 2 for EMS scan
rates of 2, 3, 4, 5, and 6 seconds at
http://www.nerc.com/filez/standards/Frequency_Response.html.
Arrested Frequency Response
There is another measure of Frequency Response that is of interest when developing a
Frequency Response estimate that not only will be used for estimating the Frequency Bias
Setting, but will also be used to assure reliability by operating in a manner that will bound
interconnection frequency and prevent the operation of Under-frequency Relays. This
Frequency Response Measure has recently been named “arrested frequency response.” This
Frequency Response is significantly affected by the inertial Frequency Response, the governor
Frequency Response and the time delays associated with the delivery of governor Frequency
14
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003997
Response. It is calculated by using the change in frequency between the initial frequency, A,
and the maximum frequency change during the event, C, instead of using the change between
A and B. Arrested Frequency Response is the correct response for determining the minimum
Frequency Response related to under-frequency relay operation and the support of
interconnection reliability. This is because it can be used to provide a direct estimate of the
maximum frequency deviation an interconnection will experience for an initial frequency and a
given size event in MW. Unfortunately, arrested frequency response cannot currently be
measured using the existing EMS-based measurement infrastructure. This limitation exists
because the scan rates currently used in industry EMSs are incapable of measuring the net
actual interchange at the same instant that the maximum frequency deviation is reached.
Fortunately, the ratio of arrested frequency response and settled frequency response tends to
be stable on an interconnection. This allows the settled frequency response value to be used as
a surrogate for the arrested frequency response and implement a reasonable measure upon
which to base a standard. One consequence of using the settled frequency response as a
surrogate for the arrested frequency response is the inclusion of a large reliability margin in
Interconnection Frequency Response Obligation to allow for the difference between the settled
frequency response as measured and the arrested frequency response that indicates reliability.
As measurement infrastructure improves one might expect the Frequency Response Obligation
to transition to a measurement based directly on the arrested frequency response while the
Frequency Bias Setting will continue to be based on the settled frequency response. However,
at this time, the measurement devices and methods in use do not support the necessary level
of accuracy to estimate arrested frequency response contribution for an individual Balancing
Authority.
Frequency Response Definition and Examples
Limitations of the measurement infrastructure determine the measurement methods
recommended in this standard. The measurement limitations provide opportunities to improve
the Frequency Response as measured in the standard without contributing to an improvement
in Frequency Response that contributes to reliability. These definitions and examples provide a
basis for determining which contributions to Frequency Response contribute the most to
improved reliability. They also provide the basis for determining on a case by case basis
whether the individual contributors to the Frequency Response Measure are also contributing
to reliability.
General Frequency Response Characteristics
In the simplest case Frequency Response includes any automatic response to changes in local
frequency. If that response works to decrease that change in frequency, it is beneficial to
reliability. If that response works to increase that change in frequency, it is detrimental to
reliability. However, this definition does not address the relative value of one response as
compared to other responses that may be provided in a specific case.
There are numerous characteristics associated with the Frequency Response that affect the
reliability value and economic value of the response. These characteristics include:
1. Inertial – the response is inertial or approximates inertial response
15
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003998
Inertial response provides power without delay that is proportional to the frequency
and the change in frequency. Therefore, power provided by electronic control as
synthetic Inertial response must be proportional to the frequency and change in
frequency and be provided without a time delay.
2. Immediate – no unnecessary intentional time delays or reduction in the rate of
response delivery
a. time delay before the beginning of the response
Turbines that convert heat or kinetic energy have time delays related to the time
delay from the time that the control valves are moved to initiate the change in
power and the time that the power is delivered to the generator. These times
are usually associated with the time it takes a change in mass flow to travel from
the control valve to the first blades of the turbine in the turbine generator.
b. reduction in the rate of response delivery
There are natural delays associated with the rate of response delivery that are
related to the mass flow travel from the first turbine blades to the last turbine
blades. In addition, some turbines have intentional delays designed into the
control system to slow the rate of change in the delivery of the kinetic energy or
fuel to the turbine to prevent the turbine or other equipment from being
damaged, hydro turbines, or to prevent the turbine from tripping due to
excessive rate of change, gas turbines.
3. Proportional – the amount of the total response is proportional to the frequency error
a. No Deadband – the response is proportional across the entire frequency range
b. Deadband – the response is only proportional outside of a defined deadband
4. Bi-directional – the response occurs to both increases and decreases in frequency
5. Continuous – there are no discontinuities in the delivery of the response (no step
changes)
6. Sustained – the response is sustained until frequency is returned to schedule
Frequency Response Reliability Value
This section contains a more detailed discussion of the various characteristics of Frequency
Response listed in the previous section. It also provides an indication of the relative value of
these characteristics with respect to their contribution to reliability. Finally, it includes some
examples of the described responses.
Inertial Response is provided from the stored energy in the rotating mass of the turbinegenerators and synchronous motors on the interconnection. It limits the rate of change of
frequency until sufficient Frequency Response can be supplied to arrest the change in
frequency. Its reliability value increases as the time delay associated with the delivery of other
Frequency Response on the interconnection increases. If those time delays are minimal, then
the value of inertial response is low. If all time delays associated with the Frequency Response
could be eliminated, then inertial response would have little value.
16
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
003999
The reliability value of Inertial Response is the greatest on small interconnections because the
size of the Disturbance events is larger relative to the inertia of the interconnection. Electronic
controls have been developed to provide synthetic inertial response from the stored energy in
asynchronous generators to supplement the natural inertial response. Some Type III & IV Wind
Turbines have this capability. In addition, electronically controlled SCRs have been developed
that can store energy in the electrical system and release this stored energy to supply synthetic
inertial response when required.
Immediate Response is provided by load damping and because the time delays associated with
its delivery are very short (related to the speed of electrical signal in the electrical system); load
damping requires very little inertial response to limit arrested frequency effectively. Synthetic
immediate response can also be supplied from loads because in many cases, there is no mass
flow time delay associated with the load process providing the power and energy reduction.
Therefore, loads can provide an immediate response with a higher reliability value than
generators with time delays required by the physics of the turbine-generator.
Governor response has time delays associated with its delivery. Governor response provided
with shorter time delays has a higher reliability value because those shorter time delays require
less inertial response to arrest frequency. Governor response is provided by the turbinegenerators on the interconnection. Time delays associated with governor response vary
depending on the type of turbine-generator providing the response.
The longest time delays are usually associated with high head hydro turbine-generators that
require long times from the governor action until the additional mass flow through the turbine.
These units may also have the longest delivery time associated with the full delivery of
response because of the timing designed into the governor response.5
Intermediate time delays are usually associated with steam turbine-generators. The response
begins when the steam control valves are adjusted and the steam mass flows from the valves to
the first high pressure turbine blades. The delivery times associated with the full delivery of
response may require the steam to flow through high, intermediate and low pressure turbines
including reheat flows before full power is delivered. These times are shorter than those of the
hydro turbine-generators in general, but not as fast as the times associated with gas turbines.6
Gas turbines typically have the shortest time delays, because control is provided by injecting
more or less fuel into the turbine combustor and adjusting the air control dampers. These
control changes can be initiated rapidly and the mass flow has the shortest path to the turbine
5
6
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-6 – 1-9.
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-4 – 1-6.
17
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004000
blades. There may be timing limitations related to the rate of change in output of the gas
turbine-generator to maintain flame stability in some cases slowing the rate of change.7
Synthetic Governor Response can be supplied by certain loads and storage systems. The
immediacy of the response is normally limited only by the electronic controls used to activate
the desired response. Synthetic response, when it can be supplied immediately without
significant time delay, has a higher reliability value because it requires less inertial response to
achieve smaller arrested frequency deviations.
Proportional Response indicates that the response provided is proportional in magnitude to
the frequency error. Response deadbands cause a non-proportional response and reduce the
value of the response with respect to reliability. Contrary to general consensus, deadbands do
not reduce the amount of Frequency Response that must be provided, they only transfer the
responsibility for providing that Frequency Response from one source on the interconnection to
another. For a given response, the response with the smaller deadband has the greater
reliability value. Therefore, deadbands should be set to the smallest value that supports overall
reliable operation including the reliable operation of the generator.
Electronic controls have also been developed to provide synthetic governor response. When
these controls are applied to certain loads or stored energy systems, they can be programmed
to provide synthetic governor response similar to the proportional response of a turbinegenerator governor. Governor response in generators is limited to a small percentage of the
output of the generating unit, while synthetic governor response could be applied to much
larger percentages of loads or storage devices providing such response.
Load damping provides a proportional response.
Continuous Response is response that has no discontinuous (step) changes in the frequency
versus response curve. Step changes (Non-continuous Response) in the Governor Response
curve can lead to frequency instabilities at frequencies near the changes. The ERCOT
Interconnection observed this and has since prohibited the use of governor response
characteristics incorporating step responses.
Step responses also occur with the implementation of load interruption using under-frequency
or over-frequency relays.
Bi-directional Response is response that occurs in both directions, when the frequency is
increasing and when the frequency is decreasing. A uni-directional response is a response that
only occurs once when frequency is decreasing or when frequency is increasing.
Inertial response, governor response and load damping are all bi-directional responses. Certain
loads are capable of providing proportional bi-directional response while others are only
capable of providing non-proportional bi-directional response.
7
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-16 – 1-19.
18
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004001
The ERCOT Load Resource program is a uni-directional response program. Loads are only
tripped when frequency declines below a given set-point. When frequency is restored above
that set-point, the loads must be manually reconnected. As a consequence, the Frequency
Response only occurs once with declining frequency and does not oppose the increase in
frequency after the initial decline. If there should be a frequency oscillation, the uni-directional
response will not contribute to the opposition of a second frequency decline across the setpoint during an oscillation event. Once a uni-directional response has occurred, it is unavailable
for a second decline before reset.
Step or proportional responses implemented bi-directionally can lead to frequency instability
when there is less continuous frequency response than the magnitude of the change in
continuous response between the trip and reset frequencies in step, or the proportional
response rate of change is greater than the underlying continuous response. A step bidirectional response will have the load reconnected as frequency recovers from the event thus
opposing the increase in frequency during recovery, and also resetting the load response for
the next frequency decline automatically. Bi-directional response obviously has a greater
reliability value than uni-directional response.
Sustained Response is provided at its full value until frequency is restored to its scheduled
value. On today’s interconnections, few frequency responses are fully sustained until
frequency has been restored to its scheduled value. On steam based turbine-generators, the
steam pressure may drop after a time as the result of the additional steam flow from governor
action. However, in general this has not been a problem because most responses are
incomplete at the time that frequency has been initially arrested and the additional response
has generally been sufficient to make up for more than the these unpreventable reductions in
response. However, the intentional withdrawal of response before frequency has been
restored to schedule can cause a decline in frequency beyond that which would be otherwise
expected. This intentional withdrawal of response is highly detrimental to reliability.
Therefore, it can be concluded in general that sustained response has a higher reliability value
than un-sustained response.
On an interconnection, the withdrawal of response due to the loss of steam pressure on the
steam units may be offset by the slower response of hydro turbine-generators. In these cases,
the reliability of the combined response provides a greater reliability value than the individual
response of each type. The steam turbine-generators provide a fast response that may be
reduced, while the hydro turbine-generators provide a slower response, contributing less to the
arresting response, offsetting any reduction by the steam turbine-generators to assure a
sustained response.
Sustained Response must also be considered for any resource that has a limited duration
associated with its response. The amount of stored energy available from a resource may limit
its ability to sustain response for a duration of time necessary to support reliability.
Frequency Response Cost Factors
In every system of exchange there are two sides; the supply side and the demand side. The
supply side provides the services used by the demand side. In the case of Frequency Response,
19
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004002
the supply side includes all providers of Frequency Response and the demand side includes all
participants that create the need for Frequency Response.
Frequency Response Costs – Supply Side
There are a number of factors that affect the cost of providing Frequency Response from
resources. Since there is a cost associated with those factors, some method of appropriate
compensation could be made available to those resources providing Frequency Response.
Without compensation, providers of Frequency Response will be put in the position of incurring
additional cost that can be avoided only by reducing or eliminating the response they provide.
These costs are incurred independently of whether provided for in a formal Regional
Transmission Organization/Independent System Operator (RTO/ISO) market or in a traditional
BA subject to the FERC pro-forma tariffs.
It is the responsibility of the BA or the RTO/ISO to acquire the necessary amount of Frequency
Response to support reliability in the most cost effective manner. This function is performed
best when the suppliers are evaluated based on the value of the Frequency Response they
provide and compensated appropriately for that Frequency Response. Suppliers provide
Frequency Response when they are assured that they will receive fair compensation. Before
considering how to perform this evaluation and compensation, the costs associated with
providing Frequency Response should be understood and evaluated with respect to the level of
reliability they offer.
Some cost factors that have been identified for providing Frequency Response include:
1. Capacity Opportunity Cost – the costs, including opportunity costs, associated with
reserving capacity to provide Frequency Response. These costs are usually associated
with the alternative use of the same capacity to provide energy or other ancillary
services. There may also be capacity opportunity costs associated with the loss in
average capacity by a load providing Frequency Response.
2. Fuel Cost – The cost of fuel used to provide the Frequency Response. The costs for fuel
to provide Frequency Response can result in energy costs significantly different from the
system marginal energy cost, both higher and lower. This is the case when Frequency
Response is provided by resources that are not at the system marginal cost.
3. Energy Efficiency Penalty Costs – the costs associated with the loss in efficiency when
the resource is operated in a mode that supports the delivery of Frequency Response.
This cost is usually in the form of additional fuel use to provide the same amount of
energy. An example is the difference between operating a steam turbine in valve
control mode with an active governor and sliding pressure mode with valves wide open
and no active governor control except for over-speed. This cost is incurred for all of the
energy provided by the resource, not just the energy provided for Frequency Response.
There may be additional energy costs associated with a load providing Frequency
Response from loss in efficiency of their process when load is reduced.
4. Capacity Efficiency Penalty Costs – the costs associated with any reduction in capacity
resulting from the loss of capacity associated with the loss in energy efficiency. When
efficiency is lost, capacity may be lost at the same time because of limitations in the
amount of input energy that can be provided to the resource.
20
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004003
5. Maintenance Costs – the operation of the resource in a manner necessary to provide
Frequency Response may result in increases in the maintenance costs associated with
the resource.
6. Emissions Costs – the additional costs incurred to manage any additional emissions that
result when the resource is providing Frequency Response or stands ready to provide
Frequency Response.
A good contract for the acquisition of Frequency Response from a resource will provide
appropriate compensation to the resource for all of the costs the resource incurs to provide
Frequency Response. It will also provide a method to evaluate the least cost mix of resources
necessary to provide the minimum required Frequency Response for maintaining reliability.
Finally, it will provide the least complex method of evaluation considering the complexity and
efficiency of the acquisition process.
Frequency Response Costs – Demand Side
Not only are there costs associated with acquiring Frequency Response from the supplying
resources, there are costs associated with the amount of Frequency Response that must be
acquired and influenced by those participants that create the need for Frequency Response. If
the costs of acquiring Frequency Response from the supply resources can be assigned to those
parties that create the need for Frequency Response, there is the promise that the amount of
Frequency Response required to maintain reliability can be minimized. The considerations are
the same as those that are driving the development of “real time pricing” and “dynamic
pricing”. If the costs are passed on to those contributing to the need for Frequency Response,
incentives are created to reduce the need for Frequency Response making interconnection
operations less expensive and more reliable. The problem is to balance both cost and
complexity against reliability on both the supply side and the demand side.
21
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004004
Rationale by Requirement
Requirement 1
R1. Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more negative than its
Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each FRSG or Balancing Authority that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more negative than the Interconnection
Frequency Response Obligation.
Background and Rationale
R1 is intended to meet the following primary objectives:
• Determine whether a Balancing Authority (BA) has sufficient Frequency Response for
reliable operations.
• Provide the feeder information needed to calculate CPS limits and Frequency Bias
Settings.
Primary Objective
With regard to the first objective, FRS Form 1 and the process in Attachment A provide the
method for determining the Interconnections’ necessary amount of Frequency Response and
allocating it to the Balancing Authorities. The field trial for BAL-003-1 is testing an allocation
methodology based on the amount of load and generation in the BA. This is to accommodate
the wide spectrum of BAs from generation-only all the way to load-only.
Frequency Response Sharing Groups (FRSGs)
This standard proposes an entity called FRSG, which is defined as:
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to
jointly meet the sum of the Frequency Response Obligations of its members.
This standard allows Balancing Authorities to cooperatively form FRSGs as a means to jointly
meet the FRS. There is no obligation to form or be a part of FRSGs. The members of the FRSG
would determine how to allocate sanctions among its members. This standard does not
mandate the formation of FRSGs, but allows them as a means to meet one of FERC’s Order No.
693 directives.
FRSG performance may be calculated one of two ways:
•
•
22
Calculate a group NIA and measure the group response to all events in the reporting
year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each
participant’s individual event performance.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004005
Frequency Response Obligation and Calculation
The basic Frequency Response Obligation is based on annual load and generation data reported
in FERC Form 714 (where applicable, see below for non-jurisdictional entities) for the previous
full calendar year. The basic allocation formula used by NERC is:
FRO
Annual Gen Annual Load
FRO
Annual Gen Annual Load
Where:
• Annual GenBA is the annual “Net Generation (MWh)”, FERC Form 714, line 13, column c
of Part II - Schedule 3.
• Annual LoadBA is the annual “Net Energy for Load (MWh)”, FERC Form 714, line 13,
column e of Part II - Schedule 3.
• Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
• Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to
assemble and submit equivalent data. Until the BAL-003-1 process outlined in Attachment 1 is
implemented, Balancing Authorities can approximate their FRO by multiplying their
Interconnection’s FRO by their share of Interconnection Bias. The data used for this calculation
should be for the most recently filed Form 714. As an example, a report to NERC in January
2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that merge or that transfer load or generation need to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation for
the Interconnection remains the same and so that CPS limits can be adjusted.
Attachment A proposes the following Interconnection event criteria as a basis to determine an
Interconnection’s Frequency Response Obligation:
•
•
•
Largest category C loss-of-resource (N-2) event.
Largest total generating plant with common voltage switchyard.
Largest loss of generation in the interconnection in the last 10 years.
With regard to the second objective above (determining Frequency Bias Settings and CPS
limits), Balancing Authorities have been asked to perform annual reviews of their Frequency
Bias Settings by measuring their Frequency Response, dating back to Policy 1. This obligation
was carried forward into BAL-003-01.b. While the associated training document provided
useful information, it left many of the details to the judgment of the person doing the analysis.
The FRS Form 1 and FRS Form 2 provide a consistent, objective process for calculating
Frequency Response to develop an annual measure, the FRM.
23
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004006
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as:
“the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz”. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change of its net
actual interchange on its tie lines with its adjacent Balancing Authorities divided by the change
in interconnection frequency. (Some Balancing Authorities may choose to apply corrections to
their net actual interchange values to account for factors such as nonconforming loads. FRS
Form 1 shows the types of adjustments that are allowed.)
A standardized sampling interval of approximately 20 to 52 seconds will be used in the
computation of SEFRD values. Microsoft Excel® spreadsheet interfaces for EMS scan rates of 2
through 6 seconds are provided to support the computation.
Single Event Frequency Response Data8
The use of a “single event measure” was considered early in the development of the FRS for
compliance because a single event measure could be enforced for each event on the
interconnection making compliance enforcement a simpler process. The variability of the
measurement of Frequency Response for an individual BA for an individual Disturbance event
was evaluated to determine its suitability for use as a compliance measure. The individual
Disturbance events were normalized and plotted for each BA on the Eastern and Western
Interconnections. This data was plotted with a dot representing each event. Events with a
measured Frequency Response above the FRO were shown as blue dots and events with a
measured Frequency Response below the FRO were shown as red dots. In order to show the
full variability of the results the plots have been provided with two scales, a large scale to show
all of the events and small scale to show the events closer to the FRO or a value of 1.0. This
data is presented on four charts titled Frequency Response Events as Normalized by FRO.
Analysis of this data indicates a single event based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in these charts.
Based on the field trial data provided, only 3 out of 19 BAs on the Western Interconnection
would be compliant for all events with a standard based on a single event measure. Only 1 out
of 31 BAs on the Eastern Interconnection would be compliant for all events with a standard
based on a single event measure. The general consensus of the industry is that there is not a
reliability issue with insufficient Frequency Response on any of the North American
Interconnections at this time. Therefore, it is unreasonable to even consider a standard that
would indicate over 90% of the BAs in North American to be non-compliant with respect to
maintaining sufficient Frequency Response to maintain adequate reliability.
In an attempt to balance the workload of Balancing Authorities with the need for accuracy in
the FRM, the standard will require at least 20 samples selected during the course of the year to
compute the FRM. Research conducted by the FRSDT indicated that a Balancing Authority’s
FRM will converge to a reasonably stable value with at least 20 samples.
8
Single Event Analysis based on results of Frequency Response Standard Field Trial Analysis, September 17, 2012.
24
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004007
Frequency Response Events as Normalized by FRO
Eastern Interconnection - 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
-25.0
32
31
30
29
28
27
25
26
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
-50.0
Balancing Authority
25
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004008
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
-5.0
-10.0
-15.0
-20.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-25.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-10.0
Balancing Authority
26
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004009
Sample Size
In order to support field trial evaluations of sample size, sampling intervals, and aggregation
techniques, the FRSDT will be retrieving scan rate data from the Balancing Authorities for each
SEFRD. Additional frequency events may also be requested for research purposes, though they
will not be included in the FRM computation.
FERC Order No. 693 directed the ERO (at P 375) to define the number of Frequency Response
surveys that were conducted each year and to define a necessary amount of Frequency
Response. R1 addresses both of these directives:
•
•
There is a single annual survey of at least 20 events each year.
The FRM calculated on FRS Form 1 is compared by the ERO against the FRO determined
12 months earlier (when the last FRS Form 1 was submitted) to verify the Balancing
Authority provided its share of Interconnection Frequency Response.
Median as the Standard’s Measure of Balancing Authority Performance
The FRSDT evaluated different approaches for “averaging” individual event observations to
compute a technically sound estimate of Frequency Response Measure. The MW contribution
for a single BA in a multi-BA Interconnection is small compared to the minute to minute
changes in load, interchange and generation. For example, a 3000 MW BA in the Eastern
Interconnection may only be called on to contribute 10MW for the loss of a 1000MW. The 10
MW of governor and load response may easily be masked as a coincident change in load.
In general, statisticians use the median as the best measure of central tendency when a
population has outliers. Two independent reviews by the FRSDT has shown the Median to be
less influenced by noise in the measurement process and the team has chosen the median as
the initial metric for calculating the BAs’ Frequency Response Measure.
The FRSDT performed extensive empirical studies and engaged in lively discussions in an
attempt to determine the best aggregation technique for a sample set size of at least 20 events.
Mean, median, and linear regression techniques were used on a trial basis with the data that
was available during the early phases of the effort.
A key characteristic of the “aggregation challenge” is related to the use of actual net
interchange data for measuring frequency response. The tie line flow measurements are
varying continuously due to other operational phenomena occurring concurrently with the
provision of frequency response. (See Appendix 1 for details.) All samples have “noise” in
them, as most operational personnel who have computed the frequency response of their BA
can attest. What has also become apparent to the FRSDT is that while the majority of the
frequency response samples have similar levels of noise in them, a few of the samples may
have much larger errors in them than the others that result in unrepresentative results. And
with the sample set size of interest, it is common to have unrepresentative errors in these few
samples to be very large and asymmetric. For example, one BA’s subject matter expert
observed recently that 4 out of 31 samples had a much larger error contribution than the other
27 samples, and that 3 out of 4 of the very high error samples grossly underestimated the
frequency response. The median value demonstrated greater resiliency to this data quality
problem than the mean with this data set. (The median has also demonstrated superiority to
27
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004010
linear regression in the presence of these described data quality problems in other analyses
conducted by the FRSDT, but the linear regression showed better performance than the mean.)
The above can be demonstrated with a relatively simple example. Let’s assume that a
Balancing Authority’s true frequency response has an average value of -200 MW/ .1 Hz. Let’s
also assume that this Balancing Authority installed “special” perfect metering on key loads and
generators, so that we could know the true frequency response of each sample. And then we
will compare them with that measured by typical tie line flow metering, with the kind of noise
and error that occurs commonly and “not so commonly”. Let’s start with the following 4
samples having a common level of noise, with MW/ .1 Hz as the unit of measurement.
Perfect measurement
-190
-210
-220
-180
-200
-200
Noise
-30
-20
10
20
Mean
Median
Samples from tie lines
-220
-230
-210
-160
-205
-215
Now let’s add a fifth sample, which is highly contaminated with noise and error that grossly
underestimates frequency response.
Perfect measurement
-190
-210
-220
-180
-200
-200
-200
Noise
-30
-20
10
20
250
Mean
Median
Samples from tie lines
-220
-230
-210
-160
+50
-154
-210
It is clear from the above simplistic example that the mean drops by about 25% while the
median is affected minimally by the single highly contaminated value.
Based on the analyses performed thus far, the FRSDT believes that the median’s superior
resiliency to this type of data quality problem makes it the best aggregation technique at this
time. However, the FRSDT sees merit and promise in future research with sample filtering
combined with a technique such as linear regression.
When compared with the mean, linear regression shows superior performance with respect to
the elimination of noise because the measured data is weighted by the size of the frequency
change associated with the event. Since the noise is independent from frequency change, the
greater weighting on larger events provides a superior technique for reducing the effect of
noise on the results.
However, linear regression does not provide a better method when dealing with a few samples
with large magnitudes of noise and unrepresentative error. There are only two alternatives to
improve over the use of median when dealing with these larger unrepresentative errors:
1. Increase the sample size, or
2. Actively eliminate outliers due to unrepresentative error.
28
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004011
Unfortunately, the first alternative, increasing the sample size is not available because
significantly more sample events are not available within the measurement time period of one
year. Linear regression techniques are being investigated that have an active outlier
elimination algorithm that would eliminate data that lie outside ranges of the 96th percentile
and 99th percentile, for example.
Still, the use of linear regression has value in the context of this standard. The NERC Resources
Subcommittee will use linear regression to evaluate Interconnection frequency response,
particularly to evaluate trends, seasonal impacts, time of day influences, etc. The Good
Practices and Tools section of this document outlines how a BA can use linear regression to
develop a predictive tool for its operators.
Additional discussion on this topic is contained in “Appendix 1 – Data Quality Concerns Related
to the Use of Actual Net Interchange Value” of this document.
The NERC Frequency Response Initiative Report addressed the relative merits of using the
median versus linear regression for aggregating single event frequency response samples into a
frequency response measurement score for compliance evaluation. This report provided 11
evaluation criteria as a basis for recommending the use of linear regression instead of the
median for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but concluded
that the median would be the best aggregation technique to use initially when the relative
importance of each criterion was considered. A brief summary of the FRSDT majority
consensus on the basis of each evaluation criterion is provided below.
•
•
•
•
•
•
29
Provides two dimensional measurement – The FRSDT agrees that the two dimensional
concept is a useful way to perceive frequency response characteristics, and that it may
be useful for potential future modeling activities. Better data quality would increase
support for such future efforts, and the use of the median for initial compliance
evaluations within BAL-003-1 should not hinder any such effort. The FRSDT perceived
this as a mild advantage for linear regression.
Represents nonlinear characteristics – With considerations similar to those applied to
the previous criterion, the FRSDT perceived this as a mild advantage for linear
regression.
Provides a single best estimator – The FRSDT gave minimal importance to the
characteristic of the median averaging the middle values when used with an even
number of samples.
Is part of a linear system - With considerations similar to those applied to the first two
criteria, the FRSDT perceived this as a mild advantage for linear regression (particularly
in the modeling area.)
Represents bimodal distributions – The FRSDT gave minimal weight of this criterion, as
a change in Balancing Authority footprint does not seem to be addressed adequately by
any aggregation technique.
Quality statistics available – The FRSDT perceived this as a mild advantage for linear
regression in that the statistics would be coupled directly to the compliance evaluation.
The FRSDT also included this criterion as part of the modeling advantages cited above.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004012
•
•
•
•
•
The FRSDT supports collecting data and performing quality statistical analysis. If it is
determined that the use of the median, as opposed to a mean or linear regression
aggregation, is yielding undesirable consequences, the FRSDT recommends that other
aggregation techniques be re-evaluated at that time.
Reducing influence of noise - This is the dominant concern of the FRSDT, and it
perceives the median to have a major advantage over linear regression in addressing
noise in the change in actual net interchange calculation. The FRSDT bases this
judgment on: prior FRSDT studies that have shown that the median produces more
stable results; the data used in the NERC Frequency Response Initiative document
exhibits large quantities of noise; prior efforts of FRSDT members in performing
frequency response sampling for their own Balancing Authorities over many years; and
similar observations of noise in the CERTS frequency Monitoring Application. The
FRSDT has serious concerns that the influence of noise has a greater tendency to yield a
“false positive” compliance violation with linear regression than with the median. Also,
limited studies performed by the FRSDT indicates the possibility that the resultant
frequency response measure would yield more measurement variation across years
with linear regression versus the median while the actual Balancing Authority
performance remains unchanged.
Reducing the influence of outliers – This is related to the previous criterion. The FRSDT
recognizes four main sources of noise: concurrent operating phenomena (described
elsewhere in this document), transient tie line flows for nearby contingencies, data
acquisition time skew in tie line data measurements, and time skew and data
compression issues in archiving techniques and tools such as PI. Some outliers may be
caused in part by true variation in the actual frequency response, and it is desirable to
include those in the frequency response measure. The FRSDT supports efforts in the
near future to distinguish between outliers caused by noise versus true frequency
response, and progress in this area may make it feasible and desirable to replace the
median with linear regression, or some other validated technique. The FRSDT does
note that this is a substantial undertaking, and it would require substantial input from a
sufficient number of experts to help distinguish noise from true frequency response.
Easy to calculate – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made in noise elimination.
Familiar indicator – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made as a result of noise elimination.
Currently used as a measure in BAL-003 – The present standard refers to an average
and does not provide specific guidance on the computation of that average, but the
FRSDT puts minimal weight on this evaluation criterion.
In summary, the FRSDT perceives an approximate balance between the modeling advantage for
linear regression and the simplicity advantage of the median. However, the clear determinant
in endorsing the use of the median is the data quality issue related to concurrent operational
phenomena, transient tie line flows, and data acquisition and archiving limitations.
30
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004013
FERC Order No. 693 also directed the Standard (at P 375) to identify methods for Balancing
Authorities to obtain Frequency Response. Requirement R1 allows Balancing Authorities to
participate in Frequency Response Sharing Groups (FRSGs) to provide or obtain Frequency
Response. These may be the same FRSGs that cooperate for BAL-002-0 or may be FRSGs that
form for the purposes of BAL-003-1.
If BAs participate as an FRSG for BAL-003-1, compliance is based on the sum of the participants’
performance.
Two other ways that BAs could obtain Frequency Response are through Supplemental Service
or Overlap Regulation Service:
• No special action is needed if a BA provides or receives supplemental regulation. If the
regulation occurs via Pseudo Tie, the transfer occurs automatically as part of Net Actual
Interchange (NIA) and in response to information transferred from recipient to
provider.
• If a BA provides overlap regulation, its FRS Form 1 will include the Frequency Bias
setting as well as peak load and generation of the combined Balancing Authority Areas.
The FRM event data will be calculated on the sum of the provider’s and recipient’s
performance.
In the Violation Severity Levels for Requirement R1, the impact of a BA not having enough
frequency response depends on two factors:
• Does the Interconnection have sufficient response?
• How short is the BA in providing its FRO?
The VSL takes these factors into account. While the VSLs look different than some other
standards, an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is
intended to measure a violation’s impact on reliability and thus levy an appropriate sanction.
Frequency Response is an interconnection-wide resource. The proposed VSLs are intended to
put multi-BA Interconnections on the same plane as single-BA Interconnections.
Consider a small BA whose performance is 70% of its FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability,
yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection
that had insufficient Frequency Response, because this would treat multi-BA Interconnections
more harshly than single BA Interconnections on a significant scale.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and
Severe VSLs say the Interconnection does not meet the FRO and assesses sanctions based on
whether the BA is deficient by a small or larger amount respectively.
31
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004014
Requirement 2
R2. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined in accordance with Attachment
A, as validated by the ERO, into its Area Control Error (ACE) calculation during the
implementation period specified by the ERO.
Background and Rationale
Attachment A of the Standard discusses the process the ERO will follow to validate the BA’s FRS
Form 1 data and publish the official Frequency Bias Settings. Historically, it has taken multiple
rounds of validation and outreach to confirm each BA’s data due to transcription errors,
misunderstanding of instructions, and other issues. While BAs historically submit Bias Setting
data by January 1, it often takes one or more months to complete the process.
The target is to have BAs submit their data by January 10. The BAs are given 30 days to
assemble their data since the BAs are dependent on the ERO to provide them with FRS Form 1,
and there may be process delays in distributing the forms since they rely on identification of
frequency events through November 30 of the preceding year.
Frequency Bias Settings generally change little from year to year. Given the fact that BAs can
encounter staffing or EMS change issues coincident with the date the ERO sets for new
Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date.
To recap the annual process:
1. The ERO posts the official list of frequency events to be used for this Standard in early
December. The FRS Form 1 for each Interconnection will be posted shortly thereafter.
2. The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3. The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, The ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which
to implement revised Frequency Bias Setting values. Implementation typically would be
on or about March 1st of each year.
BAL-003-0.1b standard requires a minimum Frequency Bias Setting equal in absolute value to
one percent of the Balancing Authority’s estimated yearly peak demand (or maximum
generation level if native load is not served). For most Balancing Authorities this calculated
amount of Frequency Bias is significantly greater in absolute value than their actual Frequency
Response characteristic (which represents an over-bias condition) resulting in over-control
32
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004015
since a larger magnitude response is realized. This is especially true in the Eastern
Interconnection where this condition requires excessive secondary frequency control response
which degrades overall system performance and increases operating cost as compared to
requiring an appropriate balance of primary and secondary frequency control response.
Balancing Authorities were given a minimum Frequency Bias Setting obligation because there
had never been a mandatory Frequency Response Obligation. This historic “one percent of
peak per 0.1Hz” obligation, dating back to NERC’s predecessor, NAPSIC, was intended to ensure
all BAs provide some support to Interconnection frequency.
The ideal system control state exists when the Frequency Bias Setting of the Balancing
Authority exactly matches the actual Frequency Response characteristic of the Balancing
Authority. If this is not achievable, over-bias is significantly better from a control perspective
than under-bias with the caveat that Frequency Bias is set relatively close in magnitude to the
Balancing Authority actual Frequency Response characteristic. Setting the Frequency Bias to
better approximate the Balancing Authority natural Frequency Response characteristic will
improve the quality and accuracy of ACE control, CPS & DCS and general AGC System control
response. This is the technical basis for recommending an adjustment to the long standing “1%
of peak/0.1Hz” Frequency Bias Setting. The Procedure for ERO Support of Frequency
Response and Frequency Bias Setting Standard is intended to bring the Balancing
Authorities’ Frequency Bias Setting closer to their natural Frequency Response. Procedure for
ERO Support of Frequency Response and Frequency Bias Setting Standard balances the
following objectives:
•
Bring the Frequency Bias Setting and Frequency Response closer together.
•
Allow time to analyze impact on other Standards (CPS, BAAL and to a lesser extent DCS)
by adjustments in the minimum Frequency Bias Setting, by accommodating only minor
adjustments.
•
Do not allow the Frequency Bias Setting minimum to drop below natural Frequency
Response, because under-biasing could affect an Interconnection adversely.
Additional flexibility has been added to the Frequency Bias Setting based on the actual
Frequency Response (FRM) by allowing the Frequency Bias Setting to have a value in the range
from 100% of FRM to 125% of FRM. This change has been included for the following reasons:
•
33
When the new standardized measurement method is applied to BAs with a Frequency
Response close to the interconnection minimum response, the requirement to use FRM
is as likely to result in a Frequency Bias Setting below the actual response as it is to
result in a response above the actual response. From a reliability perspective, it is
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004016
always better to have a Frequency Bias Setting slightly above the actual Frequency
Response.
•
As with single BA interconnections, the tuning of the control system may require that
the BA implement a Frequency Response Setting slightly greater in absolute terms than
its actual Frequency Response to get the best performance.
•
The new standardized measurement method for determining FRM in some cases results
in a measured Frequency Response significantly lower than the previous methods used
by some BAs. It is desirable to not require significant change in the Frequency Bias
Setting for these BAs that experience a reduction in their measured Frequency
Response.
Requirement 3
R3. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
•
•
Less than zero at all times, and
Equal to or more negative than its Frequency Response Obligation when the Frequency
varies from 60 Hz by more that +/- 0.036 Hz.
Background and Rationale
In multi-Balancing Authority interconnections, the Frequency Bias Setting should be
coordinated among all BAs on the interconnection. When there is a minimum Frequency Bias
Setting requirement, it should apply for all BAs. However, BAs using a variable Frequency Bias
Setting may have non-linearity in their actual response for a number of reasons including the
dead-bands implemented on their generator governors. The measurement to ensure that
these BAs are conforming to the interconnection minimum is adjusted to remove the deadband range from the calculated average Frequency Bias Setting actually used. For BAs using
variable bias, FRS Form 1 has a data entry location for the previous year’s average monthly Bias.
The Balancing Authority and the ERO can compare this value to the previous year’s Frequency
Bias Setting minimum to ensure R3 has been met.
On single BA interconnections, there is no need to coordinate the Frequency Bias Setting with
other BAs. This eliminates the need to maintain a minimum Frequency Bias Setting for any
reason other than meeting the reliability requirement as specified by the Frequency Response
Obligation.
Requirement 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias Setting for
the combined Balancing Authority Area, to be equivalent to either:
34
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004017
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting as shown on FRS Form 1 and FRS Form 2 for the entirety of
the participating Balancing Authorities’ Areas.
Background and Rationale
This requirement reflects the operating principles first established by NERC Policy 1 and is
similar to Requirement R6 of the approved BAL-003-0.1b standard. Overlap Regulation Service
is a method of providing regulation service in which the Balancing Authority providing the
regulation service incorporates another Balancing Authority’s actual interchange, frequency
response, and schedules into the providing Balancing Authority’s AGC/ACE equation.
As noted earlier, a BA that is providing Overlap Regulation will report the sum of the Bias
Settings in its FRS Form 1. Balancing Authorities receiving Overlap Regulation Service have an
ACE and Frequency Bias Setting equal to zero (0).
35
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004018
How this Standard Meets the FERC Order 693
Directives
FERC Directive
The following is the relevant paragraph of Order No. 693.
Accordingly, the Commission approves Reliability Standard BAL-003-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a modification to
BAL-003-0 through the Reliability Standards development process that: (1) includes
Levels of Non-Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other requirements of
the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) defines the necessary amount of Frequency Response needed for
Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.
1. Levels of Non-Compliance
VRFs and VSLs are an equally effective way of assigning compliance elements to the standard.
2. Determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other Requirements of
the Reliability Standard are met
BAL-003 V0 R2 (the basis of Order No. 693) deals with the calculation of Frequency Bias Setting
such that it reflects natural Frequency Response.
The drafting team has determined that a sample size on the order of at least 20 events is
necessary to have a high confidence in the estimate of a BA’s Frequency Response. Selection of
the frequency excursion events used for analysis will be done via a method outlined in
Attachment A to the Standard.
On average, these events will represent the largest 2-3 “clean” frequency excursions occurring
each month.
Since Frequency Bias Setting is an annual obligation, the survey of the at least 20 frequency
excursion events will occur once each year.
3. Define the necessary amount of Frequency Response needed for
Reliable Operation for each Balancing Authority with methods of
obtaining and measuring that the frequency response is achieved
Necessary Amount of Frequency Response
The drafting team has proposed the following approach to defining the necessary amount of
frequency response. In general, the goal is to avoid triggering the first step of under-frequency
load shedding (UFLS) in the given Interconnection for reasonable contingencies expected. The
36
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004019
methodology for determining each Interconnection’s and Balancing Authority’s obligation is
outlined in Attachment A to the Standard.
It should be noted the standard cannot guarantee there will never be a triggering of UFLS as the
magnitude of “point C” differs throughout an interconnection during a disturbance and there
are local areas that see much wider swings in frequency.
The contingency protection criterion is the largest reasonably expected contingency in the
Interconnection. This can be based on the largest observed credible contingency in the
previous 10 years or the largest Category C event for the Interconnection.
Attachment A to the standard presents the base obligation by Interconnection and adds a
Reliability Margin. The Reliability Margin included addresses the difference between Points B
and C and accounts for variables.
For multiple BA interconnections, the Frequency Response Obligation is allocated to BAs based
on size. This allocation will be based on the following calculation:
FRO FRO
Annual Gen Annual Load
Annual Gen Annual Load
Methods of Obtaining Frequency Response
The drafting team believes the following are valid methods of obtaining Frequency Response:
•
•
•
•
•
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a
contractual share of Frequency Response from Adjacent Balancing Authorities. See FRS
Form 1. While the final rules with regard to contractual services are being defined, the
current expectation is that the ERO and the associated Region(s) should be notified
beforehand and that the service be at least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the
development of a NAESB business practice for Frequency Response service for linear
(droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service,
BAs and FRSGs may use whatever is most appropriate for their situation.
Measuring that the Frequency Response is Achieved
FRS Form 1 and the underlying data retained by the BA will be used for measuring whether
Frequency Response was provided. FRS Form 1 will provide the guidance on how to account for
and measure Frequency Response.
37
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004020
Going Beyond the Directive
Based on the combined operating experience of the SDT, the drafting team consensus is that
each Interconnection has sufficient Frequency Response. If margins decline, there may be a
need for additional standards or tools. The drafting team and the Resources Subcommittee are
working with the ERO on its Frequency Response Initiative to develop processes and good
practices so the Interconnections are prepared. These good practices and tools are described in
the following section.
The drafting team is also evaluating a risk-based approach for basing the Interconnection
Frequency Response Obligation on an historic probability density of frequency error, and for
allocating the obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error. This allocation method uses the inverse of the rationale for allocating the CPS1
epsilon requirement by Bias share.
38
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004021
Good Practices and Tools
Background
This section outlines tips and tools to help Balancing authorities meet the Frequency Response
Standard or to operate more reliably. If you have suggested additions, please send them to
[email protected].
Identifying and Estimating Frequency Responsive Reserves
Knowing the quantity and depth of frequency responsive reserves in real time is a possible next
step to being better prepared for the next event. The challenge in achieving this is having the
knowledge of the capabilities of all sources of frequency response. Presently the primary
source of Frequency Response remains with the generation resources in our fleets.
Understanding how each of these sources performs to changes in system frequency and
knowing their limitations would improve the BA’s ability to measure frequency responsive
reserves. Presently there are only guidelines, criteria and protocols in some regions of the
industry that identify specific settings and performance expectations of Primary Frequency
Response of resources.
One method of gaining a better understanding of performance is to measure performance
during actual events that occur on the system. Measuring performance during actual events
would only provide feedback for performance during that specific event and would not provide
insight into depth of response or other limitations.
Repeated measurements will increase confidence in expected performance. NERC modeling
standards are in process to be revised that will improve the BA’s insight into predicting
available frequency responsive reserves. However, knowing how resources are operated, what
modes of operation provide sustained Primary Frequency Response and knowing the operating
range of this response would give the BA the knowledge to accurately predict frequency
response and the amount of frequency responsive reserves available in real time.
Some benefits have been realized by communicating to generation resources (GO) the
importance of operating in modes that allow Primary Frequency Response to be sustained by
the control systems of the resource. Other improvements in implementation of Primary
Frequency Response have been achieved through improved settings on turbine governors
through the elimination of “step” frequency response with the simultaneous reduction in
governor dead-band settings.
Improvements in the full AGC control loop of the generating resource, which accounts for the
expected Primary Frequency Response, have improved the delivery of quality Primary
Frequency Response while minimizing secondary control actions of generators. Some of these
actions can provide quick improvement in delivery of Primary Frequency Response.
39
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004022
Once Primary Frequency Response sources are known, the BA could calculate available reserves
that are frequency responsive. Planning for these reserves during normal and emergency
operations could be developed and added to the normal planning process.
Using FRS Form 1 Data
The information collected for this standard can be supplemented by a few data points to
provide the Balancing Authority useful tools and information. The BA could do a regression
analysis of its frequency response against the following values:
•
•
•
•
Load (value A).
Interchange (Value A).
Total generation.
Spinning reserve.
While the last two values above are not part of Form 1, they should be readily available. Small
BAs might even include headroom on its larger generators as part of the regression.
The regression would provide a formula the BA could program in its EMS to present the
operator a real time estimate of the BA’s Frequency Response.
Statistical outliers in the regression would point to cases meriting further inspection to find
causes of low Frequency Response or opportunities for improvement.
Tools
Single generating resource performance evaluation tools for steam turbine, combustion turbine
(simple cycle or combined cycle) and for intermittent resources are available at the following
link. http://texasre.org/standards_rules/standardsdev/rsc/sar003/Pages/Default.aspx.
These tools and the regional standard associated with them are in their final stages of
development in the Texas region.
These tools will be posted on the NERC website.
40
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004023
References
NERC Frequency Response Characteristic Survey Training Document (Found in the NERC
Operating Manual)
NERC Resources Subcommittee Position Paper on Frequency Response
NERC TIS Report Interconnection Criteria for Frequency Response Requirements (for the
Determination Interconnection Frequency Response Obligations (IFRO)
Frequency Response Standard Field Trial Analysis, September 17, 2012
41
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004024
Appendix 1 - Data Quality Concerns Related To The Use Of The
Actual Net Interchange Value
Actual net interchange for a typical Balancing Authority (BA) is the summation of its tie lines to
other BAs. In some cases, there are pseudo-ties in it which reflect the effective removal or
addition of load and/or generation from another BA, or it could include supplemental
regulation as well. But in the typical scenario, actual net interchange values that are extracted
from EMS data archiving can be influenced by data latency times in the data acquisition
process, and also any timestamp skewing in the archival process.
Of greater concern, however, are the inevitable variations of other operating phenomena
occurring concurrently with a frequency event. The impacts of these phenomena are
superimposed on actual net interchange values along with the frequency response that we wish
to measure through the use of the actual net interchange value.
To explore this issue further, let’s begin with the idealized condition:
•
•
•
•
•
•
•
frequency is fairly stable at some value near or a little below 60 Hz
ACE of the non-contingent BA of interest is 0 and has been 0 for an extended period,
and AGC control signals have not been issued recently
Actual net interchange is “on schedule”, and there are no schedule changes in the
immediate future
BA load is flat
All generators not providing AGC are at their targets
Variable generation such as wind and solar are not varying
Operators have not directed any manual movements of generation recently
And when the contingency occurs in this idealized state, the change in actual net interchange
will be measuring only the decline in load due to lesser frequency and generator governor
response, and, none of the contaminating influences. While the ACE may become negative due
to the actual frequency response being less than that called for by the frequency bias setting
within the BA’s AGC system, this contaminating influence on measuring frequency response will
not appear in the actual net interchange value if the measurement interval ends before the
generation on AGC responds.
Now let’s explore the sensitivity of the resultant frequency response sampling to the relaxation
of these idealized circumstances.
1. The “60 Hz load” increases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be reduced by the
moderate increase in load and the frequency response will be underestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be increased by the AGC response (and/or manual
adjustments) and the frequency response will be overestimated.
42
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004025
2. The “60 Hz load” decreases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be increased by the
moderate reduction in load and the frequency response will be overestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be decreased by the AGC response (and/or manual
adjustments) and the frequency response will be underestimated.
3. In anticipation of increasing load during the next hour, the operator increases manual
generation before the load actually appears. If the frequency event happens while the
generation “leading” the load is increasing, then the actual net interchange will be
increased by the increase in manual generation and the frequency response will be
overestimated. But if the frequency event occurs when the result of AGC signals sent to
offset the operator’s leading actions take effect, then the actual net interchange will be
decreased and the frequency response is underestimated.
4. In anticipation of decreasing load during the next hour, the operator decreases manual
generation before the load actually declines. If the frequency event happens while the
generation “leading” the load downward is decreasing, then the actual net interchange
will be decreased by the reduction in manual generation and the frequency response
will be underestimated. But if the frequency event occurs when the result of AGC
signals sent to offset the operator’s leading actions take effect, then the actual net
interchange will be increased and the frequency response is overestimated.
5. A schedule change to export more energy is made at 5 minutes before the top of the
hour. The BA’s “60 Hz load” is not changing. The schedule change is small enough that
the operator is relying on upward movement of generators on AGC to provide the
additional energy to be exported. The time at which the AGC generators actually begin
to provide the additional energy is dependent on how much time passes before the AGC
algorithm gets out of its deadbands, the individual generator control errors get large
enough for sending out the control signal, and maybe 20 seconds to 3 minutes for the
response to be effected. The key point here is that it is not clear when the effects of a
schedule change, as manifested in a change in generation and then ultimately a change
in actual net interchange, will occur.
6. With the expected penetration of wind in the near future, unanticipated changes in
their output will tend to affect actual net interchange and add noise to the frequency
response observation process.
To a greater or lesser extent, 1 through 4 above are happening continuously for the most part
with most BAs in the Eastern and Western Interconnections. The frequency response is buried
within the typical hour to hour operational cacophony superimposed on actual net interchange
values. The choice of metrics will be important to artfully extract frequency response from the
noise and other unrepresentative error.
43
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004026
Frequency Response
Standard Background
Document
November, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004027
Table of Contents
Table of Contents ............................................................................................................................ 1
Introduction .................................................................................................................................... 2
Background ..................................................................................................................................... 2
Rationale by Requirement .......................................................................................................... 224
Requirement 1 .................................................................................................................... 224
Background and Rationale .................................................................................................. 224
Requirement 2 .................................................................................................................... 328
Background and Rationale .................................................................................................. 329
Requirement 3 .................................................................................................................... 349
Requirement 4 .................................................................................................................. 3410
Background and Rationale ................................................................................................ 3510
Requirement 5 .................................................................................................................. 3510
Background and Rationale ................................................... Error! Bookmark not defined.10
How this Standard Meets the FERC Order 693 Directives........................................................ 3611
FERC Directive ....................................................................................................................... 3611
1. Levels of Non-Compliance ............................................................................................. 3611
2. Determine the appropriate periodicity of frequency response surveys necessary to
ensure that Requirement R2 and other Requirements of the Reliability Standard are met 3612
3. Define the necessary amount of Frequency Response needed for Reliable Operation for
each Balancing Authority with methods of obtaining and measuring that the frequency
response is achieved ............................................................................................................. 3612
Necessary Amount of Frequency Response ..................................................................... 3612
Methods of Obtaining Frequency Response .................................................................... 3713
Measuring that the Frequency Response is Achieved ...................................................... 3713
Going Beyond the Directive .................................................................................................. 3813
Future Work ............................................................................. Error! Bookmark not defined.13
Good Practices and Tools.......................................................................................................... 3914
Background ........................................................................................................................... 3914
Identifying and Estimating Frequency Responsive Reserves ............................................... 3914
Using FRS Form 1 Data .......................................................................................................... 4015
Tools ...................................................................................................................................... 4015
Field Trial ...................................................................................... Error! Bookmark not defined.16
1
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004028
Introduction
This document provides background on the development, testing and implementation of BAL003-1 - Frequency Response Standard (FRS).1 The intent is to explain the rationale and
considerations for the Requirements of this standard and their associated compliance
information. The document also provides good practices and tips for Balancing Authorities
(“BAs”) with regard to Frequency Response.
In Order No. 693, the Federal Energy Regulatory Commission (“FERC” or the “Commission”)
directed additional changes to BAL-003.2 This document explains how compliance with those
directives are met by BAL-003-1.
The original Standards Authorization Request (“SAR”), finalized on June 30, 2007, assumed
there was adequate Frequency Response in all the North American Interconnections. The goal
of the SAR was to update the Standard to make the measurement process of frequency
response more objective and to provide this objective data to Planners and Operators for
improved modeling. The updated models will improve understanding of the trends in
Frequency Response to determine if reliability limits are being approached. The Standard
would also lay the process groundwork for a transition to a performance-based Standard if
reliability limits are approached.
This document will be periodically updated by the FRS Drafting Team (FRSDT) until the Standard
is approved. Once approved, this document will then be maintained and updated by the ERO
and the NERC Resources Subcommittee to be used as a reference and training resource.
Background
This section discusses the different components of frequency control and the individual
components of Primary Frequency Control also known as Frequency Response.
Frequency Control
Most system operators generally have a good understanding of frequency control and Bias
Setting as outlined in the balancing standards and the references to them in the NERC
Operating Manual. Frequency control can be divided into four overlapping windows of time as
outlined below.
Primary Frequency Control (Frequency Response) – Actions provided by the
Interconnection to arrest and stabilize frequency in response to frequency deviations.
Primary Control comes from automatic generator governor response (also known as speed
1
2
2
Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of Terms Used in NERC Reliability
Standards, available here: http://www.nerc.com/files/Glossary_of_Terms.pdf.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 368-375, order on reh’g, Order
No. 693-A, 120 FERC ¶ 61,053 (2007).
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004029
regulation), load response (typically from motors), and other devices that provide an
immediate response based on local (device-level) control systems.
Secondary Frequency Control – Actions provided by an individual BA or its Reserve Sharing
Group to correct the resource – load unbalance that created the original frequency
deviation, which will restore both Scheduled Frequency and Primary Frequency Response.
Secondary Control comes from either manual or automated dispatch from a centralized
control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced basis
that are coordinated so there is a net zero effect on Area Control Error (ACE). Examples of
Tertiary Control include dispatching generation to serve native load; economic dispatch;
dispatching generation to affect Interchange; and re-dispatching generation. Tertiary
Control actions are intended to replace Secondary Control Response by reconfiguring
reserves.
Time Control includes small offsets to scheduled frequency to keep long term average
frequency at 60 Hz.
Primary Frequency Control – Frequency Response
Primary Frequency Control, also known generally as Frequency Response, is the first stage of
overall frequency control and is the response of resources and load to a locally sensed change
in frequency in order to arrest that change in frequency. Frequency Response is automatic, not
driven by any centralized system, and begins within seconds rather than minutes. Different
resources, loads, and systems provide Frequency Response with different response times,
based on current system conditions such as total resource/load and their respective mix.
The proposed NERC Glossary of Terms defines Frequency Response as:
•
•
(Equipment) The immediate and automatic reaction or response of power from a
system or power from elements of the system to a change in locally sensed system
frequency.
(System) The sum of the change in demand, and the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 Hertz (MW/0.1 Hz).
As noted above, Frequency Response is the characteristic of load and generation within
Balancing Authorities and Interconnections. It reacts or responds with changes in power to
attempted changes in load-resource balance that result in changes to system frequency.
Because the loss of a large generator is much more likely than a sudden loss of an equivalent
amount of load, Frequency Response is typically discussed in the context of a loss of a large
generator. Included within Frequency Response are many components of that response.
Understanding Frequency Response and the FRS requires an understanding of each of these
components and how they relate to each other.
Frequency Response Illustration
The following simple example is presented to illustrate the components of Frequency Response
in graphical form. It includes a series of seven graphs that illustrate the various components of
3
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004030
Frequency Response and a brief discussion of each describing how these components react to
attempted changes in the load-resource balance and resulting changes in system frequency.
The illustration is based on an assumed Disturbance event of the sudden loss of 1000 MW of
generation. Although a large event is used to illustrate the response components, even small
frequently occurring events will result in similar reactions or responses. The magnitude of the
event only affects the shape of the curves on the graph; it does not obviate the need for
Frequency Response.
Primary Frequency Control - Frequency Response - Graph 1
3000
60.100
Power Deficit
2500
60.000
2000
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Change in Power (MW)
Frequency
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The first graph, Primary Frequency Control – Frequency Response – Graph 1, presents a sudden
loss of generation of 1000 MW. The components are presented relative to time as shown on
the horizontal Time axis in seconds. This simplified example assumes a Disturbance event of
the sudden loss of generation resulting from a breaker trip that instantaneously removes 1000
MW of generation from the interconnection. This sudden loss is illustrated by the power deficit
line shown in black using the MW scale on the left. Interconnection frequency is illustrated by
the frequency line shown in red using the Hertz scale on the right. Since the Scheduled
Frequency is normally 60 Hz, it is assumed that this is the frequency when the Disturbance
event occurs.
Even though the generation has tripped and power injected by the generator has been
removed from the interconnection, the loads continue to use the same amount of power. The
4
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004031
“Law of Conservation of Energy”3 requires that the 1000 MW must be supplied to the
interconnection if energy balance is to be “conserved”. This additional 1000 MW of power is
produced by extracting kinetic energy that was stored in the rotating mass of all of the
synchronized generators and motors on the interconnection – essentially using this equipment
as a giant flywheel. The extracted energy supplies the “balancing inertia”4 power required to
maintain the power and energy balance on the interconnection. This balancing inertia power is
produced by the generators’ spinning inertial mass’ resistance to the slowdown in speed of the
rotating equipment on the interconnection that both provides the stored kinetic energy and
reduces the frequency of the interconnection. This is illustrated in the second graph, Primary
Frequency Control – Frequency Response – Graph 2, by the orange dots representing the
balancing inertia power that exactly overlay and offset the power deficit.
Primary Frequency Control - Frequency Response - Graph 2
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
As the frequency decreases, synchronized motors slow, as does the work they are providing,
resulting in a decrease in load called “load damping.” This load damping is the reason that the
power deficit initially declines. Synchronously operated motors will contribute to load
damping. Variable speed drives that are decoupled from the interconnection frequency do not
3
4
5
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power which is the first
derivative of energy with respect to time, must also be conserved.
The term “balancing Inertia” is coined here from the terms “inertial frequency response” and “balancing energy”. Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004032
contribute to load damping. In general, any load that does not change with interconnection
frequency including resistive load will not contribute to load damping or Frequency Response.
It is important to note that the power deficit equals exactly the balancing inertia, indicating that
there is no power or energy imbalance at any time during this process. What is normally
considered as “balancing power or energy” is actually power or energy required to correct the
frequency error from scheduled frequency. Any apparent power or energy imbalance is
corrected instantaneously by the balancing inertia power and energy extracted from the
interconnection. Thus the balancing function is really a frequency control function described as
a balancing function because ACE is calculated in MWs instead of Hertz, frequency error.
During the initial seconds of the Disturbance event, the governors have yet to respond to the
frequency decline. This is illustrated with the Blue line on the third graph, Primary Frequency
Control – Frequency Response – Graph 3, showing Governor Response. This time delay results
from the time that it takes the controller to adjust the equipment and the time it takes the
mass to flow from the source of the energy (main steam control valve for steam turbines, the
combustor for gas turbines, or the gate valve for hydro turbines) to the turbine-generator
blades where the power is converted to electrical energy.
Primary Frequency Control - Frequency Response - Graph 3
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Note that the frequency continues to decline due to the ongoing extraction by balancing inertia
power of energy from the rotating turbine-generators and synchronous motors on the
interconnection. The reduction in load also continues as the effect of load damping continues
6
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004033
to reduce the load while frequency declines. During this time delay (before the governor
response begins) the balancing inertia limits the rate of change of frequency.
After a short time delay, the governor response begins to increase rapidly in response to the
initial rapid decline in frequency, as illustrated on the fourth graph, Primary Frequency Control
– Frequency Response – Graph 4. Governor response exactly offsets the power deficit at the
point in time that the frequency decline is arrested. At this point in time, the balancing inertia
has provided its contribution to reliability and its power contribution is reduced to zero as it is
replaced by the governor response. If the time delay associated with the delivery of governor
response is reduced, the amount of balancing inertia required to limit the change in frequency
by the Disturbance event can also be reduced. This supports the conclusion that balancing
inertia is required to manage the time delays associated with the delivery of Frequency
Response. Not only is the rapid delivery of Frequency Response important, but the shortening
of the time delay associated with its delivery is also important. Therefore, two important
components of Frequency Response are 1) how long the time delay is before the initial delivery
of response begins; and 2) how much of the response is delivered before the frequency change
is arrested.
Primary Frequency Control - Frequency Response - Graph 4
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
This point, at which the frequency is first arrested, is defined as “Point C” and Frequency
Response calculated at this point is called the “arrested frequency response.” The arrested
frequency is normally the minimum (maximum for load loss events) frequency that will be
7
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004034
experienced during a Disturbance event. From a reliability perspective, this minimum
frequency is the frequency that is of concern. Adequate reliability requires that frequency at
the time frequency is arrested remain above the under-frequency relay settings so as not to trip
these relays and the firm load interrupted by them. Frequency Response delivered after
frequency is arrested at this minimum level provides less reliability value than Frequency
Response delivered before Point C, but greater value than Secondary Frequency Control power
and energy which is delivered minutes later.
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with their Governor Response. This results in the frequency partially
recovering from the minimum arrested value and results in an oscillating transient that follows
the minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period that ends roughly 20 seconds after the Disturbance event. This postdisturbance transient period is included on the fifth illustrative graph, Primary Frequency
Control – Frequency Response – Graph 5.
Primary Frequency Control - Frequency Response - Graph 5
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The total Disturbance event illustration is presented on the sixth graph, Primary Frequency
Control – Frequency Response – Graph 6. Frequency and power contributions stabilize at the
end of the transient period. Frequency Response calculated from data measured during this
settled period is called the “Settled Frequency Response.” The Settled Frequency Response is
the best measure to use as an estimator for the “Frequency Bias Setting” discussed later.
8
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004035
Primary Frequency Control - Frequency Response - Graph 6
3000
60.100
Power Deficit
Balancing Inertia
2500
60.000
Load Damping
Governor Response
59.900
1500
59.800
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
Frequency
2000
59.400
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
The final Disturbance event illustration is presented on the seventh graph, Primary Frequency
Control – Frequency Response – Graph 7. This graph shows the averaging periods used to
estimate the pre-disturbance A-Value averaging period and the post-disturbance B-Value
averaging period used to calculate the settled frequency response. A discussion of the
measurement of Frequency Response immediately follows these graphs. That discussion
includes consideration of the factors that affect the methods chosen to measure Frequency
Response for implementation in a reliability standard.
9
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004036
Primary Frequency Control - Frequency Response - Graph 7
3000
60.100
Power Deficit
Balancing Inertia
Load Damping
Governor Response
A-value
B-value
2500
60.000
Frequency
59.900
1500
59.800
B-Value Averaging Period
A-Value Averaging Period
Point C
1000
59.700
500
59.600
0
59.500
-500
Frequency (Hz)
Power (MW)
2000
59.400
-20
-15
-10
-5
0
5
10
15
20
25
30
35
40
45
50
55
60
TIme (Seconds)
Frequency Response Measurement (FRM)
The classic Frequency Response points A, C, and B, shown below in Fig. 1 Frequency Response
Characteristic, are used for measurement as found in the Frequency Response Characteristic
Survey Training Document within the NERC operating manual, found at
http://www.nerc.com/files/opman_7-1-11.pdf. This traditional Frequency Response Measure
has recently been more specifically termed “settled frequency response.” This term has been
used because it provides the best Frequency Response Measure to estimate the Frequency Bias
Setting in Tie-line Bias Control based Automatic Generation Control Systems. However, the
industry has recognized that there is considerable variability in measurement resulting from the
selection of Point A and Point B in the traditional measure making the traditional measurement
method unsuitable as the basis for an enforceable reliability standard in a real world setting of
multiple Balancing Authority interconnections.
10
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004037
Frequency Response
60.050
60.025
A = 60.000
60.000
Frequency (Hz)
59.975
59.950
59.925
59.900
B = 59.874
59.875
59.850
59.825
C = 59.812
59.800
59.775
59.750
-30
-20
-10
0
10
20
30
40
50
60
Time (Seconds)
Figure 1. Frequency Response Characteristic
By contrast, measuring an Interconnection’s settled frequency response is straightforward and
fairly accurate. All that’s needed to make the calculation is to know the size of a given
contingency (MW), divide this value by the change in frequency and multiply the results by 10
since frequency response is expressed in MW/0.1Hz.
Measuring a BA’s frequency response is more challenging. Prior to BAL-003-1, NERC’s
Frequency Response Characteristic Survey Training Document provided guidance to calculate
Frequency Response. In short, it told the reader to identify the BA’s interchange values
“immediately before” and “immediately after” the Disturbance event and use the difference to
calculate the MWs the BA deployed for the event. There are two challenges with this
approach:
•
•
Two people looking at the same data would come up with different values when
assessing which exact points were immediately before and after the event.
In practice, the actual response provided by the BA can change significantly in the
window of time between point B and when secondary and tertiary control can assist in
recovery.
Therefore, the measurement of settled frequency response has been standardized in a number
of ways to limit the variability in measurement resulting from the poorly specified selection of
Point A and Point B. It should be noted that t-0 has been defined as the first scan value that
11
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004038
shows a deviation in frequency of some significance, usually approaching about 10 mHz. The
goal is such that the first scan prior to t-0 was unaffected by the deviation and appropriate for
one of the averaging points.
•
•
The A-value averaging period of approximately the previous 16 seconds prior to t-0 was
selected to allow for an averaging of at least 2 scans for entities utilizing 6 second scan
rates. (All time average period references in this document are for 2 second scan rates
unless noted otherwise.)
The B-value averaging period of approximately (t+20 to t+52 seconds) was selected to
attempt to obtain the average of the data after primary frequency response was
deployed and the transient completed(settled), but before significance influence of
secondary control. Multiple periods were considered for averaging the B-value:
o 12 to 24 sec
o 18 to 30 sec
o 20 to 40 sec
o 18 to 52 sec
o 20 to 52 sec
It is necessary for all BAs from an interconnection to use the same averaging periods to
provide consistent results. In addition, the SDT decided that until more experience is
gained, it is also desirable for all interconnections to use the same averaging periods to
allow comparison between interconnections.
The methods presented in this document only address the values required to calculate the
frequency response associated with the frequency change between the initial frequency, AValue, and the settling frequency, B-Value. No reasonable or consistent calculations can be
made relating to the arresting frequency, C-Value, using Energy Management System (EMS)
scan rate data as long as 6-seconds or tie-line flow values associated with the minimum value of
the frequency response characteristic (C-value) as measured at the BA level.
Both the calculation of the frequency at Point A and the frequency at Point B began with the
assumption that a 6-second scan rate was the source of the data. Once the averaging periods
for a 6-second scan rate were selected, the averaging periods for the other scan rates were
selected to provide as much consistency as possible between BAs with different scan rates.
The Frequency at Point A was initially defined as the average of the two scans immediately
prior to the frequency event. All other averaging periods were selected to be as consistent as
possible with this 12 second average scan from the 6-second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” is defined as the average of the
same scans as used for the Point A frequency average.
The Frequency at Point B was then selected to be an average as long as the average of 6-second
scan data as possible that would not begin until most of the hydro governor response had been
delivered and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” is defined as the average of the same
scans as used for the Point B frequency average.
12
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004039
B Averaging Period Selection:
Experience from the Electric Reliability Council of Texas (“ERCOT”) and the field trail on
other interconnections indicated that the 12 to 24 second and 18 to 30 second
averaging periods were not suitable because they did not provide the consistency in
results that the other averaging periods provided, and that the remaining measuring
periods do not provide significantly different results from each other. The team
believed that this was observed because the transients were not complete in all of the
samples using these averaging periods.
The 18 to 52 second and 20 to 52 second averaging periods were compared to each
other, with the 20 to 52 second period providing more consistent values, believed to
result from the incomplete transient in some of the 18 to 52 second samples.
This left a choice between the 20 to 40 second and the 20 to 52 second averaging
periods. The team recognized that there would be more AGC response in the 20 to 52
second period, but the team also recognized that the 20 to 52 second period would
provide a better measure of squelched response from outer loop control action. The 20
to 52 second period was selected because it would indicate squelched response from
outer-loop control and provide incentive to reduce response withdrawal. The final
selections for the data averaging periods used in FRS Form 1 are shown in the table
below.
Definitions of Frequency Values for Frequency Response Calculation
Scan Rate
T 0 Scan
6-Seconds
5-Seconds
4-Seconds
3-Seconds
2-Seconds
Identify first
significant
change in
frequency as
the T 0 scan
A Value (average)
B Value (average)
Average of T-1 through T-2 scans
Average of T+4 through T+8 scans
Average of T-1 through T-2 scans
Average of T+5 through T+10 scans
Average of T-1 through T-3 scans
Average of T+6 through T+12 scans
Average of T-1 through T-5 scans
Average of T+7 through T+17 scans
Average of T-1 through T-8 scans
Average of T+10 through T+26 scans
Consistent measurement of Primary Frequency Response is achievable for a selected number of
events and can produce representative frequency response values, provided an appropriate
sample size is used in the analysis. Available research investigating the minimum sample size to
provide consistent measurements of Frequency Response has shown that a minimum sample
size of 20 events should be adequate.
Measurement of Primary Frequency Response on an individual resource or load basis requires
analysis of energy amounts that are often small and difficult to measure using current methods.
In addition, the number of an interconnection's resources and loads providing their response
could be problematic when compiling results for multiple events.
Measurement of Primary Frequency Response on an interconnection (System) basis is straight
forward provided that an accurate frequency metering source is available and the magnitude of
the resource/load imbalance is known in MWs.
13
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004040
Measurement on a Balancing Authority basis can be a challenge, since the determination of
change in MWs is determined by the change in the individual BA's metered tie lines.
Summation of tie lines is accomplished by summing the results of values obtained by the digital
scanning of meters at intervals up to six seconds, resulting in a non-coincidental summing of
values. Until the technology to GPS time stamp tie line values at the meter and the summing of
those values for coincidental times is in use throughout the industry, it is necessary to use
averaging of values described above to obtain consistent results.
Figure 2. Frequency Response Measurement
The standardized measure is shown graphically in Fig. 2 Frequency Response Measurement
with the averaging periods shown by the solid blue green and red lines on the graph. Since FERC
directed a performance obligation for BAL-003-1, it is important to be more objective in the
measurement process. The standardized calculation is available on FRS Form 2 for EMS scan
rates of 2, 3, 4, 5, and 6 seconds at
http://www.nerc.com/filez/standards/Frequency_Response.html.
Arrested Frequency Response
There is another measure of Frequency Response that is of interest when developing a
Frequency Response estimate that not only will be used for estimating the Frequency Bias
Setting, but will also be used to assure reliability by operating in a manner that will bound
interconnection frequency and prevent the operation of Under-frequency Relays. This
Frequency Response Measure has recently been named “arrested frequency response.” This
Frequency Response is significantly affected by the inertial Frequency Response, the governor
Frequency Response and the time delays associated with the delivery of governor Frequency
14
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004041
Response. It is calculated by using the change in frequency between the initial frequency, A,
and the maximum frequency change during the event, C, instead of using the change between
A and B. Arrested Frequency Response is the correct response for determining the minimum
Frequency Response related to under-frequency relay operation and the support of
interconnection reliability. This is because it can be used to provide a direct estimate of the
maximum frequency deviation an interconnection will experience for an initial frequency and a
given size event in MW. Unfortunately, arrested frequency response cannot currently be
measured using the existing EMS-based measurement infrastructure. This limitation exists
because the scan rates currently used in industry EMSs are incapable of measuring the net
actual interchange at the same instant that the maximum frequency deviation is reached.
Fortunately, the ratio of arrested frequency response and settled frequency response tends to
be stable on an interconnection. This allows the settled frequency response value to be used as
a surrogate for the arrested frequency response and implement a reasonable measure upon
which to base a standard. One consequence of using the settled frequency response as a
surrogate for the arrested frequency response is the inclusion of a large reliability margin in
Interconnection Frequency Response Obligation to allow for the difference between the settled
frequency response as measured and the arrested frequency response that indicates reliability.
As measurement infrastructure improves one might expect the Frequency Response Obligation
to transition to a measurement based directly on the arrested frequency response while the
Frequency Bias Setting will continue to be based on the settled frequency response. However,
at this time, the measurement devices and methods in use do not support the necessary level
of accuracy to estimate arrested frequency response contribution for an individual Balancing
Authority.
Frequency Response Definition and Examples
Limitations of the measurement infrastructure determine the measurement methods
recommended in this standard. The measurement limitations provide opportunities to improve
the Frequency Response as measured in the standard without contributing to an improvement
in Frequency Response that contributes to reliability. These definitions and examples provide a
basis for determining which contributions to Frequency Response contribute the most to
improved reliability. They also provide the basis for determining on a case by case basis
whether the individual contributors to the Frequency Response Measure are also contributing
to reliability.
General Frequency Response Characteristics
In the simplest case Frequency Response includes any automatic response to changes in local
frequency. If that response works to decrease that change in frequency, it is beneficial to
reliability. If that response works to increase that change in frequency, it is detrimental to
reliability. However, this definition does not address the relative value of one response as
compared to other responses that may be provided in a specific case.
There are numerous characteristics associated with the Frequency Response that affect the
reliability value and economic value of the response. These characteristics include:
1. Inertial – the response is inertial or approximates inertial response
15
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004042
Inertial response provides power without delay that is proportional to the frequency
and the change in frequency. Therefore, power provided by electronic control as
synthetic Inertial response must be proportional to the frequency and change in
frequency and be provided without a time delay.
2. Immediate – no unnecessary intentional time delays or reduction in the rate of
response delivery
a. time delay before the beginning of the response
Turbines that convert heat or kinetic energy have time delays related to the time
delay from the time that the control valves are moved to initiate the change in
power and the time that the power is delivered to the generator. These times
are usually associated with the time it takes a change in mass flow to travel from
the control valve to the first blades of the turbine in the turbine generator.
b. reduction in the rate of response delivery
There are natural delays associated with the rate of response delivery that are
related to the mass flow travel from the first turbine blades to the last turbine
blades. In addition, some turbines have intentional delays designed into the
control system to slow the rate of change in the delivery of the kinetic energy or
fuel to the turbine to prevent the turbine or other equipment from being
damaged, hydro turbines, or to prevent the turbine from tripping due to
excessive rate of change, gas turbines.
3. Proportional – the amount of the total response is proportional to the frequency error
a. No Deadband – the response is proportional across the entire frequency range
b. Deadband – the response is only proportional outside of a defined deadband
4. Bi-directional – the response occurs to both increases and decreases in frequency
5. Continuous – there are no discontinuities in the delivery of the response (no step
changes)
6. Sustained – the response is sustained until frequency is returned to schedule
Frequency Response Reliability Value
This section contains a more detailed discussion of the various characteristics of Frequency
Response listed in the previous section. It also provides an indication of the relative value of
these characteristics with respect to their contribution to reliability. Finally, it includes some
examples of the described responses.
Inertial Response is provided from the stored energy in the rotating mass of the turbinegenerators and synchronous motors on the interconnection. It limits the rate of change of
frequency until sufficient Frequency Response can be supplied to arrest the change in
frequency. Its reliability value increases as the time delay associated with the delivery of other
Frequency Response on the interconnection increases. If those time delays are minimal, then
the value of inertial response is low. If all time delays associated with the Frequency Response
could be eliminated, then inertial response would have little value.
16
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004043
The reliability value of Inertial Response is the greatest on small interconnections because the
size of the Disturbance events is larger relative to the inertia of the interconnection. Electronic
controls have been developed to provide synthetic inertial response from the stored energy in
asynchronous generators to supplement the natural inertial response. Some Type III & IV Wind
Turbines have this capability. In addition, electronically controlled SCRs have been developed
that can store energy in the electrical system and release this stored energy to supply synthetic
inertial response when required.
Immediate Response is provided by load damping and because the time delays associated with
its delivery are very short (related to the speed of electrical signal in the electrical system); load
damping requires very little inertial response to limit arrested frequency effectively. Synthetic
immediate response can also be supplied from loads because in many cases, there is no mass
flow time delay associated with the load process providing the power and energy reduction.
Therefore, loads can provide an immediate response with a higher reliability value than
generators with time delays required by the physics of the turbine-generator.
Governor response has time delays associated with its delivery. Governor response provided
with shorter time delays has a higher reliability value because those shorter time delays require
less inertial response to arrest frequency. Governor response is provided by the turbinegenerators on the interconnection. Time delays associated with governor response vary
depending on the type of turbine-generator providing the response.
The longest time delays are usually associated with high head hydro turbine-generators that
require long times from the governor action until the additional mass flow through the turbine.
These units may also have the longest delivery time associated with the full delivery of
response because of the timing designed into the governor response.5
Intermediate time delays are usually associated with steam turbine-generators. The response
begins when the steam control valves are adjusted and the steam mass flows from the valves to
the first high pressure turbine blades. The delivery times associated with the full delivery of
response may require the steam to flow through high, intermediate and low pressure turbines
including reheat flows before full power is delivered. These times are shorter than those of the
hydro turbine-generators in general, but not as fast as the times associated with gas turbines.6
Gas turbines typically have the shortest time delays, because control is provided by injecting
more or less fuel into the turbine combustor and adjusting the air control dampers. These
control changes can be initiated rapidly and the mass flow has the shortest path to the turbine
5
6
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-6 – 1-9.
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-4 – 1-6.
17
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004044
blades. There may be timing limitations related to the rate of change in output of the gas
turbine-generator to maintain flame stability in some cases slowing the rate of change.7
Synthetic Governor Response can be supplied by certain loads and storage systems. The
immediacy of the response is normally limited only by the electronic controls used to activate
the desired response. Synthetic response, when it can be supplied immediately without
significant time delay, has a higher reliability value because it requires less inertial response to
achieve smaller arrested frequency deviations.
Proportional Response indicates that the response provided is proportional in magnitude to
the frequency error. Response deadbands cause a non-proportional response and reduce the
value of the response with respect to reliability. Contrary to general consensus, deadbands do
not reduce the amount of Frequency Response that must be provided, they only transfer the
responsibility for providing that Frequency Response from one source on the interconnection to
another. For a given response, the response with the smaller deadband has the greater
reliability value. Therefore, deadbands should be set to the smallest value that supports overall
reliable operation including the reliable operation of the generator.
Electronic controls have also been developed to provide synthetic governor response. When
these controls are applied to certain loads or stored energy systems, they can be programmed
to provide synthetic governor response similar to the proportional response of a turbinegenerator governor. Governor response in generators is limited to a small percentage of the
output of the generating unit, while synthetic governor response could be applied to much
larger percentages of loads or storage devices providing such response.
Load damping provides a proportional response.
Continuous Response is response that has no discontinuous (step) changes in the frequency
versus response curve. Step changes (Non-continuous Response) in the Governor Response
curve can lead to frequency instabilities at frequencies near the changes. The ERCOT
Interconnection observed this and has since prohibited the use of governor response
characteristics incorporating step responses.
Step responses also occur with the implementation of load interruption using under-frequency
or over-frequency relays.
Bi-directional Response is response that occurs in both directions, when the frequency is
increasing and when the frequency is decreasing. A uni-directional response is a response that
only occurs once when frequency is decreasing or when frequency is increasing.
Inertial response, governor response and load damping are all bi-directional responses. Certain
loads are capable of providing proportional bi-directional response while others are only
capable of providing non-proportional bi-directional response.
7
Interconnected Power System Response to Generation Governing: Present Practice and Outstanding Concerns –
Final Report, IEEE, May 2007, pp. 1-16 – 1-19.
18
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004045
The ERCOT Load Resource program is a uni-directional response program. Loads are only
tripped when frequency declines below a given set-point. When frequency is restored above
that set-point, the loads must be manually reconnected. As a consequence, the Frequency
Response only occurs once with declining frequency and does not oppose the increase in
frequency after the initial decline. If there should be a frequency oscillation, the uni-directional
response will not contribute to the opposition of a second frequency decline across the setpoint during an oscillation event. Once a uni-directional response has occurred, it is unavailable
for a second decline before reset.
Step or proportional responses implemented bi-directionally can lead to frequency instability
when there is less continuous frequency response than the magnitude of the change in
continuous response between the trip and reset frequencies in step, or the proportional
response rate of change is greater than the underlying continuous response. A step bidirectional response will have the load reconnected as frequency recovers from the event thus
opposing the increase in frequency during recovery, and also resetting the load response for
the next frequency decline automatically. Bi-directional response obviously has a greater
reliability value than uni-directional response.
Sustained Response is provided at its full value until frequency is restored to its scheduled
value. On today’s interconnections, few frequency responses are fully sustained until
frequency has been restored to its scheduled value. On steam based turbine-generators, the
steam pressure may drop after a time as the result of the additional steam flow from governor
action. However, in general this has not been a problem because most responses are
incomplete at the time that frequency has been initially arrested and the additional response
has generally been sufficient to make up for more than the these unpreventable reductions in
response. However, the intentional withdrawal of response before frequency has been
restored to schedule can cause a decline in frequency beyond that which would be otherwise
expected. This intentional withdrawal of response is highly detrimental to reliability.
Therefore, it can be concluded in general that sustained response has a higher reliability value
than un-sustained response.
On an interconnection, the withdrawal of response due to the loss of steam pressure on the
steam units may be offset by the slower response of hydro turbine-generators. In these cases,
the reliability of the combined response provides a greater reliability value than the individual
response of each type. The steam turbine-generators provide a fast response that may be
reduced, while the hydro turbine-generators provide a slower response, contributing less to the
arresting response, offsetting any reduction by the steam turbine-generators to assure a
sustained response.
Sustained Response must also be considered for any resource that has a limited duration
associated with its response. The amount of stored energy available from a resource may limit
its ability to sustain response for a duration of time necessary to support reliability.
Frequency Response Cost Factors
In every system of exchange there are two sides; the supply side and the demand side. The
supply side provides the services used by the demand side. In the case of Frequency Response,
19
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004046
the supply side includes all providers of Frequency Response and the demand side includes all
participants that create the need for Frequency Response.
Frequency Response Costs – Supply Side
There are a number of factors that affect the cost of providing Frequency Response from
resources. Since there is a cost associated with those factors, some method of appropriate
compensation could be made available to those resources providing Frequency Response.
Without compensation, providers of Frequency Response will be put in the position of incurring
additional cost that can be avoided only by reducing or eliminating the response they provide.
These costs are incurred independently of whether provided for in a formal Regional
Transmission Organization/Independent System Operator (RTO/ISO) market or in a traditional
BA subject to the FERC pro-forma tariffs.
It is the responsibility of the BA or the RTO/ISO to acquire the necessary amount of Frequency
Response to support reliability in the most cost effective manner. This function is performed
best when the suppliers are evaluated based on the value of the Frequency Response they
provide and compensated appropriately for that Frequency Response. Suppliers provide
Frequency Response when they are assured that they will receive fair compensation. Before
considering how to perform this evaluation and compensation, the costs associated with
providing Frequency Response should be understood and evaluated with respect to the level of
reliability they offer.
Some cost factors that have been identified for providing Frequency Response include:
1. Capacity Opportunity Cost – the costs, including opportunity costs, associated with
reserving capacity to provide Frequency Response. These costs are usually associated
with the alternative use of the same capacity to provide energy or other ancillary
services. There may also be capacity opportunity costs associated with the loss in
average capacity by a load providing Frequency Response.
2. Fuel Cost – The cost of fuel used to provide the Frequency Response. The costs for fuel
to provide Frequency Response can result in energy costs significantly different from the
system marginal energy cost, both higher and lower. This is the case when Frequency
Response is provided by resources that are not at the system marginal cost.
3. Energy Efficiency Penalty Costs – the costs associated with the loss in efficiency when
the resource is operated in a mode that supports the delivery of Frequency Response.
This cost is usually in the form of additional fuel use to provide the same amount of
energy. An example is the difference between operating a steam turbine in valve
control mode with an active governor and sliding pressure mode with valves wide open
and no active governor control except for over-speed. This cost is incurred for all of the
energy provided by the resource, not just the energy provided for Frequency Response.
There may be additional energy costs associated with a load providing Frequency
Response from loss in efficiency of their process when load is reduced.
4. Capacity Efficiency Penalty Costs – the costs associated with any reduction in capacity
resulting from the loss of capacity associated with the loss in energy efficiency. When
efficiency is lost, capacity may be lost at the same time because of limitations in the
amount of input energy that can be provided to the resource.
20
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004047
5. Maintenance Costs – the operation of the resource in a manner necessary to provide
Frequency Response may result in increases in the maintenance costs associated with
the resource.
6. Emissions Costs – the additional costs incurred to manage any additional emissions that
result when the resource is providing Frequency Response or stands ready to provide
Frequency Response.
A good contract for the acquisition of Frequency Response from a resource will provide
appropriate compensation to the resource for all of the costs the resource incurs to provide
Frequency Response. It will also provide a method to evaluate the least cost mix of resources
necessary to provide the minimum required Frequency Response for maintaining reliability.
Finally, it will provide the least complex method of evaluation considering the complexity and
efficiency of the acquisition process.
Frequency Response Costs – Demand Side
Not only are there costs associated with acquiring Frequency Response from the supplying
resources, there are costs associated with the amount of Frequency Response that must be
acquired and influenced by those participants that create the need for Frequency Response. If
the costs of acquiring Frequency Response from the supply resources can be assigned to those
parties that create the need for Frequency Response, there is the promise that the amount of
Frequency Response required to maintain reliability can be minimized. The considerations are
the same as those that are driving the development of “real time pricing” and “dynamic
pricing”. If the costs are passed on to those contributing to the need for Frequency Response,
incentives are created to reduce the need for Frequency Response making interconnection
operations less expensive and more reliable. The problem is to balance both cost and
complexity against reliability on both the supply side and the demand side.
21
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004048
Rationale by Requirement
Requirement 1
R1. Each Frequency Response Sharing Group (FRSG) or Balancing Authority that is not a
member of a FRSG shall achieve an annual Frequency Response Measure (FRM) (as calculated
and reported in accordance with Attachment A) that is equal to or more negative than its
Frequency Response Obligation (FRO) to ensure that sufficient Frequency Response is provided
by each FRSG or Balancing Authority that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more negative than the Interconnection
Frequency Response Obligation.
Background and Rationale
R1 is intended to meet the following primary objectives:
• Determine whether a Balancing Authority (BA) has sufficient Frequency Response for
reliable operations.
• Provide the feeder information needed to calculate CPS limits and Frequency Bias
Settings.
Primary Objective
With regard to the first objective, FRS Form 1 and the process in Attachment A provide the
method for determining the Interconnections’ necessary amount of Frequency Response and
allocating it to the Balancing Authorities. The field trial for BAL-003-1 is testing an allocation
methodology based on the amount of load and generation in the BA. This is to accommodate
the wide spectrum of BAs from generation-only all the way to load-only.
Frequency Response Sharing Groups (FRSGs)
This standard proposes an entity called FRSG, which is defined as:
A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply operating resources required to
jointly meet the sum of the Frequency Response Obligations of its members.
This standard allows Balancing Authorities to cooperatively form FRSGs as a means to jointly
meet the FRS. There is no obligation to form or be a part of FRSGs. The members of the FRSG
would determine how to allocate sanctions among its members. This standard does not
mandate the formation of FRSGs, but allows them as a means to meet one of FERC’s Order No.
693 directives.
FRSG performance may be calculated one of two ways:
•
•
22
Calculate a group NIA and measure the group response to all events in the reporting
year on a single FRS Form 1, or
Jointly submit the individual BAs’ Form 1s, with a summary spreadsheet that sums each
participant’s individual event performance.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004049
Frequency Response Obligation and Calculation
The basic Frequency Response Obligation is based on annual loadnon-coincident peak load and
generation data reported in FERC Form 714 (where applicable, see below for non-jurisdictional
entities) for the previous full calendar year. The basic allocation formula used by NERC is:
FRO
Annual Gen Annual Load
FRO
Annual Gen Annual Load
Where:
• Annual GenBA is the annual “Net Generation (MWh)”, FERC Form 714, line 13, column c
of Part II - Schedule 3.
• Annual LoadBA is the annual “Net Energy for Load (MWh)”, FERC Form 714, line 13,
column e of Part II - Schedule 3.
• Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
• Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
Balancing Authorities that are not FERC jurisdictional should use the Form 714 Instructions to
assemble and submit equivalent data. Until the BAL-003-1 process outlined in Attachment 1 is
implemented, Balancing Authorities can approximate their FRO by multiplying their
Interconnection’s FRO by their share of Interconnection Bias. The data used for this calculation
should be for the most recently filed Form 714. As an example, a report to NERC in January
2013 would use the Form 714 data filed in 2012, which utilized data from 2011.
Balancing Authorities that merge or that transfer load or generation need to notify the ERO of
the change in footprint and corresponding changes in allocation such that the net obligation for
the Interconnection remains the same and so that CPS limits can be adjusted.
Attachment A proposes the following Interconnection event criteria as a basis to determine an
Interconnection’s Frequency Response Obligation:
•
•
•
Largest category C loss-of-resource (N-2) event.
Largest total generating plant with common voltage switchyard.
Largest loss of generation in the interconnection in the last 10 years.
With regard to the second objective above (determining Frequency Bias Settings and CPS
limits), Balancing Authorities have been asked to perform annual reviews of their Frequency
Bias Settings by measuring their Frequency Response, dating back to Policy 1. This obligation
was carried forward into BAL-003-01.b. While the associated training document provided
useful information, it left many of the details to the judgment of the person doing the analysis.
The FRS Form 1 and FRS Form 2 provide a consistent, objective process for calculating
Frequency Response to develop an annual measure, the FRM.
23
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004050
The FRM will be computed from Single Event Frequency Response Data (SEFRD), defined as:
“the data from an individual event from a Balancing Authority that is used to calculate its
Frequency Response, expressed in MW/0.1Hz”. The SEFRD for a typical Balancing Authority in
an Interconnection with more than one Balancing Authority is basically the change of its net
actual interchange on its tie lines with its adjacent Balancing Authorities divided by the change
in interconnection frequency. (Some Balancing Authorities may choose to apply corrections to
their net actual interchange values to account for factors such as nonconforming loads. FRS
Form 1 shows the types of adjustments that are allowed.)
A standardized sampling interval of approximately 20 to 52 seconds will be used in the
computation of SEFRD values. Microsoft Excel® spreadsheet interfaces for EMS scan rates of 2
through 6 seconds are provided to support the computation.
Single Event Frequency Response Data8
The use of a “single event measure” was considered early in the development of the FRS for
compliance because a single event measure could be enforced for each event on the
interconnection making compliance enforcement a simpler process. The variability of the
measurement of Frequency Response for an individual BA for an individual Disturbance event
was evaluated to determine its suitability for use as a compliance measure. The individual
Disturbance events were normalized and plotted for each BA on the Eastern and Western
Interconnections. This data was plotted with a dot representing each event. Events with a
measured Frequency Response above the FRO were shown as blue dots and events with a
measured Frequency Response below the FRO were shown as red dots. In order to show the
full variability of the results the plots have been provided with two scales, a large scale to show
all of the events and small scale to show the events closer to the FRO or a value of 1.0. This
data is presented on four charts titled Frequency Response Events as Normalized by FRO.
Analysis of this data indicates a single event based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in these charts.
Based on the field trial data provided, only 3 out of 19 BAs on the Western Interconnection
would be compliant for all events with a standard based on a single event measure. Only 1 out
of 31 BAs on the Eastern Interconnection would be compliant for all events with a standard
based on a single event measure. The general consensus of the industry is that there is not a
reliability issue with insufficient Frequency Response on any of the North American
Interconnections at this time. Therefore, it is unreasonable to even consider a standard that
would indicate over 90% of the BAs in North American to be non-compliant with respect to
maintaining sufficient Frequency Response to maintain adequate reliability.
In an attempt to balance the workload of Balancing Authorities with the need for accuracy in
the FRM, the standard will require at least 20 samples selected during the course of the year to
compute the FRM. Research conducted by the FRSDT indicated that a Balancing Authority’s
FRM will converge to a reasonably stable value with at least 20 samples.
8
Single Event Analysis based on results of Frequency Response Standard Field Trial Analysis, September 17, 2012.
24
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004051
Frequency Response Events as Normalized by FRO
Eastern Interconnection - 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
-25.0
32
31
30
29
28
27
25
26
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
-50.0
Balancing Authority
25
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004052
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
-5.0
-10.0
-15.0
-20.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-25.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection - 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-10.0
Balancing Authority
26
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004053
Sample Size
In order to support field trial evaluations of sample size, sampling intervals, and aggregation
techniques, the FRSDT will be retrieving scan rate data from the Balancing Authorities for each
SEFRD. Additional frequency events may also be requested for research purposes, though they
will not be included in the FRM computation.
FERC Order No. 693 directed the ERO (at P 375) to define the number of Frequency Response
surveys that were conducted each year and to define a necessary amount of Frequency
Response. R1 addresses both of these directives:
•
•
There is a single annual survey of at least 20 events each year.
The FRM calculated on FRS Form 1 is compared by the ERO against the FRO determined
12 months earlier (when the last FRS Form 1 was submitted) to verify the Balancing
Authority provided its share of Interconnection Frequency Response.
Median as the Standard’s Measure of Balancing Authority Performance
The FRSDT evaluated different approaches for “averaging” individual event observations to
compute a technically sound estimate of Frequency Response Measure. The MW contribution
for a single BA in a multi-BA Interconnection is small compared to the minute to minute
changes in load, interchange and generation. For example, a 3000 MW BA in the east Eastern
Interconnection may only be called on to contribute 10MW for the loss of a 1000MW. The 10
MW of governor and load response may easily be masked as a coincident change in load.
In general, statisticians use the median as the best measure of central tendency when a
population has outliers. Two independent reviews by the FRSDT has shown the Median to be
less influenced by noise in the measurement process and the team has chosen the median as
the initial metric for calculating the BAs’ Frequency Response Measure.
The FRSDT performed extensive empirical studies and engaged in lively discussions in an
attempt to determine the best aggregation technique for a sample set size of at least 20 events.
Mean, median, and linear regression techniques were used on a trial basis with the data that
was available during the early phases of the effort.
A key characteristic of the “aggregation challenge” is related to the use of actual net
interchange data for measuring frequency response. The tie line flow measurements are
varying continuously due to other operational phenomena occurring concurrently with the
provision of frequency response. (See Appendix 1 for details.) All samples have “noise” in
them, as most operational personnel who have computed the frequency response of their BA
can attest. What has also become apparent to the FRSDT is that while the majority of the
frequency response samples have similar levels of noise in them, a few of the samples may
have much larger errors in them than the others that result in unrepresentative results. And
with the sample set size of interest, it is common to have unrepresentative errors in these few
samples to be very large and asymmetric. For example, one BA’s subject matter expert
observed recently that 4 out of 31 samples had a much larger error contribution than the other
27 samples, and that 3 out of 4 of the very high error samples grossly underestimated the
frequency response. The median value demonstrated greater resiliency to this data quality
problem than the mean with this data set. (The median has also demonstrated superiority to
27
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004054
linear regression in the presence of these described data quality problems in other analyses
conducted by the FRSDT, but the linear regression showed better performance than the mean.)
The above can be demonstrated with a relatively simple example. Let’s assume that a
Balancing Authority’s true frequency response has an average value of -200 MW/ .1 Hz. Let’s
also assume that this Balancing Authority installed “special” perfect metering on key loads and
generators, so that we could know the true frequency response of each sample. And then we
will compare them with that measured by typical tie line flow metering, with the kind of noise
and error that occurs commonly and “not so commonly”. Let’s start with the following 4
samples having a common level of noise, with MW/ .1 Hz as the unit of measurement.
Perfect measurement
-190
-210
-220
-180
-200
-200
Noise
-30
-20
10
20
Mean
Median
Samples from tie lines
-220
-230
-210
-160
-205
-215
Now let’s add a fifth sample, which is highly contaminated with noise and error that grossly
underestimates frequency response.
Perfect measurement
-190
-210
-220
-180
-200
-200
-200
Noise
-30
-20
10
20
250
Mean
Median
Samples from tie lines
-220
-230
-210
-160
+50
-154
-210
It is clear from the above simplistic example that the mean drops by about 25% while the
median is affected minimally by the single highly contaminated value.
Based on the analyses performed thus far, the FRSDT believes that the median’s superior
resiliency to this type of data quality problem makes it the best aggregation technique at this
time. However, the FRSDT sees merit and promise in future research with sample filtering
combined with a technique such as linear regression.
When compared with the mean, linear regression shows superior performance with respect to
the elimination of noise because the measured data is weighted by the size of the frequency
change associated with the event. Since the noise is independent from frequency change, the
greater weighting on larger events provides a superior technique for reducing the effect of
noise on the results.
However, linear regression does not provide a better method when dealing with a few samples
with large magnitudes of noise and unrepresentative error. There are only two alternatives to
improve over the use of median when dealing with these larger unrepresentative errors:
1. Increase the sample size, or
2. Actively eliminate outliers due to unrepresentative error.
28
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004055
Unfortunately, the first alternative, increasing the sample size is not available because
significantly more sample events are not available within the measurement time period of one
year. Linear regression techniques are being investigated that have an active outlier
elimination algorithm that would eliminate data that lie outside ranges of the 96th percentile
and 99th percentile, for example.
Still, the use of linear regression has value in the context of this standard. The NERC Resources
Subcommittee will use linear regression to evaluate Interconnection frequency response,
particularly to evaluate trends, seasonal impacts, time of day influences, etc. The Good
Practices and Tools section of this document outlines how a BA can use linear regression to
develop a predictive tool for its operators.
Additional discussion on this topic is contained in “Appendix 1 – Data Quality Concerns Related
to the Use of Actual Net Interchange Value” of this document.
The NERC Frequency Response Initiative Report addressed the relative merits of using the
median versus linear regression for aggregating single event frequency response samples into a
frequency response measurement score for compliance evaluation. This report provided 11
evaluation criteria as a basis for recommending the use of linear regression instead of the
median for the frequency response measurement aggregation technique. The FRSDT made its
own assessment on the basis of these evaluation criteria on September 20, 2012, but concluded
that the median would be the best aggregation technique to use initially when the relative
importance of each criterion was considered. A brief summary of the FRSDT majority
consensus on the basis of each evaluation criterion is provided below.
•
•
•
•
•
•
29
Provides two dimensional measurement – The FRSDT agrees that the two dimensional
concept is a useful way to perceive frequency response characteristics, and that it may
be useful for potential future modeling activities. Better data quality would increase
support for such future efforts, and the use of the median for initial compliance
evaluations within BAL-003-1 should not hinder any such effort. The FRSDT perceived
this as a mild advantage for linear regression.
Represents nonlinear characteristics – With considerations similar to those applied to
the previous criterion, the FRSDT perceived this as a mild advantage for linear
regression.
Provides a single best estimator – The FRSDT put gave minimal importance to the
characteristic of the median averaging the middle values when used with an even
number of samples.
Is part of a linear system - With considerations similar to those applied to the first two
criteria, the FRSDT perceived this as a mild advantage for linear regression (particularly
in the modeling area.)
Represents bimodal distributions – The FRSDT put gave minimal weight of this criterion,
as a change in Balancing Authority footprint does not seem to be addressed adequately
by any aggregation technique.
Quality statistics available – The FRSDT perceived this as a mild advantage for linear
regression in that the statistics would be coupled directly to the compliance evaluation.
The FRSDT also included this criterion as part of the modeling advantages cited above.
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004056
•
•
•
•
•
The FRSDT supports collecting data and performing quality statistical analysis. If it is
determined that the use of the median, as opposed to a mean or linear regression
aggregation, is yielding undesirable consequences, the FRSDT recommends that other
aggregation techniques be re-evaluated at that time.
Reducing influence of noise - This is the dominant concern of the FRSDT, and it
perceives the median to have a major advantage over linear regression in addressing
noise in the change in actual net interchange calculation. The FRSDT bases this
judgment on: prior FRSDT studies that have shown that the median produces more
stable results; the data used in the NERC Frequency Response Initiative document
exhibits large quantities of noise; prior efforts of FRSDT members in performing
frequency response sampling for their own Balancing Authorities over many years; and
similar observations of noise in the CERTS frequency Monitoring Application. The
FRSDT has serious concerns that the influence of noise has a greater tendency to yield a
“false positive” compliance violation with linear regression than with the median. Also,
limited studies performed by the FRSDT indicates the possibility that the resultant
frequency response measure would yield more measurement variation across years
with linear regression versus the median while the actual Balancing Authority
performance remains unchanged.
Reducing the influence of outliers – This is related to the previous criterion. The FRSDT
recognizes four main sources of noise: concurrent operating phenomena (described
elsewhere in this document), transient tie line flows for nearby contingencies, data
acquisition time skew in tie line data measurements, and time skew and data
compression issues in archiving techniques and tools such as PI. Some outliers may be
caused in part by true variation in the actual frequency response, and it is desirable to
include those in the frequency response measure. The FRSDT supports efforts in the
near future to distinguish between outliers caused by noise versus true frequency
response, and progress in this area may make it feasible and desirable to replace the
median with linear regression, or some other validated technique. The FRSDT does
note that this is a substantial undertaking, and it would require substantial input from a
sufficient number of experts to help distinguish noise from true frequency response.
Easy to calculate – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made in noise elimination.
Familiar indicator – The FRSDT perceives this to be a minor to moderate advantage for
the median. However, more complex (but reasonably so) techniques would receive
more support if clear progress can be made as a result of noise elimination.
Currently used as a measure in BAL-003 – The present standard refers to an average
and does not provide specific guidance on the computation of that average, but the
FRSDT puts minimal weight on this evaluation criterion.
In summary, the FRSDT perceives an approximate balance between the modeling advantage for
linear regression and the simplicity advantage of the median. However, the clear determinant
in endorsing the use of the median is the data quality issue related to concurrent operational
phenomena, transient tie line flows, and data acquisition and archiving limitations.
30
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004057
FERC Order No. 693 also directed the Standard (at P 375) to identify methods for Balancing
Authorities to obtain Frequency Response. Requirement R1 allows Balancing Authorities to
participate in Frequency Response Sharing Groups (FRSGs) to provide or obtain Frequency
Response. These may be the same FRSGs that cooperate for BAL-002-0 or may be FRSGs that
form for the purposes of BAL-003-1.
If BAs participate as an FRSG for BAL-003-1, compliance is based on the sum of the participants’
performance.
Two other ways that BAs could obtain Frequency Response are through Supplemental Service
or Overlap Regulation Service:
• No special action is needed if a BA provides or receives supplemental regulation. If the
regulation occurs via Pseudo Tie, the transfer occurs automatically as part of Net Actual
Interchange (NIA) and in response to information transferred from recipient to
provider.
• If a BA provides overlap regulation, its FRS Form 1 will include the Frequency Bias
setting as well as peak load and generation of the combined Balancing Authority Areas.
The FRM event data will be calculated on the sum of the provider’s and recipient’s
performance.
In the Violation Severity Levels for Requirement R1, the impact of a BA not having enough
frequency response depends on two factors:
• Does the Interconnection have sufficient response?
• How short is the BA in providing its FRO?
The VSL takes these factors into account. While the VSLs look different than some other
standards, an explanation would be helpful.
VSLs are a starting point for the enforcement process. The combination of the VSL and VRF is
intended to measure a violation’s impact on reliability and thus levy an appropriate sanction.
Frequency Response is an interconnection-wide resource. The proposed VSLs are intended to
put multi-BA Interconnections on the same plane as single-BA Interconnections.
Consider a small BA whose performance is 70% of its FRO. If all other BAs in the
Interconnection are compliant, the small BA’s performance has negligible impact on reliability,
yet would be sanctioned at the same level as a BA who was responsible for its entire
Interconnection. It is not rational to sanction this BA the same as a single BA Interconnection
that had insufficient Frequency Response, because this would treat multi-BA Interconnections
more harshly than single BA Interconnections on a significant scale.
The “Lower” and “Medium” VSLs say that the Interconnection has sufficient Frequency
Response but individual BAs are deficient by small or larger amounts respectively. The High and
Severe VSLs say the Interconnection does not meet the FRO and assesses sanctions based on
whether the BA is deficient by a small or larger amount respectively.
31
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004058
Requirement 2
R2. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection and is not receiving Overlap Regulation Service and uses a fixed Frequency Bias
Setting shall implement the Frequency Bias Setting determined in accordance withsubject to
Attachment A, as validated by the ERO, into its Area Control Error (ACE) calculation during the
implementation period specified by the ERO.
Background and Rationale
Attachment A of the Standard discusses the process the ERO will follow to validate the BA’s FRS
Form 1 data and publish the official Frequency Bias Settings. Historically, it has taken multiple
rounds of validation and outreach to confirm each BA’s data due to transcription errors,
misunderstanding of instructions, and other issues. While BAs historically submit Bias Setting
data by January 1, it often takes one or more months to complete the process.
The target is to have BAs submit their data by January 10. The BAs are given 30 days to
assemble their data since the BAs are dependent on the ERO to provide them with FRS Form 1,
and there may be process delays in distributing the forms since they rely on identification of
frequency events through November 30 of the preceding year.
Frequency Bias Settings generally change little from year to year. Given the fact that BAs can
encounter staffing or EMS change issues coincident with the date the ERO sets for new
Frequency Bias Setting implementation, the standard provides a 24 hour window on each side
of the target date.
To recap the annual process:
1. The ERO posts the official list of frequency events to be used for this Standard in early
December. The FRS Form 1 for each Interconnection will be posted shortly thereafter.
2. The Balancing Authority submits its revised annual Frequency Bias Setting value to
NERC by January 10.
3. The ERO and the Resources Subcommittee validate Frequency Bias Setting values,
perform error checking, and calculate, validate, and update CPS2 L10 values. This data
collection and validation process can take as long as two months.
4. Once the L10 and Frequency Bias Setting values are validated, The ERO posts the values
for the upcoming year and also informs the Balancing Authorities of the date on which
to implement revised Frequency Bias Setting values. Implementation typically would be
on or about March 1st of each year.
BAL-003-0.1b standard requires a minimum Frequency Bias Setting equal in absolute value to
one percent of the Balancing Authority’s estimated yearly peak demand (or maximum
generation level if native load is not served). For most Balancing Authorities this calculated
amount of Frequency Bias is significantly greater in absolute value than their actual Frequency
Response characteristic (which represents an over-bias condition) resulting in over-control
32
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004059
since a larger magnitude response is realized. This is especially true in the Eastern
Interconnection where this condition requires excessive secondary frequency control response
which degrades overall system performance and increases operating cost as compared to
requiring an appropriate balance of primary and secondary frequency control response.
Balancing Authorities were given a minimum Frequency Bias Setting obligation because there
had never been a mandatory Frequency Response Obligation. This historic “one percent of
peak per 0.1Hz” obligation, dating back to NERC’s predecessor, NAPSIC, was intended to ensure
all BAs provide some support to Interconnection frequency.
The ideal system control state exists when the Frequency Bias Setting of the Balancing
Authority exactly matches the actual Frequency Response characteristic of the Balancing
Authority. If this is not achievable, over-bias is significantly better from a control perspective
than under-bias with the caveat that Frequency Bias is set relatively close in magnitude to the
Balancing Authority actual Frequency Response characteristic. Setting the Frequency Bias to
better approximate the Balancing Authority natural Frequency Response characteristic will
improve the quality and accuracy of ACE control, CPS & DCS and general AGC System control
response. This is the technical basis for recommending an adjustment to the long standing “1%
of peak/0.1Hz” Frequency Bias Setting. The Procedure for ERO Support of Frequency
Response and Frequency Bias Setting Standard is intended to bring the Balancing
Authorities’ Frequency Bias Setting closer to their natural Frequency Response. Procedure for
ERO Support of Frequency Response and Frequency Bias Setting Standard balances the
following objectives:
•
Bring the Frequency Bias Setting and Frequency Response closer together.
•
Allow time to analyze impact on other Standards (CPS, BAAL and to a lesser extent DCS)
by adjustments in the minimum Frequency Bias Setting, by accommodating only minor
adjustments.
•
Do not allow the Frequency Bias Setting minimum to drop below natural Frequency
Response, because under-biasing could affect an Interconnection adversely.
Additional flexibility has been added to the Frequency Bias Setting based on the actual
Frequency Response (FRM) by allowing the Frequency Bias Setting to have a value in the range
from 100% of FRM to 125% of FRM. This change has been included for the following reasons:
•
33
When the new standardized measurement method is applied to BAs with a Frequency
Response close to the interconnection minimum response, the requirement to use FRM
is as likely to result in a Frequency Bias Setting below the actual response as it is to
result in a response above the actual response. From a reliability perspective, it is
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004060
always better to have a Frequency Bias Setting slightly above the actual Frequency
Response.
•
As with single BA interconnections, the tuning of the control system may require that
the BA implement a Frequency Response Setting slightly greater in absolute terms than
its actual Frequency Response to get the best performance.
•
The new standardized measurement method for determining FRM in some cases results
in a measured Frequency Response significantly lower than the previous methods used
by some BAs. It is desirable to not require significant change in the Frequency Bias
Setting for these BAs that experience a reduction in their measured Frequency
Response.
Requirement 3
R3. Each Balancing Authority that is a member of a multiple Balancing Authority
Interconnection, is not receiving Overlap Regulation Service and utilizing a variable Frequency
Bias Setting shall maintain a Frequency Bias Setting that is:
•
•
Less than zero at all times, and
Equal to or more negative than its Frequency Response Obligation when the Frequency
varies from 60 Hz by more that +/- 0.036 Hz.
Background and Rationale
In multi-Balancing Authority interconnections, the Frequency Bias Setting should be
coordinated among all BAs on the interconnection. When there is a minimum Frequency Bias
Setting requirement, it should apply for all BAs. However, BAs using a variable Frequency Bias
Setting may have non-linearity in their actual response for a number of reasons including the
dead-bands implemented on their generator governors. The measurement to ensure that
these BAs are conforming to the interconnection minimum is adjusted to remove the deadband range from the calculated average Frequency Bias Setting actually used. For BAs using
variable bias, FRS Form 1 has a data entry location for the previous year’s average monthly Bias.
The Balancing Authority and the ERO can compare this value to the previous year’s Frequency
Bias Setting minimum to ensure R3 has been met.
On single BA interconnections, there is no need to coordinate the Frequency Bias Setting with
other BAs. This eliminates the need to maintain a minimum Frequency Bias Setting for any
reason other than meeting the reliability requirement as specified by the Frequency Response
Obligation.
Requirement 4
R4. Each Balancing Authority that is performing Overlap Regulation Service shall modify its
Frequency Bias Setting in its ACE calculation, in order to represent the Frequency Bias Setting for
the combined Balancing Authority Area, to be equivalent to either:
34
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004061
•
The sum of the Frequency Bias Settings as shown on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated by the ERO, or
•
The Frequency Bias Setting as shown on FRS Form 1 and FRS Form 2 for the entirety of
the participating Balancing Authorities’ Areas.
Background and Rationale
This requirement reflects the operating principles first established by NERC Policy 1 and is
similar to Requirement R6 of the approved BAL-003-0.1b standard. Overlap Regulation Service
is a method of providing regulation service in which the Balancing Authority providing the
regulation service incorporates another Balancing Authority’s actual interchange, frequency
response, and schedules into the providing Balancing Authority’s AGC/ACE equation.
As noted earlier, a BA that is providing Overlap Regulation will report the sum of the Bias
Settings in its FRS Form 1. Balancing Authorities receiving Overlap Regulation Service have an
ACE and Frequency Bias Setting equal to zero (0).
35
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004062
How this Standard Meets the FERC Order 693
Directives
FERC Directive
The following is the relevant paragraph of Order No. 693.
Accordingly, the Commission approves Reliability Standard BAL-003-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a modification to
BAL-003-0 through the Reliability Standards development process that: (1) includes
Levels of Non-Compliance; (2) determines the appropriate periodicity of frequency
response surveys necessary to ensure that Requirement R2 and other requirements of
the Reliability Standard are being met, and to modify Measure M1 based on that
determination and (3) defines the necessary amount of Frequency Response needed for
Reliable Operation for each balancing authority with methods of obtaining and
measuring that the frequency response is achieved.
1. Levels of Non-Compliance
VRFs and VSLs are an equally effective way of assigning compliance elements to the standard.
2. Determine the appropriate periodicity of frequency response surveys
necessary to ensure that Requirement R2 and other Requirements of
the Reliability Standard are met
BAL-003 V0 R2 (the basis of Order No. 693) deals with the calculation of Frequency Bias Setting
such that it reflects natural Frequency Response.
The drafting team has determined that a sample size on the order of at least 20 events is
necessary to have a high confidence in the estimate of a BA’s Frequency Response. Selection of
the frequency excursion events used for analysis will be done via a method outlined in
Attachment A to the Standard.
On average, these events will represent the largest 2-3 “clean” frequency excursions occurring
each month.
Since Frequency Bias Setting is an annual obligation, the survey of the at least 20 frequency
excursion events will occur once each year.
3. Define the necessary amount of Frequency Response needed for
Reliable Operation for each Balancing Authority with methods of
obtaining and measuring that the frequency response is achieved
Necessary Amount of Frequency Response
The drafting team has proposed the following approach to defining the necessary amount of
frequency response. In general, the goal is to avoid triggering the first step of under-frequency
load shedding (UFLS) in the given Interconnection for reasonable contingencies expected. The
36
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004063
methodology for determining each Interconnection’s and Balancing Authority’s obligation is
outlined in Attachment A to the Standard.
It should be noted the standard cannot guarantee there will never be a triggering of UFLS as the
magnitude of “point C” differs throughout an interconnection during a disturbance and there
are local areas that see much wider swings in frequency.
The contingency protection criterion is the largest reasonably expected contingency in the
Interconnection. This can be based on the largest observed credible contingency in the
previous 10 years or the largest Category C event for the Interconnection.
Attachment A to the standard presents the base obligation by Interconnection and adds a
Reliability Margin. The Reliability Margin included addresses the difference between Points B
and C and accounts for variables.
For multiple BA interconnections, the Frequency Response Obligation is allocated to BAs based
on size. This allocation will be based on the following calculation:
FRO FRO
Annual Gen Annual Load
Annual Gen Annual Load
Methods of Obtaining Frequency Response
The drafting team believes the following are valid methods of obtaining Frequency Response:
•
•
•
•
•
Regulation services.
Contractual service. The drafting team has developed an approach to obtain a
contractual share of Frequency Response from Adjacent Balancing Authorities. See FRS
Form 1. While the final rules with regard to contractual services are being defined, the
current expectation is that the ERO and the associated Region(s) should be notified
beforehand and that the service be at least 6 months in duration.
Through a tariff (e.g. Frequency Response and regulation service).
From generators through an interconnection agreement.
Contract with an internal resource or loads (The drafting team encourages the
development of a NAESB business practice for Frequency Response service for linear
(droop) and stepped (e.g. LaaR in Texas) response).
Since NERC standards should not prescribe or preclude any particular market related service,
BAs and FRSGs may use whatever is most appropriate for their situation.
Measuring that the Frequency Response is Achieved
FRS Form 1 and the underlying data retained by the BA will be used for measuring whether
Frequency Response was provided. FRS Form 1 will provide the guidance on how to account for
and measure Frequency Response.
37
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004064
Going Beyond the Directive
Based on the combined operating experience of the SDT, the drafting team consensus is that
each Interconnection has sufficient Frequency Response. If margins decline, there may be a
need for additional standards or tools. The drafting team and the Resources Subcommittee are
working with the ERO on its Frequency Response Initiative to develop processes and good
practices so the Interconnections are prepared. These good practices and tools are described in
the following section.
The drafting team is also evaluating a risk-based approach for basing the Interconnection
Frequency Response Obligation on an historic probability density of frequency error, and for
allocating the obligation on the basis of the Balancing Authority’s average annual ACE share of
frequency error. This allocation method uses the inverse of the rationale for allocating the CPS1
epsilon requirement by Bias share.
38
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004065
Good Practices and Tools
Background
This section outlines tips and tools to help Balancing authorities meet the Frequency Response
Standard or to operate more reliably. If you have suggested additions, please send them to
[email protected].
Identifying and Estimating Frequency Responsive Reserves
Knowing the quantity and depth of frequency responsive reserves in real time is a possible next
step to being better prepared for the next event. The challenge in achieving this is having the
knowledge of the capabilities of all sources of frequency response. Presently the primary
source of Frequency Response remains with the generation resources in our fleets.
Understanding how each of these sources performs to changes in system frequency and
knowing their limitations would improve the BA’s ability to measure frequency responsive
reserves. Presently there are only guidelines, criteria and protocols in some regions of the
industry that identify specific settings and performance expectations of Primary Frequency
Response of resources.
One method of gaining a better understanding of performance is to measure performance
during actual events that occur on the system. Measuring performance during actual events
would only provide feedback for performance during that specific event and would not provide
insight into depth of response or other limitations.
Repeated measurements will increase confidence in expected performance. NERC modeling
standards are in process to be revised that will improve the BA’s insight into predicting
available frequency responsive reserves. However, knowing how resources are operated, what
modes of operation provide sustained Primary Frequency Response and knowing the operating
range of this response would give the BA the knowledge to accurately predict frequency
response and the amount of frequency responsive reserves available in real time.
Some benefits have been realized by communicating to generation resources (GO) the
importance of operating in modes that allow Primary Frequency Response to be sustained by
the control systems of the resource. Other improvements in implementation of Primary
Frequency Response have been achieved through improved settings on turbine governors
through the elimination of “step” frequency response with the simultaneous reduction in
governor dead-band settings.
Improvements in the full AGC control loop of the generating resource, which accounts for the
expected Primary Frequency Response, have improved the delivery of quality Primary
Frequency Response while minimizing secondary control actions of generators. Some of these
actions can provide quick improvement in delivery of Primary Frequency Response.
39
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004066
Once Primary Frequency Response sources are known, the BA could calculate available reserves
that are frequency responsive. Planning for these reserves during normal and emergency
operations could be developed and added to the normal planning process.
Using FRS Form 1 Data
The information collected for this standard can be supplemented by a few data points to
provide the Balancing Authority useful tools and information. The BA could do a regression
analysis of its frequency response against the following values:
•
•
•
•
Load (value A).
Interchange (Value A).
Total generation.
Spinning reserve.
While the last two values above are not part of Form 1, they should be readily available. Small
BAs might even include headroom on its larger generators as part of the regression.
The regression would provide a formula the BA could program in its EMS to present the
operator a real time estimate of the BA’s Frequency Response.
Statistical outliers in the regression would point to cases meriting further inspection to find
causes of low Frequency Response or opportunities for improvement.
Tools
Single generating resource performance evaluation tools for steam turbine, combustion turbine
(simple cycle or combined cycle) and for intermittent resources are available at the following
link. http://texasre.org/standards_rules/standardsdev/rsc/sar003/Pages/Default.aspx.
These tools and the regional standard associated with them are in their final stages of
development in the Texas region.
These tools will be posted on the NERC website.
40
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004067
References
NERC Frequency Response Characteristic Survey Training Document (Found in the NERC
Operating Manual)
NERC Resources Subcommittee Position Paper on Frequency Response
NERC TIS Report Interconnection Criteria for Frequency Response Requirements (for the
Determination Interconnection Frequency Response Obligations (IFRO)
Frequency Response Standard Field Trial Analysis, September 17, 2012
41
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004068
Appendix 1 - Data Quality Concerns Related To The Use Of The
Actual Net Interchange Value
Actual net interchange for a typical Balancing Authority (BA) is the summation of its tie lines to
other BAs. In some cases, there are pseudo-ties in it which reflect the effective removal or
addition of load and/or generation from another BA, or it could include supplemental
regulation as well. But in the typical scenario, actual net interchange values that are extracted
from EMS data archiving can be influenced by data latency times in the data acquisition
process, and also any timestamp skewing in the archival process.
Of greater concern, however, are the inevitable variations of other operating phenomena
occurring concurrently with a frequency event. The impacts of these phenomena are
superimposed on actual net interchange values along with the frequency response that we wish
to measure through the use of the actual net interchange value.
To explore this issue further, let’s begin with the idealized condition:
•
•
•
•
•
•
•
frequency is fairly stable at some value near or a little below 60 Hz
ACE of the non-contingent BA of interest is 0 and has been 0 for an extended period,
and AGC control signals have not been issued recently
Actual net interchange is “on schedule”, and there are no schedule changes in the
immediate future
BA load is flat
All generators not providing AGC are at their targets
Variable generation such as wind and solar are not varying
Operators have not directed any manual movements of generation recently
And when the contingency occurs in this idealized state, the change in actual net interchange
will be measuring only the decline in load due to lesser frequency and generator governor
response, and, none of the contaminating influences. While the ACE may become negative due
to the actual frequency response being less than that called for by the frequency bias setting
within the BA’s AGC system, this contaminating influence on measuring frequency response will
not appear in the actual net interchange value if the measurement interval ends before the
generation on AGC responds.
Now let’s explore the sensitivity of the resultant frequency response sampling to the relaxation
of these idealized circumstances.
1. The “60 Hz load” increases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be reduced by the
moderate increase in load and the frequency response will be underestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be increased by the AGC response (and/or manual
adjustments) and the frequency response will be overestimated.
42
Frequency Response Standard Background Document – November 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004069
2. The “60 Hz load” decreases moderately due to time of day concurrent with the
frequency event. If the frequency event happens before AGC or operator-directed
manual load adjustments occur, then the actual net interchange will be increased by the
moderate reduction in load and the frequency response will be overestimated. But if
the frequency event happens while AGC response and/or manual adjustments occur,
then the actual net interchange will be decreased by the AGC response (and/or manual
adjustments) and the frequency response will be underestimated.
3. In anticipation of increasing load during the next hour, the operator increases manual
generation before the load actually appears. If the frequency event happens while the
generation “leading” the load is increasing, then the actual net interchange will be
increased by the increase in manual generation and the frequency response will be
overestimated. But if the frequency event occurs when the result of AGC signals sent to
offset the operator’s leading actions take effect, then the actual net interchange will be
decreased and the frequency response is underestimated.
4. In anticipation of decreasing load during the next hour, the operator decreases manual
generation before the load actually declines. If the frequency event happens while the
generation “leading” the load downward is decreasing, then the actual net interchange
will be decreased by the reduction in manual generation and the frequency response
will be underestimated. But if the frequency event occurs when the result of AGC
signals sent to offset the operator’s leading actions take effect, then the actual net
interchange will be increased and the frequency response is overestimated.
5. A schedule change to export more energy is made at 5 minutes before the top of the
hour. The BA’s “60 Hz load” is not changing. The schedule change is small enough that
the operator is relying on upward movement of generators on AGC to provide the
additional energy to be exported. The time at which the AGC generators actually begin
to provide the additional energy is dependent on how much time passes before the AGC
algorithm gets out of its deadbands, the individual generator control errors get large
enough for sending out the control signal, and maybe 20 seconds to 3 minutes for the
response to be effected. The key point here is that it is not clear when the effects of a
schedule change, as manifested in a change in generation and then ultimately a change
in actual net interchange, will occur.
6. With the expected penetration of wind in the near future, unanticipated changes in
their output will tend to affect actual net interchange and add noise to the frequency
response observation process.
To a greater or lesser extent, 1 through 4 above are happening continuously for the most part
with most BAs in the Eastern and Western Interconnections. The frequency response is buried
within the typical hour to hour operational cacophony superimposed on actual net interchange
values. The choice of metrics will be important to artfully extract frequency response from the
noise and other unrepresentative error.
43
Frequency Response Standard Background Document – November 2012
004070
Project 2007-12 Frequency Response BAL-003-1
Mapping Document
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
R1. Each Balancing Authority shall
This
Attachment A
review its Frequency Bias
Requirement
Balancing Authorities that merge or that transfer load or
Settings by January 1 of each
has been
generation are encouraged to notify the ERO of the change
year and recalculate its setting
moved into
in footprint and corresponding changes in allocation such
to reflect any change in the
BAL-003-1
that the net obligation to the Interconnection remains the
Frequency Response of the
Attachment A
Balancing Authority Area.
& FRS Form 1
same and so that CPS limits can be adjusted.
R1.1. The Balancing Authority
as described in
Each Balancing Authority reports its previous year’s
may change its Frequency the Proposed
Frequency Response Measure (FRM), Frequency Bias
Bias Setting, and the
Language
method used to determine Section
Setting and Frequency Bias type (fixed or variable) to the
the setting, whenever any
ERO each year to allow the ERO to validate the revised
of the factors used to
Frequency Bias Settings on FRS Form 1. If the ERO posts
determine the current bias
the official list of events after the date specified in the
value change.
timeline below, Balancing Authorities will be given 30 days
R1.2. Each Balancing Authority
from the date the ERO posts the official list of events to
shall report its Frequency
Bias Setting, and method
004071
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
for determining that
submit their FRS Form 1.
setting, to the NERC
AND
Operating Committee.
FRS Form 1
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias
Settings. The previous year’s monthly averages will be
reported annually on FRS Form 1.
R2. Each Balancing Authority shall
establish and maintain a Frequency
Bias Setting that is as close as practical
to, or greater than, the Balancing
Authority’s Frequency Response.
Frequency Bias may be calculated
several ways:
R2.1. The Balancing Authority
may use a fixed Frequency Bias
value which is based on a
fixed, straight-line function of
Tie Line deviation versus
Frequency Deviation. The
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
is included in
BAL-003-1 as
described in
the Proposed
Language
Section.
R2.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and is not receiving
Overlap Regulation Service and uses a fixed Frequency
Bias Setting shall implement the Frequency Bias Setting
determined subject to Attachment A, as validated by the
ERO, into its Area Control Error (ACE) calculation during
the implementation period specified by the ERO.
R3.
Each Balancing Authority that is a member of a multiple
Balancing Authority Interconnection, is not receiving
Overlap Regulation Service and is utilizing a variable
Frequency Bias Setting shall maintain a Frequency Bias
setting that is:
2
004072
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Balancing Authority shall
3.1 Less than zero at all times, and
determine the fixed value by
3.2 Equal to or more negative than its Frequency
observing and averaging the
Response Obligation when Frequency varies from 60 Hz
Frequency Response for
by more than +/- 0.036 Hz.
several Disturbances during
AND
on-peak hours.
R2.2. The Balancing Authority
may use a variable (linear or
Attachment A
non-linear) bias value, which is
Each Balancing Authority reports its previous year’s
based on a variable function of
Frequency Response Measure (FRM), Frequency Bias
Tie Line deviation to
Setting and Frequency Bias type (fixed or variable) to the
Frequency Deviation. The
Balancing Authority shall
ERO each year to allow the ERO to validate the revised
determine the variable
Frequency Bias Settings on FRS Form 1. If the ERO posts
frequency bias value by
the official list of events after the date specified in the
analyzing Frequency Response
timeline below, Balancing Authorities will be given 30 days
as it varies with factors such as
from the date the ERO posts the official list of events to
load, generation, governor
submit their FRS Form 1.
characteristics, and frequency.
AND
FRS Form 1
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
3
004073
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Note : Balancing Authorities with variable Frequency Bias
Settings shall calculate monthly average Frequency Bias
Settings. The previous year’s monthly averages will be
reported annually on FRS Form 1.
AND
R3. Each Balancing Authority shall
operate its Automatic Generation
Control (AGC) on Tie Line Frequency
Bias, unless such operation is adverse
to system or Interconnection
reliability.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
removed from
the BAL-003-1
standard.
A portion of this Requirement is being phased out in accordance
with the process detailed in the Procedure. This phase out is
intended to bring the Frequency Bias Setting closer or equal to the
natural Frequency Response.
This Requirement has been removed from proposed standard BAL003-I. It is duplicative of BAL-005-0.1b Requirements R6 and
R7.
BAL-005-0.1b
R6. The Balancing Authority’s AGC shall compare total Net
Actual Interchange to total Net Scheduled Interchange
plus Frequency Bias obligation to determine the
Balancing Authority’s ACE. Single Balancing Authorities
operating asynchronously may employ alternative ACE
calculations such as (but not limited to) flat frequency
control. If a Balancing Authority is unable to calculate
ACE for more than 30 minutes it shall notify its
4
004074
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Reliability Coordinator.
R4. Balancing Authorities that use
Dynamic Scheduling or Pseudoties for jointly owned units shall
reflect their respective share of
the unit governor droop response
in their respective Frequency Bias
Setting.
R4.1. Fixed schedules for Jointly
Owned Units mandate that
Balancing Authority (A) that
contains the Jointly Owned Unit
must incorporate the respective
share of the unit governor droop
response for any Balancing
Authorities that have fixed
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
removed from
the BAL-003-1
standard.
R7. The Balancing Authority shall operate AGC continuously
unless such operation adversely impacts the reliability
of the Interconnection. If AGC has become inoperative,
the Balancing Authority shall use manual control to
adjust generation to maintain the Net Scheduled
Interchange.
This Requirement addresses how to calculate Frequency Bias
Settings. This is no longer needed since the Frequency Bias Settings
are calculated in FRS Form 1 using Frequency Response associated
with the “official” list of events and a couple of “floor or ceiling”
limits (% of peak load/gen and FRO). The entire calculation is built
into the FRS Form 1 workbook.
5
004075
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
schedules (B and C).
R4.2. The Balancing Authorities that
have a fixed schedule (B and C)
but do not contain the Jointly
Owned Unit shall not include
their share of the governor
droop response in their
Frequency Bias Setting.
R5. Balancing Authorities that serve
This
R2. Each Balancing Authority that is a member of a multiple
native load shall have a monthly
Requirement
Balancing Authority Interconnection and is not receiving
average Frequency Bias Setting that is has been
Overlap Regulation Service and uses a fixed Frequency
at least 1% of the Balancing
combined into
Bias Setting shall implement the Frequency Bias Setting
Authority’s estimated yearly peak
Requirements
determined subject to Attachment A, as validated by the
demand per 0.1 Hz change.
R2 and R3 of
ERO, into its Area Control Error (ACE) calculation during
R5.1. Balancing Authorities
BAL-003-1.
the implementation period specified by the ERO.
that do not serve native load
R3. Each Balancing Authority that is a member of a multiple
shall have a monthly average
Balancing Authority Interconnection, is not receiving
Frequency Bias Setting that is
Overlap Regulation Service and is utilizing a variable
at least 1% of its estimated
Frequency Bias Setting shall maintain a Frequency Bias
maximum generation level in
setting that is:
the coming year per 0.1 Hz
3.1 Less than zero at all times, and
change.
3.2 Equal to or more negative than its Frequency
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
6
004076
Standard: BAL-003-1 Frequency Response and Frequency Bias Setting
Requirement in Approved Standard
Translation to
Proposed Language in BAL-003-1/Comments
New Standard
or Other
Action
Response Obligation when Frequency varies from 60 Hz
by more than +/- 0.036 Hz.
R6. A Balancing Authority that is
performing Overlap Regulation
Service shall increase its Frequency
Bias Setting to match the frequency
response of the entire area being
controlled. A Balancing Authority shall
not change its Frequency Bias Setting
when performing Supplemental
Regulation Service.
Project 2007-12 Frequency Response
BAL-003-1 Mapping Document
This
Requirement
has been
moved into
BAL-003-1
Requirement
R4.
R4.
Each Balancing Authority that is performing Overlap
Regulation Service shall modify its Frequency Bias Setting
in its ACE calculation, in order to represent the
Frequency Bias Setting for the combined Balancing
Authority Area, to be equivalent to either:
The sum of the Frequency Bias Settings as shown
on FRS Form 1 and FRS Form 2 for the
participating Balancing Authorities as validated
by the ERO, or
The Frequency Bias Setting as shown on FRS
Form 1 and FRS Form 2 for the entirety of the
participating Balancing Authorities’ Areas.
7
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004077
Violation Risk Factor and Violation Severity
Level Assignments
Project 2007-12 – Frequency Response
This document provides the drafting team’s justification for assigning draft standard Requirement
violation risk factors (VRFs) and violation severity levels (VSLs) for:
•
BAL-003-1 — Frequency Response and Frequency Bias Setting
Each primary Requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violation of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors
The Frequency Response Standard Drafting Team applied the following NERC criteria when proposing
VRFs for the requirements under this project:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration
to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004078
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs 1:
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations
could severely affect the reliability of the Bulk-Power System: 2
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
1
North American Electric Reliability Corp., 119 FERC 61,145, order on reh’g and compliance filing, 120 FERC 61,145
(2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004079
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
Justification for Assignment of Violation Severity Levels:
In developing the VSLs for the standards under this project, the SDT anticipated the evidence that would
be reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may find
during a typical audit. The SDT based its assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for
each requirement in this standard meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence
of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in
the Determination of Penalties
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004080
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding
Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a
Cumulative Number of Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement
is a separate violation. Section 4 of the Sanction Guidelines states that assessing penalties per
violation per day basis is the “default” for penalty calculations.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004081
VRF and VSL Justification
BAL-003-1 VRF and VSL Justifications
Proposed VRF
Medium
NERC VRF Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G1
Discussion
This Requirement is more administrative in nature requiring
calculated FRM to be equal to or more negative than FRO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This requirement is similar in concept to
the current enforceable BAL-003-0.1b standard Requirement R2
which specifies a Medium VRF.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for the contingency. This is consistent
with the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
R1
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004082
Discussion
Proposed Lower VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 1% but by at most 30% or 15
MW/0.1 Hz, whichever one is the greater deviation from its
FRO
Proposed Moderate VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection was equal to or more negative than the
Interconnection’s FRO and the Balancing Authority’s, or
Frequency Response Sharing Group’s, FRM was less negative
than its FRO by more than 30% or by more than 15 MW/0.1
Hz, whichever is the greater deviation from its FRO
Proposed High VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 1% but by at most
30% or 15 MW/0.1 Hz, whichever one is the greater deviation
from its FRO
Proposed Severe VSL
The summation of the Balancing Authorities’ FRM within an
Interconnection did not meet its FRO and the Balancing
Authority’s, or Frequency Response Sharing Group’s, FRM
was less negative than its FRO by more than 30% or by more
than 15 MW/0.1 Hz, whichever is the greater deviation from its
FRO
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated FRM being less
negative than FRO.
FERC VSL G1
Discussion
This is not applicable since there was not a Requirement mandating a
certain level of Frequency Response prior to this standard.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on the amount the
calculated FRM is less negative than FRO.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004083
Proposed VRF
NERC VRF Discussion
FERC VRF G1
Discussion
R2
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
This Requirement is more administrative in nature requiring entities
to implement the Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R3,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004084
Proposed Lower VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting failed to implement the
validated Frequency Bias Setting value into its ACE calculation
within the implementation period specified but did so within 5
calendar days from the implementation period specified by the
ERO.
Proposed Moderate VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 5 calendar days but less than or equal to 15
calendar days from the implementation period specified by the
ERO.
Proposed High VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting implemented the
validated Frequency Bias Setting value into its ACE calculation
in more than 15 calendar days but less than or equal to 25
calendar days from the implementation period specified by the
ERO.
Proposed Severe VSL
The Balancing Authority in a multiple Balancing Authority
Interconnection and not receiving Overlap Regulation Service
and uses a fixed Frequency Bias Setting did not implement the
validated Frequency Bias Setting value into its ACE calculation
in more than 25 calendar days from the implementation period
specified by the ERO.
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating increments
for tardiness implementing the validated Frequency Bias Setting into
the ACE calculation.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Lower VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based only on how late the validated
Frequency Bias Setting is implemented.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider performance of required action. Proposed
VSL’s are consistent with the requirement.
FERC VSL G4
Proposed VSL’s are based on a single violation and not a cumulative
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004085
Discussion
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting in its ACE equation and
would provide support for a contingency. This is consistent with the
NERC definition.
This Requirement is more administrative in nature requiring entities
to implement a Frequency Bias Setting validated by the ERO. The
requirement does not directly correlate to the list of critical areas
identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R3
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R1 which
specifies a Lower VRF however BAL-003-1 Requirements R1, R2,
and R4 specify a Medium VRF and the SDT believes it is appropriate
for this Requirement to also possess a Medium VRF given the nature
of the revision to BAL-003-0.1b.
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support for a contingency. This is consistent with
the NERC definition.
FERC VRF G5
This requirement does not co-mingle reliability objectives.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004086
Discussion
Proposed Lower VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 1% but by at most 10%.
Proposed Moderate VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 10% but by at most 20%.
Proposed High VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
Obligation by more than 20% but by at most 30%.
Proposed Severe VSL
The Balancing Authority that is a member of a multiple
Balancing Authority Interconnection and not receiving Overlap
Regulation Service and uses a variable Frequency Bias Setting
average Frequency Bias Setting during periods when the clockminute average frequency was outside of the range 59.964 Hz
to 60.036 Hz was less negative than its Frequency Response
obligation by more than 30%..
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R1 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G1
Discussion
FERC VSL G2
Discussion
Proposed VSL is not binary. Proposed VSL language does not
include ambiguous terms and ensures uniformity and consistency in
the determination of penalties based on the calculated average
Frequency Bias Setting being less negative than its minimum as
defined in Attachment B.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004087
FERC VSL G3
Discussion
Proposed VSL does not expand on what is required. The VSLs
assigned only consider compliance with the Frequency Bias Setting
calculation and implementation required. Proposed VSL’s are
consistent with the requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
Proposed VRF
Medium
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
This Requirement is more administrative in nature requiring entities
providing Overlap Regulation Services to correctly increase its
Frequency Bias Setting. The requirement does not directly correlate
to the list of critical areas identified in the FERC VRF Guideline 1.
Guideline 1 appears to conflict with guideline 4. Guideline 1
identifies a list of topics that encompass nearly all topics within the
NERC Reliability Standards and implies that these requirements
should be assigned a High VRF. Guideline 4 directs assignment of
VRFs based on the impact of a specific requirement on the reliability
of the system. The SDT believes that Guideline 4 better reflects the
intent for assigning VRFs for this standard since this approach is
focused on the reliability impact of the requirement.
NERC VRF Discussion
FERC VRF G1
Discussion
R4
FERC VRF G2
Discussion
Consistency within a Reliability Standard exists. This Requirement
does not contain Parts. Requirement action is unique with respect to
other standard requirements. All standard requirements have a
common reliability focus relevant to Frequency Response and
Frequency Bias Setting.
FERC VRF G3
Discussion
The Requirement VRF is consistent with other BES standards
addressing responsiveness. This Requirement is similar in concept to
the current enforceable BAL-003-0.1b Requirement R6 which
specifies a Medium VRF
FERC VRF G4
Discussion
This Requirement, if violated, could directly affect the electrical state
or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but would
unlikely result in the bulk electric system instability, separation, or
cascading failures since a Balancing Authority would have the
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004088
previous year’s Frequency Bias Setting already in its ACE equation
and would provide support f the contingency. This is consistent with
the NERC definition. In addition, this Requirement VRF is consistent
with the BAL-003-0 Requirement which has been approved by
FERC.
FERC VRF G5
Discussion
This requirement does not co-mingle reliability objectives.
Proposed Lower VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error less than
10% of the validated or calculated value.
Proposed Moderate VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
10% but less than or equal to 20% of the validated or calculated value
Proposed High VSL
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with combined footprint setting error more than
20% but less than or equal to 30% of the validated or calculated
value.
The Balancing Authority incorrectly changed the Frequency Bias
Setting value used in its ACE calculation when providing Overlap
Regulation Services with setting error more than 30% of the validated
or calculated value.
OR
The Balancing Authority failed to change the Frequency Bias Setting
value used in its ACE calculation when providing Overlap Regulation
Services
Proposed Severe VSL
Compliance with NERC
Revised VSL Guidelines
The NERC VSL guidelines are satisfied by incorporating percentage
of noncompliance performance for the absolute value of the
Balancing Authorities’ calculated monthly average Frequency Bias
Setting being below the minimum percentage specified by the ERO.
The VSL also includes a binary requirement for failing to change the
Frequency Bias Setting value when providing Overlap Regulation
Services.
FERC VSL G1
Discussion
This Requirement is similar in concept to the current enforceable
BAL-003-0.1b Requirement R6 which specifies a Medium VRF.
Proposed VSL’s meet or exceed the current threshold of compliance.
FERC VSL G2
Discussion
Proposed VSL’s has both a percentage of noncompliance
performance and binary element. The binary element is designated
severe. Proposed VSL language does not include ambiguous terms
and ensures uniformity and consistency in the determination of
penalties based only on the amount the calculated monthly average
Frequency Bias Setting is below the minimum percentage specified
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004089
by the ERO or if the entity fails to change the Frequency Bias Setting
value when providing Overlap Regulation Services.
FERC VSL G3
Discussion
Proposed VSL’s do not expand on what is required. The VSL’s
assigned only consider results of the calculation required and if the
Frequency Bias Setting is correctly set when providing Overlap
Regulation Services. Proposed VSL’s are consistent with the
requirement.
FERC VSL G4
Discussion
Proposed VSL’s are based on a single violation and not a cumulative
violation methodology.
VRF and VSL Assignments Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004090
Frequency Response
Initiative Report
The Reliability Role of Frequency Response
October 30, 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004091
Future Analysis Work Recommendations
3
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004092
NERC’s Mission
NERC’s Mission
The North American Electric Reliability Corporation’s (NERC) mission is to ensure the reliability
of the North American bulk power system. NERC is the electric reliability organization (ERO)
certified by the Federal Energy Regulatory Commission (FERC) to establish and enforce
reliability standards for the bulk power system. NERC develops and enforces reliability
standards; assesses adequacy annually via a 10-year forecast and summer and winter forecasts;
monitors the bulk power system; and educates, trains, and certifies industry personnel. ERO
activities in Canada related to the reliability of the bulk power system are recognized and
overseen by the appropriate governmental authorities in that country. 1
NERC assesses and reports on the reliability and adequacy of the North American bulk power
system, which is divided into eight Regional areas, as shown on the map and table below. The
users, owners, and operators of the bulk power system within these areas account for virtually
all the electricity supplied in the United States, Canada, and a portion of Baja California Norte,
Mexico.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load-serving
entities participate in one Region and their
associated transmission owner/operators in
another.
1
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability
Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst
Corporation
WECC
Western Electricity
Coordinating Council
As of June 18, 2007, FERC granted NERC the legal authority to enforce reliability standards with all U.S. users, owners, and operators of the
bulk power system, and made compliance with those standards mandatory and enforceable. In Canada, NERC has memorandums of
understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia, Québec, and Saskatchewan, and with the
Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and New Brunswick as a matter of provincial
law. NERC has an agreement with Manitoba Hydro that makes reliability standards mandatory for that entity, and Manitoba has recently
adopted legislation setting out a framework for standards to become mandatory for users, owners, and operators in the province. In
addition, NERC has been designated the “electric reliability organization” under Alberta’s Transportation Regulation, and certain reliability
standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been recognized as standards-setting bodies by
the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards to become mandatory. Nova Scotia and
British Columbia also have frameworks in place for reliability standards to become mandatory and enforceable. NERC is working with the
other governmental authorities in Canada to achieve equivalent recognition.
i
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
004093
Table of Contents
NERC’s Mission................................................................................................................................. i
Table of Contents .............................................................................................................................ii
Introduction .................................................................................................................................... 1
Executive Summary......................................................................................................................... 3
Recommendations ...................................................................................................................... 3
Findings ....................................................................................................................................... 7
Frequency Response Overview ....................................................................................................... 9
Frequency Control ...................................................................................................................... 9
Primary Frequency Control – Primary Frequency Response ...................................................... 9
Frequency Response Illustration .............................................................................................. 10
Balancing Authority Frequency Response ................................................................................ 17
Historical Frequency Response Analysis ....................................................................................... 22
History of Frequency Response and its Decline ....................................................................... 22
Projections of Frequency Response Decline ......................................................................... 23
Statistical Analysis of Frequency Response (Eastern Interconnection).................................... 27
Key Statistical Findings .......................................................................................................... 27
Frequency Response Withdrawal ............................................................................................. 31
Modeling of Frequency Response in the Eastern Interconnection .......................................... 35
Concerns for Future of Frequency Response ........................................................................... 38
Role of Inertia in Frequency Response ................................................................................. 39
Need for Higher Speed Primary Frequency Response .......................................................... 40
Preservation or Improvement of Existing Generation Primary Frequency Response.......... 40
Frequency Response Initiative Report – October 2012
ii
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
004094
Withdrawal of Primary Frequency Response ....................................................................... 41
Interconnection Frequency Response Obligation (IFRO) ............................................................. 43
Tenets of IFRO ........................................................................................................................... 43
Statistical Analyses.................................................................................................................... 44
Frequency Variation Statistical Analysis ............................................................................... 44
Point C Analysis – One-second versus Sub-second Data ...................................................... 48
Adjustment for Differences between Value B and Point C................................................... 48
Adjustment for Primary Frequency Response Withdrawal .................................................. 50
Variables in Determination of Interconnection Frequency Response Obligation from Criteria
.................................................................................................................................................. 51
Low Frequency Limit ............................................................................................................. 51
Credit for Load Resources (CLR)............................................................................................ 52
Interconnection Resource Contingency Protection Criteria..................................................... 53
Largest N-2 Event .................................................................................................................. 53
Largest Total Plant with Common Voltage Switchyard ........................................................ 54
Largest Resource Event in Last 10 Years ............................................................................... 54
Recommended Resource Contingency Protection Criteria .................................................. 55
Comparison of Alternative IFRO Calculations ............................................................................... 56
IFRO Formulae .......................................................................................................................... 56
Determination of Maximum Delta Frequencies ....................................................................... 57
Largest N-2 Event ...................................................................................................................... 58
Largest Total Plant with Common Voltage Switchyard ............................................................ 59
Largest Resource Event in Last 10 Years................................................................................... 60
Recommended IFROs................................................................................................................ 61
Special IFRO Considerations ..................................................................................................... 61
iii
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Table of Contents
004095
Comparison of IFRO Calculations.............................................................................................. 63
Allocation of IFRO to Balancing Authorities.................................................................................. 66
Frequency Response Performance Measurement ....................................................................... 68
Interconnection Process ........................................................................................................... 68
Frequency Event Detection, Analysis, and Trending (for Metrics and Analysis) .................. 68
Ongoing Evaluation ............................................................................................................... 69
Balancing Authority Level Measurements ................................................................................ 69
Single-Event Compliance....................................................................................................... 70
Balancing Authority Frequency Response Performance Measurement Analysis .................... 71
Event Sample Size ................................................................................................................. 72
Measurement Methods – Median, Mean, or Regression Results ........................................ 72
Role of Governors ......................................................................................................................... 79
Deadband and Droop................................................................................................................ 79
ERCOT Experience ..................................................................................................................... 80
Frequency Regulation ........................................................................................................... 80
Turbine-Generator Performance with Reduced Deadbands ................................................ 84
Generator Governor Survey...................................................................................................... 87
Administrative Findings ........................................................................................................ 87
Summary of the Survey Responses....................................................................................... 88
Reported Deadband Settings ................................................................................................ 90
Reported Droop Settings ...................................................................................................... 92
Governor Status and Operational Parameters ..................................................................... 93
Response to Selected Frequency Events .............................................................................. 94
Future Analysis Work Recommendations..................................................................................... 99
Testing of Eastern Interconnection Maximum Allowable Frequency Deviations .................... 99
Frequency Response Initiative Report – October 2012
iv
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004096
Table of Contents
Eastern Interconnection Inter-area Oscillations – Potential for Large Resource Losses ......... 99
This report was approved by the Planning Committee October 4, 2012, via e-mail vote.
This report was accepted by the Operating Committee October 12, 2012, via e-mail vote.
v
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004097
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004098
Introduction
Introduction
System planning and operations experts are anticipating significantly higher penetrations of
renewable energy resources, most of which are electronically coupled to the grid. This presents
some new and different technical challenges, particularly in the reduction of system inertia
through the displacement of conventional generation resources during light load periods. Load
management and other demand-side initiatives also continue to grow. Most importantly, a
continued downward trend for frequency response over a number of years has raised concern
that credible contingencies may result in frequency excursions that encroach on the first step of
under-frequency load shedding (UFLS). Such large frequency excursions could also trigger
undesirable reactions from frequency-sensitive smart grid loads and electronically coupled
renewable resources. Taken together, it is clear that maintaining adequate frequency response
for bulk power system reliability is becoming more important and complex. While the decline in
frequency response has lessened in the last couple of years, it is important that the industry
understands the growing complexities of frequency control and is ready with comprehensive
strategies to stay ahead of any potential problems.
NERC has undertaken various activities over the past few years in an effort to understand the
steady decline in frequency response, particularly in the Eastern Interconnection. While some
significant insight has been gained and system-wide and technical improvements have been
achieved in the Western Interconnection and ERCOT, a deeper and more dedicated effort is
needed.
To comprehensively address the issues related to frequency response, NERC launched the
Frequency Response Initiative in 2010. In addition to coordinating the myriad of efforts
underway in standards development and performance analysis, the initiative includes
performing in-depth analysis of interconnection-wide frequency response to achieve a better
understanding of the factors influencing frequency performance across North America.
Basic objectives of the Frequency Response Initiative include:
1
•
development of a clearer and more specific statement of frequency-related reliability
factors, including better definitions for “ownership” of responsibility for frequency
response;
•
collection and provision of more granular frequency response data on and technical
analyses of frequency-driven bulk power system events, including root cause analyses;
•
metrics and benchmarks to improve frequency response performance tracking;
•
increasing coordinated communication and outreach on the issue to include webinars
and NERC alerts and to share lessons learned; and
•
focused discussion on communication of emerging technology issues, including
frequency-related effects caused by renewable energy integration, smart grid
technology deployment, and new end-use technology.
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Introduction
004099
In March 2011, the NERC Planning Committee tasked the Transmission Issues Subcommittee
(TIS, now the System Analysis and Modeling Subcommittee (SAMS)) with determining what
criteria should be used to decide the appropriate level of interconnection-wide frequency
response needed for reliability. The TIS started with a body of work already underway by the
Resources Subcommittee (RS) and the Frequency Working Group (FWG) of the Operating
Committee, and the Frequency Responsive Reserve Standard Drafting Team (FRRSDT). The RS
produced a position paper on frequency response outlining the method to translate a resource
contingency criterion into an Interconnection Frequency Response Obligation (IFRO).
The report on IFRO was approved by the Planning Committee September 2011. 2 Since that
time, numerous modifications and improvements have been made to the IFRO determination
analysis and calculations. Those changes are reflected in the IFRO section of this report.
This report provides an overview of the work that has been done to date toward gaining
understanding of frequency response. It is in support of NERC Standards Project 2007-12
Frequency Response, which is preparing a revised draft standard (BAL-003-1). That standard is
intended to codify a Frequency Response Obligation and means for measuring the performance
of the Balancing Authorities.
2
http://www.nerc.com/docs/pc/tis/Agenda_Item_5.d_Draft_TIS_IFRO_Criteria%20Rev_Final.pdf
Frequency Response Initiative Report – October 2012
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004100
Executive Summary
Executive Summary
Recommendations
1.
NERC should embark immediately on the development of a NERC Frequency Response
Resource Guideline to define the performance characteristics expected of those
resources for supporting reliability. That guideline should address appropriate
parameters for the following:
•
Existing conventional generator fleet – In order to retain or regain frequency
response capabilities of the existing generator fleet, adopt:
o
o
o
o
o
•
deadbands of ±16.67 mHz,
droop settings of 3%–5% depending on turbine type,
continuous, proportional (non-step) implementation of the response,
appropriate operating modes to provide frequency response, and
appropriate outer-loop controls modifications to avoid primary frequency
response withdrawal at a plant level.
Other frequency-responsive resources – Augment existing generation response with
fast-acting, electronically coupled frequency responsive resources, particularly for
the arresting and rebound periods of a frequency event:
o
o
o
o
contractual high-speed demand-side response,
wind and photo-voltaic – particularly for over-frequency response,
storage – automatic high-speed energy retrieval and injection, and
variable-speed drives – non-critical, short-time load reduction.
2.
Instead of using a fixed margin, the calculation of the Interconnection Frequency
Response Obligations should use statistical analysis to determine the necessary margin.
3.
The starting frequency for the calculation of IFROs should be the frequency 5% of the
lower tail of samples from the statistical analysis, representing a 95% confidence that
frequencies will be at or above that value at the start of any frequency event, as shown
in table A.
Table A: Interconnection Frequency Variation Analysis (Hz)
3
Value
Eastern
Western
ERCOT
Québec
Starting Frequency (FStart)
59.974
59.976
59.963
59.972
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004101
Executive Summary
4.
The recommended UFLS first-step limitations for IFRO calculations are listed in table B.
Table B: Low-frequency Limits (Hz)
Interconnection
5.
Highest UFLS Trip Frequency
Eastern
59.5 3
Western
59.5
ERCOT
59.3
Québec
58.5
The allowable frequency deviation (starting frequency minus the highest UFLS step)
should be reduced to account for differences between the 1-second and sub-second
data for Point C (frequency nadir) by a statistically determined adjustment as listed in
table C. Sub-second measurements will more accurately detect Point C.
Table C: Analysis of 1-Second and Sub-Second Data for Point C (CCADJ)
Number
of
Samples
Mean
Standard
Deviation
CCADJ
(95% Quantile)
Eastern
30
0.0006
0.0038
0.0068
Western
17
0.0012
0.0019
0.0044
ERCOT
58
0.0021
0.0061
0.0121
Québec
0
N/A
N/A
N/A
Interconnection
6.
The allowable change in frequency from the IFRO Starting Frequency should be adjusted
by a statistically determined value to account for the differences between the Value B
and the Point C for historical frequency events as listed in table D.
Table D: Analysis of B Value and Point C (CBR)
3
4
Interconnection Number of Samples
Mean
Eastern
Western
ERCOT
Québec5
0.964
1.570
1.322
1
41
30
88
N/A
Standard
Deviation
CBR
(95% Quantile)
0.0149
0.0326
0.0333
1.0 (0.989)4
1.625
1.377
1.550
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
CBR value limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not need to be adjusted. The
calculated value is 0.989.
Frequency Response Initiative Report – October 2012
4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004102
Executive Summary
7.
An adjustment should be made to the maximum allowable delta frequency to
compensate for the predominant withdrawal of primary frequency response exhibited
in an interconnection until such withdrawal is no longer exhibited in that
interconnection.
8.
The determination of the maximum delta frequencies should be calculated in
accordance with the methods embodied in Table E – Determination of Maximum Delta
Frequencies.
Table E: Determination of Maximum Delta Frequencies
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Minimum Frequency
Limit
59.500
59.500
59.300
58.500
Hz
Base Delta Frequency
0.474
0.476
0.663
1.472
Hz
CCADJ 6
0.007
0.004
0.012
N/A
Hz
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
Hz
CBR 7
1.000 8
1.625
1.377
1.550 9
Hz
Delta Frequency
(DFCBR) 10
0.467
0.291
0.473
0.949
Hz
BC’ADJ 11
.018
N/A
N/A
N/A
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
5
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 millisecond operating time (responsive to Point C) and 59.0 Hz UFLS step
with a 20-second delay (responsive to Value B or beyond) with a 0.05 Hz confidence interval. See the Adjustment for Differences between
Value B and Point C section of this report for further details.
6
Adjustment for the differences between 1-second and sub-second Point C observations for frequency events.
7
Adjustment for the differences between Point C and Value B.
8
CBR value for the Eastern Interconnection limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not
need to be adjusted. The calculated value is 0.989.
9
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 ms operating time (responsive to Point C)and 59.0 Hz UFLS step with a 20second delay (responsive to Value B or beyond).
10
DFCC/CBR
11
Adjustment for the event nadir being below the Value B (Eastern Interconnection only) due to primary frequency response withdrawal.
5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004103
Executive Summary
9.
The Interconnection Frequency Response Obligations should be calculated as shown in
Table F: Recommended IFROs.
Table F: Recommended IFROs
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
2,740
2,750
1,700
MW
–
300
1,400
–
MW
-1,002
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 13
40.6%
71.2%
48.7%
23.9%
% of Interconnection
Load 14
0.17%
0.56%
0.45%
0.50%
Credit for LR
IFRO
12
10.
NERC and the Western Interconnection should analyze the FRO allocation implications
of the Pacific Northwest RAS generation tripping of 3,200 MW.
11.
Trends in frequency response sustainability should be measured and tracked by
observing frequency between T+45 seconds and T+180 seconds. A pair of indices for
gauging sustainability should be calculated comparing that value to both the Point C and
Value B.
12.
Frequency response performance by Balancing Authorities should not be judged for
compliance on a per-event basis.
13.
Linear regression is the method that should be used for calculating Balancing Authority
Frequency Response Measure (FRM) for compliance with Standard BAL-003-1 –
Frequency Response.
12
IFRO =
13
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
14
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004104
Executive Summary
14.
NERC and the Frequency Working Group should annually review the process for
detection of frequency events and the method for calculating the A and B Values and
Point C. The associated interconnection frequency event database, methods for
calculating interconnection metrics on risks to reliability, the associated probabilities,
and the calculation of the IFROs using updated data should also undergo review in an
effort to improve the process. Throughout this process, NERC should strive to improve
the quality and consistency of the data measurements.
15.
NERC should address improving the level of understanding of the role of turbine
governors through seminars and webinars, with educational materials available to the
Generator Owners and Generator Operators on an ongoing basis.
16.
When the Eastern Interconnection Reliability Assessment Group Multiregional Modeling
Working Group (ERAG MMWG) completes its review of turbine governor modeling, a
new light-load case should be developed, and the resource loss criterion for the Eastern
Interconnection’s IFRO should be re-simulated.
17.
Eastern Interconnection inter-area oscillatory behavior should be further investigated by
NERC, including the testing of large resource loss analysis for IFRO validation.
Findings
1.
Analysis of data submitted by the Balancing Authorities during the field trial indicates
that a single-event-based compliance measure is unsuitable for compliance evaluation
when based on data that has the large degree of variability demonstrated by the field
trial.
2.
Analysis of data submitted by the Balancing Authorities during the field trial confirms
that the sample size selected (a minimum of 20–25 frequency events) is sufficient to
stabilize the result and alleviate the perceived problem associated with outliers in the
measurement of Balancing Authority frequency response performance.
3.
There is a strong positive correlation between Eastern Interconnection load and
frequency response for the 2009–2011 events. On average, when interconnection load
changes by 1,000 MW, frequency response changes by 3.5 MW/0.1Hz.
4.
Pre-disturbance frequency (Value A) is a statistically significant contributor to the
variability of frequency response for the Eastern Interconnection. The expected (mean
of the sample) frequency response for events where Value A is greater than 60 Hz is
2,188 MW/0.1 Hz versus 2,513 MW/0.1 Hz for events where Value A is less than or
equal to 60 Hz based on data from 2009 through April 2012.
5.
There is a statistically significant seasonal (summer/not summer) correlation to the
variability of frequency response for the Eastern Interconnection. The expected
frequency response for summer (June–August) frequency events is 2,598 MW/0.1 Hz
versus 2,271 MW/0.1 Hz for non-summer events based on data from 2009 through April
2012.
7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Executive Summary
6.
004105
The difference in average frequency response between on-peak events and off-peak
events is not statistically significant for the Eastern Interconnection and could occur by
chance.
Frequency Response Initiative Report – October 2012
8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004106
Frequency Response Overview
Frequency Response Overview
To understand the role frequency response plays in system reliability, it is important to
understand the different components of frequency control and the individual components of
Primary Frequency Control (also known as frequency response). It is also important to
understand how those individual components relate to each other.
Frequency Control
Frequency control can be divided into four overlapping windows of time:
Primary Frequency Control (frequency response) – Actions provided by the
interconnection to arrest and stabilize frequency in response to frequency deviations.
Primary Control comes from automatic generator governor response, load response
(typically from motors), and other devices that provide an immediate response based on
local (device-level) control systems.
Secondary Frequency Control – Actions provided by an individual Balancing Authority or
its Reserve Sharing Group to correct the resource-load unbalance that created the
original frequency deviation, which will restore both Scheduled Frequency and Primary
frequency response. Secondary Control comes from either manual or automated
dispatch from a centralized control system.
Tertiary Frequency Control – Actions provided by Balancing Authorities on a balanced
basis that are coordinated so there is a net-zero effect on area control error (ACE).
Examples of Tertiary Control include dispatching generation to serve native load,
economic dispatch, dispatching generation to affect interchange, and re-dispatching
generation. Tertiary Control actions are intended to replace Secondary Control
Response by reconfiguring reserves.
Time Control – This includes small offsets to scheduled frequency to keep long-term
average frequency at 60 Hz.
Primary Frequency Control – Primary Frequency Response
Primary Frequency Control, also known generally as primary frequency response, is the first
stage of frequency control and is the response of resources and load to arrest local changes in
frequency. Primary frequency response is automatic, is not driven by any centralized system,
and begins within seconds after the frequency changes, rather than minutes. Different
resources, loads, and systems provide primary frequency response with different response
times, based on current system conditions such as total resource/load mix and characteristics.
9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
004107
The NERC Glossary of Terms defines Frequency Response 15 in two parts:
•
Equipment – The ability of a system or elements of the system to react or respond to a
change in system frequency.
•
System – The sum of the change in demand, plus the change in generation, divided by
the change in frequency, expressed in megawatts per 0.1 hertz (MW/0.1 Hz).
Because the loss of a large generator is much more likely than a sudden loss of an equivalent
amount of load, frequency response is typically discussed in the context of a loss of generation.
NOTE: For purposes of this report, the term “frequency response” is considered to be the
overall response measured between T+20 and T+52 seconds, as used in the BAL-003-1 draft
standard.
Frequency Response Illustration
Many components are included within the defined frequency response. The following
simplified example graphically illustrates those components of frequency response and how
they react to changes in system frequency. The example is presented as an energy balance
problem for the interconnection. It is not intended to be a treatise on governors or other
turbine-generator controls or the internal machine dynamics associated with those control
actions. For additional information on those topics, see the References on Rotating Machines
section in Appendix L.
The example is based on an assumed disturbance event due to the sudden loss of 1,000 MW of
generation. Although a large event is used to illustrate the response components, even small
events can result in similar reactions or responses. The magnitude of the event only affects the
shape of the curves on the graph; it does not obviate the need for frequency response.
The loss of generation is illustrated by the black power deficit line using the MW scale on the
left. The interconnection frequency is illustrated in red, using the hertz (Hz) scale on the right.
The interconnection frequency is assumed to be 60 Hz when the disturbance occurs.
Figure 1 shows the tripping of a 1,000 MW generator. Even though the generation has tripped
and power injected by the generator has been removed from the interconnection, the loads
across the system continue to use the same amount of power. The Law of Conservation of
Energy 16 requires that the 1,000 MW must be supplied to the interconnection if the energy
balance is to be conserved. That 1,000 MW of balancing power is provided by extracting it from
the kinetic energy stored as inertial energy in the rotating mass of all of the synchronized
turbine-generators and motors on the interconnection. It is produced by the slowing of the
spinning inertial mass of rotating equipment on the interconnection that both releases the
stored kinetic energy and reduces the frequency of the interconnection. The extracted energy
15
16
Capitalized as referenced in the NERC Glossary of Terms; lowercased otherwise.
The “Law of Conservation of Energy” is applied here in the form of power. If energy must be conserved, then power—which is the first
derivative of energy with respect to time—must also be conserved.
Frequency Response Initiative Report – October 2012
10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004108
Frequency Response Overview
supplies the “balancing inertia” 17 power required to maintain the power and energy balance on
the interconnection.
Figure 1: Loss of a 1,000 MW Generator
As this balancing power from inertia is used, the speed of the rotating equipment on the
interconnection declines, resulting in a reduction of the interconnection frequency.
Synchronously operated motors contribute to load damping; adjustable or variable speed drive
motors are effectively decoupled from the interconnection frequency through their electronic
controls, and they do not contribute to load damping. In general, any load that does not
change with interconnection frequency (such as resistive loads) will not contribute to load
damping or frequency response. The balancing inertia is illustrated in figure 2 by the orange
dots, which represent the balancing inertia power that exactly overlays and offsets the power
deficit. At this point in the example, no other energy injection has occurred through any
governor control action.
17
The term “balancing inertia” is coined here from the terms “inertial frequency response” and “balancing energy.” Inertial frequency
response is a common term used to describe the power supplied for this portion of the frequency response, and balancing energy is a term
used to describe the market energy supposedly purchased to restore energy balance.
11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
004109
Figure 2: Inertial Energy Extracted from Rotating Mass of Generation and
Synchronous Motor Load
As the rotating machines slow down (reflected as a decline of frequency), the generator
governors, which are the controls that “govern” the speed of the generator turbines, sense this
as a change in turbine speed. In this example, the change in frequency will be used to reflect
this control parameter. Governor action then takes physical action, such as injecting more gas
into a gas turbine, opening steam valves wider on a steam unit (also injecting more fuel into the
boiler), or opening the control gates wider on a hydraulic turbine. This control action results in
more combusted gases, steam, or water to impart more mechanical energy to the shaft of the
turbine to increase its speed. The turbine shaft is coupled to the generator, where it is
converted into additional electric energy. The process of the turbine slowing, the detection of
change in speed, and the injection of additional mechanical energy is not instantaneous.
Until the additional mechanical energy can be injected, the frequency continues to decline, due
to the ongoing extraction of balancing power from the inertial energy of the rotating turbinegenerators and synchronous motors on the interconnection. As frequency continues to decline,
the reduction in load also continues as the effect of load damping continues to reduce the load.
Frequency Response Initiative Report – October 2012
12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004110
Frequency Response Overview
Figure 3: Time Delay of Governor Response
During the initial seconds of the disturbance event, the primary frequency response from the
turbine governors has not yet influenced the frequency decline. For this example, primary
frequency response from governors that injects additional energy into the system is reflected
by the blue line (in MW) on figure 3.
After a short time delay, the governor response begins to increase rapidly in response to the
initial decline in frequency, as illustrated in figure 4. In order to arrest the frequency decline,
the governor response must offset the power deficit and replace the balancing power that had
extracted inertial energy from the rotating machines of the interconnection. At this point in
time, the balancing power from inertia is reduced to zero as it is replaced by the governor
response. That replacement is shown as the crossing of the orange and blue lines in figure 4.
The point at which the frequency decline is arrested is called the nadir, or Point C, and
frequency response calculated to that point is “arrested frequency response.”
If the time delay associated with the delivery of governor response is reduced, the amount of
balancing power from inertia required to limit the change in frequency for the disturbance
event can also be reduced. This supports the conclusion that balancing power from inertia is
required to manage the time delays associated with the delivery of primary frequency
response. Not only is the rapid delivery of primary frequency response important, but so is the
shortening of the time delay associated with its delivery.
13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
004111
Figure 4: Governor Response Replaces Balancing Power from Inertia and
Arrests Frequency Decline
The above components are related to the length of time before the initial delivery of primary
frequency response from governors begins and how much of the response is delivered before
the frequency change is arrested.
From a system standpoint during this time delay, the amount of inertia on the interconnection,
which determines the amount of energy available to be extracted from rotating machines,
determines the slope of the frequency decline: the less inertia there is, the steeper the slope.
This is important in the relationship between the balancing power from inertia and the time
delay associated with the governor response. For a given time delay in primary frequency
response from governors, the steeper the slope, the lower frequency will dip before it is
arrested. Conversely, for a given balancing power from inertia and slope of frequency decline,
the faster governor response can be provided, the sooner the frequency decline is arrested,
making the nadir less severe.
Therefore, as traditional rotating generators are replaced by electronically coupled resources,
such as wind turbines and solar voltaic resources (which provide less overall system inertia), the
speed of delivery of governor response should increase, or other methods should be provided
that support fast-acting energy injection to minimize the depth of frequency excursions.
The arrested frequency is normally the minimum (maximum for load loss events) frequency
that will be experienced during a disturbance event. This minimum frequency is the frequency
that is of concern from a reliability perspective. The goal is to arrest the frequency decline so
frequency remains above the under-frequency load shedding (UFLS) relays with the highest
settings so that load is not tripped. Frequency response delivered after frequency is arrested at
Frequency Response Initiative Report – October 2012
14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004112
Frequency Response Overview
this minimum provides less reliability value than frequency response delivered before Point C,
but greater value than secondary frequency control power and energy that is delivered minutes
later.
Figure 5: Post-Disturbance Transient Period (0 to 20 seconds)
Point C
Once the frequency decline is arrested, the governors continue to respond because of the time
delay associated with the governor action. This results in the frequency partially recovering
from the minimum arrested value and results in some oscillating transient that follows the
minimum frequency (arrested frequency) until power flows and frequency settle during the
transient period, which typically ends around 20 seconds after start of the disturbance event.
This post-disturbance transient period is shown in figure 5.
The total disturbance event is illustrated in figure 6. Frequency and power contributions
stabilize at the end of the transient period. Frequency response calculated from data measured
during this settled period is called the “settled frequency response.” The settled frequency
response is the measure used as an estimator for determining the Frequency Bias 18 setting
used in the automated generator control (AGC) systems of the energy management systems
(EMS) in energy control centers.
18
As defined in the NERC Glossary: “A value, usually expressed in megawatts per 0.1 hertz (MW/0.1 Hz), associated with a Balancing Authority
Area that approximates the Balancing Authority Area’s response to Interconnection frequency error.”
15
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004113
Frequency Response Overview
Figure 6: Disturbance Event Frequency Excursion
Point C
Figure 7: Averaging Periods used for Measuring Frequency Response
Frequency Response Initiative Report – October 2012
16
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004114
Frequency Response Overview
Figure 7 shows the averaging periods used to calculate 19 the pre-disturbance Value A frequency
averaging period (T-16 through T+0 seconds) and the post-disturbance Value B frequency
averaging period (T+20 through T+52 seconds) used to calculate the settled frequency
response. The length of those periods is based on the length of the system control and data
acquisition (SCADA) scan rates of the energy management systems (EMS) of the Balancing
Authorities.
The calculation of the Value A and Value B frequencies began with the assumption that a 6second scan rate was the source of the data. Once the averaging periods for a 6-second SCADA
scan rate were selected, the averaging periods for the other scan rates were selected to provide
as much consistency as possible between Balancing Authorities with different scan rates.
The Value A frequency was initially defined as the average of the two scans immediately prior
to the frequency event. All other averaging periods were then selected to be as consistent as
possible with this 12-second average scan from the 6-second scan rate method. In addition, the
“actual net interchange immediately before Disturbance” was then defined as the average of
the same period and same scans as used for Value A averaging.
The Value B frequency was then selected to be an average as long as the average of 6-second
scan data as possible, that would not begin until most of the hydro governor response had been
delivered, and would end before significant Automatic Generation Control (AGC) recovery
response had been initiated as indicated by a consistent frequency restoration slope. The
“actual net interchange immediately after Disturbance” was then similarly defined as the
average of the same period and same scans as used for the Value B.
Balancing Authority Frequency Response
Disturbances can cause the frequency to either increase from loss of load or decrease from loss
of generation; frequency response characteristics of Balancing Authorities should be evaluated
for both types of events.
Accurate measurement of frequency response for an interconnection or for individual
Balancing Authorities is difficult unless the frequency deviation resulting from a system
disturbance is significant. Therefore, it is better to analyze response only when significant
frequency deviations occur.
Frequency response considers the following elements of an interconnected transmission
system:
1.
Frequency Response Characteristic (FRC) – For any change in generation/load balance
in the interconnection, a frequency change occurs. Each Balancing Authority in the
interconnection will respond to this frequency change through:
•
19
a load change that is proportional to the frequency change due to the load’s FRC,
and
As proposed in Standard BAL-003-1 – Frequency Response.
17
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
•
004115
a generation change that is inverse to the frequency change due to turbine governor
action. The net effect of these two actions is the Balancing Authority’s response to
the frequency change; that is, its FRC. The combined response of all Balancing
Authorities in the interconnection will cause the interconnection frequency to settle
at some value different from the pre-disturbance value. It will not return frequency
to the pre-disturbance value because of the turbine governor droop characteristic.
Frequency will remain different until the Balancing Authority with the
generation/load imbalance (referred to as the “Contingent Balancing Authority”)
corrects that imbalance, thus returning the interconnection frequency to its predisturbance value.
2.
Response to Internal and External Generation/Load Imbalances – Most of a Balancing
Authority’s frequency response will be reflected in a change in its actual net
interchange. By monitoring the frequency error (the difference between actual and
scheduled frequency) and the difference between actual and scheduled interchange,
using its response to frequency deviation, a Balancing Authority’s automatic generation
control (AGC) can determine whether the imbalance in load and generation is internal
or external to its system. If internal, the Balancing Authority’s AGC should correct the
imbalance. If external, the Balancing Authority’s AGC should allow its generator
governors to continue responding (preserved by its frequency bias contribution in its
ACE equation) until the contingent Balancing Authority corrects its imbalance, which
should return frequency to its pre-disturbance value.
3.
Frequency Bias versus Frequency Response Characteristic (FRC) – The Balancing
Authority should set its bias setting in its AGC ACE equation to match its FRC. In doing
so, the Balancing Authority’s bias contribution term would exactly offset the tie line flow
error (NiA – NiS) of the ACE that results from governor action following a frequency
deviation on the interconnection. The following sections discuss the effects of bias
settings on control action and explain the importance of setting the bias equal to the
Balancing Authority’s FRC. The discussion explains the control action on all Balancing
Authorities external to the contingent Balancing Authority (the Balancing Authority that
experienced the sudden generation/load imbalance) and on the contingent Balancing
Authority itself.
While this discussion deals with loss of generation, it applies equally to loss of load, or
any sudden contingency resulting in a generation/load mismatch. Each Balancing
Authority’s frequency response will vary with each disturbance because generation and
load characteristics change continuously. This discussion also assumes that the
frequency error from 60 Hz was zero (all ACE values were zero) just prior to the sudden
generation/load imbalance.
4.
Effects of a Disturbance on all Balancing Authorities External to the Contingent
Balancing Authority – When a loss of generation occurs, an interconnection frequency
error will occur as rotating kinetic energy from the generators of the interconnection is
expended, slowing the generators throughout the interconnection. All Balancing
Authorities’ generator governors will respond to the frequency error and increase the
Frequency Response Initiative Report – October 2012
18
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004116
Frequency Response Overview
output of their generators (increase speed) accordingly. This will cause a change in the
Balancing Authorities’ actual net interchange. In other words, the Actual Net
Interchange (NiA) will be greater than the Scheduled Net Interchange (NiS) for all but the
contingent Balancing Authority, and the result is a positive flow out of the noncontingent Balancing Authorities. The resulting tie flow error (NiA – NiS) will be counted
as Inadvertent Interchange.
If the Balancing Authorities were using only tie line flow error (i.e., flat tie control
ignoring the frequency error), this non-zero ACE would cause their AGC to reduce
generation until NiA was equal to NiS, returning their ACE to zero. However, doing this
would not help arrest interconnection frequency decline, because the Balancing
Authorities would not be helping to temporarily replace some of the generation
deficiency in the interconnection. With the tie line bias method, the Balancing
Authorities’ AGC should allow their governors to continue responding to the frequency
deviation until the contingent Balancing Authority replaces the generation it has lost.
In order for the AGC to allow governor action to continue to support frequency, a
frequency bias contribution term is added to the ACE equation to counteract the tie
flow error. This bias contribution term is equal in magnitude and opposite in direction
to the governor action and should ideally be equal to each Balancing Authority’s
frequency response characteristic measured in MW/0.1 Hz. Then, when multiplied by
the frequency error, the bias should exactly counteract the tie flow error portion of the
ACE calculation, allowing the continued support of the generator governor action to
support system frequency.
In other words, BiasContributionTerm
= 10 B ( f A − f S ) . ACE will be zero, and AGC will
not read just generation.
The ACE equation is then:
ACE = ( NiA − NiS ) − 10 B( f A − f S ) − I ME
Where:
• The factor 10 converts the bias setting (B) from MW/0.1 Hz to MW/Hz.
•
IME is meter error correction estimate; this term should normally be very small or
zero.
NOTE: Although frequency response and bias are often discussed as positive values
(such as “our bias is 50 MW/0.1 Hz”), frequency response and bias are actually negative
values.
If the bias setting is greater than the Balancing Authority’s actual frequency response
characteristic, then its AGC will increase generation beyond the primary frequency
response from governors, which further helps arrest the frequency decline, but
increases Inadvertent Interchange. Likewise, if the bias contribution term is less than
19
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Overview
004117
the actual FRC, its AGC will reduce generation, reducing the Balancing Authority’s
contribution to arresting the frequency change. In both cases, the resultant control
action is unwanted.
5.
Effects of a Disturbance on the Contingent Balancing Authority – In the contingent
Balancing Authority where the generation deficiency occurred, most of the replacement
power comes from the interconnection over its tie lines from the frequency response
contributions of the other Balancing Authorities in the interconnection. A small portion
will be made up internally from the contingent Balancing Authority’s own governor
response. In this case, the difference between NiA and NiS for the contingent Balancing
Authority is much greater than its frequency bias component. Its ACE will be negative (if
the loss is generation), and its AGC will begin to increase generation.
•
NiA – drops by the total generation lost less the contingent Balancing Authority’s
own primary frequency response from governors
•
NiS – does not change
The contingent Balancing Authority must take appropriate steps to reduce its ACE to
zero or pre-disturbance ACE if ACE is negative within 15 minutes of the contingency.
(Reference: formerly Operating Criterion II.A.) The energy supplied from the
interconnection is posted to the contingent Balancing Authority’s inadvertent balance.
6.
Effects of a Disturbance on the Contingent Balancing Authority with a Jointly Owned
Unit – In the contingent Balancing Authority where the generation deficiency occurred
on a jointly owned unit (with dynamically scheduled shares being exported), the effect
on the tie line component (NiA – NiS) of their ACE equation is more complicated. The NiA
drops by the total amount of the generator lost, while the NiS is reduced only by the
dynamic reduction in the shares being exported.
•
NiA – drops by the total generation lost less the contingent Balancing Authority’s
own primary frequency response from governors
•
NiS – decreases by the reduction in dynamic shares being exported
The net effect is that the tie line bias component only reflects the contingent Balancing
Authority’s share of the lost generation. Most of the replacement power comes from
the interconnection over its tie lines from the frequency bias contributions of the other
Balancing Authorities in the interconnection.
7.
Effects of a Disturbance on the Non-contingent Balancing Authority with a Jointly
Owned Unit – In the non-contingent Balancing Authority where the generation
deficiency occurred on a jointly-owned unit in another Balancing Authority (with
dynamically scheduled shares being exported), the effect on the tie line component (NiA
– NiS) of their ACE equation is also complicated. The NiA increases by the Balancing
Authority’s own primary frequency response from governors, while the NiS is reduced
only by the dynamic reduction in the shares being imported.
Frequency Response Initiative Report – October 2012
20
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004118
Frequency Response Overview
•
•
NiA – increases by the Balancing Authority’s own primary frequency response
from governors
NiS – decreases by withdrawn dynamic shares of the jointly-owned unit
The net effect is that the tie line bias component only reflects the contingent Balancing
Authority’s share of the lost generation. Most of the replacement power comes from
the interconnection over its tie lines from the frequency bias contributions of the other
Balancing Authorities in the interconnection.
21
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
004119
Historical Frequency Response Analysis
History of Frequency Response and its Decline
Interconnection frequency response has been a subject of industry interest and attention since
the first two electric systems became interconnected and the concept of frequency bias was
adopted. In 1942, the first test to determine the system’s load/frequency characteristic was
conducted for use in setting bias control. As interconnected systems grew larger and the
characteristics of load and generation changed, it became apparent that guidelines were
needed regarding frequency response to avoid one system imposing undue frequency
regulation burdens on its interconnected neighbors. During the 1970s and 1980s, NERC’s
Performance Subcommittee (now the Resources Subcommittee of the Operating Committee),
which is charged with monitoring the control performance of the interconnections, observed
that generators’ governor responses to frequency deviations had been decreasing, especially in
the Eastern Interconnection. The result was quite noticeable during large generation losses
where the frequency deviation was not arrested as quickly as it once was. The industry did not
initially recognize that power systems operations could significantly influence primary
frequency response. 20
In 1991, NERC’s Performance Subcommittee approached the Electric Power Research Institute
(EPRI) with a request to fund and manage a study of the apparent decline in governor response
in the interconnections. EPRI agreed and in turn contracted with EPIC Engineering to perform
this study. The conclusions were captured in a joint EPRI/NERC report, “Impacts of Governor
Response Changes on the Security of North American Interconnections.” 21 These studies
indicated that the frequency response of the interconnections was declining at rates greater
than would be expected with the growth of demand and generating capacity. 22 Although
frequency response was declining, the opinion of experts at the time was that the decline had
not reached a point at which reliability was being compromised.
The NERC Resources Subcommittee proposed a frequency response standard for comment in
2001. In response to these comments, the Frequency Task Force of the NERC Resources
Subcommittee published a Frequency Response Standard white paper 23 intended to create an
understanding of the need for a frequency response standard and the technical and economic
drivers motivating its development. The paper documented and discussed the decline
observed in frequency response in the Eastern and Western Interconnections.
20
See Illian, H.F. Frequency Control Performance Measurement and Requirements, LBNL-4145E (December 2010).
EPRI Report TR-101080, Impacts of Governor Response Changes on the Security of North American Interconnections, October 1992.
22
See EPRI Report TR-101080, Impacts of Governor Response Changes on the Security of North American Interconnections, October 1992 (“An
analysis of the 14 Frequency Response Characteristics Surveys conducted by NERC over the 1971 to 1993 period showed that the Frequency
Response in percent MW/O. 1Hz has deteriorated. This value in 1971 was between 2.25 and 3.25% (depending on the area) and by 1993 had
dropped to 0.75 and 1.25 %.”).
23
Available here: http://www.nerc.com/docs/oc/rs/Frequency_Response_White_Paper.pdf (“Frequency Response Standard Whitepaper”).
21
Frequency Response Initiative Report – October 2012
22
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004120
Historical Frequency Response Analysis
P rojections of Frequency R esponse Decline
In August 2011, the Transmission Issues Subcommittee 24 of the NERC Planning Committee
completed an analysis titled “Interconnection Criteria for Frequency Response Requirements –
Determination of Interconnection Frequency Response Obligations.” 25 The analysis included
comparisons of various Resource Contingency Protection Criteria for loss of resources, including
largest potential loss-of-resource event (N-2), the largest total generating plant with common
voltage switchyard, and the largest loss of generation in the interconnection in the last 10
years. Also examined in that analysis were the various other factors that must be considered in
an IFRO determination: the highest under-frequency load shedding (UFLS) program setpoint
within each interconnection, special consideration of demand-side frequency responsive
programs in ERCOT, and a reliability margin to account for the variability of frequency due to
items such as time error correction (TEC), variability of load, variability of interchange,
variability of frequency over the course of a normal day, and other uncertainties. The proposed
margin was analyzed using a probabilistic approach based on 1-minute frequency performance
data for each interconnection. The Transmission Issues Subcommittee recommended the
following IFROs for the four interconnections: Eastern: -1,875 MW/0.1 Hz; Western: -637
MW/0.1 Hz; Texas: -327 MW/0.1 Hz; and Québec: -113 MW/0.1 Hz. The Transmission Issues
Subcommittee IFRO report was approved by the NERC Planning Committee in September 2011
and forwarded to the Standard Drafting Team for their consideration.
A similar report had been prepared by the Resources Subcommittee of the NERC Operating
Committee in January 2011 titled “NERC Resources Subcommittee Position Paper on Frequency
Response.” 26 That report used similar Resource Contingency Protection Criteria but used the
prevalent 59.5 Hz highest UFLS setpoint for the Eastern Interconnection and a lower 59.3 Hz
UFLS setpoint for ERCOT. The Resources Subcommittee analysis also used a 25% reliability
margin for all four interconnections. The Resources Subcommittee recommended the following
IFROs for the four interconnections: Eastern: -1,406MW/0.1 Hz; Western: -685 MW/0.1 Hz;
Texas: -286 MW/0.1 Hz; and Québec: -141 MW/0.1 Hz. The Resources Subcommittee position
paper was approved by the Operating Committee in March 2011 and was considered by the
Frequency Response Standard Drafting Team. NERC has been tracking the decline of frequency
response in the Eastern Interconnection for several years.
24
The Transmission Issues Subcommittee is now the System Analysis and Modeling Subcommittee (SAMS).
Available here: http://www.nerc.com/docs/pc/tis/Agenda_Item_5.d_Draft_TIS_IFRO_Criteria%20Rev_Final.pdf.
26
Available here:
http://www.nerc.com/docs/oc/rs/NERC%20RS%20Position%20Paper%20on%20Frequency%20Response%20Final%20(May%2027%202011).p
df.
25
23
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004121
Historical Frequency Response Analysis
Figure 8: Eastern Interconnection Mean Primary Frequency Response 27
(March 30, 2012)
4,000
Source 1994-2009: J. Ingleson & E. Allen, "Tracking the
Eastern Interconnection Frequency Governing
Characteristic" presented at 2010 IEEE PES.
Source 2010-2011: Daily Automated Reliability Reports
3,500
*
* 1999 Data Interpolated
MW / 0.1 Hz
3,000
2,500
2,000
1,500
1,000
Year
Figure 8 shows how frequency response has declined since 1994, as filed in NERC’s “Motion for
an Extension of Time of the North American Electric Reliability Corporation” (for the
development of Standard BAL-003-1 – Frequency Response). 28 That request for extension of
time was granted by FERC in its Order on Motion for an Extension of Time and Setting
Compliance Schedule (Issued May 4, 2012). 29
Comparing the proposed IFROs from those two studies, the Eastern Interconnection IFROs
range from about 1,400 MW/0.1 Hz to about 1,900 MW/0.1 Hz, and the linear projection of the
frequency response decline intercepts those target IFROs between 2019 and 2024. Even the
more pessimistic polynomial projection of the decline intercepts the proposed IFROs between
2014 and 2016. This shows that there was still some time as of that filing for revising BAL-003-1
and responding to the decline in frequency response.
Figure 8 was revised shortly after the March 2012 filing in conjunction with revised frequency
response calculation methods used in NERC’s 2012 State of Reliability report (May 2012).
Figure 9 reflects the revised frequency response calculations for 2009 through 2011.
27
The Frequency Response data from 1994 through 2009 displayed in figure 2 is from a report by J. Ingleson & E. Allen, Tracking the Eastern
Interconnection Frequency Governing Characteristic that was presented at the 2010 IEEE.
28
Filing available at: http://www.nerc.com/files/MotionExtTime_RM06-16_03302012.pdf
29
Order available at: http://www.nerc.com/files/Order_Motion_Extension_Time_Compliance_Sched_2012.5.4.pdf
Frequency Response Initiative Report – October 2012
24
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004122
Historical Frequency Response Analysis
Figure 9: Updated Eastern Interconnection Mean Primary Frequency Response
(May 2012)
Change in Value A & B
Calculation Method
Figure 9 shows an improvement in frequency response in 2009 through 2011 due to alignment
of the methods for calculation Values A and B. That method is consistent with the method
being proposed in NERC Standard BAL-003-1. The method has since been further refined, as
reflected in the Statistical Analysis of Frequency Response section of this report.
Figures 10–13 show the statistical analysis of the frequency response for 2009–2011 for the
Eastern, Western, and ERCOT Interconnections from the 2012 State of Reliability report in box
plot format (only 2011 data was available for the Québec Interconnection).
Figure 10: Eastern Interconnection Frequency Response Analysis for 2009–2011
4500
4000
Frequency Response (MW/0.1 Hz)
3500
3000
2,206
2,200
2,312
2500
First Quartile
Minimum
Median
2000
Maximum
Third Quartile
1500
1000
500
0
2009
25
2010
Period
2011
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004123
Historical Frequency Response Analysis
Figure 11: Western Interconnection Frequency Response Analysis for 2009–2011
5000
4500
4000
Frequency Response
3500
3000
First Quartile
2500
Minimum
1,635
1,623
1,521
2000
Median
Maximum
Third Quartile
1500
1000
500
0
2010
Period
2009
2011
Figure 12: ERCOT Interconnection Frequency Response Analysis for 2009–2011
1800
1600
1400
Frequency Response
1200
1000
First Quartile
Minimum
576
567
800
511
Median
Maximum
Third Quartile
600
400
200
0
2009
2010
Period
2011
It is important to note the range of variability of the frequency response for each year.
Additional events and modifications to the calculation methods for the A, B, and C values have
been made since these values were calculated for the May 2012 report. The new values are
reflected in the Statistical Analysis section of this report.
Frequency Response Initiative Report – October 2012
26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004124
Historical Frequency Response Analysis
Figure 13: Québec Interconnection Frequency Response Analysis for 2011
900
800
700
506
Frequency Response
600
500
First Quartile
Minimum
400
Median
Maximum
Third Quartile
300
200
100
0
2011
Period
Statistical Analysis of Frequency Response (Eastern
Interconnection)
In July 2012, a statistical analysis of the frequency response of the Eastern Interconnection was
performed for the calendar years 2009–2011 and the first three months of 2012. The size of
the dataset was 163 (with 44 observations for 2009, 49 for 2010, 65 for 2011, and 5 for 2012).
Table 1: Statistical Analysis Dataset
Sample Parameter
Sample Size
Sample Mean
Sample Standard
Deviation
2009
2010
2011
44
49
65
2,258.4
2,335.7
2,467.8
522.5
697.6
593.7
The report on that analysis was updated in August and September 2012 and is contained in
Appendix G. Its results are paraphrased here for brevity. For the analysis, frequency response
pertains to the absolute value of frequency response.
K ey Statistical Findings
1. A linear regression equation with the parameters defined in Appendix G is an adequate
statistical model to describe the relationship between time (predictor) and frequency
response (responsive variable). The graph of the linear regression line and frequency
response scatter plot is given in figure 14.
27
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
004125
Figure 14: Linear Regression Fit Plot for Eastern Interconnection Frequency Response
2. The probability distribution of the whole frequency response dataset is approximately
normal, with an expected frequency response of 2,363 MW/0.1 Hz and a standard deviation
of 605.7 MW/0.1 Hz as shown in figure 15.
Figure 15: Probability Distribution Eastern Interconnection Frequency Response
January 2009–April 2012
Frequency Response Initiative Report – October 2012
28
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004126
Historical Frequency Response Analysis
3. There is a statistically significant seasonal (summer/not summer) correlation to the
variability of frequency response for the Eastern Interconnection. The expected frequency
response (mean of the samples) for summer (June–August) frequency events is 2,598
MW/0.1 Hz versus 2,271 MW/0.1 Hz for non-summer events. This is attributable to at least
two factors: higher load contribution to frequency response and increased generation
dispatch of units with higher frequency response characteristics.
4. Pre-disturbance (average) frequency (Value A) is another statistically significant contributor
to the variability of frequency response. The expected frequency response (mean of the
samples) for events where Value A is greater than 60 Hz is 2,188 MW/0.1 Hz versus 2,513
MW/0.1 Hz for events where Value A is less than or equal to 60 Hz.
Figure 16: Linear Regression for Frequency Response and Interconnection Load
5. The difference in average frequency response between on-peak events and off-peak events
is not statistically significant and could occur by chance. According to the NERC definition,
Eastern Interconnection on-peak hours are designated as follows: Monday to Saturday from
07:00 to 22:00 hours (Central Time) excluding six holidays: New Year’s Day, Memorial Day,
Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. Analysis showed that
the on-peak/off-peak variable is not a statistically significant contributor to the variability of
frequency response. There is a positive correlation of 0.06 between the indicator function
of on-peak hours and frequency response; however, difference in average frequency
response between on-peak events and off-peak events is not statistically significant and
could occur by chance (P-value—the probability of obtaining a result at least as extreme—is
0.49).
29
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004127
Historical Frequency Response Analysis
6. There is a strong positive correlation of 0.364 between interconnection load and frequency
response for the 2009–2011 events. On average, when interconnection load changes by
1,000 MW, frequency response changes by 3.5 MW/0.1 Hz.
This correlation indicates a statistically significant linear relationship between
interconnection load (predictor) and frequency response (response variable). Figure 16
shows the linear regression line and frequency response scatter plot. For the dataset, the
regression line has a positive slope estimate of 0.00349; thus, the frequency response
variable increases when interconnection load grows.
7. For the 2009–2011 dataset, five variables (time, summer, high pre-disturbance frequency,
on-peak/off peak hour, and interconnection load) were involved in the statistical analysis of
frequency response. Four of these—time, summer, on-peak hours, and interconnection
load—have a positive correlation with frequency response (0.16, 0.24, 0.06, and 0.36,
respectively), and the high pre-disturbance frequency has a negative correlation with
frequency response (-0.26). The corresponding coefficients of determination R2 (the square
of correlation) indicate that about 2.6% in variability of frequency response can be
explained by the changes in time, about 5.8% is seasonal, 0.4% is due to on-peak/off-peak
changes, 13.3% is the effect of interconnection load variability, and about 6.9% can be
accounted for by a high pre-disturbance frequency. However, the correlation between
frequency response and on-peak hours is not statistically significant, with the probability of
about 0.44 having occurred by mere chance (the same holds true for the corresponding R2).
Table 2: Explanatory Variables for Eastern Interconnection
Frequency Response
P-Value
Linear
Regression
Statistically
Significant
Coefficient of
Determination
R2 (Single
Regression)
0.36
<0.0001
Yes
13.3%
Value A > 60 Hz
-0.26
0.0008
Yes
6.9%
Summer/Not
Summer
0.24
0.0023
Yes
5.8%
Date
0.16
0.044
Yes
2.6%
On-Peak Hours
0.06
0.438
No
N/A
Sample
Correlation
(X, FR)
Interconnection
Load
Variable X
Therefore, out of the five parameters, interconnection load has the biggest impact on
frequency response followed by the indicator of high pre-disturbance frequency. A
multivariate regression with interconnection load and starting frequency (Value A) greater
Frequency Response Initiative Report – October 2012
30
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004128
Historical Frequency Response Analysis
than 60 Hz as the explanatory variables for frequency response yields a linear model with
the best fit (it has the smallest mean square error among the linear models with any other
set of explanatory variables selected from the five studied). Together these two factors can
account for about 20% of the variability in frequency response.
Frequency response is, therefore, affected by other parameters that have low correlation with
those studied and account for the remaining share of frequency response variability, minimizing
the random error variance.
Note that interconnection load is positively correlated with summer (0.55), on-peak hours
(0.45), and time (0.20), but is uncorrelated with starting frequency greater than 60 Hz (P-value
of the test on zero correlation is 0.90).
Frequency Response Withdrawal
Withdrawal of primary frequency response is an undesirable characteristic associated most
often with digital turbine-generator control systems using setpoint output targets for generator
output. These are typically outer-loop control systems that defeat the primary frequency
response of the governors after a short time to return the unit to operating at a requested MW
output.
Figure 17: Primary Response Sustainability
0.0
100.0
Time (sec)
Blue = frequency response is sustained
Red = generator has a “slow” load controller returning to MW set-point
Figure 17 shows how the outer-loop control on a single machine would influence its ability to
provide primary frequency response.
Some of the typical causes of the withdrawal are:
•
•
31
Plant outer-loop control systems – driving the units to MW setpoints
Unit characteristics
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
•
004129
o Plant incapable of sustaining primary frequency response
o Governor controls overridden by other turbine/steam cycle controls
Operating philosophies – operating characteristic choices made by plant operators
o Desire to maintain highest efficiencies for the plant
The phenomenon is most prevalent in the Eastern Interconnection and can easily be seen in the
comparison of the typical frequency response performance of the three interconnections
(figure 18).
Figure 18: Typical Interconnection Responses for 2011 30
Sustainability of primary frequency response becomes more important during light load
conditions (nighttime) when there are generally fewer frequency-responsive generators online.
A number of the governor survey questions addressed the operational status and parameters
of the governor fleet. The results of the survey show:
•
About 90% of the generators were reported to have governors.
30
NERC interconnections 2011 typical event frequency patterns using the median of the same second of each RS−FWG selected event –
Revised: 09/26/12 provided by Advanced Systems Researchers.
Frequency Response Initiative Report – October 2012
32
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004130
Historical Frequency Response Analysis
•
•
•
Virtually all (95–99% by interconnection) of the GOs and GOPs reported that their
governors are operational.
80–85% (by interconnection) of the governors were reported to be capable of sustaining
primary frequency response for longer than 1 minute if the frequency remained outside
of their deadband.
Roughly 50% of the governors reported that they had unit-level or plant-level control
systems that override or limit governor performance.
Despite the fact that the majority of generators reported they have operational turbine
governors, half of them have unit- or plant-level control systems that override governor
responses. These control systems allow the units to return to scheduled output (MW setpoint)
or an optimized operating point for economic reasons. These factors heavily influence the
sustainability of primary frequency response, contributing to the withdrawal symptom often
observed. This is often evident during light load periods in the middle of the night when highefficiency, low-cost units that operate on MW setpoints are the majority of the generators
dispatched to serve load.
This was exhibited by two events involving generator trips in the spring of 2012 in one
weekend. During the first event (figure 19), 1,711 MW of generation was tripped with a typical
-2,369 MW/0.1 Hz frequency response.
Figure 19: 3:30 pm Saturday Afternoon 1,711 MW Resource Loss
Value A
60.021 HZ
ΔF = 0.0722 Hz
FR = -2,369 MW/0.1 Hz
Value B
59.948 Hz
33
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004131
Historical Frequency Response Analysis
The second event (figure 20) occurred late Sunday night when load in the Eastern
Interconnection was much lighter, and the generators dispatched—probably the most efficient
units—were of a different character. Despite the resource loss being almost 700 MW less, the
frequency response of the interconnection was significantly reduced and exhibited the “lazy L”
of primary frequency response withdrawal. Point C defined to occur during the first 8 seconds
(at that time) was 59.962 Hz, while a lower point of about 59.939 Hz occurred about 1 minute
after the event.
Figure 20: 11:21 pm Sunday Night 1,049 MW Resource Loss
Value A
60.026 HZ
ΔF = 0.0799 Hz
FR = -1,312 MW/0.1 Hz
Value B
59.946 Hz
Point C’
These two events point to the composition of the dispatch and the characteristics of the units
on-line as primary elements in the frequency response strength, as well as the key elements in
creating withdrawal. Therefore, when calculating an Interconnection Frequency Response
Obligation (IFRO), it is important for operational planners and operators to recognize the
potential for that withdrawal and the frequency consequentially being lower one to two
minutes after the beginning of the event.
A similar withdrawal was experienced during the major frequency excursion of August 4, 2007
(figure 21). During that event some 4,500 MW of generation was lost.
The lowest frequency in the event was 59.868 Hz at about one minute after the start. Recovery
to pre-event frequency was about 8 minutes, but the measurement of Value B (20 to 52
seconds) would not capture the lowest frequency. That frequency point is the true frequency
Frequency Response Initiative Report – October 2012
34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004132
Historical Frequency Response Analysis
event nadir, hereafter referred to as Point C’ (“Point C Prime”), and is normally equal to Point C
for events that don’t exhibit the so-called “lazy L” effect.
It is important that the phenomenon be recorded and trended to determine if it is improving or
deteriorating.
Figure 21: Interconnection Frequency – August 4, 2007 EI Frequency Excursion
Recommendation – Measure and track frequency response sustainability trends by observing
frequency between T+45 seconds and T+180 seconds. A pair of indices for gauging
sustainability should be calculated comparing that value to both Point C and Value B.
Modeling of Frequency Response in the Eastern Interconnection
Modeling of frequency response characteristics has been a known problem since at least 2008,
when forensic modeling of the Eastern Interconnection required a “de-tuning” of the existing
MMWG dynamics governor to 20% of modeled (80% error) to approach the measured
frequency response values from the event.
Figure 22 shows the response comparison for that event analysis. Although the event was an
over-frequency problem at that point, it is indicative of the larger problem of governor
modeling in the Eastern Interconnection. The problem was further highlighted in the 2010 “Use
of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable
Integration of Variable Renewable Generation,” by Ernest Orlando Lawrence Berkeley National
Laboratory (LBNL). In that analysis, an attempt was made to simulate a 4,500 MW loss event
that occurred on August 4, 2007. Figure 23 shows a comparison of the simulation to the
measured frequency from the event.
35
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Historical Frequency Response Analysis
004133
Figure 22: 2007 Event Frequency Response Forensic Analysis
Figure 23: Eastern Interconnection Frequency Response – August 4, 2007 Initial 20 Seconds
As part of the NERC Frequency Response Initiative and the Modeling Improvements Initiative,
NERC collaborated with the Eastern Interconnection Reliability Assessment Group (ERAG)
Multiregional Modeling Working Group (MMWG) to perform an analysis of the modeling of
overall frequency response in the Eastern Interconnection. That review was a prelude to a plan
Frequency Response Initiative Report – October 2012
36
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004134
Historical Frequency Response Analysis
for thorough examination of the governor models in the Eastern Interconnection dynamics
study cases that are assembled by the MMWG. That report stated, “The turbine-governor
modeling currently reflected in the MMWG dynamics simulation database is not a valid
representation of the frequency control behavior of the Eastern Interconnection.”
That project created a “generic case” dynamics model, replacing the turbine governor models
in the case with a generic governor model in order to ascertain the basic characteristics of the
frequency response of the Eastern Interconnection. Figure 24 shows a comparison of the actual
event data and the simulations using the original governor data and the generic case.
The characteristics found in that study were:
•
•
•
Only 30% of the units on-line provide primary frequency response.
Two-thirds of the units that did respond exhibit withdrawal of primary frequency
response.
Only 10% of units on-line sustain primary frequency response.
Figure 24: Comparison of Legacy and Generic Simulations to August 4 Event
Following that study, a follow-on analysis was performed by NERC staff to determine the
general order of magnitude of a frequency event that could be sustained by the Eastern
Interconnection without violating the 59.7 Hz first step UFLS in FRCC. A simulation was run that
tripped about 8,500 MW of generation in the southeast United States (north of Florida). Figure
25 shows the result of that testing.
37
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004135
Historical Frequency Response Analysis
The simulation showed that the lowest frequency would be about 59.76 Hz in southern Florida.
The initial nadir of 59.78 Hz in southern Florida is lower than the nadir in northern Florida due
to the wave properties of the disturbance.
Figure 25: 8,500 MW Resource Loss Simulation
60.10
60.05
Blue = Duval (Northern FL)
Green= Turkey Point (Southern FL)
60.00
59.95
Frequency (Hz)
59.90
59.85
59.80
59.75
59.78 Hz
59.76 Hz
59.70
59.65
59.60
Time (seconds)
Although the simulations using the generic governor models are not exact, that analysis is
indicative of the Eastern Interconnection’s ability to sustain a resource loss event significantly
higher than the Resource Contingency Protection Criteria proposed in this report.
Concerns for Future of Frequency Response
There is a growing concern about the future of frequency response in light of a number of
factors:
•
Electronically coupled resources – The incorporation of renewable resources such as
wind and solar and the increasing penetration of variable speed motor drives presents a
continuing erosion of system inertia; all are electronically coupled to the system. As
such, those resources, unless specifically designed to mimic inertial response, do not
have inertial response.
•
Electronically coupled loads – As synchronous motors are replaced by variable speed
drives, the load response of the motors is eliminated by the power electronics of the
motor controller. This reduces the load damping factor for the interconnection.
•
Displacement of traditional turbine-generators in the dispatch – Traditional turbinegenerators are being displaced in the dispatch, particularly during off-peak hours when
wind generation is at its highest and the loads and generation levels are at their lowest.
Frequency Response Initiative Report – October 2012
38
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004136
Historical Frequency Response Analysis
Such displacement of frequency responsive resources increasingly depletes the inertia
of the interconnection at those times.
R ole of I nertia in Frequency R esponse
Inertia plays a crucial role in determining the slope of a frequency decline during a resource loss
event.
The slope of frequency excursion is determined by the inertia of the system and a factor to
account for the load damping characteristics of the interconnection.
Where:
D = Load Damping Factor
The load damping factor ranges from 0 to 2, where 2 would represent a load of
all motors.
H = Inertia Constant of the interconnection
The inertia constant ranges from 2.5 to 6.5
Figure 26 shows the sensitivity of frequency response to changes to system inertia. The lower
green curve represents an inertia constant of 2.5, and the lower red curve represents an inertia
constant of 5.0.
Figure 26: Frequency Response Sensitivity to System Inertia
39
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004137
Historical Frequency Response Analysis
Figure 27 shows an actual example from ERCOT of how frequency response is changed for
similarly sized resource loses with differences in inertia. It is clear that when the inertia on the
system is lower, a similar resource MW loss creates a much steeper and deeper frequency
excursion. This is a good example of the displacement of traditional resources with
electronically coupled resources during light load periods.
Figure 27: Inertial Response Sensitivity
High Inertia
Light Inertia
Need for Higher Speed P rim ary Frequency R esponse
The reduction of inertia drives a need for higher speed response to frequency excursions. If the
slope of the frequency decline is steeper, it is necessary for high-speed injection of energy to
arrest the decline in order to prevent the excursion from being too deep. Such energy injection
can come from a number of sources, such as energy storage devices and wind turbines with
modified inverters.
P reservation or I m provem ent of Existing Generation P rim ary Frequency
R esponse
Additionally, to further ensure strong overall frequency response, it is important to preserve or
improve the primary frequency response of the existing generation fleet. The Role of
Governors section of this report discusses the results of the 2010 survey on generator
governors. The survey results show that there is a significant portion of the existing generator
fleet that has operational governors. However, the reported deadband ranges make those
governors ineffective for all but catastrophic losses of resources. Figure 28 shows the reported
deadband ranges.
Frequency Response Initiative Report – October 2012
40
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004138
Historical Frequency Response Analysis
If the existing generator fleet primary frequency response performance can be improved
through adjustments in deadbands and implementation of no-step droop responses, a
significant improvement in interconnection frequency response could be realized. Further, if all
of the existing generators were made capable of response, any generators that are on-line
during light load periods would be more able to provide response.
Figure 28: Reported Governor Deadband Settings
The Role of Governors section of this report recommends immediate development of a NERC
turbine-generator governor guideline calling for deadbands of ±16.67 mHz with droop settings
of 4%–5% depending on turbine type in order to retain or regain frequency response
capabilities of the existing generator fleet.
W ithdraw al of P rim ary Frequency R esponse
Withdrawal of primary frequency response caused by outer-loop control systems must be
addressed. As shown in the Frequency Response Withdrawal section of this report, frequency
response during light load periods can be highly influenced by the mix of dispatched resources.
Economics of the dispatch dictates that the most efficient, cost-effective generation will remain
on-line during those periods. Such generation employs setpoint controls that return generation
to AGC-prescribed or efficiency-prescribed generation levels regardless of system frequency.
This results in “squelching” of any primary frequency response that the governors may have
provided during a frequency event. This withdrawal of primary response before secondary
frequency response from AGC becomes effective starting at about T+45 to T+60 seconds,
creating the “lazy L” event response prevalent in the Eastern Interconnection.
To illustrate this effect, a dynamic simulation of a 3,700 MW resource loss frequency event was
performed for the Eastern Interconnection using the generic dynamics case described in the
Modeling of Frequency Response in the Eastern Interconnection section of this report. Two
simulation runs were performed to mimic about 1,400 MW/0.1 Hz frequency response
41
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004139
Historical Frequency Response Analysis
(between 20 and 52 seconds), with different combinations of generator dispatch and differing
amounts of response “squelch.” Figure 29 shows that the effects on frequency response
sustainability can be highly influenced by the composition of the resource dispatch, even with
the same measured frequency response.
There are potential ways of alleviating this withdrawal symptom, including introduction of a
frequency bias into the outer-loop controls systems that would prevent withdrawal of primary
frequency response, similar to the frequency bias settings in an automatic generation control
(AGC) system.
Recommendation – NERC should include guidance on methods to reduce or eliminate the
effects of primary frequency response withdrawal by outer-loop unit or plant control systems.
Figure 29: Simulations of Varying Levels of Primary Frequency Response Withdrawal
Eastern Interconnection
3,700 MW Resource Loss
1,400 MW/0.1 Hz Response
Lower
Squelch
59.7 Hz
Higher
Squelch
59.5 Hz
Note that these simulation runs were done for illustrative purposes only; the simulations are
not yet accurate enough to confidently predict system performance, and AGC secondary
frequency response was NOT simulated. Secondary frequency response from AGC becomes
effective starting at about T+45 to T+60 seconds.
Frequency Response Initiative Report – October 2012
42
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004140
Interconnection Frequency Response Obligation (IFRO)
Interconnection Frequency Response Obligation
(IFRO)
Tenets of IFRO
The IFRO is intended to be the minimum amount of frequency response that must be
maintained by an interconnection. Each Balancing Authority in the interconnection should be
allocated a portion of the IFRO that represents its minimum responsibility. In order to be
sustainable, Balancing Authorities that may be susceptible to islanding may need to carry
additional frequency responsive reserves to coordinate with their under-frequency load
shedding (UFLS) plans for islanded operation.
A number of methods to assign the frequency response targets for each interconnection can be
considered. Initially, the following tenets should be applied:
1. A frequency event should not trip the first stage of regionally approved UFLS systems within
the interconnection.
2. Local tripping of first-stage UFLS systems for severe frequency excursions, particularly those
associated with protracted faults or on systems on the edge of an interconnection, may be
unavoidable.
3. Other frequency-sensitive loads or electronically coupled resources may trip during such
frequency events (as is the case for photovoltaic inverters in the Western Interconnection).
4. Other susceptible frequency sensitivities may have to be considered in the future (e.g.,
electronically coupled load common-mode sensitivities).
UFLS is intended to be a safety net to prevent against system collapse from severe
contingencies. Conceptually, that safety net should not be violated for frequency events that
happen on a relatively regular basis. As such, the resource criteria are selected to avoid
violating UFLS settings approved by the Regional Entities.
The Frequency Responsive Reserve Standard Drafting Team (FRRSDT) is proposing an
administered value approach for the BAL-003-1 field trial. Eventually, an agreed-upon method
of determining the interconnection FRO will be included in a reliability standard, or in the NERC
Rules of Procedure. 31
31
http://www.nerc.com/files/NERC_Rules_of_Procedure_EFFECTIVE_20110412.pdf
43
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004141
Interconnection Frequency Response Obligation (IFRO)
Statistical Analyses
Frequency Variation Statistical Analysis
A statistical analysis of the variability of frequency for each of the four interconnections was
performed using 1-second measured frequency for the Eastern, Western, and ERCOT
Interconnections for 2007–2011 (five years). Data for the Québec Interconnection was only
available for 2010 and 2011. Analysis of data showed the Western Interconnection frequency
deviations (Epsilon) to be more volatile since the Balancing Authority ACE Limit (BAAL) field trial
began there in March of 2010. Therefore, it was decided to limit the analysis to the years
2009–2011 to more accurately portray the current frequency characteristics.
This variability accounts for items such as time error correction; variability of load, interchange,
and frequency over the course of a normal day; and other uncertainties, including time error
corrections and all frequency events—no large events were excluded. The results of the
analysis are shown in table 3.
Table 3: Interconnection Frequency Variation Analysis (Hz)
Value
Eastern
Western
ERCOT
Québec
2009–2011
2009–2011
2009–2011
2010–2011
91,283,555
90,446,802
85,924,929
34,494,049
Expected Value
60.0000367
59.9999522
59.9999847
60.00002303
Maximum Value
60.3090
60.3575
62.1669
60.8776
Minimum Value
59.0015
59.7364
58.0000
59.1879
Variance of Frequency
(σ²)
0.00024092
Hz2
0.00022266
Hz2
0.00060749
Hz2
0.00035315
Hz2
σ
0.01552147
0.01492184
0.02464722
0.01879236
2σ
0.03104295
0.02984369
0.04929445
0.03758472
3σ
0.04656442
0.04476553
0.07394167
0.05637708
59.974
59.976
59.963
59.972
Timeframe
Number
32
of Samples
Starting Frequency (FStart)
5% of lower tail samples
32
Numbers of samples vary due to exclusion of data drop-outs and other obvious observation anomalies.
Frequency Response Initiative Report – October 2012
44
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004142
Interconnection Frequency Response Obligation (IFRO)
For each interconnection, the distribution of the interconnection frequency fails the normality
test (both the chi-square goodness-of-fit and the Kolmogorov-Smirnov goodness-of-fit) at any
standard significance level. The combined datasets for the interconnection frequency consist of
very large numbers of observations. For such large samples, the empirical distribution can be
considered as a very good approximation of the actual distribution of the frequency, and was
judged a better predictor than use of standards deviation for predicting the interconnection
starting frequencies for an event. The rate of convergence in the Glivenko-Cantelli theorem is
n(-1/2), where n is the sample size. Therefore, quantiles of the empirical distribution function
can be used directly to calculate intervals where values of frequency belong with any predetermined probability.
Only resource losses (frequency drops) are examined for IFRO calculations, so the focus is on
the one-sided lower tail of the distribution for frequencies that fall outside the upper 95%
interval of the overall distribution. Therefore, the starting frequency that should be used for
the calculation of the IFROs is the 10% quantile frequency value, which represents a 95%
confidence in the prediction for that single tail.
Those starting frequencies encompass all variations in frequency, including changes to the
target frequency during time error correction. That eliminates the need to expressly evaluate
TEC as a variable in the IFRO calculation.
Recommendation – The starting frequency for the calculation of IFROs should be frequency of
the 5% of lower tail of samples from the statistical analysis, representing a 95% confidence that
frequencies will be at or above that value at the start of any frequency event.
45
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004143
Interconnection Frequency Response Obligation (IFRO)
Figures 30–33 show the interconnection histograms broken into 1-mHz “bins.” A complete set
of graphs for the four interconnections is located in Appendix D of this report.
Figure 30: Eastern Interconnection 2009–2011 Frequency Histogram
4.5
4
Percentage of Observations (%)
3.5
3
2.5
2
1.5
1
0.5
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure 31: Western Interconnection 2009–2011 Frequency Histogram
0.035
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Frequency Response Initiative Report – October 2012
46
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004144
Interconnection Frequency Response Obligation (IFRO)
Figure 32: ERCOT Interconnection 2009–2011 Frequency Histogram
0.016
0.014
Percentage of Observations (%)
0.012
0.01
0.008
0.006
0.004
0.002
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Note that the ERCOT frequency histogram displays the influence of the “flat-top” f profile that
was common to that interconnection prior to 2008. That phenomenon was caused by a
standardized ±36 mHz deadband with a step-function implementation. Additional discussion
on that topic is in the ERCOT Experience section of this report.
Figure 33: Québec Interconnection 2010–2011 Frequency Histogram
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
47
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004145
Interconnection Frequency Response Obligation (IFRO)
P oint C Analysis – One-second versus Sub-second Data
Additional statistical analysis was performed for the differences between Point C and Value B
calculated as a ratio of Point C to Value B using 1-second data for events from December 2010
through May 2012. Although the 1-second data sample is robust, it does not necessarily ensure
the nadir of the event was accurately captured. To do so requires sub-second measurements
that can only be provided by PMUs or FDRs. Therefore, a “CC” adjustment component (CCADJ)
for the IFRO calculation was designed to account for the differences observed between the 1second Point C and high-speed Point C measurements.
Table 4: Analysis of One-second and Sub-second Data for Point C (CCADJ)
Number
of
Samples
Mean
Standard
Deviation
CCADJ
(95% Quantile)
Eastern
30
0.0006
0.0038
0.0068
Western
17
0.0012
0.0019
0.0044
ERCOT
58
0.0021
0.0061
0.0121
0
N/A
N/A
N/A
Interconnection
Québec
33
This adjustment should be made to the allowable frequency deviation value before it is
adjusted for the ratio of Point C to Value B. Note: No sub-second data was available for the
Québec Interconnection.
Recommendation – The allowable frequency deviation (starting frequency minus the highest
UFLS step) should be reduced by the CCADJ to account for differences between the 1-second and
sub-second data for Point C as listed in table B-C9.
Adjustm ent for Differences betw een Value B and P oint C
All of the calculations of the IFRO are based on protecting from instantaneous or time-delayed
tripping of the highest step of UFLS, either for the initial nadir (Point C), or for any lower
frequency that might occur during the frequency event. The frequency variance analysis in the
previous section of this report is based on 1-second data from 2007 through 2011 (except
Québec 2010 and 2011 only).
As a practical matter, the ability to measure the tie line and loads for the Balancing Authorities
is limited to system control and data acquisition (SCADA) scan-rate data of 1–6 seconds.
Therefore, the ability to measure frequency response of the Balancing Authorities is still limited
by the SCADA scan rates available to calculate Point B.
33
Sub-second data from Québec was not available.
Frequency Response Initiative Report – October 2012
48
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004146
Interconnection Frequency Response Obligation (IFRO)
Candidate events from the ALR1-12 Interconnection Frequency Response selection process
(Appendix E) for frequency response analysis were used to analyze the relationship between
Value B and Point C for the significant frequency disturbances from December 2010 through
May 2012. This sample set was selected because data was available for the analysis on a
consistent basis. This resulted in the number of events shown in table 5.
Analysis Method
When evaluating some physical systems, the nature of the system and the data resulting from
measurements derived from that system do not fit the standard linear regression methods that
allow for both a slope and an intercept for the regression line. In those cases, it is better to use
a linear regression technique that represents the system correctly.
The Interconnection Frequency Response Obligation is a minimum performance level that must
be met by the Balancing Authorities in an interconnection. Such response is expected to come
from the frequency response in MWs of the Balancing Authorities to a change in frequency. As
such, if there is no change in frequency there should be no change in MWs resulting from
frequency response.
This response is also related to the function of the frequency bias setting in the ACE equation of
the Balancing Authorities for longer term. The ACE equation looks at the difference between
scheduled frequency and actual frequency times the frequency bias setting to estimate the
amount of MWs that are being provided by load and generation within the Balancing Authority.
If the actual frequency is equal to the scheduled frequency, the frequency bias component of
ACE must be zero.
Since the IFRO is ultimately a projection of how the interconnection is expected to respond to
changes in frequency related to a change in MW (resource loss or load loss), there should be no
expectation of frequency response without an attendant change in MW. It is this relationship
that indicates the appropriateness of the use of regression with a forced fit through zero.
Evaluation of data to determine C-to-B ratio:
The evaluation of data to determine C-to-B ratio to account for the differences between
arrested frequency response (to the nadir, Point C) and settled frequency response (Value B) is
also based on a physical representation of the electrical system. Evaluation of this system
requires investigation of the meaning of an intercept. The C-to-B ratio is defined as the
difference between the pre-disturbance frequency and the frequency at the maximum
deviation in post-disturbance frequency, divided by the difference between the pre-disturbance
frequency and the settled post-disturbance frequency.
A stable physical system requires the ratio to be positive; a negative ratio indicates frequency
instability or recovery of frequency greater than the initial deviation.
49
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Interconnection Frequency Response Obligation (IFRO)
004147
Table 5: Analysis of Value B and Point C (CBR)
Number
Standard
CBR
Interconnection
of
Mean
Deviation
(95% Quantile)
Samples
Eastern
41
0.964
0.0149
1.0 (0.989)34
Western
30
1.570
0.0326
1.625
ERCOT
88
1.322
0.0333
1.377
35
Québec
1.550
This statistical analysis was completed using 1-second averaged data that does not accurately
capture Point C and is better measured by high-speed metering (PMUs or FDRs). Therefore, a
separate correction must be used to account for the differences between the Point C in the 1second data and the Point C values measured with sub-second measurements from the FNet
FDRs.
The CBR value for the Eastern Interconnection indicates that the Value B is generally below the
Point C value. Therefore, there is no adjustment necessary for that interconnection.
The Québec Interconnection’s resources are predominantly hydraulic and are operated to
optimize efficiency, typically at about 85% of rated output. Consequently, most generators
have about 15% headroom to supply primary frequency response. This results in a robust
response to most frequency events, exhibited by high rebound rates between Point C and the
calculated B Value. For the 26 frequency events in their event sample, Québec’s CBR value
would be 3.613, or two to three times as high as the CBR value of other interconnections. Using
the same calculation method for CBR would effectively penalize Québec for their outstanding
rebound performance and make their IFRO artificially high. Therefore, the method for
calculating the Québec CBR was modified.
Québec operates with an operating mandate for frequency responsive reserves to protect from
tripping their 58.5 Hz (300 ms trip time) first step UFLS for their largest hazard at all times,
effectively protecting against tripping for Point C frequency excursions. They also protect
against tripping a UFLS step set at 59.0 Hz that has a 20-second time delay, which protects them
for Value B low frequency and any withdrawals. This results in a Point C to Value B ratio of 1.5.
To account for the confidence interval, 0.05 is then added, making the CBR = 1.550.
Adjustm ent for P rim ary Frequency R esponse W ithdraw al
At times, the nadir for a frequency event occurs after Point C—defined in BAL-003-1 as
occurring in the T+0 to T+12 second period, during the Value B averaging period (T+20 through
T+52 seconds), or later. For purposes of this report, that later occurring nadir is termed Point
34
CBR value limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does not need to be adjusted. The
calculated value is 0.989.
35
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 millisecond operating time (responsive to Point C)and 59.0 Hz UFLS step
with a 20 second delay (responsive to Value B or beyond).
Frequency Response Initiative Report – October 2012
50
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004148
Interconnection Frequency Response Obligation (IFRO)
C’. This lower nadir is symptomatic of primary frequency response withdrawal, or squelching,
by unit or plant-level outer-loop control systems. Withdrawal is most prevalent in the Eastern
Interconnection, as described earlier.
As described in the Withdrawal of Primary Frequency Response section of this report,
frequency response withdrawal can become important depending on the type and
characteristics of the generators in the resource dispatch, especially during light load periods.
Therefore, an additional adjustment to the maximum allowable delta frequency for calculating
the IFROs was statistically developed. This adjustment should be used whenever withdrawal is
a prevalent feature of frequency events. Initially, it is only being applied to the Eastern
Interconnection.
Table 6 shows the statistical results of the analysis based on the 34 frequency response events
in the Eastern Interconnection. Note that the expected timeframe for the C’ nadir to occur is
about 82 seconds after the start of the event.
Table 6: Statistical Analysis of the Adjustment for C’ Nadir (BC’ADJ)
Value
Delta Frequency from Value
B to Point C’ Nadir
Seconds from T+0 to C’ Nadir
Number of
Samples
Mean
Standard
Deviation
BC’ADJ
(95% Quantile)
34
4.0 mHz
8.2 mHz
17.5 mHz
34
38.9 s
26.3 s
82.1 s
This BC’ADJ should be applied to the allowable delta frequency after the differences from Value
B to Point C are adjusted. The values driving this adjustment should also be carefully monitored
and the adjustment recalculated during the annual review of IFRO calculations.
Variables in Determination of Interconnection Frequency
Response Obligation from Criteria
To make a determination of the appropriate Resource Contingency Protection Criteria to
protect for a certain kind of event, the MW target value needs to be translated into an
Interconnection Frequency Response Obligation (IFRO) for an appropriate comparison. A
number of other variables must be taken into consideration.
Low Frequency Lim it
The low frequency limit to be used for the IFRO calculations should be the highest setpoint in
the interconnection for regionally approved UFLS systems.
Recommendation – Based on the tenet that UFLS should not trip for a frequency event
throughout the interconnection, the recommended UFLS first-step limitations for IFRO
calculations listed in table 7 should be used.
51
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004149
Interconnection Frequency Response Obligation (IFRO)
Table 7: Low-Frequency Limits (Hz)
Interconnection
Highest UFLS Trip Frequency
Eastern
59.5 36
Western
59.5
ERCOT
59.3
Québec
58.5
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, while the prevalent
highest setpoint in the rest of that interconnection is 59.5 Hz. The FRCC 59.7 Hz first UFLS step
is based on internal stability concerns and preventing the Florida peninsula from separation
from the rest of the interconnection. The FRCC concluded that the IFRO starting point of 59.5
Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation for an interconnection resource loss event than for an internal FRCC event.
Protection against tripping the highest step of UFLS does not ensure that generation that has
frequency-sensitive protection or turbine control systems will not trip. Severe system
conditions might drive the frequency to levels that may present protection and control systems
with a combination of conditions that may cause the generation to trip, such as severe rate of
change in voltage or frequency, which might actuate volts per hertz relays. Similarly, some
combustion turbines may not be able to sustain operation at frequencies below 59.5 Hz.
Recent laboratory testing by Southern California Edison of inverters used on residential and
commercial scale photovoltaic (PV) systems revealed a propensity to trip at about 59.4 Hz,
which is 200 mHz above the expected 59.2 Hz prescribed in IEEE Standard 1547 for distributionconnected PV rating ≤ 30 kW (57.0 Hz for larger installations). This could become problematic
in areas of high penetration of photovoltaic resources.
Credit for Load R esources (CLR )
The ERCOT Interconnection depends on contractually interruptible demand that automatically
trips at 59.7 Hz to help arrest frequency declines. A 1,400 MW Load Resource (formerly Load
acting as a Resource – LaaR) credit is included against the Resource Contingency for the ERCOT
Interconnection. Similarly, there is a remedial action scheme (RAS) in WECC that trips 300 MW
of load for the loss of two Palo Verde generating units.
For the Western Interconnection, if the larger 3,200 MW resource loss activates the RAS and
trips the Pacific DC Intertie (PDCI), the 300 MW credit for Load Resources associated with the
loss of the two Palo Verde units does not apply.
36
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
Frequency Response Initiative Report – October 2012
52
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004150
Interconnection Frequency Response Obligation (IFRO)
For both interconnections, credit for load resources is handled in the calculation of the IFRO as
a reduction to the loss of resources, when appropriate.
Interconnection Resource Contingency Protection Criteria
Selection of discrete event protection criteria for each interconnection must be done before
the IFRO can be calculated. The protection criteria selected should ensure that Point C would
not encroach on the first step UFLS. However, the criteria may need to be different from one
interconnection to the other due to the differences in size and design characteristics.
The following potential interconnection event criteria were considered:
•
largest N-2 loss-of-resource event,
•
largest total generating plant with common voltage switchyard, and
•
largest loss-of-resource event in the interconnection in the last 10 years.
Largest N-2 Event
For this approach, each interconnection will have a target Resource Contingency Protection
Criteria based on the largest N-2 loss-of-resource event. This should not be confused with a
Category C, N-2 event prescribed in the NERC TPL standards; it is intended to reflect a
simultaneous loss of the resources without time for system adjustments. As such, these events
would be considered Category D events in the current standards.
Table 8: Largest N-2 Event
Interconnection
Basis
MW
Eastern
Nelson DC Bi-poles 1 & 2
3,854 37
Western
Two Palo Verde Units
2,740 38
Two South Texas Project Units
2,750 39
ERCOT
For both the ERCOT and Western Interconnections, that would be the loss of the two largest
generating units in the interconnection. However, for the Eastern Interconnection, the largest
N-2 loss-of-resource event would be the loss of the two Nelson dc bi-pole converters.
37
Nelson Bi-poles 1 and 2 are rated 1,854 MW and 2,000 MW, respectively.
38
Net winter ratings per Form EIA-860 reporting.
39
Net rating from ERCOT Resource Asset Registration Form (RARF).
53
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004151
Interconnection Frequency Response Obligation (IFRO)
Largest Total P lant w ith Com m on Voltage Sw itchyard
Another approach is to examine the largest complete generating plant outage in each of the
interconnections, limiting this classification to those generators with a common voltage
switchyard. The reasoning for considering such a protection criteria is that despite popular
belief, complete plant outages can and do happen on a regular basis; 15 complete plant
outages occurred in North America in the 12 months from July 1, 2010 through June 30, 2011.
Table 9: Largest Total Plant with Common Voltage Switchyard
Interconnection
Basis
MW
Eastern
Darlington Units 1-4
3,524 40
Western
3 Palo Verde Units
3,575 41
2 South Texas Project Units
2,750 42
ERCOT
Note that in the Western Interconnection, multi-plant generation tripping by the operation of
the Pacific Northwest remedial action scheme (RAS) results in resource loss of 3,200 MW. That
issue is further discussed in the Special IFRO Considerations section of this report.
Largest R esource Event in Last 10 Years
A third approach is to examine the largest complete resource loss event in the interconnection
over the last 10 years. Although this method yields a reasonable value for the Eastern
Interconnection, the values for the other two interconnections would likely not be sustainable
without activating some UFLS. It also results in a larger resource contingency for the Western
Interconnection than for the Eastern Interconnection. These single events were not
approached in magnitude by any other events in the 10-year period.
Table 10: Largest Resource Contingency Event in Last 10 Years
Interconnection
Basis
MW
Eastern
August 4, 2007
Disturbance 43
4,500
Western
June 14, 2004 Disturbance 44
5,000
ERCOT
May 15, 2003 Disturbance 45
3,400
40
Net winter ratings from the NERC Electricity Supply and Demand.
Net winter ratings per Form EIA-860 reporting.
42
Net rating from ERCOT Resource Asset Registration Form (RARF).
43
The August 4, 2007 frequency excursion was a complex, multi‐faceted event involving nine generators across three states. Of those nine
generators, seven tripped because of turbine control actions, and the others tripped on instability. This was not an N‐1 event.
44
The June 14, 2004 disturbance was a complex series of events thattripped ten generators across the western Interconnection as the result of
a protracted fault. This was not an N‐1 event.
41
Frequency Response Initiative Report – October 2012
54
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004152
Interconnection Frequency Response Obligation (IFRO)
R ecom m ended R esource Contingency P rotection Criteria
Because the philosophy is for the criteria to protect against the largest frequency excursion the
interconnection can withstand, the contingency criteria may vary significantly between the
interconnections. For example, because of its sheer size and generating capacity, the Eastern
Interconnection can withstand a greater loss of resources.
Therefore, a blending of Resource Contingency Protection Criteria is recommended (table 4) for
the determination of IFROs.
Table 11: Recommended Resource Contingency Protection Criteria
Interconnection
Resource Contingency
Basis
MW
Eastern
Largest Resource Event in
Last 10 Years
August 4, 2007
Disturbance
4,500
Western
Largest N-2 Event
2 Palo Verde Units
2,740 46
ERCOT
Largest N-2 Event
2 South Texas Project
Units
2,750 47
Although the size of a resource contingency that can be sustained by an interconnection should
be tested through dynamic simulations, that test can currently be done only for the Western
and ERCOT Interconnections.
Recommendation – Dynamic simulation testing of the Western and ERCOT Resource
Contingency Protection Criteria should be conducted as soon as possible.
Recommendation – Dynamic simulation testing of the Eastern Interconnection Resource
Contingency Protection Criteria should be conducted when the dynamic simulation models of
the interconnection are capable of performing the analysis.
45
The May 15, 2003 disturbance was a complex series of events that tripped six generators due to a protracted fault. This was not an N‐1
event.
46
Net winter ratings per Form EIA-860 reporting.
47
Net rating from ERCOT Resource Asset Registration Form (RARF).
55
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Comparison of Alternative IFRO Calculations
004153
Comparison of Alternative IFRO Calculations
Each of the proposed resource loss criteria alternatives were compared through development
of the corresponding IFROs. The following tables show the calculation of an IFRO for each
alternative for the Eastern, Western, and ERCOT Interconnections. The criterion for the Québec
Interconnection was kept constant throughout.
IFRO Formulae
The following are the formulae that comprise the calculation of the IFROs.
Where:
•
DFBase is the base delta frequency.
•
FStart is the starting frequency determined by the statistical analysis.
•
UFLS is the highest UFLS trip setpoint for the interconnection.
•
CCADJ is the adjustment for the differences between 1-second and sub-second Point C
observations for frequency events. A positive value indicates that the sub-second C
data is lower than the 1-second data.
•
DFCC is the delta frequency adjusted for the differences between 1-second and subsecond Point C observations for frequency events.
•
CBR is the statistically determined ratio of the Point C to Value B.
•
DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.
•
BC’ADJ is the statistically determined adjustment for the event nadir occurring below the
Value B (Eastern Interconnection only) during primary frequency response withdrawal.
•
MDF is the maximum allowable delta frequency.
•
RLPC is the resource loss protection criteria.
•
CLR is the credit for load resources.
Frequency Response Initiative Report – October 2012
56
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004154
Comparison of Alternative IFRO Calculations
•
ARLPC is the adjusted resource loss protection criteria adjusted for the credit for load
resources.
•
IFRO is the interconnection frequency response obligation.
Determination of Maximum Delta Frequencies
Because of the limitation of measurement of the Balancing Authority-level frequency response
performance using Value B, the Interconnection Frequency Obligations must be calculated in
“Value B space.” Protection from tripping UFLS for the interconnections based on Point C (the
nadir defined as occurring between T=0 and T+12 seconds in BAL-003-1), Value B (defined as
occurring from T+20 seconds to T+52 seconds), or any nadir occurring after point C, within
Value B, or after T+52 seconds must be reflected in the maximum allowable delta frequency for
IFRO calculations expressed as a Value B.
Table 12: Determination of Maximum Delta Frequencies
Eastern
Western
ERCOT
Québec
Units
59.974
59.976
59.963
59.972
Hz
Minimum Frequency Limit 59.500 48
59.500
59.300
58.500
Hz
Base Delta Frequency
0.474
0.476
0.663
1.472
Hz
CCADJ
0.007
0.004
0.012
N/A
Hz
Delta Frequency (DFCC)
0.467
0.472
0.651
1.472
Hz
1.000 49
1.625
1.377
1.550 50
Hz
Delta Frequency (DFCBR) 51
0.467
0.291
0.473
0.949
Hz
BC’ADJ
.018
N/A
N/A
N/A
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Starting Frequency
CBR
Table 12 shows the calculation of the maximum allowable delta frequencies for each of the
interconnections. All adjustments to the maximum allowable change in frequency are made to
include:
•
•
adjustments for the differences between 1-second and sub-second Point C observations
for frequency events,
adjustments for the differences between Point C and Value B, and
48
The highest UFLS setpoint in the Eastern Interconnection is 59.7 Hz in FRCC, based on internal stability concerns. The FRCC concluded that
the IFRO starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable in that it imposes no greater risk of UFLS
operation in FRCC for an external resource loss event than for an internal FRCC event.
49
CBR value for the Eastern Interconnection limited to 1.0 because values lower than that indicate the Value B is lower than Point C and does
not need to be adjusted. The calculated value is 0.989.
50
Based on Québec UFLS design between their 58.5 Hz UFLS with 300 ms operating time (responsive to Point C) and 59.0 Hz UFLS step with a
20-second delay (responsive to Value B or beyond).
51
DFCC/CBR
57
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004155
Comparison of Alternative IFRO Calculations
•
adjustments for the event nadir being below the Value B (Eastern Interconnection only)
due to primary frequency response withdrawal.
Recommendation – The determination for the Maximum Delta Frequencies should be
calculated in accordance with the methods embodied in Table 12 – Determination of Maximum
Delta Frequencies.
Largest N-2 Event
Table 13 shows the determination of IFROs based on a resource loss equivalent to the largest
N-2 event in each interconnection. This calculation has been adjusted to include the
recommended adjustment for the differences between Value B and Point C, and for the
differences in measurement of Point C using 1-second and sub-second data.
Table 13: Largest N-2 Event
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
3,854
2,740
2,750
1,700
MW
300
1,400
Credit for LR
52
MW
IFRO 52
-858
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
858
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 53
34.8%
71.2%
48.7%
23.9%
% of Interconnection
Load 54
0.14%
0.56%
0.45%
0.50%
IFRO =
53
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
54
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
58
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004156
Comparison of Alternative IFRO Calculations
Largest Total Plant with Common Voltage Switchyard
Table 14 shows the determination of IFROs based on a resource loss equivalent to the largest
total plant with common voltage switchyard in each interconnection. This calculation has been
adjusted to include the recommended adjustment for the differences between Value B and
Point C, and for the differences in measurement of Point C using 1-second and sub-second data.
Table 14: Largest Total Plant with Common Voltage Switchyard
Starting Frequency
Max. Delta Frequency
Resource Contingency
Protection Criteria
Credit for LR
IFRO 55
Absolute Value of
IFRO
% of Current
Interconnection
Performance 56
% of Interconnection
Load 57
55
Eastern
59.974
0.449
Western
59.976
0.291
ERCOT
59.963
0.473
Québec
59.972
0.949
Units
Hz
Hz
3,524
3,575
2,750
1,700
MW
-785
300
-1,127
1,400
-286
-179
MW
MW/0.1Hz
785
1,127
286
23.9%
MW/0.1Hz
31.8%
95.6%
48.7%
23.9%
0.13%
0.76%
0.45%
0.50%
IFRO =
56
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
57
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
59
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004157
Comparison of Alternative IFRO Calculations
Largest Resource Event in Last 10 Years
Table 15 shows the determination of IFROs based on a resource loss equivalent to the largest
resource event in the last 10 years in each interconnection. This calculation has been adjusted
to include the recommended adjustment for the differences between Value B and Point C, and
for the differences in measurement of Point C using 1-second and sub-second data.
Table 15: Largest Resource Event in Last 10 Years
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
5,000
3,400
1,700
MW
300
1,400
Credit for LR
58
MW
IFRO 58
-1,002
-1,721
-423
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
1,721
423
179
MW/0.1Hz
% of Current
Interconnection
Performance 59
40.6%
146.0%
72.2%
23.9%
% of Interconnection
Load 60
0.17 %
1.16%
0.66%
0.50%
IFRO =
59
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
60
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
Frequency Response Initiative Report – October 2012
60
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004158
Comparison of Alternative IFRO Calculations
Recommended IFROs
Table 16 shows the determination of IFROs based on a resource loss equivalent to the
recommended criteria in each interconnection. This calculation has been adjusted to include
the recommended adjustment for the differences between Value B and Point C, and for the
differences in measurement of Point C using 1-second and sub-second data.
Recommendation – The Interconnection Frequency Response Obligations should be calculated
as shown in Table 16 – Recommended IFROs.
Table 16: Recommended IFROs
Eastern
Western
ERCOT
Québec
Units
Starting Frequency
59.974
59.976
59.963
59.972
Hz
Max. Delta Frequency
0.449
0.291
0.473
0.949
Hz
Resource Contingency
Protection Criteria
4,500
2,740
2,750
1,700
MW
300
1,400
Credit for LR
MW
IFRO 61
-1,002
-840
-286
-179
MW/0.1Hz
Absolute Value of
IFRO
1,002
840
286
179
MW/0.1Hz
% of Current
Interconnection
Performance 62
40.6%
71.2%
48.7%
23.9%
% of Interconnection
Load 63
0.17%
0.56%
0.45%
0.50%
Special IFRO Considerations
The IFRO calculation scenarios for the Western Interconnection do not take into account
intentional tripping of generation during the operation of remedial action schemes (RAS). A key
example is the Pacific Northwest RAS for loss of the Pacific DC Intertie (PDCI), which trips up to
3,200 MW of generation in the Pacific Northwest when the PDCI trips, depending on the
loading of the PDCI. The RAS is intended to avoid system instability, tripping generation,
inserting the Chief Joseph braking resistor (for up to 30 cycles), and other reactive configuration
61
IFRO =
62
Current Interconnection Frequency Response Performance: EI = -2,467 MW / 0.1Hz, WI = -1,179 MW / 0.1Hz, TI = -586 MW / 0.1Hz, and
QI = -750 MW/0.1 Hz.
63
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI winter load = 36,000 MW.
61
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004159
Comparison of Alternative IFRO Calculations
changes. However, because the generation in the Pacific Norwest is some of the most
responsive to frequency deviations in the Western Interconnection, the RAS also blocks
frequency response by a number of generators and Balancing Authorities to avoid overloading
the Pacific AC ties (such as the California–Oregon Interface (COI)).
Frequency events caused by the 3,200 MW generation trips from that RAS have not been
considered historically as candidate events for the Western Interconnection calculation of
frequency bias settings by the Balancing Authorities because of the response blocking.
However, from an interconnection perspective, the frequency of the interconnection still must
be maintained as a whole, regardless of which Balancing Authorities are responding to the
event. This creates a dilemma when calculating an IFRO for the interconnection—the resultant
resource loss is larger than the design loss criteria of two Palo Verde units (2,440 MW). Table
17 shows a comparison of the two resource losses in calculating the IFRO for the Western
Interconnection.
Table 17: Western Interconnection IFRO Comparison
2-PV
PNW RAS
Units
Starting Frequency
59.976
59.976
Hz
Max. Delta Frequency
0.291
0.291
Hz
Resource Contingency Protection Criteria
2,740
3,200
MW
Credit for LR
300
IFRO 64
-840
-1,101
MW/0.1Hz
840
1,101
MW/0.1Hz
71.2 %
93.4 %
0.56 %
0.74 %
Absolute Value of IFRO
% of Current Interconnection Performance
% of Interconnection Load
66
65
MW
Using a 3,200 MW resource loss criterion in the IFRO calculation increases the obligation by 260
MW but is further complicated when that obligation is allocated to the Balancing Authorities in
the interconnection; allocation of FRO to Balancing Authorities whose response is blocked by
the RAS is inappropriate. Therefore, a different FRO allocation would be necessary for that
IFRO.
Recommendation – NERC and the Western Interconnection should analyze the FRO allocation
implications of the Pacific Northwest RAS generation tripping of 3,200 MW.
64
IFRO =
65
Current Interconnection Frequency Response Performance: WI = -1,179 MW / 0.1Hz.
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: WI = 148,895 MW.
66
Frequency Response Initiative Report – October 2012
62
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004160
Comparison of Alternative IFRO Calculations
Comparison of IFRO Calculations
Table 18 shows a comparison of the four criteria analyzed by the TIS, as well as the criteria
recommended by the NERC Resources Subcommittee (RS) in their white paper on frequency
response. The table also compares the IFROs to current levels of frequency response
performance 67 for each of the interconnections. A comparison is also made to IFROs adjusted
to include the recommended adjustment for the differences between Value B and Point C.
Table 18: IFRO Calculation Comparison
Current Interconnection
Frequency Response Performance
Eastern
Western
ERCOT
Québec
Units
-2,467
-1,179
-586
N/A
MW/0.1Hz
Largest N-2 Event
Resource Loss Criteria
3,854
2,740
2,750
1,700
MW
IFRO
-858
-840
-286
-179
MW/0.1Hz
34.8%
71.2%
48.7%
23.9%
0.14%
0.56%
0.45%
0.50%
IFRO as % of Current Performance
IFRO as % of Load
68
Largest Total Plant with Common Voltage Switchyard
Resource Loss Criteria
3,524
3,575
2,750
1,700
MW
IFRO
-785
-1,127
-286
-179
MW/0.1Hz
IFRO as % of Current Performance
31.8%
95.6%
48.7%
23.9%
IFRO as % of Load
0.13%
0.76%
0.45%
0.50%
Largest Resource Event in Last 10 Years
Resource Loss Criteria
4,500
5,000
3,400
1,700
MW
IFRO
-1,002
-1,716
-423
-179
MW/0.1Hz
IFRO as % of Current Performance
40.6%
146.0%
72.2%
23.9%
IFRO as % of Load
0.17%
1.16%
0.66%
0.50%
67
Based on the frequency response performance calculated in the daily CERTS-EPG Automated Reliability Reports for 2011 through August 16,
2011.
68
Interconnection projected Total Internal Demands from the 2010 NERC Long-Term Reliability Assessment: EI = 604,245 MW, WI = 148,895
MW, TI = 63,810 MW, and QI = 20,599 MW.
63
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004161
Comparison of Alternative IFRO Calculations
Table 19 compares the recommended IFROs with those recommended by the Resources
Subcommittee.
Table 19: IFRO Calculation Comparison
Current Interconnection
Frequency Response
Performance
Eastern
Western
ERCOT
Québec
Units
-2,467
-1,179
-586
N/A
MW/0.1Hz
Recommended IFROs
Resource Loss Criteria
4,500
2,740
2,750
1,700
MW
IFRO
-1,692
-838
-286
-417
MW/0.1Hz
IFRO as % of Load
0.28 %
0.56 %
0.45 %
2.03 %
RS Recommendation
Resource Loss Criteria
4,500
2,740
2,750
1,700
MW
Base IFRO
-1,125
-548
-229
-113
MW/0.1Hz
-281
-137
-57
-28
MW/0.1Hz
IFRO
-1,406
-685
-286
-141
MW/0.1Hz
IFRO as % of Load
0.23 %
0.46 %
0.45 %
0.68 %
25 % Margin
Frequency Response Initiative Report – October 2012
64
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004162
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004163
Allocation of IFRO to Balancing Authorities
Allocation of IFRO to Balancing Authorities
The allocation of the IFRO to individual Balancing Authorities in a multi-Balancing Authority
interconnection will be done in accordance with the “Attachment A – BAL-003-1 Frequency
Response and Frequency Bias Setting Supporting Document,” which can be found at:
http://www.nerc.com/docs/standards/sar/Att_A_Freq_Response_Standard_Support_Documen
t_100611.pdf)
The process is paraphrased here for brevity.
Once the IFROs have been calculated by the ERO, the FRO for each Balancing Authority in a
multi-Balancing Authority interconnection is allocated based on the Balancing Authority’s
annual load and annual generation to each Balancing Authority by the following formula:
FROBA = FROInt X
AnnualGenBA + AnnualLoad BA
AnnualGenInt + AnnualLoad Int
Where:
•
Annual GenBA is the total annual “Output of Generating Plants” within the Balancing
Authority Area (BAA), on FERC Form 714, column C of Part II – Schedule 3.
•
Annual LoadBA is total annual load within the BAA, on FERC Form 714, column E of Part II
– Schedule 3.
•
Annual GenInt is the sum of all Annual GenBA values reported in that interconnection.
•
Annual LoadInt is the sum of all Annual LoadBA values reported in that interconnection.
The data used for this calculation is from the most recently filed Form 714. As an example, a
report to NERC in January 2013 would use the Form 714 data filed in 2012, which used data
from 2011. Balancing Authorities that are not FERC-jurisdictional will use the Form 714
instructions to assemble and submit equivalent data to the ERO for use in the FRO allocation
process.
Balancing Authorities that elect to form a Frequency Response Sharing Group (FRSG) will
calculate an FRSG FRO by summing the individual Balancing Authority FROs. Balancing
Authorities that elect to form an FRSG as a means to jointly meet the FRO will calculate their
FRM performance for the FRS Form 1 as follows:
•
calculate a group NIA and measure the group response to all events in the reporting year
on a single FRS Form 1, or
•
jointly submit each Balancing Authority’s Form 1 with a summary spreadsheet that sums
each participant’s individual event performance.
Frequency Response Initiative Report – October 2012
66
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004164
Allocation of IFRO to Balancing Authorities
Balancing Authorities that merge or transfer load or generation are encouraged to notify the
ERO of the change in footprint and corresponding changes in allocation such that the net
obligation to the interconnection remains the same and so that Control Performance Standard
(CPS) limits can be adjusted.
Each Balancing Authority reports its previous year’s Frequency Response Measure (FRM),
frequency bias setting and frequency bias type (fixed or variable) to the ERO each year to allow
the ERO to validate the revised frequency bias settings on FRS Form 1. If the ERO posts the
official list of events after the date specified in the timeline below, Balancing Authorities will be
given 30 days from the date the ERO posts the official list of events to submit FRS Form 1.
Once the ERO reviews the data submitted in FRS Form 1 and FRS Form 2 for all Balancing
Authorities, the ERO will use FRS Form 1 data to post the following information for each
Balancing Authority for the upcoming year:
•
frequency bias setting
•
Frequency Response Obligation (FRO)
A Balancing Authority providing Overlap Regulation will report the historic peak demand and
generation of its combined Balancing Authorities’ areas on FRS Form 1 as described in
Requirement R4 of the BAL-003-1 standard.
67
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
004165
Frequency Response Performance Measurement
Interconnection Process
The process for detection of candidate interconnection frequency events for use in frequency
response metrics is described in the ALR1-12 Metric Event Selection Process contained in
Appendix W. It is paraphrased here for brevity.
Frequency Event Detection, Analysis, and Trending (for M etrics and Analysis)
Interconnection frequency events are detected through a number of systems, including:
•
FNet (Frequency monitoring Network) – FNet is a wide-area power system frequency
measurement system that uses a type of phasor measurement unit (PMU) known as a
Frequency Disturbance Recorder (FDR). FNet is able to measure the power system
frequency, voltage, and angle very accurately at a rate of 10 samplers per second. The
FNet system is currently operated by the Power Information Technology Laboratory at
Virginia Tech and the University of Tennessee, Knoxville. FNet alarms are received by
the NERC Situational Awareness staff and contain an estimate of the size of the resource
or load loss and general location description based on triangulation between FDRs.
•
CERTS–EPG Resource Adequacy Tool Intelligent Alarms – The Electric Power Group
(EPG) operates the Resource Adequacy (RA) tool developed under the auspices of the
Consortium for Electric Reliability Technology Solutions (CERTS). The RA tool uses 1minute frequency and area control error (ACE) SCADA data transmitted to a NERC
central database. The RA tool constantly monitors frequency and produces many Smart
Alarms for a number of frequency change conditions, but most useful for frequency
event detection is the short-term frequency deviation alarm, which indicates when
there has been a significant change in frequency over the last few minutes, typically
indicating a resource loss.
•
CERTS–EPG Frequency Monitoring and Analysis (FMA) Tool – EPG also developed and
operates the FMA tool that allows rapid analysis of frequency events, calculating the A,
B, and C values for a frequency event in accordance with parameters set by the
Frequency Working Group (FWG). Event selection criteria are further discussed in
Appendix E of this report.
Those three systems are used in combination by NERC staff to detect and collect data about
frequency excursions in the four North American interconnections. The size of resource losses
is verified with the Regional Entities for events where FNet estimates of resource loss meet the
following criteria:
•
Eastern: >1,000 MW (60 mHz excursion)
•
Western: >700 MW (80 mHz excursion)
•
ERCOT: >450 MW (100 mHz excursion)
Frequency Response Initiative Report – October 2012
68
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004166
Frequency Response Performance Measurement
Events that are detected and meet the ALR1-12 metric criteria are then considered to be
“candidate events” and are used by NERC to calculate interconnection frequency response
metrics and trends. Those candidate events are also presented to the Frequency Working
Group for consideration to be used as events for calculation of Balancing Authority frequency
response and bias setting calculations in accordance with NERC Standard BAL-003-1.
Ongoing Evaluation
The process for detection of frequency events and the calculation of Values A, B, and C and the
associated interconnection level metrics will undergo constant review in an effort to improve
the process. NERC staff and the Frequency Working Group will perform that review at least
annually.
Recommendation –NERC staff and the Frequency Working Group should annually review the
process for detection of frequency events and the method for calculating A and B Values and
Point C. The associated interconnection frequency event database, methods for calculating
interconnection metrics on risks to reliability, the associated probabilities, and the calculation
of the IFROs using updated data should also undergo review in an effort to improve the
process. Throughout this process, NERC should strive to improve the quality and consistency of
the data measurements.
Balancing Authority Level Measurements
A statistical analysis and evaluation was performed on field trial data with similar sample sizes
to those specified in the draft Standard BAL-003-1 Frequency Response and Frequency Bias
Setting. Field trial data was provided on FRS Form 1 for 2011 for 60 Balancing Authorities on
the Eastern and Western Interconnections; the analysis was not performed for either of the
single Balancing Authority interconnections, (i.e., ERCOT or Québec). Of the 60 Balancing
Authorities that provided data, only 50 provided data of sufficient quality to be used in the
analysis. Balancing Authorities that were excluded provided frequency data that was either
obviously incorrect (i.e., frequency data in hertz instead of change in hertz) or frequency data
that was uncorrelated to the frequency measured in an interconnection.
To protect the confidential nature of the data, the Form 1 data was normalized by dividing the
change in actual net interchange by the Frequency Response Obligation (FRO) for each
Balancing Authority, based on Interconnection Frequency Response Obligations (IFROs) of
-1,215 MW/0.1 Hz and -836 MW/0.1 Hz for the Eastern and Western Interconnections,
respectively.69 This normalization method converts all of the data from the actual frequency
response of the Balancing Authority to a per-unit frequency response value where 1.0 indicates
that the frequency response is exactly equal to the Balancing Authority’s FRO. The process also
required the development of the some of the data that would appear on the equivalent of the
CPS2 Bounds Report under this revised standard. The required data was extracted from FERC
Form 714 reports for the year 2009 and was estimated for those Balancing Authorities that did
69
As recommended by the Project 2007-12 Frequency Response Standards Drafting Team during the May 2012 Frequency Response Technical
Conferences.
69
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004167
Frequency Response Performance Measurement
not submit 714 reports from equivalent data based on other sources. The validity of this
analysis is not dependent upon the accuracy of the FRO estimates. It is only necessary for these
estimates to be close to the actual values for firm conclusions to be drawn from the results and
put the results in the proper context. Once the FROs were estimated for all of the Balancing
Authorities on the Eastern and Western Interconnections, they were transcribed onto the FRS
Form 1 for each Balancing Authority included in the analysis.
Single-Event Com pliance
The question was posed whether or not a Balancing Authority’s compliance with the proposed
BAL-003-1 standard should be measured on each event, through use of the mean, median, or a
regression analysis for a 12-month period. The variability of the measurement of frequency
response for an individual Balancing Authority for an individual disturbance event was
evaluated to determine its suitability for use as a compliance measure. The individual Balancing
Authorities’ performance disturbance events were normalized and plotted for each Balancing
Authority on the Eastern and Western Interconnections.
Figure 34: 2011 Normalized Frequency Response Events by BA Eastern Interconnection
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
32
31
30
29
28
27
26
25
24
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
3
4
2
1
0
-10.0
Balancing Authority
On Figures 34 and 35, events that had a measured Balancing Authority’s frequency response
above its FRO were shown as blue dots, and events that had a measured frequency response
below its FRO were shown as red dots.
Analysis of this data indicates that a single-event-based compliance measure is unsuitable for
compliance evaluation when the data has the large degree of variability shown in the charts in
Appendix 1. Based on the field trial data provided, only three out of 19 Balancing Authorities in
the sample (16%) would be compliant for all events with a standard based on a single event
Frequency Response Initiative Report – October 2012
70
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004168
Frequency Response Performance Measurement
measure on the Western Interconnection. Only one out of 31 Balancing Authorities in the
sample (3%) would be compliant for all events with a standard based on a single-event measure
on the Eastern Interconnection.
Figure 35: 2011 Normalized Frequency Response Events by BA Western Interconnection
10.0
Frequency Response Normalized by FRO
5.0
0.0
-5.0
20
19
18
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
-10.0
Balancing Authority
Finding – Analysis of the field trial data indicates that a single-event-based compliance measure
is unsuitable for compliance evaluation when the data has a large degree of variability.
Recommendation – Balancing Authority compliance with BAL-003-1 should not be judged on a
per-event basis. Doing so would cause almost 90% of the Balancing Authorities to be out of
compliance.
Balancing Authority Frequency Response Performance
Measurement Analysis
Data provided by the Balancing Authorities from the field trial were also analyzed to determine:
1) if the sample size minimum of 20–25 frequency events, as specified for FRM calculation of
the draft BAL-003-1 standard, is sufficient to provide stable measurements results; and 2) which
of the three candidate FRM measurement methods is most appropriate. These analyses were
carried out using the normalized data provided by a number of Balancing Authorities during the
field trial.
71
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
004169
Event Sam ple Size
Previous studies have recommended a sample size sufficient to provide a stable measure of
frequency response of 20–25 events. These previous studies were performed on limited data
and a limited number of Balancing Authorities. The field trial data set is sufficiently large to
allow conclusions to be drawn with respect to that sample size recommendation specified for
FRM calculation in the draft standard.
Review of the full set of graphs (Appendix H) indicates that the outlier problem, as previously
described, did not present itself. There were no Balancing Authorities that had a small degree
of variability in the measured single-event frequency response for most of the events that
contained a few outliers.
The variability appeared similar for all events for each Balancing Authority, which indicates that
the sample size of 20–25 events was sufficient to stabilize the result and eliminate any undue
influence from potential outliers. In those Balancing Authorities with large variations in
measured single-event response, the sample size was large enough that no single outliers
unduly influenced the result. Balancing Authorities with large measurement variation still had
enough samples to mitigate the risk associated with outliers. This demonstrates that the
sample size chosen was sufficient to stabilize all three methods of measuring FRM. Therefore,
it can be concluded that none of the methods are unduly influenced by outliers and the
selection of the measurement method should be based on other factors.
Finding – Analysis of data submitted by the Balancing Authorities during the field trial confirms
that the sample size selected (a minimum of 20–25 frequency events) is sufficient to stabilize
the result and alleviate the perceived problem associated with outliers in the measurement of
Balancing Authority frequency response performance.
M easurem ent M ethods – M edian, M ean, or R egression R esults
All of the normalized data were analyzed using all three candidate methods for measuring FRM.
median – Median is the numerical value separating the higher half of a one-dimensional
sample, a one-dimensional population, or a one-dimensional probability distribution
from the lower half. The median of a finite list of numbers is found by arranging all the
observations from lowest value to highest value and picking the middle one. When the
number of observations is even, there is no single middle value; the median is arbitrarily
defined as the mean of the two middle values.
In a sample of data, or a finite population, there may be no member of the sample
whose value is identical to the median (in the case of an even sample size), and, if there
is such a member, there may be more than one so that the median may not uniquely
identify a sample member. Nonetheless, the value of the median is uniquely
determined with the usual definition. A median is also a central point that minimizes
the arithmetic mean of the absolute deviations. However, a median need not be
Frequency Response Initiative Report – October 2012
72
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004170
Frequency Response Performance Measurement
uniquely defined. Where exactly one median exists, statisticians speak of “the median”
correctly; even when no unique median exists, some statisticians speak of “the median”
informally.
The median can be used as a measure of location when a distribution is skewed, when
end values are not known, or when one requires reduced importance to be attached to
outliers; e.g., because they may be measurement errors. A median-unbiased estimator
minimizes the risk with respect to the absolute-deviation loss function, as observed by
Laplace. 70 For continuous probability distributions, the difference between the median
and the mean is never more than one standard deviation. Calculation of medians is a
popular technique in summary statistics and summarizing statistical data, since it is
simple to understand and easy to calculate. It also gives a measure that is more robust
in the presence of outlier values than the mean.
mean – Mean is the numerical average of a one-dimensional sample, a one-dimensional
population, or a one-dimensional probability distribution. A mean-unbiased estimator
minimizes the risk (expected loss or estimate error) with respect to the squared-error
loss function, as observed by Gauss.71 The mean is more sensitive to outliers for the
very reason that it is a better estimator; it minimizes the squared-error loss function.
linear regression – Linear regression is the linear average of a multi-dimensional
sample, or a multi-dimensional population. A linear regression unbiased estimator
minimizes the risk (expected loss or estimate error) with respect to the squared-error
loss function in multiple dimensions, as observed by Gauss. 72 The linear regression is
also sensitive to outliers for the very reason that it is a better estimator; it minimizes the
squared-error loss function.
Important Considerations
The following issues are important to consider with respect to the selection of the best method
for measuring frequency response.
two-dimensional measurement – Two-dimensional measurement of frequency
response provides the best representation of the change in MWs divided by the change
in frequency and is used to estimate the frequency bias setting, which indicates the
frequency response in MWs provided at actual frequency as compared to scheduled
frequency.
non-linear attribute of frequency response – The non-linear attribute of frequency
response has been demonstrated on all of the North American interconnections and is
an important consideration in the representation of frequency response.
70
An absolute-deviation loss function is used to minimize the risk of estimate error when dealing with uniform distributions. Appendix 3
provides a description of Uniform Distributions and a derivation of the median.
71
A squared-error loss function is used to minimize the risk when dealing with normal (Gaussian) distributions. Appendix 4 provides a
description of normal (Gaussian) distributions and a derivation of the mean.
72
Appendix H provides a derivation of the linear regression.
73
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
004171
single best estimator – A single best estimator of frequency response is a necessary
result for use in compliance evaluation.
linear system – A linear system 73 is assumed in the development of the individual
Frequency Response Obligation for each Balancing Authority on a multiple Balancing
Authority interconnection and is used to distribute the Interconnection Frequency
Response Obligation among the Balancing Authorities on that interconnection. If the
system is non-linear, 74 then it cannot be assumed that the total required
Interconnection Frequency Response Obligation will be achieved when all Balancing
Authorities provide their individual Frequency Response Obligations.
bi-modal distributions – Bi-modal distributions occur whenever a reconfiguration of
Balancing Authorities occurs within a compliance year. Unless the method chosen can
correctly represent bi-modal distributions, reconfigured Balancing Authorities cannot be
effectively measured for compliance.
quality statistics – Quality statistics should be available for use in compliance
evaluation. Frequency response is used to determine compliance with minimum
provision of the Balancing Authority’s obligation for providing its share of frequency
response for the interconnection. When using a measure for compliance, one must
ensure that the measure fairly represents the Balancing Authority’s performance. There
is still a presumption that an indication of non-compliance should not occur due to pure
chance.
reducing influence of noise – Reducing influence of noise in the data is considered an
important attribute in the measurement method. All measurements of frequency
response will be affected by noise in the measurement process.
reducing influence of outliers – Reducing influence of outliers in the data is considered
the most important attribute in the measurement method. All measurements of
frequency response will be affected by true outliers. The risk associated with the
reduction in the influence of outliers is that valid information about the measure is also
lost when an outlier reduction method is used.
ease of calculation and familiar indicators – Ease of calculation and familiar indicators
are important considerations for communication and to promote ease of understanding
by the industry.
Appendix H presents the series of graphs indicating results for each Balancing Authority. Each
graph shows all of the individual data points use to determine the median, mean, and
regression lines.
73
74
A linear system is a system in which the sum of the parts is equal to the whole.
A non-linear system is a system in which the sum of the parts is not equal to the whole.
Frequency Response Initiative Report – October 2012
74
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004172
Frequency Response Performance Measurement
The median line is green, the mean line is blue, and the regression line is red. The value of the
normalized frequency response (vertical axis) where the line intercepts the value of frequency
(horizontal axis) at a value of 0.1 Hz indicates compliance. Values above 1.0 indicate an FRM
above the FRO, and values below 1.0 indicate an FRM below the FRO.
Figure 36 shows an example of a Balancing Authority with a small degree of variability in the
measured frequency response for each individual event.
Figure 36: BA with Small Degree of Variability in Measured Frequency Response
Figure 37 shows an example of a Balancing Authority with a large degree of variability in the
measured frequency response for each individual event.
During the analysis, the graphs appeared to show that the regression provided a higher
estimate of FRM than the median. Consequently, a comparison was made between the FRM as
measured by the median and the FRM as measured by the regression. The results of the
regression analysis demonstrate a performance for all samples that is 0.087% of their FRO
higher than the median’s performance on the Eastern Interconnection and 0.117% of their FRO
higher than the median’s performance on the Western Interconnection. In an unbiased
analysis, one would expect the median and regression to yield the same result. This indicates
there is an unknown statistical bias affecting the results of the analysis.
75
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
004173
Figure 37: BA with Large Degree of Variability in Measured Frequency Response
The bias causing the difference between the median and regression results can be explained by
an attribute of frequency response. As the frequency deviation increases for larger disturbance
events, the frequency response increases, but it does so disproportionately, shown in figure 38.
This attribute of frequency response has been demonstrated in technical papers.75 It has also
been implemented in the variable frequency bias settings used by ERCOT, BPA and BC Hydro.
In simple terms, the regression includes the effect of this non-linear attribute and the median
does not.
The regression accommodates the disproportion on the slope of the regression line. In this
case the effect tends to be upward—ever bigger MWs per increment in size of larger frequency
error. The median is biased against any disproportionate increase in response per increase in
size of frequency error as part of the median’s blindness to outliers. The median will give no
credit for the ever-growing amount of MWs deployed per added increment in size of frequency
error. All the median does is count the number of MW responses regardless of size and, to
represent all the MW responses, choose the one that occurred half-way in the sequence of
decreasingly negative and increasingly positive frequency errors. Therefore, the median
underestimates the FRM because it cannot evaluate the non-linear attribute correctly. It does
not see or notice that attribute at all through its blinders regardless of numerical order or
placement in a sequence. Regression is the only measurement method that captures the nonlinear frequency response correctly.
75
Hoffman, Stephen P., Frequency Response Characteristic Study for ComEd and the Eastern Interconnection, Proceedings of the American
Power Conference, 1997. Kennedy, T., Hoyt, S. M., Abell, C. F., Variable, Non-linear Tie Line Frequency Bias for Interconnected Systems
Control, IEEE Transactions on Power Systems, Vol. 3, No. 3, August 1988.
Frequency Response Initiative Report – October 2012
76
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004174
Frequency Response Performance Measurement
Figure 38: Typical Non-Linear Frequency Response
The advantages of each method of measurement are presented in Table 20 – Median, Mean
and Regression Comparison. The alphabetic key is below.
Table 20: Median, Mean, and Regression Comparison
Attribute
Provides two-dimensional
measurement
Represents non-linear attributes
Provides a single best estimator
(single value)
Is part of a linear system
Represents bi-modal distributions
Quality statistics available
Reducing influence of noise
Reducing influence of outliers
Easy to calculate
Familiar indicator
Currently used as the measure in
BAL-003-1
77
Median
Mean
Regression
A
A
Yes
B
B
Yes
C
Yes
Yes
Yes
Yes
Yes
D
E
Yes (F)
Yes
Yes
Yes
Yes
Yes (J)
Yes
Yes
Yes
Partial (G)
Partial (H)
I
No
No
Yes
No
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Performance Measurement
004175
A. Neither median nor mean can evaluate the two-dimensional nature of frequency
response.
B. Neither median nor mean can capture the non-linear attribute of frequency response.
Both underestimate the typical non-linear frequency response.
C. Median is arbitrarily defined as the average of the two central values when there is an
even number of values in the data set. The decision to further constrain this central
range of values to a single value that is the average of the ends of that range is
unsupported by any mathematical construct. It is only the desire of those looking for
simplicity in the result that supports this singular definition of median.
D. The median fails to provide a valid estimate of frequency response when the
distribution of frequency event responses is bi-modal due to Balancing Authority
reconfiguration or changes in responsibility for control such as partial-period overlap of
supplemental control.
E. The median fails to provide any methods to determine the quality, significance, or
confidence associated with the measure.
F. The median reduces the influence of noise in the data, but that noise reduction comes
with the cost of eliminating the availability of any quality statistics.
G. Linear regression provides a result that weights the data according to the change in
frequency. Since the noise in the data is independent of change in frequency, linear
regression provides a method superior to the mean for reducing the influence of noise
in the resulting estimate of frequency response.
H. Linear regression is less sensitive to outliers and large data errors than the mean.
I. Linear regression is more complex and requires more effort to calculate, but that
additional effort is small when the evaluation process has been automated.
J. Mean is currently used as the measure in the proposed draft BAL-003-1 standard.
After consideration of the mitigating effects of the sample size with respect to outliers, the
linear regression method is the preferred method for calculating the frequency response
Measure (FRM) for Balancing Authorities for compliance with proposed NERC Standard BAL003-1 – Frequency Response.
Recommendation – Linear regression is the method that should be used for calculating
Balancing Authority Frequency Response Measure (FRM) for compliance with Standard BAL003-1 – Frequency Response.
Frequency Response Initiative Report – October 2012
78
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004176
Role of Governors
Role of Governors
Deadband and Droop
Turbine-generator units use turbine speed control systems, called governors, to control shaft
speed by sensing turbine shaft speed deviations and initiating adjustments to the mechanical
input power to the turbine. This control action results in a shaft speed change (increase or
decrease). Since turbine-generators rotate at a variety of speeds, outside the power plant it is
more appropriate to generally relate shaft speed to system frequency and throttle valve
position to generator output power (MW).
The expected response of a turbine-generator’s governor to frequency deviations is often
plotted on what is known as a governor droop characteristic curve or a droop curve. The curve
shows the relationship between the generator output and system frequency. The curve droops
from left to right. Simply stated, as the frequency decreases, the generator’s output will
increase in accordance with its size.
Figure 39: Sample Droop Characteristic Curve
5% Governor Droop
63
Frequency - Hz
62
61
60
59
58
57
0
20
40
60
80
100
Percent Output
Droop settings on governors are necessary to enable multiple generators to operate in parallel
while on governor control while not competing with each other for load changes. Droop is
expressed as a percentage of the frequency change required for a governor to move a unit from
no-load to full-load or from full-load to no-load. Prior to 2004, NERC Operating Policy 1,
Generation Control and Performance, recommended generators with governor control
(typically 10 MW and larger) to have a droop setting of 5% for steam turbine (and 4% for
combustion turbines, although not explicitly stated in the policy). This means that a 3 Hz (5% of
60.00 Hz) change in system frequency is required to move a generator across its full range.
Normally governors respond only to substantial frequency deviations.
Guidelines of the 2004 NERC Operating Policy 1, Generation Control and Performance, section
C, stated:
79
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Role of Governors
004177
1. Governor installation – Generating units with nameplate ratings of 10 MW or greater
should be equipped with governors operational for frequency response unless restricted
by regulatory mandates.
2. Governors free to respond – Governors should be allowed to respond to system
frequency deviation unless there is a temporary operating problem.
3. Governor droop – All turbine-generators equipped with governors should be capable of
providing immediate and sustained response to abnormal frequency excursions.
Governors should provide a 5% droop characteristic. Governors should, at a minimum,
be fully responsive to frequency deviations exceeding ±0.036 Hz (±36 mHz).
4. Governor limits – Turbine control systems that provide adjustable limits to governor
valve movement (valve position limit or equivalent) should not restrict travel more than
necessary to coordinate boiler and turbine response characteristics.
Within the Frequency Response Initiative, NERC is considering modifications to those
parameters based on the recent advances in frequency response performance in ERCOT and
revised governor control parameters.
In 2010, NERC conducted a survey of governor status and settings through Generator Owners
and Generators Operators. The results of that survey are summarized in the Generator
Governor Survey section of this report. A complete set of the summary graphics of the survey
is contained in Appendix K.
ERCOT Experience
The general decline in primary frequency response in all interconnections has prompted
regulatory entities to address the issue. Electric grids such as the one in Texas are especially
sensitive to frequency regulation and response due to their relatively small overall
interconnected capacity compared to the other interconnections. The Texas Regional Entity
(TRE) is actively working on a regional standard for frequency regulation.
Frequency R egulation
Electric grid frequency regulation is attained by the response of the turbine governors to
deviations from nominal synchronous speed, the operation of the boilers-turbine controls in
response to the frequency change, and the actions of the dispatching system.
Frequency regulation success for any given boiler-turbine plant depends on many factors,
primarily:
•
steady state and dynamic stability of the unit
•
load following capability
•
linearization of turbine governor valves’ steam flow characteristics
•
proper calibration and coordination of the boiler and turbine frequency regulation
parameters
Frequency Response Initiative Report – October 2012
80
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004178
Role of Governors
•
proper high and low limiting of the boiler and turbine frequency regulation based on
unit conditions
•
proper dispatching actions to restore the frequency to its normal operating value
Another factor that influences a unit’s capability for frequency regulation is the available boiler
energy storage. The larger the storage, the less the initial pressure drop caused by the quick
opening of the governor valves, and the better the initial unit frequency regulation.
The standard speed regulation setting for the turbine governors of the boiler-turbine
generating units is 5%. This is a ±5% change from rated speed (0.05*3,600 = 180 RPM), which
causes the turbine governor to change its valves’ position demand ±100 percent. It is also
generalized industry practice to add a small deadband (DB) to the calibration of the governor
speed error bias in order to minimize the movement for very small speed deviations. The
selection of the DB affects the fidelity of the regulation, as shown in figure 40.
Figure 40: Regulation versus RPM Deadbands
The regulation curves of figure 40 are for the noted speed regulation at constant pressure.
They are calculated by developing the equation ΔGVD= f (ΔRPM) for each DB, where ΔGVD is
the change in the turbine Governor Valve Demand as a function of the change in RPM.
Knowing the ΔGVD for any given ΔRPM enables the regulation calculation via the equation:
REG (%) = (100 * ∆RPM/ΔGVD)*(100/3,600)
ERCOT Nodal Operating Guides Section 2 has specific requirements for governor deadband
settings. The maximum allowable deadband is ±0.036 Hz, which has been the industry standard
for mechanical “fly-ball” governors on steam turbines for many years. With the development
81
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004179
Role of Governors
of energy markets in the early 2000s, generators with electronic or digital governors began
implementing this same deadband in their primary frequency response implementation.
Unfortunately, the Guides were not clear on how to implement the droop curve at the
deadband. Since the Guides required 5% droop performance, many generators introduced a
“step function” or modified “step” once the deadband was reached in order to achieve near 5%
droop performance outside the deadband.
As can be seen in figure 40, a 2 rpm deadband on a 3,600 rpm turbine is equivalent to +/-0.033
Hz. Based on the corresponding droop (regulation percent) for this deadband, a generator’s
performance to typical frequency deviations during disturbances would be much greater than
5% without some “step” function. These governor settings resulted in an abnormal frequency
profile for the interconnection.
Figure 41: Frequency Profile for March and September 2008
(in 5 mHz bins)
Figure 41 is the ERCOT frequency profile for March and September of 2008. It is clear that the
“flat top” of the profile is centered on the ±0.036 Hz deadband. This flat frequency profile
created significant problems because frequency spent as much time at the governor deadband
points as it did at any point in between. This made it difficult to employ Frequency Regulation
to correct frequency to 60 Hz, and for ERCOT to meet the NERC BAL-001-0 — Real Power
Balancing Control Performance Requirement 1 (aka, CPS1), since ERCOT had an epsilon-1 limit
of 0.030 Hz. The frequency profile also contributed to generator instability at the deadbands
with the implementation of the various “step” functions in the governors.
If generators that had implemented governor step functions were to be electrically separated
from the grid during an islanding event, they would experience extreme instability. This would
be caused by the governor providing excessive frequency response to the island to small
generation load imbalances, resulting in large frequency swings and unit instability.
Frequency Response Initiative Report – October 2012
82
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004180
Role of Governors
The ERCOT Performance Disturbance and Compliance Working Group (PDCWG) became
increasingly concerned about the frequency instability and the realization of the risk of the step
function in the governors (see figure 42). Because of their analysis, a member of the PDCWG
discussed the issues with one large generating facility that was willing to try different deadband
settings along with a specific droop curve implementation. This implementation required a
straight linear curve from the deadband to full range of the governor, eliminating any step
function shown in figure 43.
Figure 42: Frequency Response of 600 MW Unit ±36.0 mHz Deadband and Step Response
150.00
100.00
MW Change
50.00
0.00
-50.00
Step response at
dead-band.
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
After brief testing of a number of different deadbands, a 1-rpm deadband (± 0.01666 Hz) was
chosen. Four turbine governors were set in this manner on November 3, 2008 (about 2,500
MW capacity or 7.5% of the average grid capacity in November).
Figure 43: Frequency Response of 600 MW Unit ±16.67 mHz Deadband and No-Step
Response
150.00
100.00
MW Change
50.00
0.00
-50.00
No Step response at
dead-band
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
83
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004181
Role of Governors
The possibility of leaving the deadband at ±0.036 Hz and just eliminating the stepped droop
response was considered. Analysis showed that the droop performance at 59.900 Hz would be
around 7.72% with a ±0.036 Hz deadband but only 5.97% droop with the ±0.0166 Hz deadband.
That difference increases at 59.950 Hz, with a 17.64% droop performance for the ±0.036 Hz
deadband and a 7.46% droop performance for the ±0.0166 Hz deadband. However, without
the primary frequency response of the lower deadband, the frequency profile would return to
the “flat top” frequency profile spanning the ±0.036 Hz deadbands, which is a less reliable state
(less stable) for the interconnection. Also, with the larger deadband the interconnection or
Balancing Authority may not have been able to meet the minimum frequency response
requirements.
Turbine-Generator P erform ance w ith R educed Deadbands
The general purpose for using governor deadbands is to minimize generator movement due to
frequency regulation. In an interconnection where generators have various deadband settings,
the diversity of settings creates diversity in responses to frequency changes. However, when a
majority of the generators in an interconnection set the deadband the same and with a step
function, the diversity of responses disappears, and frequency will move to the deadband
frequently as demonstrated in the profile in figure 41. When the frequency exceeds the
deadband, all units react with a stepped response simultaneously.
The amount of generator movement expected for a specific set of deadband settings can be
compared by calculating the MW-minute average movement of a hypothetical generator
exposed to actual measured frequency using the different governor settings.
Table 21 compares the movement of two generators with different governor settings: one with
a ±0.036 Hz deadband and droop step function, and one with a ±0.01666 Hz deadband and no
droop step function.
Table 21: Comparison of MW Movement for Response of Different Governor Settings
±0.036 Hz Deadband with
Droop Step Function
±0.01666 Hz Deadband
with
No Droop Step
Function
Percent
Increase
for Smaller
Deadband
2008 Frequency Profile
662,574.0 MW-min.
893,164.2 MW-min.
34.80%
2009 Frequency Profile
446,244.0 MW-min.
692,039.8 MW-min.
55.08%
Using the 2008 1-minute average frequency data, the generator with the lower deadband
would have had 893,164.2 MW-minutes of primary frequency response while the generator
with the larger deadband unit would have had 662,574.0 MW-minutes of primary frequency
response. This is a 34.80% increase in movement for the lower deadband generator.
Frequency Response Initiative Report – October 2012
84
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004182
Role of Governors
However, if the exact same comparison is made for ERCOT frequency data from 2009, where
the new deadbands had an actual impact on frequency, the following observation scan be
made. The lower deadband generator would have had 692,039.8 MW-minutes of primary
frequency response compared to the larger deadband generator with 446,244.0 MW-minutes,
a 55.08% increase in movement for the lower deadband. One observation is that the MWminute movement of the lower deadband generator is only 4.45% higher than the movement
of the larger deadband generator of the previous year (692,039.8 MW-minutes versus
662,574.0 MW-minutes).
Having the lower deadband in service for the entire year greatly reduced the frequency
movement of the interconnection and reduced the primary frequency response movement as
well. The lower deadband generator MW-minute movement decreased 201,124.4 MWminutes, or 22.518%, between 2008 and 2009. This indicates the reduced impact on the
generator movement with the smaller deadband and the non-step governor droop
implementation when the governor becomes active, as compared to the “step”
implementation.
Figure 44: MW-Minute Movement of a 600 MW Unit with 5% Droop
140000
120000
404989.0
2010 MW Response of 0.0166 db
545670.0
2008 MW Response of 0.036 db
25.78% Decrease in MW
movement with
lower deadband.
100000
MW
80000
60000
40000
20000
6
60 0
.0
1
60
.0
60 2
.0
3
60
.0
60 4
.0
5
60
.0
60 6
.0
7
60
.0
8
60
.0
9
60
.1
59
.
59 9
.9
1
59
.9
2
59
.9
59 3
.9
4
59
.9
59 5
.9
6
59
.9
59 7
.9
8
59
.9
9
0
2008 MW Response of 0.036 db
2010 MW Response of 0.0166 db
This benefit is further emphasized by the comparison in Figure 44, which shows the response of
a theoretical 600 MW unit for the 2008 ERCOT frequency profile with a ±0.036 Hz deadband
versus the same unit with a ±0.01666 Hz deadband for the 2010 frequency profile. Using the
lower deadband, there is a savings of 140,641 MW-minutes of regulation movement because
there were a larger number of generators using the ±0.01666 Hz deadband in 2010, which
greatly influenced the frequency profile. Figure 45 shows a comparison of the actual January–
September ERCOT frequency profiles for 2010 and 2008. The profile changed from a flat
response between the ±0.036 Hz deadband to a more normal distribution.
85
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004183
Role of Governors
Figure 45: ERCOT 2010 versus 2008 Frequency Profile (Jan.–Sept.)
Conclusion – The benefits of using the smaller ±0.01666 Hz deadband coupled with a non-step
governor droop implementation results in the following:
•
improved frequency response for small disturbances
•
generators responding more often in smaller increments, saving fuel and wear and tear
on turbines
•
more stable operation when near boundary conditions of deadbands
Recommendation – NERC should embark immediately on the development of a Frequency
Response Resource Guideline to define the performance characteristics expected of those
resources for supporting reliability. That guideline should address appropriate parameters for:
Existing generator fleet – In order to retain or regain frequency response capabilities of the
existing generator fleet, adopt:
deadbands of ±16.67 mHz,
droop settings of 3%-5% depending on turbine type,
continuous, proportional (non-step) implementation of the response,
appropriate operating modes to provide frequency response, and
appropriate outer-loop controls modifications to avoid primary frequency response
withdrawal at a plant level.
Frequency Response Initiative Report – October 2012
86
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004184
Role of Governors
Other frequency-responsive resources – Augment existing generation response with fastacting electronically coupled frequency responsive resources, particularly for the arresting and
rebound periods of a frequency event:
contractual high-speed demand-side response,
wind and photo-voltaic – particularly for over-frequency response,
storage – automatic high-speed energy retrieval and injection, and
variable speed drives – non-critical, short time load reduction.
Generator Governor Survey
On September 9, 2010, NERC issued a Generator Governor Information and Setting Alert (the
alert) recommending that Generator Owners (GOs) and Generator Operators (GOPs) provide
information and settings for turbine governors for all generators rated at 20 MVA or greater, or
plants that aggregate to a total of 75 MVA or greater net rating at the point of interconnection
(i.e., wind farms, PV farms, etc.). The alert was issued as a recommendation to industry, which
requires reporting obligations (as specified in Section 810 of the Rules of Procedures) from
industry to NERC and, subsequently, from NERC to FERC. Balancing Authorities in North
America were the only functional group required to respond to this alert. A copy of the survey
instructions is located in Appendix J of this report.
The survey requested three types of information:
1. policies on installation and maintenance, and testing procedures and testing frequency
for governors;
2. unit-specific characteristics and governor settings; and
3. unit-specific performance information for a recent, single event.
NERC sent the survey instrument and instructions to 799 GOs and 748 GOPs in North America.
Of the 794 GOs that acknowledged receipt of the survey, 749 developed and provided a
response. Of the 743 GOPs that acknowledged receipt of the survey, 721 developed and
provided a response.
Adm inistrative Findings
NERC staff first reviewed the information submitted by the GOs and GOPs. This initial review
led to the following findings from the administration of the survey:
1. There is a wide variety of levels of understanding among GOs and GOPs of the role of
turbine governors in maintaining frequency response, including confusion in
terminology and a lack of understanding of governor control settings. This indicates a
need for education on settings and performance of turbine governors and the
governor’s role in interconnection frequency response.
87
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004185
Role of Governors
Recommendation – NERC should address improving the level of understanding of the
role of turbine governors through seminars and webinars, with educational materials
available to GOs and GOPs on an ongoing basis.
2. There was a significant amount of duplication of reporting. This was mostly due to dual
submittals by entities that are registered both as GOs and as GOPs. NERC staff sought to
eliminate as much duplication as possible. However, eliminating duplication was
difficult when the entities that own and operate a generator differ, yet both submitted
information on the same generator. Hence, there remains some duplication in this
analysis.
Sum m ary of the Survey R esponses
Table 22 summarizes, by interconnection, the aggregate characteristics of the generators
analyzed.
Table 22: Number of Generators as Reported
Interconnection
Total
With Governors
Without Governors
Eastern
4,372 (648.7 GW)
4,217 (630.2 GW)
152 (18.5 GW)
Western
1,560 (171.6 GW)
1,445 (162.9 GW)
114 (8.7 GW)
ERCOT
503 (95.6 GW)
446 (85.6 GW)
53 (9.0 GW)
Totals
6,435 (915.9 GW)
6,110 (878.7 GW)
319 (36.2 GW)
Figures 46–48 summarize the responses on turbine governors for three of the interconnections.
Data for the Québec Interconnection is not summarized in this report. The GOs and GOPs
reported that governors were operational for 95%, 97%, and 99% of the total number of
generating units that were reported as having governors in the Eastern, Western, and Texas
Interconnections, respectively.
Frequency Response Initiative Report – October 2012
88
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004186
Role of Governors
Figure 46: Eastern Interconnection Generator Responses
Figure 47: Western Interconnection Generator Responses
89
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004187
Role of Governors
Figure 48: ERCOT Interconnection Generator Responses
R eported Deadband Settings
The deadband setting of a governor establishes a minimum frequency deviation that must be
exceeded before the governor will act. Frequency deviations that are less than the setting will
not cause the governor to act. Of the information provided by the GOs and GOPs on governor
deadbands, 51%, 63%, and 79% of the number of units in the Eastern, Western, and Texas
Interconnections, respectively, was usable. Figure 49 summarizes the usability of the deadband
data submitted in the survey.
Frequency Response Initiative Report – October 2012
90
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004188
Role of Governors
Figure 49: Usability of Information Provided on Governor Deadbands
Figure 50 summarizes the range of deadband settings reported by generating unit size for all
three interconnections. The simple average, or mean, of the frequency response values
calculated is indicated by the orange dot. A horizontal line inside the green box indicates the
median of these values. The upper and lower boundaries of the box are the inter-quartile
range, which is the range that contains half the calculated frequency response values. Finally,
the end points of the upper and lower vertical lines indicate the lowest and highest calculated
frequency response values, respectively.
The use of these descriptive statistics provides additional information on the distribution of
values. For example, if the average is lower than the median, it means that the distribution has
a small number of low values compared to the main body of values. Similarly, the height of the
inter-quartile range (the top and bottom of the box) provides a measure of how widely the
values are distributed. The location of the median within the box indicates whether values are
evenly distributed on either side of the median (when the median is close to the center of the
box) or whether values are disproportionately on one or the other side of the median (when
the median is closer to the top or the bottom of the box).
91
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004189
Role of Governors
Figure 50: Reported Governor Deadband Settings
Figure 50 indicates:
•
Eastern Interconnection – Half of the deadband settings are between 0 and 100 mHz,
with the smallest generating units having the lowest settings, followed by the mid-size,
and then the largest units. The figure also indicates that there are a number of units in
all size ranges with very high deadband settings (> 200 mHz).
•
Western Interconnection – Half of the deadband settings are between 0 and 50 mHz for
the smallest and mid-size generating units. However, the range is considerably broader
for the largest units, with half of the settings lying between 0 and more than 300 mHz.
The very large deadbands on units greater than 1,000 MW are attributable to the
nuclear units.
•
Texas Interconnection – The deadband settings are generally less than 50 mHz. There
appears to be at least one very high deadband setting for a small generating unit.
R eported Droop Settings
Governor droop expresses the effect of changes in generating unit speed in terms of changes in
power output as a function of the amount of frequency deviation from the reference
frequency. Of the information provided by the GOs and GOPs on governor droop settings, 89%,
94%, and 87% of the number of units in the Eastern, Western, and Texas Interconnections,
respectively, was usable.
Figure 51 summarizes the range of governor droop settings for the interconnections. Generally,
the droop settings were in the range of expected values.
Frequency Response Initiative Report – October 2012
92
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004190
Role of Governors
Figure 51: Range of Governor Droop Settings by Generating Unit Size
10
9
Droop Setting (%)
8
7
6
5
4
3
2
1
0
<500 MW
500-1000
MW
East
>1000 MW
<500 MW
500-1000
MW
>1000 MW
<500 MW
500-1000
MW
West
>1000 MW
Texas
Unit Size
Governor Status and Operational P aram eters
A number of the survey questions addressed the operational status and parameters of the
governor fleet. As shown in Figure 52, the vast majority of the GOs and GOPs reported that
their governors are operational.
Figure 53 shows that the governors also were reported to be able to sustain primary frequency
response for longer than 1 minute if the frequency remains outside of its deadband. However,
as shown in Figure 54, roughly half of the governors are expected to be overridden or limited by
plant-level control schemes. This factor heavily influences the sustainability of primary
frequency response, contributing to the withdrawal symptom often observed in the Eastern
Interconnection, especially during light load periods.
Figure 52: Operational Status of Governors
Western
Eastern
ERCOT
93
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004191
Role of Governors
Figure 53: Response Sustainable for More Than 1 Minute if Outside Deadband
Western
Eastern
ERCOT
Figure 54: Unit-Level or Plant-Level Control Schemes that Override
or Limit Governor Performance
Western
Eastern
ERCOT
R esponse to Selected Frequency Events
The GOs and GOPs were asked to provide information on the performance of turbine governors
during a selected event in each interconnection. Table 23 lists the date and time of the events
selected for the Eastern, Western, and Texas Interconnections (data was not requested from
the Québec Interconnection).
Frequency Response Initiative Report – October 2012
94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004192
Role of Governors
Table 23: Selected Events for Provision of
Generator Governor Performance Information
Interconnection
Basis
Frequency
Eastern
8/16/2010
1:06:15 CST
1,200 MW
Western
8/12/2010
14:44:03 CST
1,260 MW
ERCOT
8/20/2010
14:25:29 CST
1,320 MW
Of the interconnections’ total generating capacity, 64%, 58%, and 75% of the units were on-line
at the time of the event for the Eastern, Western, and Texas Interconnections, respectively.
Figure 55: Governor Response by Total Generating Capacity On-Line
Figure 55 shows:
•
Of the total generating capacity on-line, 30%, 44%, and 53% reported responding in the
expected direction of response (i.e., to correct the change in frequency) for the Eastern,
Western, and Texas Interconnections, respectively.
•
Some generation reported no response to the frequency deviations (38%, 35%, and 13%
for the Eastern, Western, and Texas Interconnections, respectively).
•
Notably, 19%, 17%, and 20% were reported as responding in the opposite direction of
the expected response (i.e., not in opposition to the change in frequency) for the
Eastern, Western, and Texas Interconnections, respectively.
The values reported for the Eastern Interconnection for capacity providing expected response
are in keeping with those calculated from the generic governor simulation of the frequency
response to the August 4, 2007 Eastern Interconnection Frequency Disturbance. Those
simulations showed that 30% of the capacity on-line responded, and 20% of the capacity online withdrew primary support, leaving only 10% of the capacity on-line providing sustained
primary frequency response.
95
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004193
Role of Governors
Figure 56 shows that for the Eastern Interconnection, total response in the expected direction
was 973 MW, while response in the direction opposite expectations was -361 MW, for a total
net response of 613 MW. Steam coal and combined-cycle gas turbine units, accounting for 327
MW and 244 MW of the net response, respectively, made the largest contributions. These
contributions were made by steam coal and combine-cycle with a total on-line generating
capacity of about 180 GW steam coal and about 60 GW combined-cycle gas turbine units, of
which about 80 GW and about 10 GW of capacity provided response in the expected direction,
respectively.
Figure 56: Eastern Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Expected
Response
Opposite of
Expected
Response
Net Response
Steam Coal
541
-214*
327
Steam Gas
55
-27
28
9
-21
-12
290
-47
244
Steam nuclear
Combined cycle gas
Hydro
36
-5
30
Remaining
42
-47
-5
973
-361
613
Sub-Total
* Excludes the impact of one outlier unit with -101 MW response
Frequency Response Initiative Report – October 2012
96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004194
Role of Governors
Figure 57 shows that for the Western Interconnection, total response in the expected direction
was 1040 MW, while response in the direction opposite expectations was -180 MW, for a total
net response of 860 MW. Hydro units, accounting for 727 MW of the net response, made the
largest contribution. Hydro units made this contribution with a total on-line generating
capacity of about 50 GW, of which about 19 GW of capacity provided response in the expected
direction.
Figure 57: Western Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Opposite of
Expected
Response
Net
Response
Steam Coal
85
-35
50
Steam Gas
32
0
32
1
-7
-6
Combined cycle gas
144
-74
70
Hydro
742
-15
727
37
-49
-12
1040
-180
860
Steam nuclear
Remaining
Sub-Totals
97
Expected
Response
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004195
Role of Governors
Figure 58 shows that for the ERCOT Interconnection, total response in the expected direction
was 896 MW, while response in the direction opposite expectations was -50 MW, for a total net
response of 845 MW. Steam gas units, accounting for 490 MW of the net response, made the
largest contribution. Steam gas units made this contribution with a total on-line generating
capacity of about 11 GW, of which ~10 GW of capacity provided response in the expected
direction.
Figure 58: ERCOT Interconnection Generator Governor Performance
Net Response Summary (MW)
Prime Mover Type
Expected
Response
Opposite of
Expected
Response
Net
Response
Steam Coal
137
-16
121
Steam Gas
490
0
490
Steam nuclear
Combined cycle gas
Hydro
Remaining
Sub-Total
Frequency Response Initiative Report – October 2012
0
0
0
197
-33
164
7
0
7
65
-1
63
896
-50
845
98
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004196
Future Analysis Work Recommendations
Future Analysis Work Recommendations
Testing of Eastern Interconnection Maximum Allowable
Frequency Deviations
The stability simulation testing of the Eastern Interconnection resource loss criteria used in the
determination of the IFRO was limited to analysis using the generic governor stability case
developed by the NERC Model Validation Working Group and the Eastern Interconnection
Reliability Assessment Group (ERAG) Multi-Regional Modeling Working Group (MMWG) in
December 2011 (based on the August 4, 2007 Eastern Interconnection Frequency Disturbance).
Simulations using that stability simulation indicated a maximum sustainable generation loss of
about 8,500 MW for the Eastern Interconnection. However, that simulation case was not for
the light load conditions where system inertia and load response would be expected to be
lower than in the generic case.
Recommendation – Dynamic simulation testing of the Western and ERCOT Resource
Contingency Protection Criteria should be conducted as soon as possible.
Recommendation – When ERAG MMWG completes its review of turbine governor modeling, a
new light-load case should be developed, and the resource loss criterion for the Eastern
Interconnection’s IFRO should be re-simulated.
Eastern Interconnection Inter-area Oscillations – Potential for
Large Resource Losses
During the spring of 2012, a number of inter-area oscillations were observed between the
upper Midwest and the New England/New Brunswick areas in the 0.25 Hz family. During one
such event, a large generation outage in Georgia instigated that oscillation mode and was
interpreted by the FNet frequency monitoring and event detection program as an 1,800 MW
resource loss in the upper Midwest. Immediately, the FNet Oscillation Monitoring system
detected the 0.025 Hz family oscillations between the upper Midwest and New England/New
Brunswick. Investigation into the event showed that it occurred while the Dorsey – Forbes 500
kV transmission line was out of service for maintenance. During that line outage, the transfers
on the Dorsey DC line from Northern Manitoba were significantly curtailed, and the oscillation
of the Dorsey DC terminal capabilities for damping the 0.025 Hz oscillations were greatly
reduced. This made the system more susceptible to such oscillations. In all instances, the
energy magnitude under the oscillations was small, well-damped, and of little danger to the
reliability of the Eastern Interconnection.
However, the instigation of those oscillations by a generator trip in Georgia seemed unlikely
until reviewed in light of the inter-area oscillations detected following the South Florida
disturbance of February 26, 2008. During that disturbance, a family of 0.22 Hz oscillations was
detected between the Southeast and the upper Midwest. In both cases, the same generation
99
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Future Analysis Work Recommendations
004197
in the upper Midwest has a strong participation in both mode shapes, and since both oscillation
modes are close in frequency, the 0.25 Hz family was easily perturbed by an instance of the
0.22 Hz mode oscillations caused by the Georgia generator tripping.
Recommendation – Eastern Interconnection inter-area oscillatory behavior should be further
investigated by NERC, including during the testing of large resource loss analysis for IFRO
validation.
Frequency Response Initiative Report – October 2012
100
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004198
Appendices – Table of Contents
Appendices Table of Contents
Appendix A – Contributors
Appendix B – Abbreviations
Appendix C – Definitions and Terminology
Appendix D – Interconnection Frequency Deviation Duration Plots
Appendix E – ALR1-12 Metric Event Selection Process
Appendix F – Procedure for ERO Support of Frequency Response and Frequency Bias
Setting Standard (BAL-003-1)
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Statistical Analysis of Frequency Response
Appendix H – Frequency Response Field Trial Analysis Graphs
Appendix I – Derivation of the Median, Mean, and Linear Regression
Appendix J – Generator Governor Survey Instructions
Appendix K – Generator Governor Survey Summary
Appendix L – References
Frequency Response Initiative Report – October 2012
ii
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004199
Appendix A – Contributors
Appendix A – Contributors
Principal – Robert W. Cummings – Director of Reliability Initiatives and System Analysis, NERC
Gregory P. Henry – Performance and Analysis Engineer, NERC
Eric H. Allen – Senior Performance and Analysis Engineer, NERC
Neil Burbure – Engineer of Reliability Initiatives and System Analysis, NERC
Matthew Varghese – Senior Performance Analysis Engineer, NERC
Svetlana Ekisheva – Senior Statistician, NERC
Stacey Tyrewala – Attorney, NERC
Mark G. Lauby – Vice President and Director of Standards, NERC
Howard F. Illian1 – President, Energy Mark, Inc.
John Undrill1 – John Undrill, LLC
Carlos A. Martinez1 – Advanced Systems Researchers (ASR)
Sydney L. Niemeyer – Control System Specialist, NRG Texas LP
Joseph H. Eto1 – Staff Scientist, Ernest Orlando Lawrence Berkeley National Laboratory,
Environmental Energy Technologies Division
NERC Frequency Response Standard Drafting Team
NERC Frequency Working Group
NERC Resources Subcommittee
NERC System Analysis and Modeling Subcommittee (formerly the Transmission Issues
Subcommittee)
1
Participation made possible through funding provided by the U.S. Department of Energy Office of Electricity and Energy Reliability,
coordinated through the Lawrence Berkeley National Laboratory.
A‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004200
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004201
Appendix B – Abbreviations
Appendix B – Abbreviations
ACE
ADF
AGC
ALR
ARLPC
BA
BAA
CERTS
CPS
Area Control Error
Adjusted Delta Frequency
Automatic Generator Control
Acceptable Level of Reliability
Adjusted resource loss protection criteria adjusted for the credit for load resources
Balancing Authority
Balancing Authority Area
Consortium for Electric Reliability Technology Solutions
Control Performance Standard
Ratio of the Point C to Value B to adjust the allowable delta frequency to account for
CBR
that difference.
Adjustment to Point C for the differences between 1‐second and sub‐second
CCADJ
measurements
COI
California‐Oregon Interface (ac)
D
Load damping factor
dc
Direct current
DCS
Disturbance Control Standard
DFBase
Base delta frequency
DFCC
Delta frequency adjusted for the differences between 1‐second and sub‐second Point
C observations for frequency events
EMS
Energy Management System
EPG
Electric Power Group
ERAG
Eastern Interconnection Reliability Assessment Group
ERCOT Electric Reliability Council of Texas
ERO
Electric Reliability Organization
FStart
Starting Frequency
FERC
The U.S. Federal Energy Regulatory Commission
FDR
Frequency Disturbance Recorder
FMA
Frequency Monitoring and Analysis tool
FNet
Frequency Monitoring Network (University of Tennessee, Knoxville, and Virginia
Tech)
FRC
Frequency Response Characteristic
FRCC
Florida Reliability Coordinating Council
FRM
Frequency Response Measure
FRO
Frequency Response Obligation (FROBA)
FRRSDT Frequency Response Standard Drafting Team
B‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004202
Appendix B – Definitions and Terminology
FR
FRS
FRSG
FWG
GOs
GOPs
GVD
GW
H
Hz
IFRO
LaaR
LBNL
mHz
MMWG
MVA
MW
N‐1
N‐2
NIA
NIS
PAS
PDCI
PDCWG
PMU
PV
RA
RARF
RAS
RLPC
RPM
RC
SAMS
SCADA
SEFRD
SEFRD
TIS
TRE
Frequency Response
Frequency Response Standard
Frequency Response Sharing Group
Frequency Working Group
Generator Owners
Generator Operators
Governor Valve Demand
gigawatts (thousands of megawatts)
Inertial constant (of the interconnection)
hertz (cycles per second)
Interconnection Frequency Response Obligation (FROInt)
Load Acting as a Resource
Ernest Orlando Lawrence Berkeley National Laboratory
millihertz
Multi‐Regional Modeling Working Group
megavoltampere
megawatts
Loss of one system element
Loss of two system elements
Net Interchange Actual
Net Interchange Scheduled
Performance Analysis Subcommittee
Pacific Direct Current Intertie
Performance Disturbance and Compliance Working Group (ERCOT)
Phasor Measurement Unit
Photovoltaic
Resource Adequacy Tool
ERCOT Resource Asset Registration Form
Remedial Action Scheme (also known as a Special Protection Scheme – SPS)
Resource Loss Protection Criteria
Revolutions per Minute
Resources Subcommittee
System Analysis and Modeling Subcommittee (formerly TIS)
System Control and Data Acquisition
Single Event Frequency Response Data
Single Event Frequency Response Data
Transmission Issues Subcommittee (now SAMS)
Texas Regional Entity
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004203
Appendix B – Abbreviations
UFLS
B‐3
Under‐Frequency Load Shedding
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004204
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004205
Appendix C – Definitions and Terminology
Appendix C – Definitions and Terminology
Definitions used in Standard BAL-003-1
Frequency Response Measure (FRM)
The median of all the Frequency Response observations reported annually by Balancing
Authorities or Frequency Response Sharing Groups for frequency events specified by the
ERO. This will be calculated as MW/0.1Hz.
Frequency Response Obligation (FRO)
The Balancing Authority’s share of the required Frequency Response needed for the
reliable operation of an Interconnection. This will be calculated as MW/0.1Hz.
Frequency Bias Setting
A number, either fixed or variable, usually expressed in MW/0.1 Hz, included in a
Balancing Authority’s Area Control Error equation to account for the Balancing
Authority’s inverse Frequency Response contribution to the interconnection, and
discourage response withdrawal through secondary control systems.
Frequency Response Sharing Group (FRSG)
Groups, whose members consist of two or more Balancing Authorities, that collectively
maintain, allocate, and supply operating resources required to jointly meet the sum of
the Frequency Response Obligations of its members.
Area Control Error (ACE)*: The instantaneous difference between a Balancing Authority’s net
actual and scheduled interchange, taking into account the effects of Frequency Bias and
correction for meter error.
Arrested Frequency – Value C – Point C – Frequency Nadir: The point of maximum frequency
excursion in the first swing of the frequency excursion between time zero (Point A) and
time zero plus 20 seconds.
Arresting Period: The period of time from time zero (Point A) to the time of Point C.
Arresting Period Frequency Response: A combination of load damping and the initial Primary
Control Response acting together to limit the duration and magnitude of frequency
change during the Arresting Period.
Automatic Generation Control (AGC)*: Equipment that automatically adjusts generation in a
Balancing Authority Area from a central location to maintain the Balancing Authority’s
C‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004206
Appendix B – Definitions and Terminology
interchange schedule plus Frequency Bias. AGC may also accommodate automatic
inadvertent payback and time error correction.
Balancing Authority (BA)*: The responsible entity that integrates resource plans ahead of time,
maintains load‐interchange‐generation balance within a Balancing Authority Area, and
supports interconnection frequency in real time.
Beta: The factor by which the frequency deviation is multiplied by in the ACE equation to
adjust the ACE to protect a BA’s Frequency Response.
Contingency Protection Criteria of an interconnection: The selected capacity contingency that
an interconnection must withstand at all times without the activation of the first tier of
UFLS.
Contingency Reserve*: The provision of capacity deployed by the Balancing Authority to meet
the Disturbance Control Standard (DCS) and other NERC and Regional Reliability
Organization contingency requirements.
Frequency ¡: The rate at which a repeating waveform repeats itself. Frequency is measured in
cycles per second or in hertz (Hz). The symbol is “F.”
Frequency Bias Setting: The term of the ACE equation that is multiplied by frequency deviation
portion. This is a corrective term to offset the tie‐line flow error caused by
generation/load responding to a frequency deviation.
Frequency Deviation*: A change in interconnection frequency.
Frequency Response*: (Equipment) The ability of a system or elements of the system to react
or respond to a change in system frequency. (System) The sum of the change in
demand, plus the change in generation, divided by the change in frequency, expressed
in megawatts per 0.1 hertz (MW/0.1 Hz).
Frequency Responsive Reserve (a.k.a., dynamic headroom): The capacity of Governor
Response and/or Frequency‐Responsive Demand Response that will be deployed for any
frequency excursion.
Frequency‐Responsive Demand Response: Voluntary load shedding that complements
governor response. This load reduction is typically triggered by relays that are activated
by frequency.
Frequency Sensitive Load: Customer loads that vary directly with changes in frequency or
would trip as a result of frequency deviations.
Governor response§: The control response of turbine‐governors to sensing a change in speed
of the turbine as frequency increases or declines, causing an adjustment to the energy
input of the turbine’s prime mover.
Headroom: The difference between the current operating point of a generator and its
maximum operating capability.
Inertia¡: The property of an object that resists changes to the motion of an object. For example,
the inertia of a rotating object resists changes to the object’s speed of rotation. The
inertia of a rotating object is a function of its mass, diameter, and speed of rotation.
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004207
Appendix C – Definitions and Terminology
Load damping¥: The damping effect of the load to a change in frequency due to the physical
aspects of the load such as the inertia of motors and the physical load to which they are
connected.
Load following¡: Commitment of energy based resources (generation or energy schedule) to
match the forecast load level for a given period. This is a form of course control for
moment‐by‐moment resource/load matching.
Non‐spinning reserve*: 1. That generating reserve not connected to the system but capable of
serving demand within a specified time. 2. Interruptible load that can be removed from
the system in a specified time.
Off‐line Reserve§: The off‐line capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection.
On‐line Reserve§: The on‐line capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection. This can consist of spinning reserve and interruptible load that can act
as a resource.
Operating Reserve*: That capability above firm system demand required to provide for
regulation, load forecasting error, equipment forced and scheduled outages, and local
area protection. It consists of spinning and non‐spinning reserves.
Other On‐line Reserves§: On‐line Resources that can increase their output or connected loads
that can decrease their consumption (curtailable loads) in time frames outside the
continuum of regulating or spinning reserve (i.e. on four hours’ notice).
Other Off‐line Reserves§: Resources that can be brought to bear outside the continuum of
non‐spinning reserve (i.e., on four hours’ notice).
Plant secondary control@: Secondary control refers to controls affected through commands to
a turbine controller issued by external entities not necessarily working in concert with
frequency management objectives. It is common for a modern power plant to have
several distinct modes of secondary control implemented within the plant and to be
able to accept secondary control inputs from sources external to the plant.
Primary Control Response Withdrawal: The withdrawal of previously delivered Primary
Control Response, through plant secondary controls.
Primary Frequency Control Response: The power delivered to the interconnection in response
to a frequency deviation through generator governor response, load response (typically
from motors), demand response (designed to arrest frequency excursions), and other
devices that provide an immediate response to frequency based on local (device‐level)
control systems, without human or remote intervention.
Primary Frequency Control Reserves: Frequency‐responsive reserves that respond nearly
instantaneously (starting in less than 1 second) to oppose any changes in power system
frequency.
C‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004208
Appendix B – Definitions and Terminology
Quick Start Reserve: A form of non‐spinning reserve that can be put on‐line and the capacity
that can be deployed in ten minutes.
Recovery Period: The period of time from when Secondary Control Response are deployed
(typically about zero plus 53 seconds) to the time of the return of frequency to within
pre‐established ranges of reliable continuous operation.
Regulation¥: Controllable resources necessary to provide for the continuous balancing of
resources (generation and interchange) with load and for maintaining scheduled
interchange and interconnection scheduled frequency. Regulation is accomplished by
committing on‐line generation whose output is raised or lowered (predominantly
through the use of automatic generating control equipment) as necessary to follow the
moment‐by‐moment changes actual net interchange.
Regulating reserve*: An amount of reserve responsive to Automatic Generation Control, which
is sufficient to provide a normal regulating margin.
Settling frequency¥, #: Refers to the third key event during a disturbance when the frequency
stabilizes following a frequency excursion. Point B represents the interconnected system
frequency at the point immediately after the frequency stabilizes due to governor action
but before the contingent control area takes corrective AGC action.
Secondary Control Response: The power delivered by a Balancing Authority or Reserve Sharing
Group in response to a frequency deviation through Secondary Control actions, such as
manual or automated dispatch from a centralized control system. Secondary control
actions are intended to restore Primary Control Response and restore frequency from
the Arrested Frequency back to Scheduled Frequency, or maintain Scheduled
Frequency.
Secondary Frequency Control: Actions provided by an individual BA or its Reserve Sharing
Group intended to restore Primary Control Response and restore frequency from the
Arrested Frequency back to Scheduled Frequency, or to maintain Scheduled Frequency
deployed in the “minutes” time frame. Secondary Control comes from either manual or
automated dispatch from a centralized control system. Secondary Control also includes
initial reserve deployment for disturbances and maintains the minute‐to‐minute balance
throughout the day and is used to restore frequency to normal following a disturbance
and is provided by both spinning and non‐spinning reserves.
Secondary Frequency Control Reserves: Frequency‐responsive reserves that respond over
slightly longer time frames (starting in 20‐30 seconds). Following the sudden loss of
generation, they assist in restoring frequency to the scheduled value after Primary
Frequency Control Reserves have been deployed. They also safeguard Primary
Frequency Control Reserves (so that primary reserves remain available to respond to
these sudden events) by controlling frequency in response to slower imbalances that
arise between electricity demand and generation such as the normal rise and fall of
system load over the course of a day.
Spinning reserve*: Unloaded generation that is synchronized and ready to serve additional
demand.
Frequency Response Initiative Report – October 2012
D‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004209
Appendix C – Definitions and Terminology
Tertiary frequency control§: Encompasses actions taken to get resources in place to handle
current and future changes in load or contingencies. Reserve deployment and Reserve
restoration following a disturbance is a common type of Tertiary frequency control.
Under‐frequency load shedding¡: The tripping of customer load based on magnitudes of
system frequency. For example, a utility may dump 5% of their connected load if
frequency falls below 59.3 Hz, dump an additional 10% if frequency falls below 58.9 Hz,
and dump a final 10% if frequency falls below 58.5 Hz. These three steps of load
shedding would form this utility’s UFLS plan. The purpose of UFLS is a final effort (safety
net) to arrest a frequency decline.
Sources:
* NERC Glossary of Terms Used in Reliability Standards,
http://www.nerc.com/files/Glossary_of_Terms.pdf
¥
NERC Reference Document Understand and Calculating Frequency Response (June 19, 2008)
§
NERC Balancing and Frequency Control (July 5, 2009)
#
NERC Frequency Response Characteristic Survey Training Document,
http://www.nerc.com/docs/standards/sar/opman_12‐
13Mar08_FrequencyResponseCharacteristicSurveyTrainingDocument.pdf (January 1, 1989)
@
Undrill, J.M. 2010. Power and Frequency Control as it Relates to Wind‐Powered Generation.
LBNL‐4143E. Berkeley: Lawrence Berkeley National Laboratory
¡
Definitions taken from the EPRI Power Systems Dynamics Tutorial. EPRI, Palo Alto, CA: 2009.
1016042
C‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004210
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004211
Appendix D – Interconnection Frequency Deviation Duration Plots
Appendix D – Interconnection Frequency Deviation
Duration Plots
Figure D1: Summary of Eastern Interconnection Frequency 2007–2011
2500000
2000000
1500000
1000000
500000
0
58.8
59
59.2
59.4
59.6
59.8
60
60.2
60.4
Figure D2: Eastern Interconnection 2007–2011 Frequency Histogram
4
3.5
Percentage of Observations (%)
3
2.5
2
1.5
1
0.5
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
D‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004212
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D3: Eastern Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Figure D4: Summary of Western Interconnection Frequency 2007–2011
600000
500000
400000
300000
200000
100000
0
59.5
59.6
59.7
59.8
59.9
60
60.1
60.2
60.3
60.4
Frequency Response Initiative Report – October 2012
D‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004213
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D5: Western Interconnection 2007–2011 Frequency Histogram
0.035
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure D6: Western Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
D‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004214
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D7: Summary of ERCOT Interconnection Frequency 2007–2011
350000
300000
250000
200000
150000
100000
50000
0
57.5
58
58.5
59
59.5
60
60.5
61
61.5
62
62.5
Figure D8: ERCOT Interconnection 2007–2011 Frequency Histogram
0.016
0.014
Percentage of Observations (%)
0.012
0.01
0.008
0.006
0.004
0.002
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Frequency Response Initiative Report – October 2012
D‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004215
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D9: ERCOT Interconnection Frequency 2007–2011 Cumulative Distribution
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Figure D10: Summary of Québec Interconnection Frequency 2010–2011
Q
120000
100000
80000
60000
40000
20000
0
59
D‐5
59.2
59.4
59.6
59.8
60
60.2
60.4
60.6
60.8
61
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004216
Appendix D – Interconnection Frequency Deviation Duration Plots
Figure D11: Québec Interconnection 2010–2011 Frequency Histogram
0.03
Percentage of Observations (%)
0.025
0.02
0.015
0.01
0.005
0
59.9
59.95
60
60.05
60.1
Frequency (Hz, bin size of 1 mHz)
Figure D12: Québec Interconnection Frequency 2010–2011 Cumulative Distribution
Q
1
0.9
0.8
Cumulative Distribution (quantile)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
59.9
59.95
60
60.05
60.1
Frequency (Hz)
Frequency Response Initiative Report – October 2012
D‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004217
Appendix E – ALR1‐12 Metric Event Selection Process
Appendix E – ALR1-12 Metric Event Selection
Process
1. CERTS‐EPG produces a monthly spreadsheet for four interconnections (Eastern
Interconnection or EI, Western or WI, ERCOT Interconnection or TI, and Québec). The
spreadsheet captures significant frequency events based on the Resources Subcommittee
(RS) specified threshold. The Frequency Monitoring and Analysis tool (FMA) gathers and
stores the raw data.
2. The spreadsheet is sent by CERTS‐EPG to the Frequency Working Group (FWG) on the 15th
of each month for the previous month’s raw data.
3. The FNET application uses automatic e‐mails to flag frequency deviations. Generation loss is
estimated.
4. The actual generation loss for the FNET flagged frequency events is determined by the NERC
Situation Awareness Coordinator from the Regional Entities and sent to the FWG.
5. The FWG members validate the data and add the actual generation loss values into the
spreadsheet.
6. FWG sends the validated monthly sheet to the Resource Subcommittee (RS) and the
Performance Analysis Subcommittee (PAS) on the 30th of each month for the previous
month’s raw data.
7. NERC staff will update the candidate event list on the NERC website that will be used to
support the standard. The final official event list for a year will be identified as a subset of
the posted candidate list.
8. PAS publishes the quarterly Frequency Response metric data on NERC’s Reliability
Indicators webpage. The initial trending will be based on annual median/mean and rolling
12 month values.
Background Information
The frequency delta thresholds recommended by RS for the Eastern, Western, ERCOT and
Québec Interconnections are shown in Table E1.
Table E1: Frequency delta thresholds recommended by RS
Interconnections
Frequency Delta for events
captured in (mHz)
Frequency Delta for
Significant events that
have a higher Delta
Time
Window
(Seconds)
Eastern
24
36
15
Western
40
70
15
ERCOT
45
90
15
Québec
140
200
15
E‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004218
Appendix E – ALR1‐12 Metric Event Selection Process
The raw statistics for events in 2008, 2009, 2010 and the first half of 2011 are listed in Table E2
below. This was sent by CERTS‐EPG to the FWG on August 31, 2011.
Table E2: Raw Statistics for frequency events from 2008 to July 2011
Interconnection
Eastern
Western
ERCOT
Québec
2008
195
102
26
No Data
2009
78
72
85
No Data
2010
132
85
122
No Data
2011 (until July)
70
37
61
159
The statistics for TI from 2008 to 2011 were validated and modified by the FWG. Table E3
shows the statistics for TI that were sent by the FWG to the RS on September 02, 2011.
Table E3: Validated Statistics for TI frequency events
from 2008 to July 2011
Interconnections
TI
2008
8
2009
51
2010
67
2011 (until July)
40
The FWG Lead members who will validate the data and add the actual generation loss values
into the spreadsheet for the four interconnections are listed in Table E4.
Table E4: Lead members for the four interconnections
Terry L. Bilke
Eastern Interconnection
Don E. Badley
Western Interconnection
Sydney L. Niemeyer
ERCOT Interconnection
Michael Potishnak
Québec Interconnection
In July 2011, CERTS‐EPG produced the first of the monthly reports for the FWG. July 2011 has
22 frequency events and a summary is shown in Table E5.
Frequency Response Initiative Report – October 2012
E‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004219
Appendix E – ALR1‐12 Metric Event Selection Process
Table E5: Summary of the 1st monthly report produced by CERTS‐EPG for the FWG in
July 2011
E‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004220
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004221
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
Appendix F – Procedure for ERO Support of
Frequency Response and Frequency Bias Setting
Standard (BAL-003-1)
Event Selection Process
This procedure outlines the ERO process for supporting the Frequency Response Standard
(FRS). A procedure revision request may be submitted to the ERO for consideration. The
revision request must provide a technical justification for the suggested modification. The ERO
will post the suggested modification for a 45‐day comment period and discuss the revision
request in a public meeting. The ERO will make a recommendation to the NERC BOT, which
may adopt the revision request, adopt it with modifications, or reject it. Any approved revision
to this procedure will be filed with FERC for informational purposes.
Event Selection Objectives
The goals of this procedure are to outline a transparent, repeatable process to annually identify
a list of frequency events to be used by Balancing Authorities (BA) to calculate their Frequency
Response to determine:
whether the BA met its Frequency Response Obligation; and
an appropriate fixed bias setting.
Event Selection Criteria
1. The ERO will use the following criteria to select FRS frequency excursion events for
analysis. The events that best fit the criteria will be used to support the FRS. The
evaluation period for performing the annual Frequency Bias Setting and the Frequency
Response Measure (FRM) calculation is December 1 of the prior year through November
30 of the current year.
2. The ERO will identify 20–35 frequency excursion events in each interconnection for
calculating the Frequency Bias Setting and the FRM. If the ERO cannot identify 20
frequency excursion events in a 12‐month evaluation period satisfying the criteria
below, then similar acceptable events from the subsequent year’s evaluation period will
be included with the data set by the ERO for determining FRS compliance.
3. The ERO will use three criteria to determine if an acceptable frequency excursion event
for the FRM has occurred:
a. The change in frequency as defined by the difference from the A Value to Point C
and the arrested frequency Point C exceeds the excursion threshold values specified
for the interconnection in Table F1 below.
i. The A Value is computed as an average over the period from ‐16 seconds to 0
seconds before the frequency transient begins to decline.
F‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004222
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
ii. Point C is the arrested value of frequency observed within 12 seconds following
the start of the excursion.
Table F1: Interconnection Frequency Excursion
Threshold Values (Hz)
A Value
to Pt C
Point C
(Low)
Point C
(High)
Eastern
0.04
< 59.96
> 60.04
Western
0.07
< 59.95
> 60.05
ERCOT
0.15
< 59.90
> 60.10
Québec
0.30
< 59.85
> 60.15
Interconnection
b. The time from the start of the rapid change in frequency until the point at which
frequency has stabilized within a narrow range should be less than 18 seconds.
c. If any data point in the B Value average recovers to the A Value, the event will not
be included.
4. Pre‐disturbance frequency should be relatively steady and near 60.000 Hz for the A
Value. The A Value is computed as an average over the period from ‐16 seconds to 0
seconds before the frequency transient begins to decline. For example, given the choice
of the two events below, the one on the right is preferred as the pre‐disturbance
frequency is stable and also closer to 60 Hz.
5. Excursions that include two or more events that do not stabilize within 18 seconds will
not be considered.
6. Frequency excursion events occurring during periods when large interchange schedule
ramping or load change is happening, and frequency excursion events occurring within 5
Frequency Response Initiative Report – October 2012
F‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004223
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
minutes of the top of the hour, will be excluded from consideration if other acceptable
frequency excursion events from the same quarter are available.
7. The ERO will select the largest (A Value to Point C) two or three frequency excursion
events occurring each month. If there are not two frequency excursion events that
satisfy the selection criteria in a month, then other frequency excursion events should
be picked in the following order of priority:
1)
2)
3)
4)
from the same event quarter of the year
from an adjacent month
from a similar load season in the year (shoulder vs. summer/winter)
the largest unused event
As noted earlier, if a total of 20 events are not available in an evaluation year, then similar
acceptable events from the next year’s evaluation period will be included with the data set by
the ERO for determining FRO compliance. The first year’s small set of data will be reported and
used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a 24
month data set.
To assist Balancing Authority preparation for complying with this standard, the ERO will provide
quarterly posting of candidate frequency excursion events for the current year FRM calculation.
The ERO will post the final list of frequency excursion events used for standard compliance as
specified in Attachment A of BAL‐003‐1. The following is a general description of the process
that the ERO will use to ensure that BAs can evaluate events during the year in order to monitor
their performance throughout the year.
Monthly
Candidate events will be initially screened by the “Frequency Event Detection Methodology”
shown on the following link located on the NERC Resources Subcommittee area of the NERC
website:
http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oc
t_2011.pdf.
Each month’s list will be posted by the end of the following month on the NERC website,
http://www.nerc.com/filez/rs.html and listed under “Candidate Frequency Events.”
Quarterly
The monthly event lists will be reviewed quarterly with the quarters defined as:
F‐3
December through February
March through May
June through August
September through November
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004224
Appendix F– Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard (BAL‐003‐1)
Based on criteria established in the “Procedure for ERO Support of Frequency Response and
Frequency Bias Setting Standard,” events will be selected to populate the FRS Form 1 for each
interconnection. Each interconnection’s Form 1 will be posted on the NERC website, in the
Resources Subcommittee area under the title “Frequency Response Standard Resources.” The
updated Form 1 documents will be posted at the end of each quarter listed above after a
review by the NERC RS Frequency Working Group. While the events on this list are expected to
be final, as outlined in the selection criteria, additional events may be considered, if the number
of events throughout the year do not create a list of at least 20 events. It is intended that this
quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events
throughout the year, lessening the burden when the yearly posting is made.
Annually
The final FRS Form 1 for each interconnection, which will contain the events from all four
quarters listed above, will be posted as specified in Attachment A. Each Balancing Authority
reports its previous year’s Frequency Response Measure (FRM), Frequency Bias Setting and
Frequency Bias type (fixed or variable) to the ERO as specified in Attachment A using the final
FRS Form 1. The ERO will error check and use the FRS Form 1 data to calculate CPS limits and
FROs for the upcoming year.
Once the data listed above is fully reviewed, the ERO may adjust the implementation specified
in Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility
in when each BA implements its settings.
Frequency Response Initiative Report – October 2012
F‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004225
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Appendix G – Statistical Analysis of Frequency
Response (Eastern Interconnection)
Statistical Analysis of Frequency Response
Eastern Interconnection August 7, 2012
Introduction
An interconnected electric power system is a complex system that must be operated within a
safe frequency range to reliably maintain the instantaneous balance between generation and
load, and is directly reflected in the frequency of the interconnection. Frequency Response is
one measurement of how a power system has performed in response to the sudden loss of
generation or load. This white paper analyzes the Frequency Response data for the Eastern
Interconnection using statistical methods to study the probability distribution of the Frequency
Response and its changes from year‐to‐year, as well as construct a set of variables that strongly
influence Frequency Response.
Objectives and Method
The main goals of the statistical analysis of the Frequency Response data for the Eastern
Interconnection are to study the:
1. time trend of Frequency Response by selecting an appropriate model describing the
relationship between a point in time when an event happens and the absolute value of
Frequency Response for this event, and to use this model for Frequency Response
forecasting with a given confidence level;
2. probability distribution of the Frequency Response and its changes over the years;
3. seasonal changes in Frequency Response distribution and correlation between Frequency
Response value and season when the event happened (summer/non‐summer);
4. impact of pre‐disturbance frequency on Frequency Response;
5. impact of on‐peak/off‐peak hours on Frequency Response;
6. impact of interconnection load on Frequency Response; and
7. hierarchy of these explanatory factors of Frequency Response.
The analysis uses the Frequency Response dataset for the Eastern Interconnection for the
calendar years 2009‐2011 and the first three months of 2012. The size of this dataset is 163
frequency events (with 44 observations for the year of 2009, 49 for 2010, 65 for 2011, and 5 for
2012). Since interconnection load data are not yet available for 2012, the part of the study
involving interconnection load deals with the 158 Frequency Response events occurred in 2009‐
2011. For purposes of this whitepaper, Frequency Response pertains to the absolute value of
Frequency Response.
G‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004226
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Key Findings
1. A linear regression equation with the parameters defined in the Appendix of this
whitepaper is an adequate statistical model to describe a relationship between time
(predictor) and Frequency Response (response variable). The graph of the linear regression
line and Frequency Response scatter plot is given in Figure G1. For the dataset, the
regression line has a small positive slope estimate, meaning that the Frequency Response
variable has a slowly increasing general trend in time. The value of the slope estimate is
0.00000303805 (the time unit is a second). This means that, on average, Frequency
Response increases daily by 0.26 MW/0.1Hz, monthly by 7.87 MW/0.1 Hz, and annually by
95.81 MW/ 0.1Hz (for a month with 30 days , and a year with 365 days). A 90% confidence
interval for slope, CI=[‐0.00000041605, 0.00000649214], has a negative left‐end point (the
same is true for a 95% CI and a 99% CI). With new data available the trend line can (a)
increase its positive slope, (b) change the positive slope to a slight negative one, or (c)
become essentially flat that will correspond to an absence of a correlation between time
and Frequency Response.
Figure G1: Frequency Response Scatter Plot
2. The probability distribution of the whole Frequency Response dataset is approximately
normal with the expected Frequency Response of 2363 MW/0.1 Hz and the standard
deviation of 605.7 MW/0.1 Hz as shown in Figure G2. The comparative statistical analysis
for every pair of years shows that the changes in the 2010 data versus the 2009 data (and
in the 2011 data versus the 2010 data) are not statistically significant enough to lead to the
conclusion that the mean value of Frequency Response for any two consecutive years
changes. However, the data for 2009 and 2011 differ at the level that results in accepting
Frequency Response Initiative Report – October 2012
G‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004227
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
the hypothesis that the expected value of Frequency Response for 2011 is greater than for
2009.
Figure G2: Probability Distribution of the Entire Frequency Response Data Set
3. A season (summer/non‐summer) is a significant contributor to the variability of Frequency
Response. There is a positive correlation of 0.24 between the indicator function for summer
(defined as 1 for events that occur in June–August and 0 otherwise) and Frequency
Response: summer events have a statistically significantly greater expected Frequency
Response (the sample mean equals to 2598MW/0.1 Hz) than non‐summer events (the mean
equals to 2271 MW/0.1 Hz).
4. Pre‐disturbance (average) frequency (A) is another significant contributor to the variability of
Frequency Response. There is a negative correlation of ‐0.27 between the indicator function
of A>60 Hz and Frequency Response: the events with A>60 Hz have a statistically significantly
smaller expected Frequency Response (the sample mean equals to 2188 MW/0.1 Hz) than
the events with A≤60 Hz (the mean equals to 2513 MW/0.1 Hz).
5. According the NERC definition, for Eastern Interconnection on‐peak hours are designated as
follows: Monday to Saturday hours from 0700 to 2200 (Central Time) excluding six holidays
(New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and
Christmas Day). It turns out that on‐peak/off‐peak variable is not a statistically significant
G‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004228
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
contributor to the variability of Frequency Response. There is a positive correlation of 0.06
between the indicator function of on‐peak hours and Frequency Response; however,
difference in average Frequency Response between on‐peak events and off‐peak events is
not statistically significant and could occur by chance (P‐value is 0.49).
6. There is a strong positive correlation of 0.364 between interconnection load and Frequency
Response for the 2009‐2011 events; this correlation indicates to a statistically significant
linear relationship between interconnection load (predictor) and Frequency Response
(response variable). The graph of the linear regression line and Frequency Response scatter
plot is given in Figure G3. For the dataset, the regression line has a positive slope estimate of
0.00349; thus, the Frequency Response variable increases when interconnection load grows.
On average, when interconnection load changes by 1000 MW, Frequency Response changes
by 3.5 MW/0.1Hz.
Figure G3: Linear Regression for Frequency Response and Interconnection Load
7. For the 2009–2011 dataset, five variables (time, summer, high pre‐disturbance frequency,
on‐peak/off‐peak hour, interconnection load) have been involved in the statistical analysis of
Frequency Response. Four of these (time, summer, on‐peak hours, and interconnection load)
have a positive correlation with Frequency Response (0.16, 0.24, 0.06, and 0.36,
Frequency Response Initiative Report – October 2012
G‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004229
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
respectively), and the high pre‐disturbance frequency has a negative correlation with
Frequency Response (‐0.26). The corresponding coefficients of determination R2 are 2.6%,
5.8%, 0.4%, 13.3% and 6.9%. These values indicate that about 2.6% in variability of
Frequency Response can be explained by the changes in time, about 5.8% of Frequency
Response variability is seasonal, 0.4% is due to on‐peak/off‐peak changes, 13.3% is the effect
of the interconnection load variability, and about 6.9% can be accounted for by a high pre‐
disturbance frequency. However, the correlation between Frequency Response and On‐Peak
hours is not statistically significant and with the probability about 0.44 occurred by mere
chance (the same holds true for the corresponding R2). Therefore, out of the five
parameters, interconnection load has the biggest impact on Frequency Response followed
by the indicator of high pre‐disturbance frequency. A multivariate regression with
interconnection load and A>60 as the explanatory variables for Frequency Response yields a
linear model with the best fit (it has the smallest mean square error among the linear models
with any other set of explanatory variables selected from the five studied). Still, together
these two factors can account for about 20% in variability of Frequency Response. Therefore,
there are other parameters that affect Frequency Response, have a low correlation with
those studied, together account for a remaining share in Frequency Response variability, and
minimize a random error variance. Note that interconnection load is positively correlated
with summer (0.55), on‐peak hours (0.45), and Date (0.20) but uncorrelated with A>60 (P‐
value of the test on zero correlation is 0.90).
Explanatory Variables for EI Frequency Response (2009-2011)
Sample
Correlation (X,FR)
P-value
Linear Regression
Statistically
Significant?
Coefficient of
Determination R^2
(Single Regression)
Interconnection Load
0.36
<0.0001
Yes
13.3%
A>60
-0.26
0.0008
Yes
6.9%
Summer
0.24
0.0023
Yes
5.8%
Date
0.16
0.044
Yes
2.6%
On-Peak Hours
0.06
0.438
No
N/A
Variable X
G‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004230
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Appendix – Background Materials
Frequency Response is a metric used to track and monitor Interconnection Frequency
Response. Frequency Response2 is a measure of an interconnection’s ability to stabilize
frequency immediately following the sudden loss of generation or load. It is a critical
component to the reliable operation of the bulk power system, particularly during disturbances
and restoration. The metric measures the average Frequency Response for all events where
frequency drops more than the interconnection’s defined threshold as shown in Table 1.
Frequency Response Definition
For a given interconnection, Frequency Response is defined as the sum of the change in
demand, plus the change in generation, divided by the change in frequency, expressed in
megawatts per 0.1 hertz (MW/0.1 Hz).
Table 1: Frequency Event Triggers for Data Collection
∆Frequency (mHz)
MW Loss Threshold
Rolling Windows
(seconds)
Eastern
40
800
15
Western
70
700
15
ERCOT
90
450
15
Québec
300
450
15
Interconnection
The change in frequency is the difference between pre‐disturbance frequencies A and setting
frequency B. Figure 3 shows the criteria for calculating average values A and B. The event starts
at time t ±0. Value A is the average from t ‐16 to t ‐2 and Value B is the average from t +20 to t
+52. These lengths of time used to calculate these values accounts for the variability in
Supervisory Control and Data Acquisition (SCADA) scan rates that vary from 2 to 6 seconds in
the multiple‐Balancing Authority interconnections. For Balancing Authority SCADA data, t ±0
represents the first scan of data that is part of the disturbance. Value A is the average of all
SCADA scans between 2 and 16 seconds before t ±0. Value B is the average of all SCADA scans
between 20 and 52 seconds after t ±0.
2
Frequency Response is in fact a negative value. However to reduce confusion for the reader, Frequency Response is expressed in this report
as positive values (the absolute value of the actual calculated value).
Frequency Response Initiative Report – October 2012
G‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004231
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Figure 3: Criteria for Calculating Value A and Value B
t ±0
The actual MW loss for the flagged frequency events is determined jointly by NERC and
Regional Entity situation awareness staff. Both the change in frequency and the MW loss
determine whether the event qualifies for further consideration in the monthly frequency
event candidate list.
Statistical Analysis
Linear Regression for Time Trend
Assumptions: Frequency Response and time are related by the following regression equation:
Where:
variable represents a time (year, month, day, hour, minute, second) when a
Frequency Response event happened. For each event the Frequency Response is
calculated and recorded. This record represents an observation from the dataset. Time
is an explanatory variable (predictor, regressor) of the linear regression;
is the Frequency Response value measured in MW/0.1 Hz (response variable of the
model);
is a slope of the regression line;
is an intercept of the regression line; and
ε is a random error which has a centered normal distribution with variance σ2.
G‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004232
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
A SAS program for the linear regression analysis yields the following results shown in figure G3.
(a) The equation of the regression line derived by the least squares method is
0.00000304
2493.41315 with
sec elapsed between midnight of
January 1, 1960 (the time origin for the date format in SAS) and the time of a FR event;
(b) Estimate for the variance σ2 of the random error ε is 362,383 and for the standard
deviation of ε is 601.98255;
(c) Statistical test for significance of the regression (based on the analysis of variance
approach) is an important part of assessing the adequacy of the linear regression model
for time and FR variables. The procedure tests a null‐hypothesis that the slope A = 0
versus an alternative hypothesis that it is not 0. Sample value of F‐statistic, 3.0170, has
P‐value of 0.0843 implying that the null hypothesis should be rejected (and the
alternative hypothesis accepted) at any significance level above 0.0843. Therefore, the
data are statistically significant to support a hypothesis about a linear relationship
between time and Frequency Response assuming that the 8.43% significance level (i.e.,
the probability to reject the null hypothesis when it is true) is appropriate for the model
selection. Alternatively, the hypothesis about the correlation coefficient ρ(time, FR) can
be tested (with the null hypothesis ρ=0). These tests are equivalent and result in the
same P‐values for their test statistics.
Another important part of the verification of the linear regression model is testing the
assumptions on the random error ε. Student’s t‐test on location and goodness‐of‐fit test for
normality both result in acceptance the corresponding null‐hypothesis (with P‐values of 1.0000
and 0.881, respectively).
The linear regression equation with the parameters defined above is an adequate statistical
model to describe the relationship between variables time of a FR event and Frequency
Response value for this event. For the dataset, the regression line has a small positive slope
estimate, meaning that Frequency Response variable has a slowly increasing general trend in
time. However, the value of this slope estimate is very small, and confidence intervals for slope
at 90%, 95% and 99% levels all have a negative left‐end point. By using T‐distribution for the
slope estimator, we estimate that the probability that the slope of the regression is negative is
below 5%.
The coefficient of determination R2 for the linear regression model equals to 0.0184. This small
value indicates very low degree of dependence of Frequency Response on time variable.
Essentially, the linear regression model connecting FR and time accounts for 1.8% of variability
in the Frequency Response data.
The random error ε has a large estimated variance that makes the “error” term of the linear
regression equation a major component of the Frequency Response value. Our next goal is to
consider the Frequency Response data as observations of a random variable independent of
time and to study properties of its distribution.
Frequency Response Initiative Report – October 2012
G‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004233
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
Distribution of Frequency Response
Goodness‐of‐Fit test for normality of the distribution of the Frequency Response data results in
acceptance on the null hypothesis at a significance level below 0.177 (including the standard
levels of 1%, 5% and 10%). The sample estimate for the expected Frequency Response equals to
2363 MW/0.1 Hz and the sample standard deviation is 605.7 MW/0.1 Hz.
Since for each full year (2009, 2010, and 2011) the sample size of the Frequency Response data
exceeds 40, we ran a large‐sample test for the difference in the mean Frequency Response for
2009 versus 2010, 2010 versus 2011, and 2009 versus 2011. The null hypothesis that the
difference is zero is accepted when the 2009 data are compared to the 2010 data, and when
the 2010 data are compared to the 2011 data at any standard significance level (P‐values of the
two‐sided tests are 0.54 and 0.28, respectively). For the 2009 versus 2011 comparison, the test
result is not that conclusive (its P‐value equals to 0.03 and, therefore, the null hypothesis
should be rejected at the 5% and 10% significance levels but is accepted at the 1% level if tested
versus an alternative hypothesis that the 2011 mean value is greater than the 2009 mean
value).
Seasonal Variability of Frequency Response
Let a function summer be defined as follows: it equals to 1 for Frequency Response events that
occur in June‐August and 0 otherwise. The FR dataset is therefore divided in two subsets: the
Frequency Response data for summer events and non‐summer events, respectively. Summer
Frequency Response set has 46 observations and non‐summer set has 117 observations. The
sample mean and the sample variance for the first dataset are 2597.7 MW/0.1 Hz and 675.5
MW/0.1 Hz, respectively. The sample mean and the sample variance for the second dataset are
2270.9 MW/0.1 Hz and 552.2 MW/0.1 Hz. A large‐sample test for the difference in the mean
Frequency Response for these distributions results in rejection of the null hypothesis that the
difference is zero and acceptance of an alternative hypothesis that the expected Frequency
Response for summer events is greater than for other events (P‐value of the one‐sided z‐test is
0.0018).
Variables summer and Frequency Response are positively correlated (with the correlation equal
to 0.24351), and the coefficient of determination R2 of the linear regression model is 0.0593.
The null hypothesis about zero correlation (no linear relationship between FR and summer)
should be rejected (P‐value is 0.0017). This analysis indicates that seasonality is a significant
factor affecting Frequency Response: almost 6% of its variability is the seasonal variability.
Impact of Pre-Disturbance Frequency
Let a function high pre‐disturbance frequency be defined as follows: it equals to 1 for
Frequency Response events with A>60 Hz and 0 otherwise. The FR dataset is therefore divided
in two subsets: the Frequency Response data for events with A>60 Hz and events with A≤60 Hz,
respectively. High pre‐disturbance frequency set has 75 observations and its complement has
88 observations. The sample mean and the sample variance for the first dataset are 2187.6
MW/0.1 Hz and 531.5 MW/0.1 Hz, respectively. The sample mean and the sample variance for
the second dataset are 2512.8 MW/0.1 Hz and 627.4 MW/0.1 Hz. A large‐sample test for the
difference in the mean Frequency Response for these distributions results in rejection of the
null hypothesis that the difference is zero and acceptance of an alternative hypothesis that the
G‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004234
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
expected Frequency Response for events with A>60 Hz is smaller than for other events (P‐value
of the one‐sided z‐test is 0.0002).
Variables high pre‐disturbance frequency and Frequency Response are negatively correlated
(with the correlation equal to ‐0.26844), and the coefficient of determination R2 of the linear
regression model is 0.0721. The null hypothesis about zero correlation (no linear relationship
between FR and high pre‐disturbance frequency) should be rejected (P‐value is 0.0005). This
analysis indicates that the high pre‐disturbance frequency is a factor that accounts for 7.2% of
the Frequency Response variability. In fact, out of the four variables involved in this study (time,
summer, high pre‐disturbance frequency, on‐peak/off‐peak hours), it is the biggest contributor
to the variability of Frequency Response.
Impact of On-Peak/Off-Peak hours
Let a function on‐peak hour be defined as follows: it equals to 1 for Frequency Response events
occurred during an on‐peak hour and 0 otherwise. The FR dataset is therefore divided in two
subsets: the Frequency Response data for on‐peak hours and off‐peak hours, respectively. On‐
peak set contains 108 observations, and off‐peak set has 55 observations. The sample mean
and the sample variance for the first dataset are 2386.9 MW/0.1 Hz and 602.9 MW/0.1 Hz,
respectively. The sample mean and the sample variance for the second dataset are 2316.6
MW/0.1 Hz and 614.1 MW/0.1 Hz. A large‐sample test for the difference in the expected
Frequency Response for these distributions results in acceptance of the null hypothesis that the
difference is zero and rejection of an alternative hypothesis that the expected Frequency
Responses for on‐peak events and off‐peak events are different (P‐value of the two‐sided z‐test
is 0.49).
Variables on‐peak hour and Frequency Response are positively correlated (with the correlation
equal to 0.005505), and the coefficient of determination R2 of the linear regression model is
0.0030. However, the correlation is not statistically significant since the null hypothesis about
zero correlation (no linear relationship between FR and on‐peak hour) should be accepted (P‐
value is 0.4852). The same is true for the coefficient of determination: there is a high
probability that on‐peak hours have no explanatory power in the Frequency Response
variability. Out of the four variables involved in this study (time, summer, high pre‐disturbance
frequency, on‐peak/off‐peak hours), it is the only factor with no statistically significant impact
on Frequency Response.
Linear Model that relates Frequency Response to Interconnection Load
Assumptions: Frequency Response and interconnection load are related by the following
regression equation:
ε
Where:
is the value of interconnection load (in MW) for a Frequency Response event.
is the Frequency Response value measured in MW/0.1 Hz (response variable of
the model);
Frequency Response Initiative Report – October 2012
G‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004235
Appendix G– Statistical Analysis of Frequency Response (Eastern Interconnection)
is a slope of the regression line;
is an intercept of the regression line; and
ε is a random error which has a zero mean and variance of
.
A SAS program for the linear regression analysis yields the following results shown in figure G3.:
(a) The equation of the regression line derived by the least squares method is
0.00349
1174.09949;
(b) Estimate for the variance σ2 of the random error ε is 327,416 and for the standard
deviation of ε is 572.2; and
(c) Statistical test for significance of the regression (based on the analysis of variance
approach) is an important part of assessing the adequacy of the linear regression
model for interconnection load and FR variables. The procedure tests a null‐
hypothesis that the slope
0 versus an alternative hypothesis that it is not 0.
Sample value of F‐statistic, 23.83, has P‐value of 0.0001 implying that the null
hypothesis should be rejected (and the alternative hypothesis accepted) at any
significance level above 0.0001. Therefore, the data are statistically significant to
support a hypothesis about linear relationship between interconnection load and
Frequency Response. Alternatively, the hypothesis about the correlation coefficient
between interconnection load and Frequency Response can tested (with the null
hypothesis ρ=0). These tests are equivalent and result in the same P‐values for their
test statistics.
The coefficient of determination R2 for the linear regression model equals to 0.1325. This value
indicates high degree of dependence of Frequency Response on interconnection load.
Essentially, the linear regression model connecting FR and interconnection load accounts for
about 13.3% of variability in the Frequency Response data.
Multiple Linear Regression
A statistically significant linear regression model connects interconnection load and high pre‐
disturbance frequency (regressors) and Frequency Response (response variable). The estimates
of the linear regression coefficients are listed in the Table 2 (P‐value of the model is below
0.0001). An error term, ε, has a zero mean and the standard deviation of 551 MW/0.1 Hz. This
multiple regression model accounts for 19.96% of the variability in Frequency Response data.
Table 2: Parameter Estimates of Multiple Regression
Variable
Parameter
DF
Intercept
1
Estimate
1325.96255
A>60
1
-317.95091
Interconnection Load
1
0.00347
G‐11
Standard
Error
243.49079
t Value
Pr > |t|
5.45
<.0001
88.191
-3.61
0.0004
0.00068929
5.03
<.0001
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004236
Appendix G – Statistical Analysis of Frequency Response (Eastern Interconnection)
Note that even though time and summer both have a statistically significant positive correlation
with Frequency Response, adding one or both of them to the set of explanatory variables does
not improve the linear model. This can be explained by a high correlation between
interconnection load and summer (0.55) and time (0.20), respectively: addition of these
variables does not increase the explanatory power of the model enough to offset an increase of
its cumulative error.
Frequency Response Initiative Report – October 2012
G‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004237
Appendix H – Frequency Response Field Trial Analysis Graphs
Appendix H – Frequency Response Field Trial
Analysis Graphs
NOTE: These are the background graphics of the Frequency Response Field Trial Analysis of BA
performance measurements.
Frequency Response Events as Normalized by FRO
Eastern Interconnection ‐ 2011
50.0
Frequency Response Normalized by FRO
25.0
0.0
‐25.0
25
26
27
28
29
30
31
32
26
27
28
29
30
31
32
24
25
23
22
21
20
19
18
17
16
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐50.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Eastern Interconnection ‐ 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
‐5.0
24
23
22
21
20
19
18
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
0
‐10.0
Balancing Authority
H‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004238
Appendix H – Frequency Response Field Trial Analysis Graphs
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
10.0
Frequency Response Normalized by FRO
5.0
0.0
‐5.0
16
17
18
19
20
16
17
18
19
20
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐10.0
Balancing Authority
Frequency Response Events as Normalized by FRO
Western Interconnection ‐ 2011
25.0
20.0
Frequency Response Normalized by FRO
15.0
10.0
5.0
0.0
‐5.0
‐10.0
‐15.0
‐20.0
15
14
13
12
11
9
10
8
7
6
5
4
3
2
1
0
‐25.0
Balancing Authority
Frequency Response Initiative Report – October 2012
H‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004239
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 1
2.93266
2.44868
2.57361
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 2
2.78374
2.95180
3.01883
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004240
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 3
1.38620
1.86272
1.65009
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 3
1.38620
1.86272
1.65009
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004241
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 4
2.69908
3.92009
3.43317
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 4
2.69908
3.92009
3.43317
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004242
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 5
3.41783
3.59448
3.36306
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 6
2.77009
3.15820
3.09135
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004243
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 7
0.35407
1.74493
1.03098
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 7
0.35407
1.74493
1.03098
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004244
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 8
0.45946
1.01731
0.76053
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 9
0.82449
1.12570
0.95545
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004245
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 10
1.33795
1.12685
1.18659
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 11
1.36260
1.79121
1.50127
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004246
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 12
3.20919
3.28179
2.93860
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 13
1.33862
0.93276
1.22791
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004247
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 13
1.33862
0.93276
1.22791
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 14
1.88020
1.80109
1.83616
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004248
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 15
3.15755
2.99668
2.93316
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 16
1.82722
1.16967
1.45768
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004249
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 17
2.40390
3.03502
2.91760
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 18
5.74785
6.08231
6.12109
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
H‐13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004250
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 18
5.74785
6.08231
6.12109
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 19
2.80118
3.68324
3.72332
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004251
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 19
2.80118
3.68324
3.72332
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 20
2.09702
2.23845
2.15337
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐15
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004252
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 21
2.88295
2.22455
2.22060
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 22
1.46450
1.24819
1.21142
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐16
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004253
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 23
1.54300
1.52179
1.56508
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 24
0.67435
0.60288
0.52881
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐17
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004254
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 25
2.52953
3.13603
3.07715
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 25
2.52953
3.13603
3.07715
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐18
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004255
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 26
1.33209
1.64291
1.19690
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 26
1.33209
1.64291
1.19690
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐19
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004256
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 27
1.42688
0.90646
1.28118
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 27
1.42688
0.90646
1.28118
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐20
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004257
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 28
0.85546
1.08848
1.38770
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 29
4.26456
3.95973
4.14329
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
H‐21
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004258
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
E BA 30
3.73638
3.56590
3.54281
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐25
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 30
3.73638
3.56590
3.54281
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐22
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004259
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
E BA 31
1.43993
1.64111
1.59776
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 1
1.56036
1.62650
1.57725
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐23
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004260
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 2
1.61236
1.52293
1.52808
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 3
2.38680
2.96222
2.61561
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐24
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004261
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 3
2.38680
2.96222
2.61561
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 4
1.09060
1.12603
1.41997
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
H‐25
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004262
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 4
1.09060
1.12603
1.41997
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 5
1.43519
1.59333
1.36018
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004263
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 6
0.59518
0.54980
0.55267
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 7
1.46146
1.74495
1.93716
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐27
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004264
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 8
1.43519
1.59333
1.36018
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 9
0.72788
0.84191
0.91201
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐28
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004265
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 10
0.79200
0.92316
0.91603
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 11
1.02018
1.10745
1.21932
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐29
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004266
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 12
2.36648
2.65442
2.61365
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 13
4.71769
5.17291
5.14399
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐30
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004267
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 13
4.71769
5.17291
5.14399
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 14
0.60768
0.87898
0.63485
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐31
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004268
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 15
‐1.38396
‐1.54605
‐1.39906
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 16
3.09936
3.30917
3.24174
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐32
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004269
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 16
3.09936
3.30917
3.24174
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 17
3.02606
2.99888
2.80485
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐33
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004270
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 18
1.45116
1.47302
1.50091
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
25
20
15
10
5
0
‐5
‐10
‐15
Data
Median
Mean
Regression
W BA 19
2.45172
2.48546
2.73588
‐20
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐25
Frequency (Hz)
Frequency Response Initiative Report – October 2012
H‐34
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004271
Appendix H – Frequency Response Field Trial Analysis Graphs
Median ‐ Mean ‐ Regression Analysis as Normalized by FRO
5
4
3
2
1
0
‐1
‐2
‐3
Data
Median
Mean
Regression
W BA 19
2.45172
2.48546
2.73588
‐4
0.000
‐0.010
‐0.020
‐0.030
‐0.040
‐0.050
‐0.060
‐0.070
‐0.080
‐0.090
‐0.100
‐0.110
‐0.120
‐0.130
‐0.140
‐0.150
‐0.160
‐0.170
‐0.180
‐0.190
‐0.200
‐0.210
‐0.220
‐0.230
‐0.240
‐0.250
‐5
Frequency (Hz)
H‐35
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004272
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004273
Appendix I – Derivation of the Median, Mean, and Linear Regression
Appendix I – Derivation of the Median, Mean, and
Linear Regression
Median
The median best represents a uniform one‐dimensional dataset.
Uniform Distribution
In probability theory and statistics, the continuous uniform distribution or rectangular
distribution is a family of probability distributions such that for each member of the family, all
intervals of the same length on the distribution's support are equally probable. The support is
defined by the two parameters, a and b, which are its minimum and maximum values.
Median
We have been taught in statistics that minimizing the sum of the differences error term
provides the best estimate for the value for a uniform data set. Define a data set as one
dimensional with values {x1, x2,…, xn}. The objective is to select a single value that best
represents this data set by minimizing the sum of the residuals.
SDE x x
n
i
m
i 1
Where:
xm
=
Best single value to represent the data set.
The result is undefined using calculus. Therefore, other logic must be used.
Organize the data from smallest to largest. Then investigate the change in total difference as
the candidate median value is raised from the smallest to the largest value in the data set.
When the candidate median value is raised above the smallest data value the difference
between the candidate median value and the smallest value increases, but the difference
between the candidate median value and all other data values decreases by an amount equal
to the increase in the difference for the smallest value times the number of data values above
the candidate median value. As the candidate median value increases, the total difference
from all values will decrease until exactly one half of the data values are above the candidate
median value and exactly one half of the data values are below the candidate median value. If
there are an even number of data values in the set, any change in the candidate median value
between the data value immediately below the half and the data point immediately above the
half will not change the total difference because the difference change in the increasing
direction and the difference change in the decreasing direction offset each other. However, if
there are an odd number of data values in the data set, the candidate median value equal to
the center data value will result in a minimum of the differences.
I‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004274
Appendix I – Derivation of the Median, Mean, and Linear Regression
This demonstrates that the medianis the best estimate for a set of uniform data because it
minimizes the sum of the error terms for the data set.
The real question is not whether the median is an appropriate estimator, but whether the
median is an appropriate estimator for the data being analyzed.
Mean
The mean best represents a normal one dimensional dataset.
Normal (Gaussian) Distribution
In probability theory, the normal (or Gaussian) distribution is a continuous probability
distribution that has a bell‐shaped probability density function, known as the Gaussian function
or informally the bell curve, where parameter μ is the mean or expectation (location of the
peak) and σ 2 is the variance, the mean of the squared deviation, (a "measure" of the width of
the distribution). σ is the standard deviation. The distribution with μ = 0 and σ 2 = 1 is called
the standard normal. A normal distribution is often used as a first approximation to describe
real‐valued random variables that cluster around a single mean value.
The normal distribution is considered the most prominent probability distribution in statistics.
There are several reasons for this:
First, the normal distribution is very tractable analytically, that is, a large number of
results involving this distribution can be derived in explicit form.
Second, the normal distribution arises as the outcome of the central limit theorem,
which states that under mild conditions the sum of a large number of random variables
is distributed approximately normally.
Third, the bell shape of the normal distribution makes it a convenient choice for
modeling a large variety of random variables encountered in practice.
For this reason, the normal distribution is commonly encountered in practice, and is used
throughout statistics, natural sciences, and social sciences as a simple model for complex
phenomena. For example, the observational error in an experiment is usually assumed to
follow a normal distribution, and the propagation of uncertainty is computed using this
assumption. Note that a normally‐distributed variable has a symmetric distribution about its
mean. Quantities that grow exponentially, such as prices, incomes or populations, are often
skewed to the right, and hence may be better described by other distributions, such as the log‐
normal distribution or Pareto distribution. In addition, the probability of seeing a normally‐
distributed value that is far (i.e., more than a few standard deviations) from the mean drops off
extremely rapidly. As a result, statistical inference using a normal distribution is not robust to
the presence of outliers (data that is unexpectedly far from the mean, due to exceptional
circumstances, observational error, etc.). When outliers are expected, data may be better
described using a heavy‐tailed distribution such as the Student's t‐distribution.
Frequency Response Initiative Report – October 2012
I‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004275
Appendix I – Derivation of the Median, Mean, and Linear Regression
Mean
We have been taught in statistics that minimizing the sum of the squares of the error term
provides the best estimate for the value for a normal data set. Let’s define a data set as one
dimensional with values {x1, x2,…, xn}. The objective is to select a single value that best
represents this data set by minimizing the sum of the squares of the residuals.
SSE x x
n
i
2
m
i 1
xm
Where:
Best single value to represent the data set.
=
SSE x 2 x x x
n
2
i
i
m
2
m
i 1
n
n
n
SSE x 2 x x x
2
i
i
i 1
i 1
n
n
m
i 1
SSE x 2 x x nx
2
i
i
i 1
2
m
m
2
m
i 1
Take the derivative of SSE with respect to xm, and set that derivative equal to zero.
SSE
x 2 x x nx
x
x
n
n
2
2
i
m
i 1
m
i
m
m
i 1
2 x x nx
SSE
x
x
x
x
x
n
n
2
i
m
i
i 1
m
i 1
m
m
2
m
m
SSE 2 x 2nx 0
x
n
i
n
1
n
x
m
i 1
m
i
x x
m
i 1
This demonstrates that the mean is the best estimate for a set of normal data because it
minimizes the sum of the squares of the error terms for the data set.
I‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004276
Appendix I – Derivation of the Median, Mean, and Linear Regression
Linear Regression
A linear regression best represents a normal two dimensional dataset.
As with the one dimensional data set, the objective is to minimize the sum of the squares of the
error terms. However, there may be differences that depend upon how we define the error
terms.
There are three alternatives available for defining the error term. It can be defined with
respect to the dependent variable alone as shown in the vertical offsets plot above. The second
is to define the error in terms of the horizontal offsets (not shown). That alternative is the
same as the first alternative when the independent variable is exchanged with the dependent
variable. The third alternative is to define the error as the perpendicular distance from the best
fit line. This is shown in the perpendicular offsets plot above. When the regression is solved
using the perpendicular offsets, both variables are considered equal with respect to
contribution to error, and the ranking of variables is not necessary.
Solution assuming an independent/dependent variable relationship
In the first example the error term is defined as one dimensional on the dependent variable
axis. This is based on the vertical offsets shown above. The result is derived as follows:
SSE y yˆ
n
i
i
i 1
2
ŷi
Where:
Best y value to represent the data set at a given x value.
=
Substitute a linear equation, ŷi = axi+b, for the estimated y value.
SSE y ax b
n
2
i
i 1
i
Since we now have two variables, a and b, the derivative must be taken with respect to each
variable. Setting each derivative equal to zero will provide two equations that can be solved for
the two unknowns, a and b.
Frequency Response Initiative Report – October 2012
I‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004277
Appendix I – Derivation of the Median, Mean, and Linear Regression
SSE y ax b 2 y ax b 0
b
b
n
n
2
i
i
i
i 1
i
i 1
SSE y ax b 2 x y ax bx 0
a
a
n
n
2
i
2
i
i
i 1
i
i
i
i 1
Rearrange terms and solve the two equations. Solve for b first.
n
n
y a x nb 0
i
i
i 1
b
i 1
n
1
n
n
y a x
1
n
i
i 1
i 1
Substitute the result for b into the second equation and solve for a.
i
b y ax
n
n
n
n
x y a x y ax x 0
2
i
i
i 1
i
i
i 1
i 1
a
x y
i
nyx
i
i 1
n
x
2
i
nx
2
i 1
Calculate the value of a and substitute into the first equation to get the value of b. These are
the most common equations used for linear regression. However, they assume that the
dependent and independent variables can be identified and that the error in the dependent
variable is more important than the error in the independent variable.
Solution without the independent/dependent variable relationship
assumption
In this section, the problem is solved using the perpendicular offsets to determine the error
terms. This provides a solution that is not dependent upon any assumption concerning the
relationship between the variables.
The first step in this solution is to determine the square of the perpendicular offset from the
regression line that represents the error term.
y ax b
SSE
1 a
2
n
i
i
2
i 1
Since we again have two variables, a and b, the derivative must be taken with respect to each
variable. Setting each derivative equal to zero will provide two equations that can be solved for
the two unknowns, a and b.
y ax b
SSE
b
b
1 a
2
n
i
i 1
I‐5
i
2
2
1 a
y ax b 0
n
2
i
i 1
i
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004278
Appendix I – Derivation of the Median, Mean, and Linear Regression
y ax b
SSE
1 a
a
a
2
n
i
i
2
i 1
2
SSE
a
1 a
y
n
2
ax b x
n
i
i 1
i
y
ax b 2a
0
1 a
2
i
i
i
2
i 1
2
Rearrange terms and solve the two equations. Solve for b first.
y a x nb 0
n
n
i
i
i 1
b
i 1
n
1
n
y
i
a
i 1
n
1
n
x
i
b y ax
i 1
This is the same result as before. Substitute the result for b into the second equation and solve
for a. The detailed intermediate equations for this solution can be found at
http://mathworld.wolfram.com/LeastSquaresFittingPerpendicularOffsets.html. After much
manipulation the following equations result:
y ny x nx
1
A
2
nyx x y
n
n
2
2
2
i
i
i 1
i 1
n
i
i
2
a A A 1
2
i 1
This solution is somewhat more complex than the vertical offset solution. That is the reason
that the vertical offset solution is commonly used. In most cases, the vertical offset solution
provides an adequate answer to the problem without the added complexity of the
perpendicular offset solution. However, when the vertical offset solution is used, it makes a
difference which variable is considered the independent variable and the dependent variable.
This can significantly affect the results when the slope is large.
Additional information requires a special case linear regression
The calculation of Frequency Response requires the use of a special case linear regression.
Frequency Response is defined as to be equal to zero when the frequency error is equal to zero.
This information requires the modification of the linear regression used to provide the best
representation of the data. The appropriate linear regression for representing Frequency
Response is a regression where the regression line crosses the origin of the axis representing
the two variables, frequency and Frequency Response (MW). Therefore, the previously
developed general solution to the problem requires modification. This is done by setting the
variable that represents the y‐intercept to zero. In the above examples, the b term must be set
to zero.
Frequency Response Initiative Report – October 2012
I‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004279
Appendix I – Derivation of the Median, Mean, and Linear Regression
Special case solution assuming an independent/dependent variable
relationship
In the first example the error term is defined as one dimensional on the dependent variable
axis. This is based on the vertical offsets but in this case the variable representing the intercept
is eliminated. The result is derived as follows:
SSE y yˆ
n
i
i
2
i 1
ŷi
Where:
Best y value to represent the data set at a given x value.
=
Substitute a linear equation, ŷi = axi, for the estimated y value.
SSE y ax
n
i
i
2
i 1
Since we now have a single variables, a, the derivative must be taken with respect to that
variable. Setting the derivative equal to zero will provide an equation that can be solved for the
unknown, a.
SSE y ax
a
a
n
i
i 1
i
2 x y ax 0
n
2
2
i
i
i
i 1
Rearrange terms and solve the equation.
n
n
n
x y a x 0
2
i
i 1
i
i
i 1
a
x y
i
i
i 1
n
x
2
i
i 1
This equation is somewhat simpler than the equation using a non‐zero intercept. In the specific
case that we are considering, the estimate of Frequency Response, the slope of the regression
line is not expected to be large, near vertical. Therefore, the assumption of dependent and
independent variables is not important to the solution. In this case, the additional complexity
added by considering the horizontal offsets is not significant to the solution and has been
eliminated from consideration.
I‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004280
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004281
Appendix J– Generator Governor Survey Instructions
Appendix J – Generator Governor Survey
Instructions
NOTE: These were the instructions for the Generators Governor Survey conducted in
September 2010.
Frequency Response Initiative
Generator Governor Survey
For the purposes of this survey, governors are defined as any device that implements Primary
Frequency Response (speed regulation) for generators.
The survey will be sent to Generator Owners and Generator Operators.
The survey includes all generators rated 20 MVA or higher, or plants that aggregate to a
total of 75 MVA or greater net rating at the point of interconnection (i.e., wind farms,
PV farms, etc.), accordance with the Statement of Compliance Registry Criteria, Rev. 5.0.
Jointly‐owned units should be reported by the operating entity.
For combined‐cycle plants, the combustion turbines and heat‐recovery (steam turbine)
units should be reported separately.
Wind farms should report on a point‐of‐interconnection basis.
If the unit is operable in more than one interconnection, complete the survey for
operation in each of the interconnections.
NOTE: The 256‐character limitation noted on the spreadsheet is a Microsoft Excel limitation on
characters in a cell. If additional space is needed, please supply supplemental documentation
as necessary.
When responding, please upload your response and any supporting documentation through the
NERC Secure Alerts System
General Questions
1.
Does your organization have a formal policy on the installation and operation of
generator governors?
Does your organization have a testing procedure for governors? If so, how often are
they tested?
2.
Unit‐Specific Questions
The following questions will all apply to each generator:
1.
J‐1
Unit name and number.
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004282
Appendix J– Generator Governor Survey Instructions
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
Balancing Authority (BA) in which the generator is operated (pull‐down).
a. If operable in more than one, please note all applicable BAs.
b. If operable in more than one interconnection, complete the survey for operation
in each of the interconnections.
Unit seasonal Net MW ratings normally reported to NERC for resource adequacy
analyses:
a. Summer Net MW rating
b. Winter Net MW rating
Prime mover (steam turbine, combustion turbine, wind turbine, etc. — pull‐down)
Fuel type (coal, oil, nuclear, etc. — pull‐down)
Unit inertia constant (H) as modeled in dynamics analyses – the combined kinetic
energy of the generator and prime‐mover in watt‐seconds at rated speed divided by
the VA (Volt‐Ampere) base.
What are the annual run hours for the unit (data for each of the last 3 years)?
What is the continuous MW rating (Pmax) of the unit?
What percent of time does the unit run at Pmax or valves wide‐open?
a. 0 to 30%
b. 31% to 60%
c. 61% to 100%
Equipped with a Governor? (Y/N) If not, no further answers are necessary.
If yes, is the governor operational? (Y/N with a comment box) If not, please explain.
a. Is the governor normally in operation? (Y/N with a comment box) (even if not
normally operated, the data on the governor is still needed)
b. What is the normal governor mode of operation? (pull‐down)
c. Is the governor response sustainable for more than one minute if conditions
remain outside of the deadband? (Y/N)
d. Are there any regulatory restrictions regarding the operation of the governor?
This should cover nuclear regulation, environmental restrictions (water
temperature, emissions), water flow, etc.
e. Does the governor respond beyond the high/low operating limit (boiler blocks)?
(Y/N)
f. Is the governor response limited by the rate of change? (Y/N)
g. Are there any other unit‐level or plant‐level control schemes that would override
or limit governor performance? If yes, please explain.
Governor Type?
Electronic (analog electro‐hydraulic);
DEH (digital electro hydraulic);
Mechanical;
Other — please specify.
Governor manufacturer and model?
a. If mixed vendor equipment is installed, please explain.
Governor Deadband setting?
a. Deadband in(+/‐) mHz
Frequency Response Initiative Report – October 2012
K‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004283
Appendix J– Generator Governor Survey Instructions
15.
16.
i. If in mHz is the deadband centered around a frequency reference (60 Hz
or current frequency)?
b. Deadband in (+/‐) RPM
i. For RPM specify number of machine poles
ii. If in RPM, is the RPM reference nominal or current RPM?
c. What is the basis for this setting?
d. Once activated, what are the conditions for which the governor action is reset?
What is the percentage (%) droop setting on the governor?
a. What is the basis for the droop setting?
Does the unit Frequency Response step into the droop curve or is it linear from the
deadband?
Capability (MW) 600.000
Frequency Response
Deadband Setting
0.036
Hz
150.00
100.00
MW Change
50.00
0.00
Step response at
dead-band.
-50.00
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
Droop Setting 5.00%
Step Implementation (step): When frequency crosses the governor dead‐band
setting the output of the governor “steps” into the 5% droop curve as if the dead‐
band did not exist.
J‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004284
Appendix J– Generator Governor Survey Instructions
Capability (MW) 600.000
Frequency Response
Deadband Setting
0.0166
Hz
150.00
100.00
MW Change
50.00
0.00
-50.00
No Step response at
dead-band.
-100.00
-150.00
59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50
Hz
Droop Setting 5.00%
Without Step Implementation (linear): When frequency crosses the governor dead‐
band setting the output of the governor adds proportional output toward the droop
curve end point.
17.
18.
Prime mover control mode – What is the normally used Turbine Control mode(s)? If
more than one is prevalently used, select a primary and explain.
Turbine manual
Thermally‐limited
Turbine following
Boiler following
Part‐load
Pre‐select
MW set point
Coordinated control
Other (please explain) If more than one is prevalently used, select a primary and
explain.
Do market rules restrict or override governor speed controls? (Y/N) If yes, please
explain.
For steam generator controls (boiler controls) or combined cycle central
station controls:
19.
Does the boiler control or combined cycle central station control have a frequency
input? (Y/N) If yes, answer the following questions:
a. Deadband in(+/‐) mHz
i. If in mHz is the deadband centered around a frequency reference (60 Hz
or current frequency)?
Frequency Response Initiative Report – October 2012
K‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004285
Appendix J– Generator Governor Survey Instructions
20.
21.
22.
23.
24.
b. Deadband in (+/‐) RPM
i. For RPM specify number of machine Poles
ii. If in RPM, is the RPM reference nominal or current RPM?
c. What is the basis for this setting?
Does the control’s Frequency Response step into the droop curve or is it linear from
the deadband?
What is the steam turbine control mode? (boiler following, turbine following,
coordinated control)
Do the unit or plant controls over‐ride governor speed control or are the control
parameters supportive? (Y/N)
Does the boiler operate under variable/sliding pressure? (Y/N)
a. What is the control/governor valve position percentage (%) during variable
pressure operation?
Do unit or plant economic controls over‐ride governor speed control? (Y/N)
Event Performance Data
The following five questions are to be answered for each generator to ascertain its performance
during the specified frequency events (one per interconnection). The frequency events data to
be reported are:
Interconnection
Date
Time
Time Zone
Eastern
8/16/2010
14:25:29
CST
Western
8/12/2010
1:06:15
CST
Texas
8/20/2010
14:44:03
CST
Québec
12/10/2009
15:09:31
EST
25.
Was the unit on‐line during the event? (Y/N)
26.
Pre‐event generation (MW) – Enter the MW output of the generator at the time just
before the event began.
27.
Post‐event generation (MW) – Enter the MW output of the generator after the
event that was reflects the response by the governor to the frequency deviation.
28.
Time to achieve post‐event response (seconds) – Enter the time (in seconds) it took
to achieve the MW response noted in question 27.
29.
Comments (256 characters) – Enter any comments necessary. If no data is available
for the event, note that here.
J‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004286
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004287
Appendix K– Generator Governor Survey Summary
Appendix K – Generator Governor Survey
Summary
The following are slides that summarize the responses of the 2010 Generator Governor Survey.
Deadband Settings
NERC 2010 GO/GOP Survey
Quality of Dead Band Data
100%
90%
21%
80%
23%
35%
37%
Unusable
49%
47%
Usable
70%
60%
50%
40%
79%
77%
65%
63%
30%
53%
51%
20%
10%
0%
East
West
Texas
No. of Units
East
West
Capacity
Texas
3
K‐1
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004288
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Eastern Interconnection Dead Bands and Size of Units
60
55
<500 MW
500-1000 MW
>1000 MW
Summer Capacity (GW)
50
45
40
35
30
25
20
15
10
5
No Response
4
No Response
Deadband (mHz)
No Governor
5000+
500-3250
54-450
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
5
NERC 2010 GO/GOP Survey
Texas Interconnection Dead Bands and Size of Units
60
55
<500 MW
Summer Capacity (GW)
50
500-1000 MW
>1000 MW
45
40
35
30
25
20
15
10
5
5000+
500-3250
54-450
No Governor
Deadband (mHz)
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
Frequency Response Initiative Report – October 2012
K‐2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004289
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Western Interconnection Dead Bands and Size of Units
60
<500 MW
55
500-1000 MW
Summer Capacity (GW)
50
>1000 MW
45
40
35
30
25
20
15
10
5
No Response
Deadband (mHz)
No Governor
5000+
500-3250
54-450
50
40-46
36-36.67
33-34
16-30
15
10-14
1-6
0+ - 0.70
0
0
6
NERC 2010 GO/GOP Survey
Interconnection Dead Bands Range and Size of Units
400
700
700
<500 MW
500-1000
MW
2000
540
Deadband Setting (mHz)
350
300
250
200
150
100
50
0
East
>1000 MW
<500 MW
500-1000
MW
West
>1000 MW
<500 MW
500-1000
MW
Texas
>1000 MW
7
Unit Size
K‐3
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004290
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Interconnection Dead Bands References
N/A, 287, 14%
Texas
N/A, 96, 10%
Eastern
Other, 28, 3%
Other, 41, 2%
60 Hz, 993,
46%
Current
Frequency,
244, 25%
60 Hz, 591,
62%
Current
Frequency,
796, 38%
Current
Frequency, 81,
24%
Other, 6, 2%N/A, 7, 2%
Western
8
60 Hz, 250,
72%
Droop Settings
NERC 2010 GO/GOP Survey
Quality of Droop data
Usable
100%
Unusable
5%
6%
11%
13%
13%
87%
87%
Texas
East
15%
90%
80%
70%
60%
50%
95%
94%
89%
85%
40%
30%
20%
10%
0%
East
West
No. of units
West
Texas
10
Capacity
Frequency Response Initiative Report – October 2012
K‐4
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004291
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Droop Settings by Number of Units
1400
East
1200
West
Texas
# of Units
1000
800
600
400
Nuclear governor
blocked
No Response
5.1‐10
5
4.01‐4.97
4
1‐3.98
.0509‐.5
0.05
.0404‐.0495
0.04
.0326‐.0396
.00128‐.03
0
0
Droop Settings (%)
Researching
200
11
NERC 2010 GO/GOP Survey
Droop Settings by Capacity
250
East
West
Texas
225
Summer Capacity (MW)
200
175
150
125
100
75
50
Researching
5.1‐10
5
No Response
Droop Settings (%)
4.01‐4.97
4
1‐3.98
.0509‐.5
0.05
.0404‐.0495
0.04
.0326‐.0396
.00128‐.03
0
0
Nuclear governor
blocked
25
12
K‐5
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004292
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Droop Settings by Capacity Class
10
9
Droop Setting (%)
8
7
6
5
4
3
2
1
0
<500 MW
500-1000
MW
>1000 MW
<500 MW
500-1000
MW
East
>1000 MW
West
<500 MW
500-1000
MW
>1000 MW
Texas
13
Unit Size
Results of Other Survey Questions
NERC 2010 GO/GOP Survey
Survey Question: Equipped with Governor?
20, 1%
162, 4%
0, 0%
0, 0%
114, 7%
171, 4%
8, 2%
0, 0%
50, 11%
1429, 92%
4208, 92%
Western
Eastern
399, 87%
Texas
Yes
No
N/A
Unknown
15
Frequency Response Initiative Report – October 2012
K‐6
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004293
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Is Governor Operational?
21, 1%
128, 3%
0, 0%
26, 1%
30, 2%
39, 1%
1, 0%
0, 0%
4, 1%
1378, 97%
4015, 95%
Western
Eastern
394, 99%
Texas
Yes
No
N/A
Unknown
16
NERC 2010 GO/GOP Survey
Survey Question: Is Governor Response sustainable for more
than 1 minute if conditions remain outside of deadband?
117, 8%
0, 0%
480, 11%
99, 7%
9, 0%
360, 9%
37, 9%
2, 1%
27, 7%
1213, 85%
3359, 80%
Western
Eastern
333, 83%
Texas
Yes
No
N/A
Unknown
17
K‐7
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004294
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Does governor respond beyond the high/low
operating limit (boiler blocks)?
179, 13%
598, 14%
306, 21%
0, 0%
63, 1%
1533, 36%
58, 15%
97, 24%
17, 4%
2014, 49%
944, 66%
Western
Eastern
227, 57%
Texas
Yes
No
N/A
Unknown
18
NERC 2010 GO/GOP Survey
Survey Question: Is the governor response limited by the rate
of change? (Filter: Governor Yes)
72, 5%
0, 0%
470, 11%
949, 23%
2, 0%
554, 39%
34, 9%
803, 56%
2, 1%
121, 30%
2787, 66%
Western
Eastern
242, 60%
Texas
Yes
No
N/A
Unknown
19
Frequency Response Initiative Report – October 2012
K‐8
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004295
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Are there any other unit-level or plant-level control
schemes that override or limit governor performance? (Filter: Governor
Yes)
65, 5%
337, 8%
0, 0%
27, 1%
700, 49%
2026, 48%
664, 46%
32, 8%
1818, 43%
2, 1%
Eastern
197, 49%
Western
168, 42%
Texas
Yes
No
N/A
Unknown
20
NERC 2010 GO/GOP Survey
Survey Question: Do market rules restrict or override governor
speed controls? (Filter: Governor Yes)
206, 5%
13, 0%
28, 2%
7, 0%
0, 0%
23, 1%
4, 1%
2, 1% 1, 0%
3966, 94%
1394, 98%
Western
Eastern
392, 98%
Texas
Yes
No
N/A
Unknown
21
K‐9
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004296
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Does the boiler control or combined cycle
central control have a frequency input?
46, 3%
298, 7%
414, 29%
2039, 48%
1549, 37%
892, 63%
79, 20%
77, 5%
124, 31%
322, 8%
Eastern
Western
50, 13%
146, 36%
Texas
Yes
No
N/A
Unknown
22
NERC 2010 GO/GOP Survey
Survey Question: Does the boiler operate under variable
pressure?
151, 11%
169, 12%
394, 9%
1030, 24%
127, 9%
2431, 59%
72, 18%
982, 68%
353, 8%
194, 49%
Eastern
68, 17%
Texas
Yes
No
N/A
Western
65, 16%
Unknown
23
Frequency Response Initiative Report – October 2012
K‐10
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004297
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Survey Question: Do unit or plant economic controls override
governor speed control?
16, 1%
48, 1%
380, 27%
1700, 40%
2173, 52%
0, 0%
114, 8%
919, 64%
287, 7%
172, 43%
Eastern
185, 46%
Western
42, 11%
Texas
Yes
No
N/A
Unknown
24
Survey Event Data
NERC 2010 GO/GOP Survey
Unit Status by Number
West
East
Unknown,
185, 12%
Unknown,
566, 12%
Offline
Generation,
566, 36%
Offline
Generation,
2197, 49%
Online
Generation,
1778, 39%
Texas
Unknown, 57,
12%
Online
Generation,
300, 66%
Online
Generation,
Offline 808, 52%
Generation,
100, 22%
26
K‐11
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004298
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Unit Status by Capacity (GW)
West
East
Unknown,
17.7, 11%
Unknown,
48.1, 7%
Offline
Generation,
51.2, 31%
Offline
Generation,
186.0, 29%
Texas
Offline
Generation,
9.6, 12%
Unknown,
10.6, 13%
Online
Generation,
415.4, 64%
Online
Generation,
97.5, 58%
27
Online
Generation,
59.8, 75%
NERC 2010 GO/GOP Survey
Response of Online Units by Number
West
East
Online, No
Data on
Response,
291, 16%
Online, No
Data on
Response, 46,
6%
Expected
Response,
471, 26%
Expected
Response,
355, 44%
No Response,
302, 37%
Online, No
Opposite of
Data on
Expected Response, 43,
Response,
14%
272, 15%
No Response,
744, 43%
Texas
Expected
Response,
137, 46%
No Response,
61, 20%
Opposite of
Expected
Response, 59,
20%
Opposite of
Expected
Response,
105, 13%
28
Frequency Response Initiative Report – October 2012
K‐12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004299
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Response of Online Units by Capacity (GW)
East
West
Online, No
Data on
Response,
53.2, 13%
Expected
Response,
124.7, 30%
Online, No
Data on
Response,
3.4, 4%
Expected
Response,
42.7, 44%
No Response,
34.6, 35%
Texas
No Response,
159.9, 38%
Online, No
Data on
Response,
8.6, 14%
Opposite of
Expected
Response,
77.6, 19%
Opposite of
Expected
Response,
16.9, 17%
No Response,
7.8, 13%
Expected
Response,
31.6, 53%
Opposite of
Expected
Response,
11.8, 20%
29
NERC 2010 GO/GOP Survey
Response of All Units by Number
West
East
Online, No
Data on
Response,
291, 6%
No Response,
744, 17%
No Response,
302, 19%
Offline
Generation,
2197, 49%
Opposite of
Expected
Response,
272, 6%
Expected
Response,
471, 10%
Texas
Online, No
Data on
Response, 43,
9%
Offline
Generation,
100, 22%
No Response,
61, 13%
Unknown,
566, 12%
Opposite of
Expected
Response,
105, 7%
Expected
Response,
355, 23%
Online, No
Data on
Response, 46,
3%
Offline
Generation,
566, 36%
Unknown,
185, 12%
Unknown, 57
12%
Opposite of
Expected
Response, 59,
13%
Expected
Response,
137, 31%
30
K‐13
Frequency Response Initiative Report – October 2012
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004300
Appendix K– Generator Governor Survey Summary
NERC 2010 GO/GOP Survey
Response of All Units by Capacity (GW)
Online, No
Data on
Response,
53.2, 8%
West
East
Offline
Generation,
186.0, 29%
No Response,
34.6, 21%
Offline
Generation,
51.2, 30%
No Response,
159.9, 25%
Texas
Unknown,
48.1, 7%
Opposite of
Expected
Response,
77.6, 12%
Online, No
Data on
Response,
3.4, 2%
Expected
Response,
124.7, 19%
Online, No
Response
Data, 8.6 GW
Offline
Generation,
9.6, 12%
No Response,
7.8, 10%
Opposite of
Expected
Response,
16.9, 10%
Unknown,
10.6, 13%
Unknown,
17.7, 11%
Expected
Response,
42.7, 26%
Opposite of
Expected
Response,
11.8, 15%
Expected
Response,
31.6, 39%
31
Frequency Response Initiative Report – October 2012
K‐14
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004301
Appendix L – References
Appendix L – References
Training Document ‐ Policy 1 Generation Control and Performance, February 24, 2003. NERC
Niemeyer, S. Frequency Regulation—Is Your Plant Compliant?
Ibrahim Abdur‐Rahman, Sydney & Ricardo Vera, PE
Eto, J.H. et al. 2010. Use of Frequency Response Metrics to Assess the Planning and Operating
Requirements for Reliable Integration of Variable Renewable Generation. LBNL‐4143E.
Berkeley: Lawrence Berkeley National Laboratory
Analysis of Eastern Interconnection Frequency Response, February 2011. NERC
L‐1
Frequency Response Initiative Report – October 2012
004302
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met
and cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's
data from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
004303
Balancing Authority
Event
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
Date/Time (t-0)
BA Time
BA
Time
Zone
NERC FRS FORM 1 20 to 52 second Value B
MyBA
BA
DelFreq
Time
BA
Relay Lmt
Bias
R1
DelFreq DelFreq
Value "A" Information
Value "B" Information
Enter Addition Data in column W ==>
SEFRD (FRM)
Exclude for
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz) data error *
Information
Value "A"
Value "B"
Enter Data in Green Highlighted Cells
NAI
Adjustment
NAI
Adjustment
1
2
3
4
5
6
7
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
N
N
N
N
N
N
N
N
N
N
N
Send copy to:
12
13
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Y
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
15
16
17
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
20
21
22
23
24
25
26
27
28
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
CST
CST
CST
CST
CST
CST
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Y
Y
Y
Y
Y
Y
Fixed
0.90%
621018
#DIV/0!
#DIV/0!
#DIV/0!
n/a
-20.87
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
31
32
33
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
1901
Eastern
MyBA
-964
1900
#DIV/0!
[email protected]
Load
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
Contact Name
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.058
-0.066
-0.040
-0.05252493
-0.07090523
-0.05190677
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
23.2
27.7
10.7
80.66089
-26.8976
9.955449
3.367024
36.33443
0.488253
2.758037
13.64342
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
0.0
0.0
-0.04999924
-0.052
11.10075
-19.9068
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05849838
-0.04850006
-0.04500008
-0.03750229
-0.04750061
0.750192
2.230058
9.477859
0.355309
2.170702
Bias Type utilized.
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: May be set to a value between 100% to 125% of its FRM if this value is more negative than the minimum Bias based on
Peak Demand. If not more negative, then the Bias must be the minimum Bias based on Peak Demand. If variable Bias is used, enter "Variable".
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.05550003
-0.047
-0.06
-0.06
-0.051
-0.1
29.38207
4.601381
1.593515
52.37091
33.94787
100
BA Bias Type and Bias Setting
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
#DIV/0!
1901 Frequency Bias Setting - (minimum of 100% to 125% of FRM, or 0.9% of Historical Peak Demand if not Variable)
0.0
0.0
0.0
0.0
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
#DIV/0!
0.00
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
34
35
36
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
0.00
0.00
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.0
0.0
37
38
39
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
N
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.0
0.0
40
41
42
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Y
Bias -MW/0.1 Hz
0.0
0.0
0.0
0.0
0.0
0.0
N
Reason(s)
Current data year (December thru November)
1901 BA Frequency Response Obligation (FRO) for next year's FRM
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
Calculate Regression
Bias -MW/0.1 Hz
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
BA Delta
10 X BA
10 X BA
SEFRDB
SEFRDR
Regression
NAI
DelFreq
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For Bias For R1
For Bias
Select Reason(s) for adjustment
Load
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Balancing Authority
Fixed
Variable
Relay Limits
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
MyBA_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
ERCOT
59.5
59.3
60.5
60.7
HQ
58.5
61.5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
595
595
595
595
595
595
595
595
595
595
595
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0
0
0
0
0
1
0
#NUM!
0
0
0
0 For R1
0
0
0
0
0
1
0
#NUM!
0
0
595
#DIV/0!
0
0
0
#N/A
0
12
0
0
#N/A
0
11
0
004304
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
#DIV/0!
0
004305
Balancing Authority
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
MyBA
DelFreq
JOU
Dynamic
Schedules
Non
conforming
Load
Pumped Hydro
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Contingent BA
Adjustment
Net Total
Adjustments
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value
B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment which is
only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
004306
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
Time
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
MyBA
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
004307
Average P.U. Performance
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
BA Performance
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping Frequency
BA
BA
Actual
Schedules
Load
Hydro
Units
Response Lost Generation
Bias
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+) Setting
Hz
MW
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
Value B
BA
Load
MW
Bias
Setting
EPFR
MW
#DIV/0!
#DIV/0!
#DIV/0!
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
#DIV/0!
20 to 52 second Average Period Evaluation
JOU
NonTransferred
Contingent
Net
Dynamic
Conforming
Pumped
Ramping
Frequency
BA
Actual
Schedules
Load
Hydro
Units
Response
Lost Generation
Frequency Interchange Imp(-) Exp (+) Load (-) Load (-) Gen (+) Gen (+) Rec (-) Del (+) Load (-) Gen (+)
Hz
MW
MW
MW
MW
MW
MW
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Unadjusted
Bias While
PFR
PFR
Hz > +/-0.036 Performance Performance
Hz
@ T(+46)
@ T(+76)
MW/0.1 Hz
P.U.
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
Adjusted
Adjusted
PFR
PFR
PFR
Performance Performance Performance
@ T(+166)
@ T(+46)
@ T(+76)
P.U.
P.U.
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz MW/0.1 Hz
004308
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
004309
004310
004311
004312
004313
004314
004315
004316
004317
004318
004319
004320
004321
MyBA
1.20
MyBA
T20 to T52 Average Performance
Initial Performance Adjusted P.U. Based on Bias Setting
Event Recovery Period Average Performance
FRI - NERC Frequency Response Initiative
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
#DIV/0 Average P.U. Performance
#DIV/0! MW/0.1 Hz Median
1.00
0.80
0.80
P.U.
1.00
0.60
0.60
0.40
0.40
0.20
0.20
0.00
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
Initial Performance Adjusted P.U.
8
9
10
11
12
MyBA
Sustained Performance P.U.
Performance based on Hz at T+76
MyBA
Performance based on Hz at T+46
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
0.800
0.800
P.U.
1.000
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
1
12
3
4
5
Performance based on Hz at T+106
6
7
8
9
10
11
12
Performance based on Hz at T+136
MyBA
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Event
Event
MyBA
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
0.800
0.800
P.U.
1.000
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
2
3
4
5
6
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
MyBA
1
2
Event
Adjusted PFR Performance @ T(+106) P.U.
1.200
1
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
004322
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will
appear in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met
and cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's
data from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on
the Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
004323
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
ERCOT
Enter Addition Data in column W ==>
Select Reason(s) for adjustment
Information
BA
Time
Zone
BA
Time
BA
Bias
DelFreq
MW/Load Lost
Adjustment
Load
Load
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1901
Bias Calculation Form 1 for Year
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
ERCOT
Interconnection
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
ERCOT
Balancing Authority
0.0
0.0
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
Contact Name
0.0
0.0
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
N
N
N
N
1
1
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-286
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1900
Current data year (December thru November)
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-286.00
1901 BA Frequency Response Obligation (FRO) for next year's FRM
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-286.00
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
BA Bias Type and Bias Setting
0.0
0.0
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
Fixed
Bias Type utilized.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.90%
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
65300
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-587.70
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
n/a
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-653.00
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0:00:00
0.000
0.000
0.0
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0:00:00
0.000
0:00:00
0:00:00
0.000
0.000
0:00:00
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq MW/Load Lost
Adjustment
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
Value "A"
[email protected]
Calculate Regression
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
0.0
Value "B"
0.0
Y
Y
-653.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
0.0
Y
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-529.36
#DIV/0!
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-529.36
0.00
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
0.000
0.0
0.0
0.0
0.0
Y
N
Do you RECEIVE Overlap regulation?
0.0
0.0
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
Bias -MW/0.1 Hz
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Bias -MW/0.1 Hz
Enter data in all green cells on this "Data Entry" worksheet.
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
ERCOT_1901_FRS_Form_1.9.xlsm
Balancing Authority
Reason(s)
004324
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the linear
regression.
BA Delta
NAI
-0.058
23.2
-0.066
27.7
-0.040
10.7
-0.05252493
80.66089
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
-0.07090523 -26.89761
-0.05190677
9.955449
-0.0580477
3.367024
-0.07557242
-0.0563805
-0.0573329
-0.0517609
36.33443
0.488253
2.758037
13.64342
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
-0.05849838
0.750192
-0.04850006
2.230058
-0.04500008
9.477859
-0.03750229
-0.04750061
0.355309
2.170702
-0.05550003
29.38207
-0.047
4.601381
-0.06
1.593515
-0.06
52.37091
-0.051
33.94787
-0.1
100
N
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Y
N
Y
Fixed
Variable
Relay Limits
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
DelFreq
For Bias
421.08749
-1.014658
726.02426
-1.212405
518.4755
-0.89661
10 X BA
DelFreq
For R1
SEFRDB
SEFRDR
(MW/0.1Hz) (MW/0.1Hz)
Regression
Statistics
For Bias
-1.014658 -415.00442
-1.212405
-598.8298
-415.00442
-0.89661 -578.26195
-1.445673 -543.37416
-578.26195 0.987084 75.02074
-529.362
-598.8298 18.25749
0
#N/A
785.54117
-1.445673
-543.37416
840.664
691.80448
-520.50213
4731351 61909.23
661.23172
-1.32911
-1.32911 -520.50213
0.3558911 0.3558911 -635.70015
-1.311035 -1.311035
-504.3586
995.08267
533.32526
762.32339
480.61002
-1.97183
-0.920725
-1.179408
-0.929121
-504.6492 -529.362
0
-579.24498 18.25749
#N/A
-646.3608 0.987084 75.02074
-517.2738 840.664
11
386.25
-0.942728
-226.24
-1.97183
-504.6492
-0.920725 -579.24498
-1.179408
-646.3608
-0.929121
-517.2738
-0.942728 -409.71529
11
-635.70015
-504.3586 For R1
-409.71529
4731351 61909.23
004325
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
004326
Balancing Authority ERCOT
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
DelFreq
Load
Resources
Tripped
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value
B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment which is
only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
004327
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Maximum
FBS* for
month
Time
weighted **
Time
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
Balancing Authority:
ERCOT
1899 Reporting period FRS Form 1 data
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
004328
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
004329
Average P.U. Performance
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
eriod Evaluation
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Unadjusted
Bias While
PFR
PFR
Hz > +/-0.036 Performance Performance
Hz
@ T(+46)
@ T(+76)
MW/0.1 Hz
P.U.
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
Adjusted
Adjusted
PFR
PFR
PFR
Performance Performance Performance
@ T(+166)
@ T(+46)
@ T(+76)
P.U.
P.U.
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
004330
Full name
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
004331
ERCOT
ERCOT
T20 to T52 Average Performance
Initial Performance Adjusted P.U. Based on Bias Setting
1.00
1.00
0.80
0.80
0.60
0.40
0.20
0.20
0.00
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
ERCOT
9
10
11
12
Performance based on Hz at T+76
ERCOT
Performance based on Hz at T+46
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
8
Sustained Performance P.U.
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
1
12
3
4
5
Performance based on Hz at T+106
ERCOT
6
7
8
9
10
11
12
Performance based on Hz at T+136
ERCOT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U. @Based
on Bias Setting
1.200
2
Event
Event
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
1.000
1.000
0.800
0.800
P.U.
P.U.
FRI - NERC Frequency Response Initiative
0.60
0.40
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
Performance based on Hz at T+166
ERCOT
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
8
Adjusted PFR Performance @ T(+136) P.U.
T+166 Performance Adjusted P.U. Based on Bias Setting
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
Event Recovery Period Average Performance
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
#DIV/0 Average P.U. Performance
#DIV/0! MW/0.1 Hz Median
P.U.
P.U.
1.20
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
9
10
11
12
9
10
11
12
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will appear
in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on the
Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
004332
Balancing Authority
NERC FRS FORM 1 20 to 52 second Value B
HQT
Enter Addition Data in column W ==>
Inform
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
Date/Time (t-0)
Time
BA
Bias
DelFreq
MW/Load Lost
Adjustment
1
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
2
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
3
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
4
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1901
5
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
HQ
HQT
BA Time
BA
Time
Zone
BA
DelFreq
Relay Lmt
Value "A" Information
R1
DelFreq
MW/Load Lost
Adjustment
Value "B" Information
SEFRD (FRM)
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz)
Exclude for
Enter Data in Green Highlighted Cells
data error *
Send copy to:
[email protected]
Bias Calculation Form 1 for Year
Interconnection
Balancing Authority
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Event
Value "A"
004333
Load
0.0
0.0
0.0
0.0
0.0
6
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
7
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
N
N
N
N
1
1
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
12
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
0.0
13
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
15
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1900
Current data year (December thru November)
0.0
16
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179.00
1901 BA Frequency Response Obligation (FRO) for next year's FRM
17
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179.00
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
18
19
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
Calculate Regression
BA Bias Type and Bias Setting
0.0
0.0
Contact Name
0.0
0.0
0.0
0.0
20
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
Fixed
Bias Type utilized.
21
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.90%
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
0.0
22
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
37153
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
0.0
23
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-334.38
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
0.0
24
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.0
25
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
0.0
26
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
n/a
27
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-442.00
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-442.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
31
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
0.0
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.00
#DIV/0!
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
32
33
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
0.0
0.0
0.0
0.0
0.0
0.0
34
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
0.0
35
36
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.00
0.00
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
N
37
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
38
39
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
40
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
41
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
42
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
Do you RECEIVE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA in the table below.
Bias -MW/0.1 Hz
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
Bias -MW/0.1 Hz
Instructions
Step 1
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of this
workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
HQT_1901_FRS_Form_1.9.xlsm
Balancing Authority
0.0
0.0
0.0
0.0
0.0
0.0
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the linear
regression.
Value "B"
Load
Reason(s)
0.0
-0.058
23.2
0.0
-0.066
27.7
-0.040
10.7
0.0
0.0
-0.05252493 80.660891
0.0
-0.07090523 -26.89761
0.0
-0.05190677 9.9554492
0.0
-0.0580477
3.367024
0.0
0.0
0.0
0.0
-0.07557242 36.334427
-0.0563805 0.488253
-0.0573329 2.7580369
-0.0517609 13.643417
0.0
-0.04999924 11.100746
0.0
-0.052 -19.90685
0.0
-0.05599976 12.325464
0.0
-0.05849838 0.7501918
0.0
-0.04850006 2.2300578
0.0
-0.04500008 9.4778593
0.0
0.0
-0.03750229 0.355309
-0.04750061 2.1707019
0.0
-0.05550003 29.382074
0.0
-0.047 4.6013813
0.0
-0.06 1.5935149
0.0
-0.06 52.370908
0.0
-0.051 33.947874
0.0
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
-0.1
100
0.0
0.0
0.0
0.0
0.0
N
0.0
Y
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
N
Y
Fixed
Variable
Relay Limits
Eastern
59.5
Western
59.5
60.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Select Reason(s) for adjustment
Information
BA Delta
NAI
10 X BA
DelFreq
For Bias
10 X BA
DelFreq
For R1
SEFRDB
SEFRDR
(MW/0.1Hz) (MW/0.1Hz)
004334
Regression
Statistics
For Bias
0
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
0
0
0
#DIV/0!
0
0
0
0
#DIV/0!
0
0
0
0
#DIV/0!
0
0
0
0
#DIV/0!
0
0
0
0
#DIV/0!
0 For R1
0
0
0
0
0
0
0
0
0
0
0
0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0
0
0
0
0
0
0
#DIV/0!
0
0
#N/A
1
0
#NUM!
12
0
0
0
1
#NUM!
0
0
0
#N/A
0
12
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
004335
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
HQT
DelFreq
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
Load
Resources
Tripped
004336
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Sign Convention for scan
data collected in Form 2
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
Instructions for utilizing Adjustments:
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
004337
Maximum
FBS* for
month
Balancing Authority:
HQT
1899 Reporting period FRS Form 1 data
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
004338
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Date
Date/Time
Event
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
004339
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Average P.U. Performance
eriod Evaluation
004340
#DIV/0!
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Full name
004341
Initial Performance Adjusted P.U. Based on Bias Setting
1.20
#DIV/0! MW/0.1 Hz Median
Event Recovery Period Average Performance
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
#DIV/0 Average P.U. Performance
1.00
1.00
0.80
0.80
P.U.
P.U.
HQT
T20 to T52 Average Performance
0.60
0.60
0.40
0.40
0.20
0.20
0.00
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
Initial Performance Adjusted P.U.
Sustained Performance P.U.
HQT
HQT
Performance based on Hz at T+46
1.000
1.000
0.800
0.800
0.600
8
9
10
11
12
Performance based on Hz at T+76
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
P.U.
P.U.
7
Event
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
HQT
004342
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
Event
8
9
10
11
12
1
2
3
4
5
6
7
Event
8
9
10
11
12
HQT
Adjusted
PFR Performance
@ T(+46) P.U.
T+106 Performance
Adjusted
P.U. Based
on Bias Setting
1.200
1.000
1.000
0.800
0.800
0.600
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
HQT
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
P.U.
0.600
0.400
9
10
11
12
004343
Performance based on Hz at T+136
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
P.U.
P.U.
Performance based on Hz at T+106
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Event
Event
HQT
9
10
11
12
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
FRI - NERC Frequency Response Initiative
004344
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
MyBA
DelFreq
Non
conforming
Load
Pumped Hydro
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Transferred
Frequency
Response
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
JOU
Dynamic
Schedules
004345
Contingent BA
Adjustment
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
Instructions for utilizing Adjustments:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Sign Convention for scan
data collected in Form 2
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
004346
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will appear
in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on the
Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
004347
UTC (t-0)
Date/Time (t-0)
Time
Number
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
1
2
01/00/1900 6:00:00
CST
01/00/1900 6:00:00
CST
Date/Time (t-0)
BA Time
1/0/1900 1:00:00
1/0/1900 1:00:00
BA
Time
Zone
CDT
CDT
NERC FRS FORM 1 20 to 52 second Value B
ERCOT
BA
DelFreq
Time
0:00:00
0:00:00
BA
Relay Lmt
Value "A" Information
Bias
R1
DelFreq
DelFreq MW/Load Lost
Adjustment
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
Value "B" Information
MW/Load Lost
0.0
0.0
Adjustment
0.0
0.0
Enter Addition Data in column W ==>
SEFRD (FRM)
Exclude for
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz) data error *
#DIV/0!
#DIV/0!
0.0
0.0
Send copy to:
0.0
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1901
5
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
6
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
7
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
N
N
N
N
0.0
#DIV/0!
0.0
12
01/00/1900 6:00:00
CST
01/00/1900 6:00:00
CST
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
N
Y
Y
10.7
80.66089
ERCOT
Interconnection
0.0
0.0
-0.07090523 -26.89761
ERCOT
Balancing Authority
0.0
0.0
-0.05190677
1
1
1
1
-286
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1900
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-286.00
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
CST
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
23.2
27.7
-0.040
CST
CST
CST
-0.058
-0.066
-0.05252493
01/00/1900 6:00:00
01/00/1900 6:00:00
Reason(s)
0.0
0.0
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
0.0
0.0
0.0
0.0
15
17
Load
Select Reason(s) for adjustment
Bias Calculation Form 1 for Year
16
18
19
Load
0.0
01/00/1900 6:00:00
01/00/1900 6:00:00
14
[email protected]
N
N
3
4
13
Information
Value "A"
Value "B"
Enter Data in Green Highlighted Cells
Y
-286.00
Y
Y
Calculate Regression
9.955449
Contact Name
0.0
0.0
-0.0580477
3.367024
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.07557242
-0.0563805
-0.0573329
-0.0517609
36.33443
0.488253
2.758037
13.64342
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
0.0
0.0
0.0
0.0
-0.04999924
11.10075
-0.052 -19.90685
-0.05599976
12.32546
Current data year (December thru November)
0.0
0.0
-0.05849838
0.750192
1901 BA Frequency Response Obligation (FRO) for next year's FRM
0.0
0.0
-0.04850006
2.230058
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
0.0
0.0
0.0
-0.04500008
9.477859
0.0
0.0
-0.03750229
-0.04750061
0.355309
2.170702
20
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
Fixed
Bias Type utilized.
0.0
0.0
-0.05550003
29.38207
21
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.90%
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
0.0
0.0
-0.047
4.601381
BA Bias Type and Bias Setting
22
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
65300
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
23
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-587.70
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
24
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
25
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
26
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
n/a
27
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-653.00
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
31
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.0
0.0
0.0
0.0
1.593515
-0.06
52.37091
0.0
-0.051
33.94787
0.0
-0.1
100
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
-0.06
0.0
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
0.0
0.0
Y
Y
-653.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
N
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
0.0
0.0
Y
32
33
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-529.36
#DIV/0!
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
34
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
0.0
0.0
35
36
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-529.36
0.00
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
37
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
N
Do you RECEIVE Overlap regulation?
0.0
0.0
38
39
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
40
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
41
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
42
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
Bias -MW/0.1 Hz
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Instructions
Step 1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
Event
004348
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
BA Delta
NAI
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Relay Limits
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of
this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
ERCOT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
DelFreq
For Bias
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For R1
For Bias
421.08749
-1.014658 -1.014658 -415.00442 -415.00442 -529.362
726.02426
-1.212405 -1.212405
518.4755
785.54117
691.80448
-0.89661
-598.8298
-598.8298 18.25749
-1.32911
0
#N/A
-0.89661 -578.26195 -578.26195 0.987084 75.02074
-1.445673 -1.445673 -543.37416 -543.37416
-1.32911 -520.50213 -520.50213
840.664
11
4731351 61909.23
-226.24 0.3558911 0.3558911 -635.70015 -635.70015
661.23172
-1.311035 -1.311035
995.08267
533.32526
762.32339
480.61002
-1.97183 -1.97183 -504.6492 -504.6492 -529.362
0
-0.920725 -0.920725 -579.24498 -579.24498 18.25749
#N/A
-1.179408 -1.179408 -646.3608 -646.3608 0.987084 75.02074
-0.929121 -0.929121 -517.2738 -517.2738 840.664
11
-0.942728 -0.942728 -409.71529 -409.71529 4731351 61909.23
386.25
-504.3586
-504.3586 For R1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
004349
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
ERCOT
DelFreq
Load
Resources
Tripped
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
004350
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Sign Convention for scan
data collected in Form 2
Imports: MWs are Exports: MWs are +
Instructions for utilizing Adjustments:
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
004351
Maximum
FBS* for
month
Balancing Authority:
ERCOT
1899 Reporting period FRS Form 1 data
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
004352
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Date
Date/Time
Event
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Value B
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Frequency
Hz
004353
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Average P.U. Performance
eriod Evaluation
004354
#DIV/0!
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Full name
004355
#DIV/0! MW/0.1 Hz Median
#DIV/0 Average P.U. Performance
1.00
1.00
0.80
0.80
0.60
0.60
0.40
0.40
0.20
0.20
0.00
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
ERCOT
Sustained Performance P.U.
0.800
0.800
P.U.
1.000
0.600
8
9
10
11
12
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
004356
Performance based on Hz at T+76
ERCOT
Performance based on Hz at T+46
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
7
Event
Initial Performance Adjusted P.U.
P.U.
Event Recovery Period Average Performance
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
P.U.
P.U.
1.20
ERCOT
T20 to T52 Average Performance
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
ERCOT
Initial Performance Adjusted P.U. Based on Bias Setting
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
7
8
9
10
11
12
Event
Event
Performance based on Hz at T+106
ERCOT
T+106 Performance Adjusted P.U. Based on Bias Setting
0.800
0.800
P.U.
P.U.
1.000
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
2
3
4
5
6
7
8
9
10
11
12
Event
Adjusted PFR Performance @ T(+106) P.U.
Performance based on Hz at T+166
1.000
P.U.
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
8
Adjusted PFR Performance @ T(+136) P.U.
T+166 Performance Adjusted P.U. Based on Bias Setting
1.200
1
Event
ERCOT
9
10
004357
T+136 Performance Adjusted P.U. Based on Bias Setting
1.200
1.000
1
Performance based on Hz at T+136
Adjusted PFR Performance @ T(+76) P.U.
Adjusted PFR Performance @ T(+46) P.U.
1.200
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
ERCOT
11
12
9
10
11
12
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
FRI - NERC Frequency Response Initiative
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
004358
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Instructions
Step 1
Enter data in all green cells on the "Data Entry" worksheet. Cell G1 with the BA name. Cells R11 through R13 with contact information. Cell R24 with BA Bias Type, Fixed or Variable.
Step 2
For identified events in column C of the "Data Entry" worksheet, collect data and complete one FRS Form 2 workbook for each event in the list.
Detailed Instructions for utilizing the "Adjustments" are located on the "Adjustments" worksheet below the table.
Step 3
PasteSpecial/Values data from FRS Form 2 "Form 1 Summary Data" worksheet into "BA Form 2 Event Data" worksheet of this workbook. Do this for each event in the list.
Step 4
Enter FERC Form 714 data from the most recent completed Form 714 in the worksheet "Form 714 Data" in cells C7 through D18. Use Copy/PasteSpecial/Values to enter data.
Your current year's Frequency Response Obligation will be calculated in cell R20 of the "Data Entry" worksheet.
Step 5
a) If a Fixed Bias was selected, cell R27 will calculate the minimum Bias (least negative) allowed based on your Peak Demand or Peak Generation for Generation only BAs.
b) If a Fixed Bias was selected, cell R28 will calculate the minimum (in absolute terms) Bias allowed based on 100% of your FRM.
c) If a Fixed Bias was selected, cell R29 will calculate the maximum Bias (in absolute terms) allowed based on 125% of your FRM.
d) If R29 was more negative than the value in R27, you may choose a Bias setting that is between R29 and the lesser of R27 or R28 and enter it here. Based on your choice, your Bias Setting will appear
in cell R33.
Step 6
a) If a Variable Bias was selected, cell R27 will indicate "not applicable" where there is no maximum or minimum Bias Setting.
b) If a Variable Bias was selected, enter "Variable" in cell R31.
c) If a Variable Bias was selected, cell R30 will calculate the minimum Bias (in absolute terms) allowed based on your FRM and Peak Demand/Peak Generation. Calculate your monthly one minute
average Variable Bias setting when frequency is lower than 59.964 Hz or higher than 60.036 Hz and enter these monthly values on the "Variable Bias Supplemental Info" worksheet in cells B2 through
D13.
d) If the "average annual Variable Bias Setting" in cell D14 on the "Variable Bias Supplemental Info" worksheet is less negative than cell E14 of this worksheet, R3 of the standard has not been met and
cell D14 on the "Variable Bias Supplementa Info" worksheet will turn red. The average minimum Bias Setting will cover two different reporting periods and Cells J3 through K10 require past year's data
from those year's Form 1s for this evaluation.
e) Depending on when the Implementation date is each year for the annual Bias Setting, the ERO may be required to edit the selection of each months' minimum average FBS value. This should be
completed by the ERO before each year's FRS Form 1 is published.
f) The comparison to the FBS minimum will be from two previous year's analysis prior to the current year and the dates in the table starting at J3 will indicate the appropriate year's data to use. For
example, if it is Feb 1, 2013 and you are calculating your 2012 FBS time weigted average, the minimum FBS value will be determined from your FRM that you calculated in Feb of 2012 and based on the
Peak Demand/Peak Gen reported in June of 2011 for 2010 data. Enter each field in green using the appropriate year's data.
Step 7
Two FRMs are calculated. One for the BA Bias Setting and one for meeting R1 of the standard.
The FRM for the BA Bias Setting will use all selected events and all SEFRD values will use the delta frequency as measured.
The FRM for the BA compliance to R1 will limit the delta frequency to no greater than those listed in Table 2 of Attachment A for each Interconnection. (Eastern +/-0.500 Hz, Western +/-0.500 Hz,
ERCOT +/-0.700 Hz and HQ +/-1.500 Hz.)
Step 7
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsx. (where NYISO is replaced with your Balancing Authority abbreviation). See cell "G74" on the Data Entry worksheet for your exact file name.
Step 8
Send completed Form 1 and each Form 2 to NERC.
004359
UTC (t-0)
Date/Time (t-0)
Time
Date/Time (t-0)
Date / Time (MM/DD/YY HH:MM:SS)
(Central Prevailing)
Zone
BA Time
BA
Time
Zone
NERC FRS FORM 1 20 to 52 second Value B
HQT
BA
DelFreq
Time
BA
Relay Lmt
Value "A" Information
Bias
R1
DelFreq
DelFreq MW/Load Lost
Adjustment
Value "B" Information
MW/Load Lost
Adjustment
Enter Addition Data in column W ==>
SEFRD (FRM)
Exclude for
for Bias
for R1
(MW/0.1Hz) (MW/0.1Hz) data error *
Information
Value "A"
Value "B"
Enter Data in Green Highlighted Cells
Send copy to:
[email protected]
Load
Load
Select Reason(s) for adjustment
Reason(s)
1
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
0.0
0.0
-0.058
23.2
2
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
0.0
0.0
-0.066
27.7
3
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
4
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
1901
5
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
HQ
N
HQT
6
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
7
01/00/1900 6:00:00
CST
1/0/1900 1:00:00
CDT
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
#DIV/0!
0.0
N
8
9
10
11
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
CST
CST
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 1:00:00
1/0/1900 0:00:00
CDT
CDT
CDT
CST
0:00:00
0:00:00
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0.0
0.0
0.0
0.0
N
N
N
N
#DIV/0!
0.0
12
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
13
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
14
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
1
1
Y
-179
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
1900
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179.00
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-179.00
Y
Y
Calculate Regression
Interconnection Frequency Response Obligation (FRO) MW/0.1 Hz. Determined by ERO.
0.0
0.0
-0.05599976
12.32546
Current data year (December thru November)
0.0
0.0
-0.05849838
0.750192
1901 BA Frequency Response Obligation (FRO) for next year's FRM
0.0
0.0
-0.04850006
2.230058
1900 BA Frequency Response Obligation (FRO) for this year's FRM from your last year's Form 1.
0.0
-0.04500008
9.477859
-0.03750229
-0.04750061
0.355309
2.170702
Fixed
0.0
-0.05550003
29.38207
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.90%
Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
0.0
0.0
-0.047
4.601381
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
37153
The Sum of the Non-Coincident peak demands for all Bas on the interconnection from FERC Form No. 714, provided by ERO.
0.0
0.0
-0.06
1.593515
23
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-334.38
Your BA's lowest absolute Fixed Frequency Bias Setting based on interconnection non-coincident peak demand.
24
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
25
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
0.000
0.0
0.0
0.0
0.0
26
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
n/a
27
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
-442.00
28
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
0.0
0.0
0.0
Y
1/0/1900 0:00:00
1/0/1900 0:00:00
0.000
0.0
0.0
11.10075
-0.052 -19.90685
CST
0:00:00
0.0
0.0
-0.04999924
CST
CST
0.0
0.0
3.367024
36.33443
0.488253
2.758037
13.64342
01/00/1900 6:00:00
1/0/1900 0:00:00
0.0
0.0
9.955449
-0.0580477
-0.07557242
-0.0563805
-0.0573329
-0.0517609
01/00/1900 6:00:00
CST
0.000
0.000
-0.05190677
0.0
0.0
0.0
0.0
0.0
21
01/00/1900 6:00:00
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
22
20
0:00:00
0:00:00
0.0
Contact Name
0.0
CST
CST
Balancing Authority
Contact Phone #
Contact e-mail
MWh Annual GenBA is the annual "Net Generation (MWh)", FERC Form 714, line 13, column c of Part II - Schedule 3.
MWh Annual LoadBA is the annual "Net Energy for Load (MWh)", FERC Form 714, line 13, column e of Part II - Schedule 3.
0.0
CST
CST
CST
-0.07090523 -26.89761
0.0
1/0/1900 0:00:00
1/0/1900 0:00:00
0.0
0.0
1/0/1900 0:00:00
1/0/1900 0:00:00
1/0/1900 0:00:00
0.0
MWh Annual GenINT is the Sum of all Annual GenBA values in this interconnection
CST
CST
Interconnection
MWh Annual LoadINT is the Sum of all Annual LoadBA values in this interconnection
CST
CST
CST
80.66089
1
01/00/1900 6:00:00
01/00/1900 6:00:00
10.7
-0.05252493
1
01/00/1900 6:00:00
01/00/1900 6:00:00
01/00/1900 6:00:00
-0.040
0.0
N
15
17
0.0
0.0
Y
16
18
19
0.0
Bias Calculation Form 1 for Year
BA Bias Type and Bias Setting
Bias Type utilized.
0.0
Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
Your BA's highest absolute Fixed Bias Setting: 125% of FRM.
0.0
0.0
0.0
Balancing Authority lowest absolute Variable Bias Setting (least negative one minute average Bias while frequency is less than 59.964 or greater than 60.036 Hz).
Balancing Authority desired Bias Setting: Single BA Interconnections have no minimum or maximum Bias Setting requirement. If variable Bias is used, enter "Variable".
0.0
-0.06
52.37091
0.0
-0.051
33.94787
0.0
-0.1
100
0.0
0.0
0.0
0.0
0.0
0.0
29
30
01/00/1900 6:00:00
01/00/1900 6:00:00
CST
CST
1/0/1900 0:00:00
1/0/1900 0:00:00
CST
CST
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
-442.00
1901 Frequency Bias Setting - (Single BA Interconnections have no minimum or maximum Bias Setting requirement)
0.0
0.0
0.0
0.0
N
31
01/00/1900 6:00:00
CST
1/0/1900 0:00:00
CST
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
#DIV/0!
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for Bias
0.0
0.0
Y
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.00
#DIV/0!
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
1900 FRM - Median Estimated Frequency Response MW/0.1Hz using SEFRD for Bias
0.0
0.0
0.0
0.0
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.00
1900 FRM - Average Estimated Frequency Response MW/0.1 Hz using SEFRD for R1
0.0
0.0
35
36
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
0.00
0.00
1900 FRM - Regression Estimated Frequency Response MW/0.1Hz using SEFRD for R1
1900 FRM - Median Estimated Frequency Response MW/0.1Hz for BA Compliance to R1, minimum Frequency Response
0.0
0.0
0.0
0.0
37
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
N
Do you RECEIVE Overlap regulation?
0.0
0.0
38
39
0:00:00
0:00:00
0.000
0.000
0.000
0.000
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Y
Y
If Yes, list the BA name and the associated Bias of that BA in the table below.
0.0
0.0
0.0
0.0
40
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
41
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
42
0:00:00
0.000
0.000
0.0
0.0
0.0
0.0
Y
0.0
0.0
32
33
34
Bias -MW/0.1 Hz
N
Balancing Authority
Do you PROVIDE Overlap regulation?
If Yes, list the BA name and the associated Bias of that BA
N
Y
Bias -MW/0.1 Hz
Balancing Authority
Fixed
Variable
Instructions
Step 1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
Event
Number
Columns BA, BB, BC, BD, BE, BF and BG are reserved for calculation of the
linear regression.
BA Delta
NAI
Dynamic schedules for joint-owned units (DS)
Nonconforming load (NL)
Pumped hydro (PH)
Invalid Data (ID)
Transfered Frequency Response (TFR)
Contingent BA adjustment for loss of units (CBA)
DS & NL
DS & PH
DS & ID
DS & TFR
DS & CBA
DS & NL & PH
DS & NL & ID
JOU DS & NL & TFR
DS & NL & CBA
DS & NL & PH & ID
DS & NL & PH & TFR
DS & NL & PH & CBA
DS & NL & PH & ID & TFR
DS & NL & PH & ID & CBA
DS & NL & PH & ID & TFR & CBA
NL & PH
NL & ID
NL & TFR
NL & CBA
NL & PH & ID
NL & PH & TFR
NL & PH & BAA
NL & PH & ID & TFR
NL & PH & ID & CBA
NL & PH & ID & TFR & CBA
PH & ID
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR
PH & ID & CBA
PH & TFR
PH & CBA
PH & ID & TFR & CBA
RU & TFR
RU & CBA
RU & TFR & CBA
TFR & CBA
Relay Limits
Enter data in all green cells on this "Data Entry" worksheet.
Step 2
For identified events in column B, collect data and complete FRS Form 2.9 for each event in the list.
Step 3
PasteSpecial/Values data from FRS Form 2.9 "Form 1 Summary Data" into "BA Form 2 Data" worksheet of this
workbook. Do this for each event in the list.
Step 4
Save this workbook using the following file name format:NYISO_yyyy_FRS_Form_1.9.xlsm and send a copy of
this workbook and all FRS_Form 2 workbooks to NERC. (where NYISO is replaced with your BA name)
HQT_1901_FRS_Form_1.9.xlsm
Eastern
59.5
60.5
Western
59.5
60.5
ERCOT
59.3
60.7
HQ
58.5
61.5
10 X BA
DelFreq
For Bias
004360
10 X BA
SEFRDB
SEFRDR
Regression
DelFreq (MW/0.1Hz) (MW/0.1Hz)
Statistics
For R1
For Bias
0
0
0
0
0
0
#DIV/0!
#DIV/0!
0
0
0
#DIV/0!
0
0
0
#DIV/0!
0
0
0
0
#DIV/0!
0
0
0
0
0
0
0
0
0
0
#N/A
1
#NUM!
0
12
0
#DIV/0!
0
0
0
0
#DIV/0!
0 For R1
0
0
0
0
0
0
0
0
0
0
0
0
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
0
0
0
0
0
0
0
#DIV/0!
0
0
0
1
#NUM!
0
0
0
#N/A
0
12
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Report 714 Data (in MW)
Part II Schedule 3
Column (b)
Month
January
Column (j)
Peak Demand
February
March
April
May
June
July
August
September
October
November
December
Average
Maximum
Peak Demand: (Your BA from Form 714, column j of Part II - Schedule 3)
#DIV/0!
0
004361
Event
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Date/Time (t-0)
(Central Prevailing)
HQT
Value A
Value B
DelFreq Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Non
conforming
Load
Not Used
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Not Used
Value A
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Value B
Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority
Load
Resources
Tripped
004362
Not Used
Value A
Value B
Adjustment Adjustment
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Net Total
Adjustments
Value B 20 to 52 seconds
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
31
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
32
33
34
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
35
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
36
37
38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
39
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
40
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
41
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
42
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Imports: MWs are Exports: MWs are +
Loads in MW as -
Load MW as Generation MW as +
Enter Gen MW as +
Instructions for utilizing Adjustments:
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Sign Convention for scan
data collected in Form 2
The transactional
amount in
MW Receiver enters Deliverer enters +
on Form 2 Data sheet
Generation MW as +
(If demand occurs due to gen
loss, enter MW as - at value B)
1) Balancing Authorities making adjustments must retain evidence to verify:
- Adjustment values are determined from scan-cycle data using Value A and Value B averaging periods. Scan-cycle data must be available if adjustments are made.
- Adjustments are necessary to improve accuracy of calculations compared to using Net Actual Interchange solely.
Said differently, unless an adjustment compensates for significant known error, it should not be made. However, as noted in the next item, once a decision to include an
adjustment for one or more of the five types is made for one event, the entity must calculate adjustments for that (those) type(s) for all events except for the Contengent BA Adjustment
which is only utilized for the events that you are contengent during that event.
- Adjustments are included consistently for all events (e.g. if adjustments for nonconforming load are made for one event, the load must be included for all events, etc.).
2) Dynamic Schedules:
- Values use schedule sign convention.
- Adjustments should include only dynamic schedules accounting for joint-owned units. Other dynamic schedules should be ignored.
3) Nonconforming Loads:
- Values must be negative numbers.
4) Pumped Hydro:
- Values for pumping must be negative values.
- Values for generating must be positive values.
5) Rampling Units:
- Values are positive values.
6) Transferred Frequency Response:
- This value is the amount agreed upon between the entities expressed in MW/0.1 Hz. Form 2 will adjust this amount for the frequency deviation experienced.
(e.g. if an entity agrees to provide 20 MW/0.1 Hz to another entity and a frequency event with a deviation of 50 mHz occurs, the delivering entity should enter +20 in the
data column of Form 2 and the receiving entity should enter - 20. The spreadsheet will adjust the SEFRD for each entity by the 10 for this event.)
- Values for the entity receiving the response must be entered as a negative number.
- Values for the entity delivering the response must be entered as a positive number.
- Values between entities must sum to zero.
7) Contingent Balancing Authority Adjustment:
- Data for Value A is the pre-contingency scan rate generation (+MW values) from the contingent unit(s).
- Data for Value B is usually 0 MW, but may be the demand (-MW values) that remains on the system that was "netted" out by the now offline generation.
004363
Maximum
FBS* for
month
Balancing Authority:
HQT
1899 Reporting period FRS Form 1 data
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Month
January
Feburary
March
April
May
June
July
August
September
October
November
December
Minimum
FBS* for
month
Time
Time
weighted **
weighted ** minimum
average
average
FBS* for
FBS* for
month
month
004364
0.00 1899 Reporting period: Balancinig Authority FRM MW/0.1 Hz, enter from FRS Form 1 for that year's FRM. If not know enter zero.
1.00% 1899 Reporting period: Interconnection Minimum Fixed Frequency Bias Setting % of Peak Demand or Peak Generation (Set by ERO)
1899 Reporting period: Your BA's Annual Peak Demand or Peak Gen for Gen only BAs from your BA Form 714.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on BA Peak Demand (Peak Generation for Generation only BA) MW/0.1 Hz.
0.00 Your BA's lowest absolute Fixed Frequency Bias Setting based on 100% of FRM.
0.00 1900 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
1899 Minimum, lowest absolute, conditional average Frequency Bias Setting MW/0.1 Hz.
0.0
0.0
1900 Average Annual Bias MW/0.1 Hz
* Frequency Bias Setting (FBS)
** Based on the one minute values used in BAL 001 when frequency is greater than 60.036 Hz or less than 59.964 Hz.
Date
Event
Date/Time
Number (Central Prevailing) DelFreq
1
1/0/1900 0:00
0.000
2
1/0/1900 0:00
0.000
3
1/0/1900 0:00
0.000
4
1/0/1900 0:00
0.000
5
1/0/1900 0:00
0.000
6
1/0/1900 0:00
0.000
7
1/0/1900 0:00
0.000
8
1/0/1900 0:00
0.000
9
1/0/1900 0:00
0.000
10
1/0/1900 0:00
0.000
11
1/0/1900 0:00
0.000
12
1/0/1900 0:00
0.000
13
1/0/1900 0:00
0.000
14
1/0/1900 0:00
0.000
15
1/0/1900 0:00
0.000
16
1/0/1900 0:00
0.000
17
1/0/1900 0:00
0.000
18
1/0/1900 0:00
0.000
19
1/0/1900 0:00
0.000
20
1/0/1900 0:00
0.000
21
1/0/1900 0:00
0.000
22
1/0/1900 0:00
0.000
23
1/0/1900 0:00
0.000
24
1/0/1900 0:00
0.000
25
1/0/1900 0:00
0.000
26
1/0/1900 0:00
0.000
27
1/0/1900 0:00
0.000
28
1/0/1900 0:00
0.000
29
1/0/1900 0:00
0.000
30
1/0/1900 0:00
0.000
31
1/0/1900 0:00
0.000
32
1/0/1900 0:00
0.000
33
1/0/1900 0:00
0.000
34
1/0/1900 0:00
0.000
35
1/0/1900 0:00
0.000
36
1/0/1900 0:00
0.000
37
1/0/1900 0:00
0.000
38
1/0/1900 0:00
0.000
39
1/0/1900 0:00
0.000
40
1/0/1900 0:00
0.000
41
1/0/1900 0:00
0.000
42
1/0/1900 0:00
0.000
A Point
Time
FPointA
Hz
A Value
Hz
t(0) Time
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
BA Performance
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
Spare
MW
Spare
MW
Spare
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Value A Data
PasteSpecial/Values the data copied from FRS Form 2 for each event.
Bias
Setting
EPFR
MW
Value B
Frequency
Hz
004365
20 to 52 second Average
Period Evaluation
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
Spare
MW
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
#DIV/0!
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Average P.U. Performance
riod Evaluation
#DIV/0!
004366
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
Initial
Performance
Adjusted
P.U.
Initial
Performance
Unadjusted
P.U.
Sustained
Performance
P.U.
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
Bias
Setting
EPFR
MW
Average
Unadjusted
Bias While
PFR
Hz > +/-0.036 Performance
Hz
@ T(+46)
MW/0.1 Hz
P.U.
Unadjusted
PFR
Performance
@ T(+76)
P.U.
Unadjusted
PFR
Performance
@ T(+106)
P.U.
Unadjusted
PFR
Performance
@ T(+136)
P.U.
Unadjusted
PFR
Performance
@ T(+166)
P.U.
Adjusted
PFR
Performance
@ T(+46)
P.U.
Adjusted
PFR
Performance
@ T(+76)
P.U.
Adjusted
PFR
Performance
@ T(+106)
P.U.
Adjusted
PFR
Performance
@ T(+136)
P.U.
Adjusted
PFR
Performance
@ T(+166)
P.U.
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
Abbreviat
ion
Offset
Atlantic Daylight Time
ADT
3:00
Atlantic Standard Time
AST
4:00
Central Daylight Time
CDT
5:00
Central Standard Time
CST
6:00
Eastern Daylight Time
EDT
4:00
Eastern Standard Time
EST
5:00
Mountain Daylight Time
MDT
6:00
Mountain Standard Time
MST
7:00
Pacific Daylight Time
PDT
7:00
Pacific Standard Time
PST
8:00
Time
zone
UTC - 3
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 4
hours
UTC - 5
hours
UTC - 6
hours
UTC - 7
hours
UTC - 7
hours
UTC - 8
hours
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Full name
004367
Initial Performance Adjusted P.U. Based on Bias Setting
#DIV/0! MW/0.1 Hz Median
Sustained Performance Adjusted P.U. Based on Bias Setting
1.20
#DIV/0 Average P.U. Performance
1.00
1.00
0.80
0.80
P.U.
P.U.
1.20
004368
Event Recovery Period Average Performance
HQT
T20 to T52 Average Performance
0.60
0.60
0.40
0.40
0.20
0.20
0.00
0.00
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
Event
Initial Performance Adjusted P.U.
Sustained Performance P.U.
HQT
HQT
Performance based on Hz at T+46
1.000
1.000
0.800
0.800
0.600
8
9
10
11
12
Performance based on Hz at T+76
T+76 Performance Adjusted P.U. Based on Bias Setting
1.200
P.U.
P.U.
7
Event
T+46 Performance Adjusted P.U. Based on Bias Setting
1.200
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
HQT
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
7
8
9
10
11
12
1
2
3
4
5
6
7
8
9
10
11
12
HQT
HQT
Adjusted
PFR Performance
T(+46) P.U.
T+106 Performance
Adjusted
P.U.@Based
on Bias Setting
1.200
1.000
1.000
0.800
0.800
0.600
0.600
0.400
0.400
0.200
0.200
0.000
0.000
1
2
3
4
5
6
7
8
9
10
11
12
Event
T+166 Performance Adjusted P.U. Based on Bias Setting
1.000
P.U.
0.800
0.600
0.400
0.200
0.000
1
2
3
4
5
6
2
3
4
5
6
7
7
8
Event
Adjusted PFR Performance @ T(+166) P.U.
8
Adjusted PFR Performance @ T(+136) P.U.
Performance based on Hz at T+166
HQT
1.200
1
Event
Adjusted PFR Performance @ T(+106) P.U.
004369
Performance based on Hz at T+136
Adjusted PFR Performance @ T(+76) P.U.
T+136 Performance
Adjusted P.U. Based on Bias Setting
1.200
P.U.
P.U.
Performance based on Hz at T+106
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Event
Event
9
10
11
12
9
10
11
12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
FRI - NERC Frequency Response Initiative
The FRI Report made recommendations to evaluate Primary Frequency Response at additional time intervals during the event recovery period.
Additional evaluations have been added to both Form 1 and Form 2 to evaluate PFR delivery for these suggested time periods.
These evaluations utilize Interconnection frequency at specific times during the recovery period and calculates the BA's delivery of PFR for each selection.
These evaluations are not part of BAL-003 and will not impact compliance to R1 of the draft standard.
The following time selections are evaluated: T+46, T+76, T+106, T+136 and T+166.
Each evaluation is a P.U. measure based on the BA's Bias setting at each of these times.
Performance is the "best" performance at the specific time through 10 seconds past each time.
This is intended to account for any delay in data in the measurement. This measurement may be changed as experience in this effort increases.
Also included is the measure of PFR delivery during the T+20 to T+52 second period, the same as R1 of the standard.
The measure (P.U.) here is based on the BA Bias setting and not the FRO. This was done to provide comparison to the additional measurement times.
Some basic observations from this data:
1) If the P.U. value is close to 1.0, the BA delivered the full amount of PFR equal to its Bias setting.
2) The average performance of the Eastern Interconnection in PFR is about 40% of the total Interconnection Bias setting. If the BA's average score is greater
than 0.40 P.U. then they are providing more PFR than the average BA. If the P.U. is less than 40% then they are providing less than average PFR.
3) If the P.U. value at T+46 is consistently less than the P.U. value at T+20 to T+52, then the PFR of the BA is not being sustained.
4) If the P.U. value at later time interval measures is consistently less, then withdrawal of PFR is occurring at a slower rate, but still being withdrawn.
5) If the P.U. value at T+20 to T+52, T+46, or T+76 is consistently greater than 1.0, this indicates that the BA Bias setting is too low.
004370
10/12/09 02:17:26
10/12/09 02:17:28
10/12/09 02:17:30
10/12/09 02:17:32
10/12/09 02:17:34
10/12/09 02:17:36
10/12/09 02:17:38
10/12/09 02:17:40
10/12/09 02:17:42
10/12/09 02:17:44
10/12/09 02:17:46
10/12/09 02:17:48
10/12/09 02:17:50
10/12/09 02:17:52
10/12/09 02:17:54
10/12/09 02:17:56
10/12/09 02:17:58
10/12/09 02:18:00
10/12/09 02:18:02
10/12/09 02:18:04
10/12/09 02:18:06
10/12/09 02:18:08
10/12/09 02:18:10
10/12/09 02:18:12
10/12/09 02:18:14
10/12/09 02:18:16
10/12/09 02:18:18
10/12/09 02:18:20
10/12/09 02:18:22
10/12/09 02:18:24
10/12/09 02:18:26
10/12/09 02:18:28
10/12/09 02:18:30
10/12/09 02:18:32
10/12/09 02:18:34
10/12/09 02:18:36
10/12/09 02:18:38
10/12/09 02:18:40
10/12/09 02:18:42
10/12/09 02:18:44
10/12/09 02:18:46
10/12/09 02:18:48
Hz
60.007
60.009
60.009
60.006
60.006
60.009
60.009
60.008
60.009
60.009
60.005
60.004
60.001
59.999
59.993
59.991
59.994
59.992
59.994
59.992
59.994
59.995
59.993
59.99
59.99
59.987
59.983
59.977
59.977
59.989
59.995
59.999
59.994
59.989
59.987
59.986
59.984
59.983
59.985
59.986
59.985
59.986
3679.946
3679.44
3679.912
3679.517
3679.888
3679.608
3679.06
3679.261
3679.164
3679.025
3679.152
3678.572
3678.295
3678.249
3678.236
3677.83
3677.955
3677.772
3676.666
3677.093
3677.141
3676.401
3678.516
3679.872
3680.197
3678.743
3678.428
3677.921
3680.254
3682.07
3681.329
3678.656
3678.077
3677.78
3678.427
3678.473
3678.278
3677.822
3676.615
3677.397
3677.917
3677.95
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-249.086395
0
-249.086395
0
Not
Used
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
102
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
7567.32
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
-0.003
0.000
0.003
0.000
-0.001
0.001
0.000
-0.004
-0.001
-0.003
-0.002
-0.006
-0.002
0.003
-0.002
0.002
-0.002
0.002
0.001
-0.002
-0.003
0.000
-0.003
-0.004
-0.006
0.000
0.012
0.006
0.004
-0.005
-0.005
-0.002
-0.001
-0.002
-0.001
0.002
0.001
-0.001
0.001
Rows of
data to
shift to
Highest
004371Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.003
0.000
0.003
0.000
0.001
0.001
0.000
0.004
0.001
0.003
0.002
0.006
0.002
0.003
0.002
0.002
0.002
0.002
0.001
0.002
0.003
0.000
0.003
0.004
0.006
0.000
0.012
0.006
0.004
0.005
0.005
0.002
0.001
0.002
0.001
0.002
0.001
0.001
0.001
10/12/09 02:18:50
10/12/09 02:18:52
10/12/09 02:18:54
10/12/09 02:18:56
10/12/09 02:18:58
10/12/09 02:19:00
10/12/09 02:19:02
10/12/09 02:19:04
10/12/09 02:19:06
10/12/09 02:19:08
10/12/09 02:19:10
10/12/09 02:19:12
10/12/09 02:19:14
10/12/09 02:19:16
10/12/09 02:19:18
10/12/09 02:19:20
10/12/09 02:19:22
10/12/09 02:19:24
10/12/09 02:19:26
10/12/09 02:19:28
10/12/09 02:19:30
10/12/09 02:19:32
10/12/09 02:19:34
10/12/09 02:19:36
10/12/09 02:19:38
10/12/09 02:19:40
10/12/09 02:19:42
10/12/09 02:19:44
10/12/09 02:19:46
10/12/09 02:19:48
10/12/09 02:19:50
10/12/09 02:19:52
10/12/09 02:19:54
10/12/09 02:19:56
10/12/09 02:19:58
10/12/09 02:20:00
10/12/09 02:20:02
10/12/09 02:20:04
10/12/09 02:20:06
10/12/09 02:20:08
10/12/09 02:20:10
10/12/09 02:20:12
Hz
59.98
59.981
59.981
59.989
59.998
60.007
60.007
59.997
59.986
59.981
59.977
59.974
59.976
59.974
59.974
59.977
59.979
59.979
59.982
59.984
59.987
59.988
59.988
59.987
59.987
59.987
59.985
59.984
59.982
59.983
59.989
59.989
59.988
59.984
59.982
59.983
59.981
59.982
59.983
59.986
59.989
59.987
3678.617
3678.963
3681.252
3680.737
3680.045
3678.161
3674.076
3676.222
3676.669
3677.497
3677.49
3675.186
3675.437
3680.451
3682.032
3683.829
3682.843
3681.108
3680.566
3678.229
3676.752
3675.759
3671.942
3671.166
3670.476
3670.129
3671.542
3672.048
3671.576
3672.104
3672.414
3671.882
3671.837
3671.336
3670.726
3670.372
3671.364
3671.401
3672.156
3672.181
3670.296
3668.071
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-249.086395
0
-249.086395
0
-249.086395
0
-253.742477
0
-253.742477
0
-253.742477
0
-253.742477
0
-253.742477
0
-257.421204
0
-257.421204
0
-257.421204
0
-257.421204
0
-257.421204
0
-261.73822
0
-261.73822
0
-261.73822
0
-261.73822
0
-261.73822
0
-271.875977
0
-271.875977
0
-271.875977
0
-271.875977
0
-271.875977
0
-262.073486
0
-262.073486
0
-262.073486
0
-262.073486
0
-262.073486
0
-260.36441
0
-260.36441
0
-260.36441
0
-260.36441
0
-260.36441
0
-352.644379
0
-352.644379
0
-352.644379
0
-352.644379
0
-352.644379
0
-354.89566
0
-354.89566
0
-354.89566
0
-354.89566
0
Not
Used
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.006
0.001
0.000
0.008
0.009
0.009
0.000
-0.010
-0.011
-0.005
-0.004
-0.003
0.002
-0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.001
-0.002
0.001
0.006
0.000
-0.001
-0.004
-0.002
0.001
-0.002
0.001
0.001
0.003
0.003
-0.002
Rows of
data to
shift to
Highest
004372Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.006
0.001
0.000
0.008
0.009
0.009
0.000
0.010
0.011
0.005
0.004
0.003
0.002
0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
0.001
0.000
0.000
0.002
0.001
0.002
0.001
0.006
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.003
0.003
0.002
10/12/09 02:20:14
10/12/09 02:20:16
10/12/09 02:20:18
10/12/09 02:20:20
10/12/09 02:20:22
10/12/09 02:20:24
10/12/09 02:20:26
10/12/09 02:20:28
10/12/09 02:20:30
10/12/09 02:20:32
10/12/09 02:20:34
10/12/09 02:20:36
10/12/09 02:20:38
10/12/09 02:20:40
10/12/09 02:20:42
10/12/09 02:20:44
10/12/09 02:20:46
10/12/09 02:20:48
10/12/09 02:20:50
10/12/09 02:20:52
10/12/09 02:20:54
10/12/09 02:20:56
10/12/09 02:20:58
10/12/09 02:21:00
10/12/09 02:21:02
10/12/09 02:21:04
10/12/09 02:21:06
10/12/09 02:21:08
10/12/09 02:21:10
10/12/09 02:21:12
10/12/09 02:21:14
10/12/09 02:21:16
10/12/09 02:21:18
10/12/09 02:21:20
10/12/09 02:21:22
10/12/09 02:21:24
10/12/09 02:21:26
10/12/09 02:21:28
10/12/09 02:21:30
10/12/09 02:21:32
10/12/09 02:21:34
10/12/09 02:21:36
Hz
59.985
59.98
59.98
59.983
59.98
59.979
59.979
59.981
59.981
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.981
59.979
59.976
59.977
59.972
59.971
59.973
59.973
59.973
59.974
59.971
59.975
59.977
59.977
59.975
59.976
59.98
59.979
59.981
59.982
59.982
59.982
59.982
59.981
59.982
59.984
3668.59
3669.908
3670.399
3670.263
3669.382
3670.102
3670.438
3671.403
3672.442
3672.372
3671.947
3670.938
3670.705
3670.137
3669.279
3672.391
3672.558
3674.052
3672.626
3671.8
3673.183
3673.874
3676.263
3676.623
3676.87
3676.543
3675.464
3675.752
3675.256
3674.87
3671.277
3671.593
3670.587
3669.963
3669.54
3669.497
3668.706
3667.677
3666.482
3666.599
3666.911
3666.442
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-354.89566
0
-340.46936
0
-340.46936
0
-340.46936
0
-340.46936
0
-340.46936
0
-337.642914
0
-337.642914
0
-337.642914
0
-337.642914
0
-337.642914
0
-284.36084
0
-284.36084
0
-284.36084
0
-284.36084
0
-284.36084
0
-260.467987
0
-260.467987
0
-260.467987
0
-260.467987
0
-260.467987
0
-253.141541
0
-253.141541
0
-253.141541
0
-253.141541
0
-253.141541
0
-251.929871
0
-251.929871
0
-251.929871
0
-251.929871
0
-251.929871
0
-250.674194
0
-250.674194
0
-250.674194
0
-250.674194
0
-250.674194
0
-253.631866
0
-253.631866
0
-253.631866
0
-253.631866
0
-253.631866
0
-246.957306
0
Not
Used
123.5
124
124.5
125
125.5
126
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.002
-0.005
0.000
0.003
-0.003
-0.001
0.000
0.002
0.000
-0.001
0.000
0.001
-0.001
0.000
-0.003
0.002
0.002
-0.002
-0.003
0.001
-0.005
-0.001
0.002
0.000
0.000
0.001
-0.003
0.004
0.002
0.000
-0.002
0.001
0.004
-0.001
0.002
0.001
0.000
0.000
0.000
-0.001
0.001
0.002
Rows of
data to
shift to
Highest
004373Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.005
0.000
0.003
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.003
0.002
0.002
0.002
0.003
0.001
0.005
0.001
0.002
0.000
0.000
0.001
0.003
0.004
0.002
0.000
0.002
0.001
0.004
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.002
10/12/09 02:21:38
10/12/09 02:21:40
10/12/09 02:21:42
10/12/09 02:21:44
10/12/09 02:21:46
10/12/09 02:21:48
10/12/09 02:21:50
10/12/09 02:21:52
10/12/09 02:21:54
10/12/09 02:21:56
10/12/09 02:21:58
10/12/09 02:22:00
10/12/09 02:22:02
10/12/09 02:22:04
10/12/09 02:22:06
10/12/09 02:22:08
10/12/09 02:22:10
10/12/09 02:22:12
10/12/09 02:22:14
10/12/09 02:22:16
10/12/09 02:22:18
10/12/09 02:22:20
10/12/09 02:22:22
10/12/09 02:22:24
10/12/09 02:22:26
10/12/09 02:22:28
10/12/09 02:22:30
10/12/09 02:22:32
10/12/09 02:22:34
10/12/09 02:22:36
10/12/09 02:22:38
10/12/09 02:22:40
10/12/09 02:22:42
10/12/09 02:22:44
10/12/09 02:22:46
10/12/09 02:22:48
10/12/09 02:22:50
10/12/09 02:22:52
10/12/09 02:22:54
10/12/09 02:22:56
10/12/09 02:22:58
10/12/09 02:23:00
Hz
59.985
59.987
59.989
59.993
59.996
59.998
59.998
60.004
60.007
60.01
60.013
60.014
60.013
60.008
60.008
60.01
60.019
60.019
60.023
60.021
60.02
60.021
60.021
60.02
60.019
60.019
60.022
60.025
60.025
60.026
60.02
60.02
60.018
60.018
60.02
60.019
60.019
60.023
60.022
60.022
60.025
60.02
3666.405
3667.456
3666.38
3665.262
3664.031
3663.825
3663.229
3662.055
3661.695
3662.076
3662.224
3662.959
3663.794
3664.139
3665.278
3664.159
3663.265
3663.184
3661.929
3661.512
3659.172
3658.661
3656.785
3657.571
3658.126
3657.71
3658.015
3660.228
3659.224
3658.698
3658.669
3658.155
3659.13
3659.778
3660.82
3662.531
3662.387
3662.079
3662.39
3662.678
3663.577
3663.539
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-246.957306
0
-246.957306
0
-246.957306
0
-246.957306
0
-254.541779
0
-254.541779
0
-254.541779
0
-254.541779
0
-254.541779
0
-256.571594
0
-256.571594
0
-256.571594
0
-256.571594
0
-256.571594
0
-258.37262
0
-258.37262
0
-258.37262
0
-258.37262
0
-258.37262
0
-263.047363
0
-263.047363
0
-263.047363
0
-263.047363
0
-263.047363
0
-260.984375
0
-260.984375
0
-260.984375
0
-260.984375
0
-260.984375
0
-261.318329
0
-261.318329
0
-261.318329
0
-261.318329
0
-261.318329
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.1026
0
-262.71701
0
-262.71701
0
-262.71701
0
Not
Used
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
-0.001
-0.005
0.000
0.002
0.009
0.000
0.004
-0.002
-0.001
0.001
0.000
-0.001
-0.001
0.000
0.003
0.003
0.000
0.001
-0.006
0.000
-0.002
0.000
0.002
-0.001
0.000
0.004
-0.001
0.000
0.003
-0.005
Rows of
data to
shift to
Highest
004374Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
0.001
0.005
0.000
0.002
0.009
0.000
0.004
0.002
0.001
0.001
0.000
0.001
0.001
0.000
0.003
0.003
0.000
0.001
0.006
0.000
0.002
0.000
0.002
0.001
0.000
0.004
0.001
0.000
0.003
0.005
10/12/09 02:23:02
10/12/09 02:23:04
10/12/09 02:23:06
10/12/09 02:23:08
10/12/09 02:23:10
10/12/09 02:23:12
10/12/09 02:23:14
10/12/09 02:23:16
10/12/09 02:23:18
10/12/09 02:23:20
10/12/09 02:23:22
10/12/09 02:23:24
10/12/09 02:23:26
10/12/09 02:23:28
10/12/09 02:23:30
10/12/09 02:23:32
10/12/09 02:23:34
10/12/09 02:23:36
10/12/09 02:23:38
10/12/09 02:23:40
10/12/09 02:23:42
10/12/09 02:23:44
10/12/09 02:23:46
10/12/09 02:23:48
10/12/09 02:23:50
10/12/09 02:23:52
10/12/09 02:23:54
10/12/09 02:23:56
10/12/09 02:23:58
10/12/09 02:24:00
10/12/09 02:24:02
10/12/09 02:24:04
10/12/09 02:24:06
10/12/09 02:24:08
10/12/09 02:24:10
10/12/09 02:24:12
10/12/09 02:24:14
10/12/09 02:24:16
10/12/09 02:24:18
10/12/09 02:24:20
10/12/09 02:24:22
10/12/09 02:24:24
Hz
60.02
60.02
60.02
60.02
60.021
60.021
60.018
60.014
60.014
60.014
60.013
60.013
60.01
60.008
60.011
60.011
60.012
60.012
60.009
60.009
60.009
60.009
60.005
60.002
59.999
59.996
59.995
59.997
59.998
59.998
59.998
59.998
59.995
59.995
59.992
59.993
59.988
59.988
59.982
59.982
59.982
59.982
3662.959
3662.552
3662.543
3663.601
3663.91
3663.69
3662.791
3663.396
3663.698
3664.315
3665.313
3665.798
3666.141
3666.726
3667.677
3667.545
3666.688
3666.449
3666.71
3667.696
3667.398
3667.043
3666.624
3666.223
3665.88
3665.403
3665.802
3665.68
3665.352
3664.948
3665.065
3666.133
3666.64
3666.735
3667.084
3667.557
3667.337
3667.853
3668.116
3668.691
3669.399
3669.606
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-262.71701
0
-262.71701
0
-260.016479
0
-260.016479
0
-260.016479
0
-260.016479
0
-260.016479
0
-263.87323
0
-263.87323
0
-263.87323
0
-263.87323
0
-263.87323
0
-264.5979
0
-264.5979
0
-264.5979
0
-264.5979
0
-264.5979
0
-262.415924
0
-262.415924
0
-262.415924
0
-262.415924
0
-262.415924
0
-259.685242
0
-259.685242
0
-259.685242
0
-259.685242
0
-259.685242
0
-255.911011
0
-255.911011
0
-255.911011
0
-255.911011
0
-255.911011
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.148193
0
-258.873596
0
-258.873596
0
-258.873596
0
-258.873596
0
-258.873596
0
Not
Used
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.000
0.000
0.000
0.001
0.000
-0.003
-0.004
0.000
0.000
-0.001
0.000
-0.003
-0.002
0.003
0.000
0.001
0.000
-0.003
0.000
0.000
0.000
-0.004
-0.003
-0.003
-0.003
-0.001
0.002
0.001
0.000
0.000
0.000
-0.003
0.000
-0.003
0.001
-0.005
0.000
-0.006
0.000
0.000
0.000
Rows of
data to
shift to
Highest
004375Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.000
0.000
0.000
0.001
0.000
0.003
0.004
0.000
0.000
0.001
0.000
0.003
0.002
0.003
0.000
0.001
0.000
0.003
0.000
0.000
0.000
0.004
0.003
0.003
0.003
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.000
0.003
0.001
0.005
0.000
0.006
0.000
0.000
0.000
10/12/09 02:24:26
10/12/09 02:24:28
10/12/09 02:24:30
10/12/09 02:24:32
10/12/09 02:24:34
10/12/09 02:24:36
10/12/09 02:24:38
10/12/09 02:24:40
10/12/09 02:24:42
10/12/09 02:24:44
10/12/09 02:24:46
10/12/09 02:24:48
10/12/09 02:24:50
10/12/09 02:24:52
10/12/09 02:24:54
10/12/09 02:24:56
10/12/09 02:24:58
10/12/09 02:25:00
10/12/09 02:25:02
10/12/09 02:25:04
10/12/09 02:25:06
10/12/09 02:25:08
10/12/09 02:25:10
10/12/09 02:25:12
10/12/09 02:25:14
10/12/09 02:25:16
10/12/09 02:25:18
10/12/09 02:25:20
10/12/09 02:25:22
10/12/09 02:25:24
10/12/09 02:25:26
10/12/09 02:25:28
10/12/09 02:25:30
10/12/09 02:25:32
10/12/09 02:25:34
10/12/09 02:25:36
10/12/09 02:25:38
10/12/09 02:25:40
10/12/09 02:25:42
10/12/09 02:25:44
10/12/09 02:25:46
10/12/09 02:25:48
Hz
59.984
59.982
59.978
59.978
59.976
59.975
59.974
59.974
59.979
59.98
59.981
59.98
59.984
59.987
59.988
59.988
59.99
59.992
59.991
59.991
59.991
59.993
59.993
59.996
60.002
60.002
60.003
60.004
60.005
60.004
60.002
60.004
60.008
60.01
60.01
60.01
60.011
60.013
60.014
60.013
60.012
60.011
3671.228
3670.25
3670.265
3671.549
3673.243
3674.263
3675.824
3676.418
3676.306
3674.637
3675.329
3675.226
3674.768
3674.399
3673.514
3673.04
3672.442
3673.056
3671.68
3671.493
3669.53
3670.066
3670.028
3671.744
3671.578
3672.625
3672.674
3673.819
3673.25
3673.182
3673.496
3672.418
3672.363
3672.217
3672.261
3673.182
3673.603
3673.553
3674.312
3674.537
3673.813
3673.204
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-249.33757
0
-249.33757
0
-249.33757
0
-249.33757
0
-249.33757
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.278168
0
-258.406372
0
-258.406372
0
-258.406372
0
-258.406372
0
-258.406372
0
-260.538879
0
-260.538879
0
-260.538879
0
-260.538879
0
-260.538879
0
-257.88208
0
-257.88208
0
-257.88208
0
-257.88208
0
-257.88208
0
-258.588654
0
-258.588654
0
-258.588654
0
-258.588654
0
-258.588654
0
-261.906158
0
-261.906158
0
-261.906158
0
-261.906158
0
-261.906158
0
-256.747803
0
-256.747803
0
-256.747803
0
-256.747803
0
-256.747803
0
-167.431976
0
-167.431976
0
Not
Used
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.002
-0.002
-0.004
0.000
-0.002
-0.001
-0.001
0.000
0.005
0.001
0.001
-0.001
0.004
0.003
0.001
0.000
0.002
0.002
-0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
0.001
0.001
-0.001
-0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
-0.001
-0.001
-0.001
Rows of
data to
shift to
Highest
004376Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.002
0.004
0.000
0.002
0.001
0.001
0.000
0.005
0.001
0.001
0.001
0.004
0.003
0.001
0.000
0.002
0.002
0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.001
10/12/09 02:25:50
10/12/09 02:25:52
10/12/09 02:25:54
10/12/09 02:25:56
10/12/09 02:25:58
10/12/09 02:26:00
10/12/09 02:26:02
10/12/09 02:26:04
10/12/09 02:26:06
10/12/09 02:26:08
10/12/09 02:26:10
10/12/09 02:26:12
10/12/09 02:26:14
10/12/09 02:26:16
10/12/09 02:26:18
10/12/09 02:26:20
10/12/09 02:26:22
10/12/09 02:26:24
10/12/09 02:26:26
10/12/09 02:26:28
10/12/09 02:26:30
10/12/09 02:26:32
10/12/09 02:26:34
10/12/09 02:26:36
10/12/09 02:26:38
10/12/09 02:26:40
10/12/09 02:26:42
10/12/09 02:26:44
10/12/09 02:26:46
10/12/09 02:26:48
10/12/09 02:26:50
10/12/09 02:26:52
10/12/09 02:26:54
10/12/09 02:26:56
10/12/09 02:26:58
10/12/09 02:27:00
10/12/09 02:27:02
10/12/09 02:27:04
10/12/09 02:27:06
10/12/09 02:27:08
10/12/09 02:27:10
10/12/09 02:27:12
Hz
60.011
60.017
60.022
60.017
60.014
60.013
60.014
60.017
60.017
60.019
60.019
60.019
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
3672.563
3673.068
3672.388
3672.52
3671.25
3671.288
3672.989
3672.982
3672.915
3671.952
3671.193
3671.627
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.19
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-167.431976
0
-167.431976
0
-167.431976
0
-164.973404
0
-164.973404
0
-164.973404
0
-164.973404
0
-164.973404
0
-157.628082
0
-157.628082
0
-157.628082
0
-157.628082
0
-157.628082
0
-155.531708
0
-155.531708
0
-155.531708
0
-155.531708
0
-155.531708
0
-160.447235
0
-160.447235
0
-160.447235
0
-160.447235
0
-160.447235
0
-163.958603
0
-163.958603
0
-163.958603
0
-163.958603
0
-163.958603
0
-166.072449
0
-166.072449
0
-166.072449
0
-166.072449
0
-166.072449
0
-163.766586
0
-163.766586
0
-163.766586
0
-163.766586
0
-163.766586
0
-165.101685
0
-165.101685
0
-165.101685
0
-165.101685
0
Not
Used
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
224.5
225
225.5
226
226.5
227
227.5
228
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.006
0.005
-0.005
-0.003
-0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
-0.001
0.000
-0.004
-0.003
-0.002
0.002
0.001
-0.001
0.002
0.000
0.000
-0.002
-0.001
0.004
0.009
0.006
0.000
-0.001
0.001
0.009
0.002
0.000
-0.005
-0.002
0.000
0.000
-0.002
0.002
0.002
Rows of
data to
shift to
Highest
004377Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.006
0.005
0.005
0.003
0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
0.001
0.000
0.004
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.000
0.002
0.001
0.004
0.009
0.006
0.000
0.001
0.001
0.009
0.002
0.000
0.005
0.002
0.000
0.000
0.002
0.002
0.002
10/12/09 02:27:14
10/12/09 02:27:16
10/12/09 02:27:18
10/12/09 02:27:20
10/12/09 02:27:22
10/12/09 02:27:24
10/12/09 02:27:26
10/12/09 02:27:28
10/12/09 02:27:30
10/12/09 02:27:32
10/12/09 02:27:34
10/12/09 02:27:36
10/12/09 02:27:38
10/12/09 02:27:40
10/12/09 02:27:42
10/12/09 02:27:44
10/12/09 02:27:46
10/12/09 02:27:48
10/12/09 02:27:50
10/12/09 02:27:52
10/12/09 02:27:54
10/12/09 02:27:56
10/12/09 02:27:58
10/12/09 02:28:00
10/12/09 02:28:02
10/12/09 02:28:04
10/12/09 02:28:06
10/12/09 02:28:08
10/12/09 02:28:10
10/12/09 02:28:12
10/12/09 02:28:14
10/12/09 02:28:16
10/12/09 02:28:18
10/12/09 02:28:20
10/12/09 02:28:22
10/12/09 02:28:24
10/12/09 02:28:26
10/12/09 02:28:28
10/12/09 02:28:30
10/12/09 02:28:32
10/12/09 02:28:34
10/12/09 02:28:36
Hz
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3737.157
3761.25
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.5
3784.962
3784.73
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-165.101685
0
-165.476395
0
-165.476395
0
-165.476395
0
-165.476395
0
-165.476395
0
-206.459106
0
-206.459106
0
-206.459106
0
-206.459106
0
-206.459106
0
-211.256042
0
-211.256042
1
-211.256042
1
-211.256042
1
-211.256042
1
-214.346695
1
-214.346695
1
-214.346695
1
-214.346695
2
-214.346695
3
-212.172699
4
-212.172699
5
-212.172699
6
-212.172699
7
-212.172699
8
-215.598175
9
-215.598175
10
-215.598175
11
-215.598175
12
-215.598175
13
-218.327255
14
-218.327255
15
-218.327255
16
-218.327255
16
-218.327255
16
-217.379425
16
-217.379425
16
-217.379425
16
-217.379425
16
-217.379425
16
-214.830353
16
Not
Used
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
249
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
7621
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
0.001
-0.005
0.000
0.000
-0.002
-0.061
-0.126
-0.016
0.033
0.023
-0.001
-0.011
-0.004
-0.001
0.008
0.004
-0.001
-0.001
0.002
0.001
0.002
0.005
-0.001
-0.001
0.001
0.000
-0.003
-0.001
-0.005
0.000
0.003
-0.001
0.001
0.000
0.002
-0.001
-0.007
-0.009
-0.016
-0.008
0.003
Rows of
data to
shift to
Highest
004378Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.001
0.005
0.000
0.000
0.002
0.061
0.126
0.016
0.033
0.023
0.001
0.011
0.004
0.001
0.008
0.004
0.001
0.001
0.002
0.001
0.002
0.005
0.001
0.001
0.001
0.000
0.003
0.001
0.005
0.000
0.003
0.001
0.001
0.000
0.002
0.001
0.007
0.009
0.016
0.008
0.003
10/12/09 02:28:38
10/12/09 02:28:40
10/12/09 02:28:42
10/12/09 02:28:44
10/12/09 02:28:46
10/12/09 02:28:48
10/12/09 02:28:50
10/12/09 02:28:52
10/12/09 02:28:54
10/12/09 02:28:56
10/12/09 02:28:58
10/12/09 02:29:00
10/12/09 02:29:02
10/12/09 02:29:04
10/12/09 02:29:06
10/12/09 02:29:08
10/12/09 02:29:10
10/12/09 02:29:12
10/12/09 02:29:14
10/12/09 02:29:16
10/12/09 02:29:18
10/12/09 02:29:20
10/12/09 02:29:22
10/12/09 02:29:24
10/12/09 02:29:26
10/12/09 02:29:28
10/12/09 02:29:30
10/12/09 02:29:32
10/12/09 02:29:34
10/12/09 02:29:36
10/12/09 02:29:38
10/12/09 02:29:40
10/12/09 02:29:42
10/12/09 02:29:44
10/12/09 02:29:46
10/12/09 02:29:48
10/12/09 02:29:50
10/12/09 02:29:52
10/12/09 02:29:54
10/12/09 02:29:56
10/12/09 02:29:58
10/12/09 02:30:00
Hz
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.01
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.67
3769.63
3768.707
3767.643
3767.021
3767.408
3766.788
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-214.830353
16
-214.830353
16
-214.830353
16
-214.830353
16
-227.655914
16
-227.655914
16
-227.655914
16
-227.655914
16
-227.655914
16
-225.018082
16
-225.018082
16
-225.018082
16
-225.018082
16
-225.018082
16
-228.365158
16
-228.365158
16
-228.365158
16
-228.365158
16
-228.365158
16
-234.075333
16
-234.075333
16
-234.075333
16
-234.075333
16
-234.075333
16
-228.798157
16
-228.798157
16
-228.798157
16
-228.798157
16
-228.798157
16
-229.466965
16
-229.466965
16
-229.466965
16
-229.466965
16
-229.466965
16
-228.980164
16
-228.980164
16
-228.980164
16
-228.980164
16
-228.980164
16
-219.975555
16
-219.975555
16
-219.975555
16
Not
Used
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.006
0.005
0.003
-0.001
0.002
-0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
-0.003
0.004
0.006
0.004
-0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
-0.001
-0.003
0.003
0.001
0.002
0.003
-0.001
0.003
-0.001
0.005
-0.005
0.001
0.003
Rows of
data to
shift to
Highest
004379Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.006
0.005
0.003
0.001
0.002
0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
0.003
0.004
0.006
0.004
0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
0.001
0.003
0.003
0.001
0.002
0.003
0.001
0.003
0.001
0.005
0.005
0.001
0.003
10/12/09 02:30:02
10/12/09 02:30:04
10/12/09 02:30:06
10/12/09 02:30:08
10/12/09 02:30:10
10/12/09 02:30:12
10/12/09 02:30:14
10/12/09 02:30:16
10/12/09 02:30:18
10/12/09 02:30:20
10/12/09 02:30:22
10/12/09 02:30:24
10/12/09 02:30:26
10/12/09 02:30:28
10/12/09 02:30:30
10/12/09 02:30:32
10/12/09 02:30:34
10/12/09 02:30:36
10/12/09 02:30:38
10/12/09 02:30:40
10/12/09 02:30:42
10/12/09 02:30:44
10/12/09 02:30:46
10/12/09 02:30:48
10/12/09 02:30:50
10/12/09 02:30:52
10/12/09 02:30:54
10/12/09 02:30:56
10/12/09 02:30:58
10/12/09 02:31:00
10/12/09 02:31:02
10/12/09 02:31:04
10/12/09 02:31:06
10/12/09 02:31:08
10/12/09 02:31:10
10/12/09 02:31:12
10/12/09 02:31:14
10/12/09 02:31:16
10/12/09 02:31:18
10/12/09 02:31:20
10/12/09 02:31:22
10/12/09 02:31:24
Hz
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.81
3712.092
3714.623
3715.13
3716.168
3716.461
3716.98
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-219.975555
16
-219.975555
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.089249
16
-229.663269
16
-229.663269
16
-229.663269
16
-229.663269
16
-229.663269
16
-229.233856
16
-229.233856
16
-229.233856
16
-229.233856
16
-229.233856
16
-231.409882
16
-231.409882
16
-231.409882
16
-231.409882
16
-231.409882
16
-218.622284
16
-218.622284
16
-218.622284
16
-218.622284
16
-218.622284
16
-213.535858
16
-213.535858
16
-213.535858
16
-213.535858
16
-213.535858
16
-225.651855
16
-225.651855
16
-225.651855
16
-225.651855
16
-225.651855
16
-212.573639
16
-212.573639
16
-212.573639
16
-212.573639
16
-212.573639
16
Not
Used
270.5
271
271.5
272
272.5
273
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7664
7665
7666
7666
7667
7668
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.002
0.002
0.004
0.000
0.008
0.004
-0.002
-0.005
-0.001
0.001
0.003
0.003
-0.001
0.002
0.002
0.001
0.001
-0.002
0.001
0.000
0.000
0.003
-0.003
0.002
-0.002
0.001
0.000
-0.001
0.002
0.000
0.005
-0.002
-0.001
-0.002
0.002
-0.001
0.003
0.003
0.001
0.000
0.006
Rows of
data to
shift to
Highest
004380Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.002
0.002
0.004
0.000
0.008
0.004
0.002
0.005
0.001
0.001
0.003
0.003
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.000
0.001
0.002
0.000
0.005
0.002
0.001
0.002
0.002
0.001
0.003
0.003
0.001
0.000
0.006
10/12/09 02:31:26
10/12/09 02:31:28
10/12/09 02:31:30
10/12/09 02:31:32
10/12/09 02:31:34
10/12/09 02:31:36
10/12/09 02:31:38
10/12/09 02:31:40
10/12/09 02:31:42
10/12/09 02:31:44
10/12/09 02:31:46
10/12/09 02:31:48
10/12/09 02:31:50
10/12/09 02:31:52
10/12/09 02:31:54
10/12/09 02:31:56
10/12/09 02:31:58
10/12/09 02:32:00
10/12/09 02:32:02
10/12/09 02:32:04
10/12/09 02:32:06
10/12/09 02:32:08
10/12/09 02:32:10
10/12/09 02:32:12
10/12/09 02:32:14
10/12/09 02:32:16
10/12/09 02:32:18
10/12/09 02:32:20
10/12/09 02:32:22
10/12/09 02:32:24
10/12/09 02:32:26
10/12/09 02:32:28
10/12/09 02:32:30
10/12/09 02:32:32
10/12/09 02:32:34
10/12/09 02:32:36
10/12/09 02:32:38
10/12/09 02:32:40
10/12/09 02:32:42
10/12/09 02:32:44
10/12/09 02:32:46
10/12/09 02:32:48
Hz
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.13
3732.53
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.3
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-219.897293
16
-219.897293
16
-219.897293
16
-219.897293
16
-219.897293
16
-231.1754
16
-231.1754
16
-231.1754
16
-231.1754
16
-231.1754
16
-226.634125
16
-226.634125
16
-226.634125
16
-226.634125
16
-226.634125
16
-227.255066
16
-227.255066
16
-227.255066
16
-227.255066
16
-227.255066
16
-229.290222
16
-229.290222
16
-229.290222
16
-229.290222
16
-229.290222
16
-221.461365
16
-221.461365
16
-221.461365
16
-221.461365
16
-221.461365
16
-241.274368
16
-241.274368
16
-241.274368
16
-241.274368
16
-241.274368
16
-243.071854
16
-243.071854
16
-243.071854
16
-243.071854
16
-243.071854
16
-241.670212
16
-241.670212
16
Not
Used
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
297.5
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.002
0.002
0.004
-0.004
-0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.000
-0.002
0.002
-0.002
0.002
-0.001
0.003
0.002
-0.001
-0.001
-0.001
0.001
-0.001
0.004
0.000
0.001
0.004
0.001
-0.002
0.000
0.004
0.002
-0.001
-0.001
-0.002
-0.003
-0.003
0.000
Rows of
data to
shift to
Highest
004381Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.002
0.002
0.004
0.004
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.002
0.002
0.002
0.001
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.004
0.000
0.001
0.004
0.001
0.002
0.000
0.004
0.002
0.001
0.001
0.002
0.003
0.003
0.000
10/12/09 02:32:50
10/12/09 02:32:52
10/12/09 02:32:54
10/12/09 02:32:56
10/12/09 02:32:58
10/12/09 02:33:00
10/12/09 02:33:02
10/12/09 02:33:04
10/12/09 02:33:06
10/12/09 02:33:08
10/12/09 02:33:10
10/12/09 02:33:12
10/12/09 02:33:14
10/12/09 02:33:16
10/12/09 02:33:18
10/12/09 02:33:20
10/12/09 02:33:22
10/12/09 02:33:24
10/12/09 02:33:26
10/12/09 02:33:28
10/12/09 02:33:30
10/12/09 02:33:32
10/12/09 02:33:34
10/12/09 02:33:36
10/12/09 02:33:38
10/12/09 02:33:40
10/12/09 02:33:42
10/12/09 02:33:44
10/12/09 02:33:46
10/12/09 02:33:48
10/12/09 02:33:50
10/12/09 02:33:52
10/12/09 02:33:54
10/12/09 02:33:56
10/12/09 02:33:58
10/12/09 02:34:00
10/12/09 02:34:02
10/12/09 02:34:04
10/12/09 02:34:06
10/12/09 02:34:08
10/12/09 02:34:10
10/12/09 02:34:12
Hz
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
3775.841
3775.363
3774.866
3775.492
3776.42
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.85
3786.304
3787.259
3787.516
3787.955
3788.03
3788.607
3789.216
3787.537
3785.842
3786.077
3787.93
3788.76
3786.875
3786.55
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-241.670212
16
-241.670212
16
-241.670212
16
-228.149307
16
-228.149307
16
-228.149307
16
-228.149307
16
-228.149307
16
-235.128983
16
-235.128983
16
-235.128983
16
-235.128983
16
-235.128983
16
-246.433136
16
-246.433136
16
-246.433136
16
-246.433136
16
-246.433136
16
-236.553543
16
-236.553543
16
-236.553543
16
-236.553543
16
-236.553543
16
-230.297562
16
-230.297562
16
-230.297562
16
-230.297562
16
-230.297562
16
-231.175537
16
-231.175537
16
-231.175537
16
-231.175537
16
-231.175537
16
-225.61763
16
-225.61763
16
-225.61763
16
-225.61763
16
-225.61763
16
-230.734421
16
-230.734421
16
-230.734421
16
-230.734421
16
Not
Used
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
1
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.005
0.005
0.003
0.002
0.001
0.002
-0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
-0.004
0.000
0.002
0.004
0.001
0.001
-0.004
-0.002
0.005
0.000
-0.003
-0.001
0.005
-0.001
-0.004
0.000
0.002
0.000
0.000
-0.001
0.000
0.002
0.000
-0.001
Rows of
data to
shift to
Highest
004382Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.005
0.005
0.003
0.002
0.001
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
0.004
0.000
0.002
0.004
0.001
0.001
0.004
0.002
0.005
0.000
0.003
0.001
0.005
0.001
0.004
0.000
0.002
0.000
0.000
0.001
0.000
0.002
0.000
0.001
10/12/09 02:34:14
10/12/09 02:34:16
10/12/09 02:34:18
10/12/09 02:34:20
10/12/09 02:34:22
10/12/09 02:34:24
10/12/09 02:34:26
10/12/09 02:34:28
10/12/09 02:34:30
10/12/09 02:34:32
10/12/09 02:34:34
10/12/09 02:34:36
10/12/09 02:34:38
10/12/09 02:34:40
10/12/09 02:34:42
10/12/09 02:34:44
10/12/09 02:34:46
10/12/09 02:34:48
10/12/09 02:34:50
10/12/09 02:34:52
10/12/09 02:34:54
10/12/09 02:34:56
10/12/09 02:34:58
10/12/09 02:35:00
10/12/09 02:35:02
10/12/09 02:35:04
10/12/09 02:35:06
10/12/09 02:35:08
10/12/09 02:35:10
10/12/09 02:35:12
10/12/09 02:35:14
10/12/09 02:35:16
10/12/09 02:35:18
10/12/09 02:35:20
10/12/09 02:35:22
10/12/09 02:35:24
10/12/09 02:35:26
10/12/09 02:35:28
10/12/09 02:35:30
10/12/09 02:35:32
10/12/09 02:35:34
10/12/09 02:35:36
Hz
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.54
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.54
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.41
3790.467
3790.665
3790.42
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-230.734421
16
-234.847107
16
-234.847107
16
-234.847107
16
-234.847107
16
-234.847107
16
-228.960922
16
-228.960922
16
-228.960922
16
-228.960922
16
-228.960922
16
-231.177917
16
-231.177917
16
-231.177917
16
-231.177917
16
-231.177917
16
-236.489288
16
-236.489288
16
-236.489288
16
-236.489288
16
-236.489288
16
-245.038925
16
-245.038925
16
-245.038925
16
-245.038925
16
-245.038925
16
-223.605682
16
-223.605682
16
-223.605682
16
-223.605682
16
-223.605682
16
-231.119354
16
-231.119354
16
-231.119354
16
-231.119354
16
-231.119354
16
-237.20665
16
-237.20665
16
-237.20665
16
-237.20665
16
-237.20665
16
-240.516373
16
Not
Used
333.5
334
334.5
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.003
0.002
0.000
0.000
0.001
0.000
-0.003
-0.001
0.001
-0.002
-0.001
-0.001
0.000
-0.002
-0.003
0.000
0.002
0.000
0.001
-0.007
-0.004
-0.004
-0.003
-0.001
0.001
0.000
-0.004
-0.002
-0.001
-0.001
0.001
-0.001
-0.002
-0.001
0.001
-0.003
-0.002
-0.001
0.000
0.003
0.003
Rows of
data to
shift to
Highest
004383Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.003
0.002
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.001
0.000
0.002
0.003
0.000
0.002
0.000
0.001
0.007
0.004
0.004
0.003
0.001
0.001
0.000
0.004
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.003
0.002
0.001
0.000
0.003
0.003
10/12/09 02:35:38
10/12/09 02:35:40
10/12/09 02:35:42
10/12/09 02:35:44
10/12/09 02:35:46
10/12/09 02:35:48
10/12/09 02:35:50
10/12/09 02:35:52
10/12/09 02:35:54
10/12/09 02:35:56
10/12/09 02:35:58
10/12/09 02:36:00
10/12/09 02:36:02
10/12/09 02:36:04
10/12/09 02:36:06
10/12/09 02:36:08
10/12/09 02:36:10
10/12/09 02:36:12
10/12/09 02:36:14
10/12/09 02:36:16
10/12/09 02:36:18
10/12/09 02:36:20
10/12/09 02:36:22
10/12/09 02:36:24
10/12/09 02:36:26
10/12/09 02:36:28
10/12/09 02:36:30
10/12/09 02:36:32
10/12/09 02:36:34
10/12/09 02:36:36
10/12/09 02:36:38
10/12/09 02:36:40
10/12/09 02:36:42
10/12/09 02:36:44
10/12/09 02:36:46
10/12/09 02:36:48
10/12/09 02:36:50
10/12/09 02:36:52
10/12/09 02:36:54
10/12/09 02:36:56
10/12/09 02:36:58
10/12/09 02:37:00
Hz
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
3789.674
3789.267
3789.148
3790.43
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.08
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.69
3784.831
3785.01
3784.32
3782.809
3782.11
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-240.516373
16
-240.516373
16
-240.516373
16
-240.516373
16
-237.566055
16
-237.566055
16
-237.566055
16
-237.566055
16
-237.566055
16
-231.581421
16
-231.581421
16
-231.581421
16
-231.581421
16
-231.581421
16
-235.850845
16
-235.850845
16
-235.850845
16
-235.850845
16
-235.850845
16
-233.559982
16
-233.559982
16
-233.559982
16
-233.559982
16
-233.559982
16
-219.009995
16
-219.009995
16
-219.009995
16
-219.009995
16
-219.009995
16
-205.338913
16
-205.338913
16
-205.338913
16
-205.338913
16
-205.338913
16
-236.285355
16
-236.285355
16
-236.285355
16
-236.285355
16
-236.285355
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
371.5
372
372.5
373
373.5
374
374.5
375
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.004
-0.002
-0.002
0.002
0.001
0.000
-0.002
-0.002
-0.004
0.001
0.001
0.002
0.005
0.003
-0.003
-0.003
-0.003
0.004
-0.001
-0.002
-0.004
-0.003
-0.001
0.001
0.003
0.001
-0.002
-0.003
-0.001
0.006
0.002
-0.005
0.000
0.002
-0.001
0.001
-0.002
0.000
-0.001
-0.001
0.006
-0.004
Rows of
data to
shift to
Highest
004384Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.004
0.002
0.002
0.002
0.001
0.000
0.002
0.002
0.004
0.001
0.001
0.002
0.005
0.003
0.003
0.003
0.003
0.004
0.001
0.002
0.004
0.003
0.001
0.001
0.003
0.001
0.002
0.003
0.001
0.006
0.002
0.005
0.000
0.002
0.001
0.001
0.002
0.000
0.001
0.001
0.006
0.004
10/12/09 02:37:02
10/12/09 02:37:04
10/12/09 02:37:06
10/12/09 02:37:08
10/12/09 02:37:10
10/12/09 02:37:12
10/12/09 02:37:14
10/12/09 02:37:16
10/12/09 02:37:18
10/12/09 02:37:20
10/12/09 02:37:22
10/12/09 02:37:24
10/12/09 02:37:26
10/12/09 02:37:28
10/12/09 02:37:30
10/12/09 02:37:32
10/12/09 02:37:34
10/12/09 02:37:36
10/12/09 02:37:38
10/12/09 02:37:40
10/12/09 02:37:42
10/12/09 02:37:44
10/12/09 02:37:46
10/12/09 02:37:48
10/12/09 02:37:50
10/12/09 02:37:52
10/12/09 02:37:54
10/12/09 02:37:56
10/12/09 02:37:58
10/12/09 02:38:00
10/12/09 02:38:02
10/12/09 02:38:04
10/12/09 02:38:06
10/12/09 02:38:08
10/12/09 02:38:10
10/12/09 02:38:12
10/12/09 02:38:14
10/12/09 02:38:16
10/12/09 02:38:18
10/12/09 02:38:20
10/12/09 02:38:22
10/12/09 02:38:24
Hz
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
3775.647
3776.597
3776.559
3776.023
3773.17
3771.73
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.25
3758.041
3760.965
3762.022
3763.822
3763.1
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.57
3761.92
3759.627
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
396
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
7761.36
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.003
0.002
0.006
-0.003
0.002
-0.001
-0.005
0.002
0.005
0.003
-0.005
-0.003
0.003
0.001
-0.002
-0.003
0.002
0.013
0.011
-0.007
-0.009
-0.007
-0.002
-0.003
0.000
-0.001
0.000
-0.001
0.003
-0.004
-0.003
-0.005
0.002
0.001
0.003
-0.001
0.005
0.002
-0.002
-0.002
0.004
Rows of
data to
shift to
Highest
004385Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.003
0.002
0.006
0.003
0.002
0.001
0.005
0.002
0.005
0.003
0.005
0.003
0.003
0.001
0.002
0.003
0.002
0.013
0.011
0.007
0.009
0.007
0.002
0.003
0.000
0.001
0.000
0.001
0.003
0.004
0.003
0.005
0.002
0.001
0.003
0.001
0.005
0.002
0.002
0.002
0.004
10/12/09 02:38:26
10/12/09 02:38:28
10/12/09 02:38:30
10/12/09 02:38:32
10/12/09 02:38:34
10/12/09 02:38:36
10/12/09 02:38:38
10/12/09 02:38:40
10/12/09 02:38:42
10/12/09 02:38:44
10/12/09 02:38:46
10/12/09 02:38:48
10/12/09 02:38:50
10/12/09 02:38:52
10/12/09 02:38:54
10/12/09 02:38:56
10/12/09 02:38:58
10/12/09 02:39:00
10/12/09 02:39:02
10/12/09 02:39:04
10/12/09 02:39:06
10/12/09 02:39:08
10/12/09 02:39:10
10/12/09 02:39:12
10/12/09 02:39:14
10/12/09 02:39:16
10/12/09 02:39:18
10/12/09 02:39:20
10/12/09 02:39:22
10/12/09 02:39:24
10/12/09 02:39:26
10/12/09 02:39:28
10/12/09 02:39:30
10/12/09 02:39:32
10/12/09 02:39:34
10/12/09 02:39:36
10/12/09 02:39:38
10/12/09 02:39:40
10/12/09 02:39:42
10/12/09 02:39:44
10/12/09 02:39:46
10/12/09 02:39:48
Hz
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
3758.522
3752.429
3750.102
3753.83
3753.51
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.37
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.65
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
413
413.5
414
414.5
415
415.5
416
416.5
417
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.002
0.003
0.000
0.000
0.002
0.003
-0.002
-0.006
0.002
0.000
0.005
0.004
-0.001
-0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
-0.002
-0.001
-0.002
0.001
-0.002
0.000
0.002
0.001
-0.001
-0.002
-0.002
-0.004
-0.001
-0.002
0.005
0.001
0.001
-0.004
Rows of
data to
shift to
Highest
004386Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.002
0.003
0.000
0.000
0.002
0.003
0.002
0.006
0.002
0.000
0.005
0.004
0.001
0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
0.002
0.001
0.002
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.002
0.004
0.001
0.002
0.005
0.001
0.001
0.004
10/12/09 02:39:50
10/12/09 02:39:52
10/12/09 02:39:54
10/12/09 02:39:56
10/12/09 02:39:58
10/12/09 02:40:00
10/12/09 02:40:02
10/12/09 02:40:04
10/12/09 02:40:06
10/12/09 02:40:08
10/12/09 02:40:10
10/12/09 02:40:12
10/12/09 02:40:14
10/12/09 02:40:16
10/12/09 02:40:18
10/12/09 02:40:20
10/12/09 02:40:22
10/12/09 02:40:24
10/12/09 02:40:26
10/12/09 02:40:28
10/12/09 02:40:30
10/12/09 02:40:32
10/12/09 02:40:34
10/12/09 02:40:36
10/12/09 02:40:38
10/12/09 02:40:40
10/12/09 02:40:42
10/12/09 02:40:44
10/12/09 02:40:46
10/12/09 02:40:48
10/12/09 02:40:50
10/12/09 02:40:52
10/12/09 02:40:54
10/12/09 02:40:56
10/12/09 02:40:58
10/12/09 02:41:00
10/12/09 02:41:02
10/12/09 02:41:04
10/12/09 02:41:06
10/12/09 02:41:08
10/12/09 02:41:10
10/12/09 02:41:12
Hz
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.86
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.34
3750.7
3749.75
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.83
3737.583
3736.229
3734.897
3733.434
3733.115
3730.51
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
417.5
418
418.5
419
419.5
420
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
437.5
438
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
0.002
0.003
-0.002
0.000
0.000
0.005
0.005
-0.004
-0.002
-0.003
0.001
0.003
0.000
0.001
0.001
0.002
-0.004
-0.003
-0.003
0.000
0.000
0.001
-0.004
-0.002
0.000
0.005
0.002
-0.001
-0.003
0.003
0.002
-0.001
-0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
Rows of
data to
shift to
Highest
004387Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.002
0.003
0.002
0.000
0.000
0.005
0.005
0.004
0.002
0.003
0.001
0.003
0.000
0.001
0.001
0.002
0.004
0.003
0.003
0.000
0.000
0.001
0.004
0.002
0.000
0.005
0.002
0.001
0.003
0.003
0.002
0.001
0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
10/12/09 02:41:14
10/12/09 02:41:16
10/12/09 02:41:18
10/12/09 02:41:20
10/12/09 02:41:22
10/12/09 02:41:24
10/12/09 02:41:26
10/12/09 02:41:28
10/12/09 02:41:30
10/12/09 02:41:32
10/12/09 02:41:34
10/12/09 02:41:36
10/12/09 02:41:38
10/12/09 02:41:40
10/12/09 02:41:42
10/12/09 02:41:44
10/12/09 02:41:46
10/12/09 02:41:48
10/12/09 02:41:50
10/12/09 02:41:52
10/12/09 02:41:54
10/12/09 02:41:56
10/12/09 02:41:58
10/12/09 02:42:00
10/12/09 02:42:02
10/12/09 02:42:04
10/12/09 02:42:06
10/12/09 02:42:08
10/12/09 02:42:10
10/12/09 02:42:12
10/12/09 02:42:14
10/12/09 02:42:16
10/12/09 02:42:18
10/12/09 02:42:20
10/12/09 02:42:22
10/12/09 02:42:24
10/12/09 02:42:26
10/12/09 02:42:28
10/12/09 02:42:30
10/12/09 02:42:32
10/12/09 02:42:34
10/12/09 02:42:36
Hz
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
60.043
60.045
60.04
60.041
60.039
60.039
3729.18
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.56
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.1
3690.477
3696.865
3696.877
3696.182
3696.541
3696.968
3698.686
3699.631
3698.787
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
450.5
451
451.5
452
452.5
453
453.5
454
454.5
455
455.5
456
456.5
457
457.5
458
458.5
459
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.3
7800.63
7800.96
7801.29
7801.62
7801.95
7802.28
7802.61
7802.94
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.002
0.004
0.001
0.001
0.002
0.000
0.008
-0.001
0.001
0.000
-0.001
0.005
0.002
0.001
-0.001
0.003
0.002
-0.002
0.000
-0.003
0.000
0.001
-0.001
0.000
0.002
-0.005
0.001
-0.002
0.000
Rows of
data to
shift to
Highest
004388Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.002
0.004
0.001
0.001
0.002
0.000
0.008
0.001
0.001
0.000
0.001
0.005
0.002
0.001
0.001
0.003
0.002
0.002
0.000
0.003
0.000
0.001
0.001
0.000
0.002
0.005
0.001
0.002
0.000
10/12/09 02:42:38
10/12/09 02:42:40
10/12/09 02:42:42
10/12/09 02:42:44
10/12/09 02:42:46
10/12/09 02:42:48
10/12/09 02:42:50
10/12/09 02:42:52
10/12/09 02:42:54
10/12/09 02:42:56
10/12/09 02:42:58
10/12/09 02:43:00
10/12/09 02:43:02
10/12/09 02:43:04
10/12/09 02:43:06
10/12/09 02:43:08
10/12/09 02:43:10
10/12/09 02:43:12
10/12/09 02:43:14
10/12/09 02:43:16
10/12/09 02:43:18
10/12/09 02:43:20
10/12/09 02:43:22
10/12/09 02:43:24
10/12/09 02:43:26
10/12/09 02:43:28
10/12/09 02:43:30
10/12/09 02:43:32
10/12/09 02:43:34
10/12/09 02:43:36
10/12/09 02:43:38
10/12/09 02:43:40
10/12/09 02:43:42
10/12/09 02:43:44
10/12/09 02:43:46
10/12/09 02:43:48
10/12/09 02:43:50
10/12/09 02:43:52
10/12/09 02:43:54
10/12/09 02:43:56
10/12/09 02:43:58
10/12/09 02:44:00
Hz
60.036
60.038
60.033
60.034
60.037
60.037
60.035
60.03
60.033
60.036
60.033
60.034
60.032
60.032
60.034
60.033
60.037
60.035
60.035
60.036
60.039
60.037
60.039
60.036
60.034
60.038
60.037
60.037
60.037
60.038
60.04
60.043
60.045
60.045
60.042
60.043
60.04
60.044
60.046
60.042
60.034
60.039
3699.712
3700.106
3699.968
3701.122
3701.865
3701.614
3701.998
3702.913
3703.909
3705.522
3704.967
3704.087
3702.771
3703.706
3704.905
3705.435
3704.36
3702.588
3702.204
3701.942
3702.25
3703.318
3702.457
3702.525
3703.269
3703.844
3702.865
3702.518
3702.28
3692.427
3692.178
3700.276
3698.755
3697.729
3696.916
3697.368
3697.346
3698.429
3694.763
3693.584
3693.241
3696.798
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
459.5
460
460.5
461
461.5
462
462.5
463
463.5
464
464.5
465
465.5
466
466.5
467
467.5
468
468.5
469
469.5
470
470.5
471
471.5
472
472.5
473
473.5
474
474.5
475
475.5
476
476.5
477
477.5
478
478.5
479
479.5
480
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7803.27
7803.6
7803.93
7804.26
7804.59
7804.92
7805.25
7805.58
7805.91
7806.24
7806.57
7806.9
7807.23
7807.56
7807.89
7808.22
7808.55
7808.88
7809.21
7809.54
7809.87
7810.2
7810.53
7810.86
7811.19
7811.52
7811.85
7812.18
7812.51
7812.84
7813.17
7813.5
7813.83
7814.16
7814.49
7814.82
7815.15
7815.48
7815.81
7816.14
7816.47
7816.8
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
0.002
-0.005
0.001
0.003
0.000
-0.002
-0.005
0.003
0.003
-0.003
0.001
-0.002
0.000
0.002
-0.001
0.004
-0.002
0.000
0.001
0.003
-0.002
0.002
-0.003
-0.002
0.004
-0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
-0.003
0.001
-0.003
0.004
0.002
-0.004
-0.008
0.005
Rows of
data to
shift to
Highest
004389Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.002
0.005
0.001
0.003
0.000
0.002
0.005
0.003
0.003
0.003
0.001
0.002
0.000
0.002
0.001
0.004
0.002
0.000
0.001
0.003
0.002
0.002
0.003
0.002
0.004
0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.004
0.008
0.005
10/12/09 02:44:02
10/12/09 02:44:04
10/12/09 02:44:06
10/12/09 02:44:08
10/12/09 02:44:10
10/12/09 02:44:12
10/12/09 02:44:14
10/12/09 02:44:16
10/12/09 02:44:18
10/12/09 02:44:20
10/12/09 02:44:22
10/12/09 02:44:24
10/12/09 02:44:26
10/12/09 02:44:28
10/12/09 02:44:30
10/12/09 02:44:32
10/12/09 02:44:34
10/12/09 02:44:36
10/12/09 02:44:38
10/12/09 02:44:40
10/12/09 02:44:42
10/12/09 02:44:44
10/12/09 02:44:46
10/12/09 02:44:48
10/12/09 02:44:50
10/12/09 02:44:52
10/12/09 02:44:54
10/12/09 02:44:56
10/12/09 02:44:58
10/12/09 02:45:00
10/12/09 02:45:02
10/12/09 02:45:04
10/12/09 02:45:06
10/12/09 02:45:08
10/12/09 02:45:10
10/12/09 02:45:12
10/12/09 02:45:14
10/12/09 02:45:16
10/12/09 02:45:18
10/12/09 02:45:20
10/12/09 02:45:22
10/12/09 02:45:24
Hz
60.039
60.036
60.037
60.034
60.033
60.032
60.031
60.033
60.027
60.031
60.032
60.031
60.031
60.033
60.039
60.039
60.038
60.037
60.035
60.037
60.04
60.042
60.035
60.036
60.04
60.045
60.045
60.048
60.042
60.044
60.044
60.044
60.041
60.04
60.04
60.045
60.044
60.042
60.039
60.042
60.042
60.041
3699.364
3701.791
3700.708
3700.753
3702.148
3705.213
3707.521
3707.287
3706.988
3707.34
3707.917
3707.384
3706.857
3707.615
3706.823
3703.746
3701.582
3700.847
3701.208
3702.212
3701.686
3700.397
3699.69
3700.366
3700.827
3700.662
3696.935
3695.688
3695.819
3693.824
3694.799
3696.897
3696.023
3697.502
3698.424
3699.427
3700.177
3699.806
3697.577
3697.681
3698.507
3698.359
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
480.5
481
481.5
482
482.5
483
483.5
484
484.5
485
485.5
486
486.5
487
487.5
488
488.5
489
489.5
490
490.5
491
491.5
492
492.5
493
493.5
494
494.5
495
495.5
496
496.5
497
497.5
498
498.5
499
499.5
500
500.5
501
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7817.13
7817.46
7817.79
7818.12
7818.45
7818.78
7819.11
7819.44
7819.77
7820.1
7820.43
7820.76
7821.09
7821.42
7821.75
7822.08
7822.41
7822.74
7823.07
7823.4
7823.73
7824.06
7824.39
7824.72
7825.05
7825.38
7825.71
7826.04
7826.37
7826.7
7827.03
7827.36
7827.69
7828.02
7828.35
7828.68
7829.01
7829.34
7829.67
7830
7830.33
7830.66
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.003
0.001
-0.003
-0.001
-0.001
-0.001
0.002
-0.006
0.004
0.001
-0.001
0.000
0.002
0.006
0.000
-0.001
-0.001
-0.002
0.002
0.003
0.002
-0.007
0.001
0.004
0.005
0.000
0.003
-0.006
0.002
0.000
0.000
-0.003
-0.001
0.000
0.005
-0.001
-0.002
-0.003
0.003
0.000
-0.001
Rows of
data to
shift to
Highest
004390Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.003
0.001
0.003
0.001
0.001
0.001
0.002
0.006
0.004
0.001
0.001
0.000
0.002
0.006
0.000
0.001
0.001
0.002
0.002
0.003
0.002
0.007
0.001
0.004
0.005
0.000
0.003
0.006
0.002
0.000
0.000
0.003
0.001
0.000
0.005
0.001
0.002
0.003
0.003
0.000
0.001
10/12/09 02:45:26
10/12/09 02:45:28
10/12/09 02:45:30
10/12/09 02:45:32
10/12/09 02:45:34
10/12/09 02:45:36
10/12/09 02:45:38
10/12/09 02:45:40
10/12/09 02:45:42
10/12/09 02:45:44
10/12/09 02:45:46
10/12/09 02:45:48
10/12/09 02:45:50
10/12/09 02:45:52
10/12/09 02:45:54
10/12/09 02:45:56
10/12/09 02:45:58
10/12/09 02:46:00
10/12/09 02:46:02
10/12/09 02:46:04
10/12/09 02:46:06
10/12/09 02:46:08
10/12/09 02:46:10
10/12/09 02:46:12
10/12/09 02:46:14
10/12/09 02:46:16
10/12/09 02:46:18
10/12/09 02:46:20
10/12/09 02:46:22
10/12/09 02:46:24
10/12/09 02:46:26
10/12/09 02:46:28
10/12/09 02:46:30
10/12/09 02:46:32
10/12/09 02:46:34
10/12/09 02:46:36
10/12/09 02:46:38
10/12/09 02:46:40
10/12/09 02:46:42
10/12/09 02:46:44
10/12/09 02:46:46
10/12/09 02:46:48
Hz
60.038
60.036
60.037
60.039
60.038
60.04
60.039
60.037
60.038
60.039
60.04
60.037
60.037
60.037
60.039
60.038
60.036
60.035
60.033
60.031
60.03
60.032
60.032
60.037
60.042
60.041
60.036
60.031
60.032
60.031
60.034
60.034
60.032
60.038
60.043
60.044
60.042
60.045
60.04
60.04
60.043
60.043
3698.466
3699.077
3700.262
3701.592
3700.902
3700.143
3700.27
3701.139
3701.586
3700.264
3699.458
3699.721
3700.458
3699.505
3698.794
3699.216
3699.4
3700.661
3702.173
3702.968
3705.195
3704.952
3705.775
3705.621
3703.744
3701.981
3700.756
3700.747
3702.213
3705.059
3705.514
3704.449
3703.831
3703.62
3702.795
3701.432
3697.38
3696.25
3696.302
3693.518
3693.577
3695.197
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
501.5
502
502.5
503
503.5
504
504.5
505
505.5
506
506.5
507
507.5
508
508.5
509
509.5
510
510.5
511
511.5
512
512.5
513
513.5
514
514.5
515
515.5
516
516.5
517
517.5
518
518.5
519
519.5
520
520.5
521
521.5
522
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7830.99
7831.32
7831.65
7831.98
7832.31
7832.64
7832.97
7833.3
7833.63
7833.96
7834.29
7834.62
7834.95
7835.28
7835.61
7835.94
7836.27
7836.6
7836.93
7837.26
7837.59
7837.92
7838.25
7838.58
7838.91
7839.24
7839.57
7839.9
7840.23
7840.56
7840.89
7841.22
7841.55
7841.88
7842.21
7842.54
7842.87
7843.2
7843.53
7843.86
7844.19
7844.52
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.002
0.001
0.002
-0.001
0.002
-0.001
-0.002
0.001
0.001
0.001
-0.003
0.000
0.000
0.002
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.002
0.000
0.005
0.005
-0.001
-0.005
-0.005
0.001
-0.001
0.003
0.000
-0.002
0.006
0.005
0.001
-0.002
0.003
-0.005
0.000
0.003
0.000
Rows of
data to
shift to
Highest
004391Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.002
0.001
0.002
0.001
0.002
0.001
0.002
0.001
0.001
0.001
0.003
0.000
0.000
0.002
0.001
0.002
0.001
0.002
0.002
0.001
0.002
0.000
0.005
0.005
0.001
0.005
0.005
0.001
0.001
0.003
0.000
0.002
0.006
0.005
0.001
0.002
0.003
0.005
0.000
0.003
0.000
10/12/09 02:46:50
10/12/09 02:46:52
10/12/09 02:46:54
10/12/09 02:46:56
10/12/09 02:46:58
10/12/09 02:47:00
10/12/09 02:47:02
10/12/09 02:47:04
10/12/09 02:47:06
10/12/09 02:47:08
10/12/09 02:47:10
10/12/09 02:47:12
10/12/09 02:47:14
10/12/09 02:47:16
10/12/09 02:47:18
10/12/09 02:47:20
10/12/09 02:47:22
10/12/09 02:47:24
10/12/09 02:47:26
10/12/09 02:47:28
10/12/09 02:47:30
10/12/09 02:47:32
10/12/09 02:47:34
10/12/09 02:47:36
10/12/09 02:47:38
10/12/09 02:47:40
10/12/09 02:47:42
10/12/09 02:47:44
10/12/09 02:47:46
10/12/09 02:47:48
10/12/09 02:47:50
10/12/09 02:47:52
10/12/09 02:47:54
10/12/09 02:47:56
10/12/09 02:47:58
10/12/09 02:48:00
10/12/09 02:48:02
10/12/09 02:48:04
10/12/09 02:48:06
10/12/09 02:48:08
10/12/09 02:48:10
10/12/09 02:48:12
Hz
60.041
60.04
60.038
60.043
60.044
60.042
60.036
60.043
60.041
60.042
60.043
60.043
60.036
60.039
60.039
60.037
60.034
60.035
60.035
60.035
60.036
60.03
60.03
60.03
60.031
60.031
60.032
60.031
60.032
60.032
60.032
60.033
60.037
60.04
60.039
60.042
60.036
60.039
60.041
60.04
60.035
60.036
3695.186
3693.786
3694.753
3694.926
3694.938
3694.159
3691.33
3692.686
3693.238
3693.39
3692.357
3690.951
3690.836
3692.042
3693.114
3694.117
3695.258
3695.581
3695.949
3695.491
3696.305
3696.486
3697.336
3699.171
3699.357
3699.251
3699.117
3699.105
3699.126
3698.954
3698.136
3698.277
3697.412
3695.94
3693.736
3693.224
3691.759
3691.919
3692.798
3691.582
3692.374
3693.302
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
522.5
523
523.5
524
524.5
525
525.5
526
526.5
527
527.5
528
528.5
529
529.5
530
530.5
531
531.5
532
532.5
533
533.5
534
534.5
535
535.5
536
536.5
537
537.5
538
538.5
539
539.5
540
540.5
541
541.5
542
542.5
543
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7844.85
7845.18
7845.51
7845.84
7846.17
7846.5
7846.83
7847.16
7847.49
7847.82
7848.15
7848.48
7848.81
7849.14
7849.47
7849.8
7850.13
7850.46
7850.79
7851.12
7851.45
7851.78
7852.11
7852.44
7852.77
7853.1
7853.43
7853.76
7854.09
7854.42
7854.75
7855.08
7855.41
7855.74
7856.07
7856.4
7856.73
7857.06
7857.39
7857.72
7858.05
7858.38
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.001
-0.002
0.005
0.001
-0.002
-0.006
0.007
-0.002
0.001
0.001
0.000
-0.007
0.003
0.000
-0.002
-0.003
0.001
0.000
0.000
0.001
-0.006
0.000
0.000
0.001
0.000
0.001
-0.001
0.001
0.000
0.000
0.001
0.004
0.003
-0.001
0.003
-0.006
0.003
0.002
-0.001
-0.005
0.001
Rows of
data to
shift to
Highest
004392Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.001
0.002
0.005
0.001
0.002
0.006
0.007
0.002
0.001
0.001
0.000
0.007
0.003
0.000
0.002
0.003
0.001
0.000
0.000
0.001
0.006
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.004
0.003
0.001
0.003
0.006
0.003
0.002
0.001
0.005
0.001
10/12/09 02:48:14
10/12/09 02:48:16
10/12/09 02:48:18
10/12/09 02:48:20
10/12/09 02:48:22
10/12/09 02:48:24
10/12/09 02:48:26
10/12/09 02:48:28
10/12/09 02:48:30
10/12/09 02:48:32
10/12/09 02:48:34
10/12/09 02:48:36
10/12/09 02:48:38
10/12/09 02:48:40
10/12/09 02:48:42
10/12/09 02:48:44
10/12/09 02:48:46
10/12/09 02:48:48
10/12/09 02:48:50
10/12/09 02:48:52
10/12/09 02:48:54
10/12/09 02:48:56
10/12/09 02:48:58
10/12/09 02:49:00
10/12/09 02:49:02
10/12/09 02:49:04
10/12/09 02:49:06
10/12/09 02:49:08
10/12/09 02:49:10
10/12/09 02:49:12
10/12/09 02:49:14
10/12/09 02:49:16
10/12/09 02:49:18
10/12/09 02:49:20
10/12/09 02:49:22
10/12/09 02:49:24
10/12/09 02:49:26
10/12/09 02:49:28
10/12/09 02:49:30
10/12/09 02:49:32
10/12/09 02:49:34
10/12/09 02:49:36
Hz
60.038
60.037
60.041
60.04
60.036
60.033
60.034
60.038
60.04
60.041
60.037
60.037
60.036
60.037
60.038
60.039
60.038
60.034
60.033
60.031
60.034
60.029
60.029
60.031
60.03
60.03
60.026
60.022
60.021
60.024
60.023
60.02
60.021
60.023
60.025
60.026
60.026
60.025
60.024
60.024
60.025
60.023
3694.71
3694.331
3693.815
3693.617
3694.324
3694.27
3694.66
3693.748
3692.532
3691.445
3691.012
3691.799
3693.077
3693.727
3693.117
3692.641
3688.159
3689.02
3688.208
3690.092
3693.172
3693.321
3694.593
3695.225
3694.609
3693.412
3693.509
3696.026
3698.012
3699.062
3699.414
3698.935
3700.084
3700.544
3700.486
3698.596
3697.961
3699.914
3700.802
3701.301
3701.45
3701.349
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
543.5
544
544.5
545
545.5
546
546.5
547
547.5
548
548.5
549
549.5
550
550.5
551
551.5
552
552.5
553
553.5
554
554.5
555
555.5
556
556.5
557
557.5
558
558.5
559
559.5
560
560.5
561
561.5
562
562.5
563
563.5
564
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7858.71
7859.04
7859.37
7859.7
7860.03
7860.36
7860.69
7861.02
7861.35
7861.68
7862.01
7862.34
7862.67
7863
7863.33
7863.66
7863.99
7864.32
7864.65
7864.98
7865.31
7865.64
7865.97
7866.3
7866.63
7866.96
7867.29
7867.62
7867.95
7868.28
7868.61
7868.94
7869.27
7869.6
7869.93
7870.26
7870.59
7870.92
7871.25
7871.58
7871.91
7872.24
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
-0.001
0.004
-0.001
-0.004
-0.003
0.001
0.004
0.002
0.001
-0.004
0.000
-0.001
0.001
0.001
0.001
-0.001
-0.004
-0.001
-0.002
0.003
-0.005
0.000
0.002
-0.001
0.000
-0.004
-0.004
-0.001
0.003
-0.001
-0.003
0.001
0.002
0.002
0.001
0.000
-0.001
-0.001
0.000
0.001
-0.002
Rows of
data to
shift to
Highest
004393Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.001
0.004
0.001
0.004
0.003
0.001
0.004
0.002
0.001
0.004
0.000
0.001
0.001
0.001
0.001
0.001
0.004
0.001
0.002
0.003
0.005
0.000
0.002
0.001
0.000
0.004
0.004
0.001
0.003
0.001
0.003
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.002
10/12/09 02:49:38
10/12/09 02:49:40
10/12/09 02:49:42
10/12/09 02:49:44
10/12/09 02:49:46
10/12/09 02:49:48
10/12/09 02:49:50
10/12/09 02:49:52
10/12/09 02:49:54
10/12/09 02:49:56
10/12/09 02:49:58
10/12/09 02:50:00
10/12/09 02:50:02
10/12/09 02:50:04
10/12/09 02:50:06
10/12/09 02:50:08
10/12/09 02:50:10
10/12/09 02:50:12
10/12/09 02:50:14
10/12/09 02:50:16
10/12/09 02:50:18
10/12/09 02:50:20
10/12/09 02:50:22
10/12/09 02:50:24
10/12/09 02:50:26
10/12/09 02:50:28
10/12/09 02:50:30
10/12/09 02:50:32
10/12/09 02:50:34
10/12/09 02:50:36
10/12/09 02:50:38
10/12/09 02:50:40
10/12/09 02:50:42
10/12/09 02:50:44
10/12/09 02:50:46
10/12/09 02:50:48
10/12/09 02:50:50
10/12/09 02:50:52
10/12/09 02:50:54
10/12/09 02:50:56
10/12/09 02:50:58
10/12/09 02:51:00
Hz
60.023
60.022
60.026
60.029
60.026
60.024
60.021
60.025
60.025
60.025
60.023
60.026
60.024
60.022
60.023
60.026
60.025
60.02
60.02
60.019
60.015
60.016
60.017
60.015
60.015
60.017
60.017
60.012
60.01
60.008
60.002
59.999
59.999
60.002
60.003
60.004
60.001
59.996
59.993
59.992
59.989
59.987
3701.094
3701.702
3702.07
3701.965
3700.269
3700.241
3701.09
3701.268
3701.205
3700.587
3700.532
3700.177
3700.295
3700.277
3700.841
3700.863
3700.26
3700.052
3699.926
3700.965
3702.581
3703.516
3703.824
3703.672
3703.689
3703.003
3702.921
3703
3703.167
3703.918
3703.616
3703.775
3703.751
3701.534
3700.617
3700.88
3700.625
3701.389
3701.737
3700.671
3700.826
3700.977
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
564.5
565
565.5
566
566.5
567
567.5
568
568.5
569
569.5
570
570.5
571
571.5
572
572.5
573
573.5
574
574.5
575
575.5
576
576.5
577
577.5
578
578.5
579
579.5
580
580.5
581
581.5
582
582.5
583
583.5
584
584.5
585
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7872.57
7872.9
7873.23
7873.56
7873.89
7874.22
7874.55
7874.88
7875.21
7875.54
7875.87
7876.2
7876.53
7876.86
7877.19
7877.52
7877.85
7878.18
7878.51
7878.84
7879.17
7879.5
7879.83
7880.16
7880.49
7880.82
7881.15
7881.48
7881.81
7882.14
7882.47
7882.8
7883.13
7883.46
7883.79
7884.12
7884.45
7884.78
7885.11
7885.44
7885.77
7886.1
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.001
0.004
0.003
-0.003
-0.002
-0.003
0.004
0.000
0.000
-0.002
0.003
-0.002
-0.002
0.001
0.003
-0.001
-0.005
0.000
-0.001
-0.004
0.001
0.001
-0.002
0.000
0.002
0.000
-0.005
-0.002
-0.002
-0.006
-0.003
0.000
0.003
0.001
0.001
-0.003
-0.005
-0.003
-0.001
-0.003
-0.002
Rows of
data to
shift to
Highest
004394Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.001
0.004
0.003
0.003
0.002
0.003
0.004
0.000
0.000
0.002
0.003
0.002
0.002
0.001
0.003
0.001
0.005
0.000
0.001
0.004
0.001
0.001
0.002
0.000
0.002
0.000
0.005
0.002
0.002
0.006
0.003
0.000
0.003
0.001
0.001
0.003
0.005
0.003
0.001
0.003
0.002
10/12/09 02:51:02
10/12/09 02:51:04
10/12/09 02:51:06
10/12/09 02:51:08
10/12/09 02:51:10
10/12/09 02:51:12
10/12/09 02:51:14
10/12/09 02:51:16
10/12/09 02:51:18
10/12/09 02:51:20
10/12/09 02:51:22
10/12/09 02:51:24
10/12/09 02:51:26
10/12/09 02:51:28
10/12/09 02:51:30
10/12/09 02:51:32
10/12/09 02:51:34
10/12/09 02:51:36
10/12/09 02:51:38
10/12/09 02:51:40
10/12/09 02:51:42
10/12/09 02:51:44
10/12/09 02:51:46
10/12/09 02:51:48
10/12/09 02:51:50
10/12/09 02:51:52
10/12/09 02:51:54
10/12/09 02:51:56
10/12/09 02:51:58
10/12/09 02:52:00
10/12/09 02:52:02
10/12/09 02:52:04
10/12/09 02:52:06
10/12/09 02:52:08
10/12/09 02:52:10
10/12/09 02:52:12
10/12/09 02:52:14
10/12/09 02:52:16
10/12/09 02:52:18
10/12/09 02:52:20
10/12/09 02:52:22
10/12/09 02:52:24
Hz
59.985
59.985
59.986
59.984
59.981
59.98
59.977
59.975
59.976
59.972
59.974
59.977
59.975
59.973
59.971
59.971
59.976
59.979
59.98
59.979
59.982
59.982
59.983
59.981
59.979
59.978
59.976
59.978
59.977
59.976
59.978
59.975
59.971
59.97
59.97
59.971
59.99
59.998
59.999
59.999
59.998
59.999
3700.7
3699.854
3700.237
3700.342
3700.77
3700.789
3701.625
3703.166
3704.187
3704.785
3705.811
3706.958
3706.688
3706.543
3706.257
3707.027
3710.118
3710.531
3708.701
3708.018
3706.942
3706.343
3706.125
3706.311
3706.119
3706.19
3707.721
3709.409
3708.971
3708.531
3708.071
3707.24
3709.213
3709.961
3711.75
3711.98
3710.695
3707.867
3704.912
3705.639
3703.787
3703.191
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
585.5
586
586.5
587
587.5
588
588.5
589
589.5
590
590.5
591
591.5
592
592.5
593
593.5
594
594.5
595
595.5
596
596.5
597
597.5
598
598.5
599
599.5
600
600.5
601
601.5
602
602.5
603
603.5
604
604.5
605
605.5
606
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7886.43
7886.76
7887.09
7887.42
7887.75
7888.08
7888.41
7888.74
7889.07
7889.4
7889.73
7890.06
7890.39
7890.72
7891.05
7891.38
7891.71
7892.04
7892.37
7892.7
7893.03
7893.36
7893.69
7894.02
7894.35
7894.68
7895.01
7895.34
7895.67
7896
7896.33
7896.66
7896.99
7897.32
7897.65
7897.98
7898.31
7898.64
7898.97
7899.3
7899.63
7899.96
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.001
-0.002
-0.003
-0.001
-0.003
-0.002
0.001
-0.004
0.002
0.003
-0.002
-0.002
-0.002
0.000
0.005
0.003
0.001
-0.001
0.003
0.000
0.001
-0.002
-0.002
-0.001
-0.002
0.002
-0.001
-0.001
0.002
-0.003
-0.004
-0.001
0.000
0.001
0.019
0.008
0.001
0.000
-0.001
0.001
Rows of
data to
shift to
Highest
004395Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.001
0.002
0.003
0.001
0.003
0.002
0.001
0.004
0.002
0.003
0.002
0.002
0.002
0.000
0.005
0.003
0.001
0.001
0.003
0.000
0.001
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.002
0.003
0.004
0.001
0.000
0.001
0.019
0.008
0.001
0.000
0.001
0.001
10/12/09 02:52:26
10/12/09 02:52:28
10/12/09 02:52:30
10/12/09 02:52:32
10/12/09 02:52:34
10/12/09 02:52:36
10/12/09 02:52:38
10/12/09 02:52:40
10/12/09 02:52:42
10/12/09 02:52:44
10/12/09 02:52:46
10/12/09 02:52:48
10/12/09 02:52:50
10/12/09 02:52:52
10/12/09 02:52:54
10/12/09 02:52:56
10/12/09 02:52:58
10/12/09 02:53:00
10/12/09 02:53:02
10/12/09 02:53:04
10/12/09 02:53:06
10/12/09 02:53:08
10/12/09 02:53:10
10/12/09 02:53:12
10/12/09 02:53:14
10/12/09 02:53:16
10/12/09 02:53:18
10/12/09 02:53:20
10/12/09 02:53:22
10/12/09 02:53:24
10/12/09 02:53:26
10/12/09 02:53:28
10/12/09 02:53:30
10/12/09 02:53:32
10/12/09 02:53:34
10/12/09 02:53:36
10/12/09 02:53:38
10/12/09 02:53:40
10/12/09 02:53:42
10/12/09 02:53:44
10/12/09 02:53:46
10/12/09 02:53:48
Hz
60.003
60.005
60.005
60.01
60.013
60.02
60.022
60.024
60.025
60.025
60.024
60.023
60.029
60.029
60.029
60.028
60.028
60.031
60.032
60.033
60.031
60.03
60.022
60.021
60.019
60.017
60.017
60.017
60.016
60.015
60.015
60.012
60.009
60.008
60.008
60.005
60.005
60.003
59.999
59.997
59.999
60
3702.071
3699.51
3698.658
3698.137
3697.882
3698.668
3698.604
3697.868
3694.672
3693.912
3693.418
3688.301
3688.021
3689.143
3688.237
3687.878
3687.026
3686.683
3685.276
3685.576
3685.985
3686.418
3687.159
3687.873
3688.997
3690.426
3690.776
3692.715
3692.578
3692.462
3693.173
3693.249
3693.743
3695.124
3694.681
3694.741
3694.199
3693.75
3693.624
3692.806
3691.15
3691.407
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
606.5
607
607.5
608
608.5
609
609.5
610
610.5
611
611.5
612
612.5
613
613.5
614
614.5
615
615.5
616
616.5
617
617.5
618
618.5
619
619.5
620
620.5
621
621.5
622
622.5
623
623.5
624
624.5
625
625.5
626
626.5
627
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7900.29
7900.62
7900.95
7901.28
7901.61
7901.94
7902.27
7902.6
7902.93
7903.26
7903.59
7903.92
7904.25
7904.58
7904.91
7905.24
7905.57
7905.9
7906.23
7906.56
7906.89
7907.22
7907.55
7907.88
7908.21
7908.54
7908.87
7909.2
7909.53
7909.86
7910.19
7910.52
7910.85
7911.18
7911.51
7911.84
7912.17
7912.5
7912.83
7913.16
7913.49
7913.82
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
-0.001
-0.001
0.006
0.000
0.000
-0.001
0.000
0.003
0.001
0.001
-0.002
-0.001
-0.008
-0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.001
0.000
-0.003
-0.003
-0.001
0.000
-0.003
0.000
-0.002
-0.004
-0.002
0.002
0.001
Rows of
data to
shift to
Highest
004396Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
0.001
0.001
0.006
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.008
0.001
0.002
0.002
0.000
0.000
0.001
0.001
0.000
0.003
0.003
0.001
0.000
0.003
0.000
0.002
0.004
0.002
0.002
0.001
10/12/09 02:53:50
10/12/09 02:53:52
10/12/09 02:53:54
10/12/09 02:53:56
10/12/09 02:53:58
10/12/09 02:54:00
10/12/09 02:54:02
10/12/09 02:54:04
10/12/09 02:54:06
10/12/09 02:54:08
10/12/09 02:54:10
10/12/09 02:54:12
10/12/09 02:54:14
10/12/09 02:54:16
10/12/09 02:54:18
10/12/09 02:54:20
10/12/09 02:54:22
10/12/09 02:54:24
10/12/09 02:54:26
10/12/09 02:54:28
10/12/09 02:54:30
10/12/09 02:54:32
10/12/09 02:54:34
10/12/09 02:54:36
10/12/09 02:54:38
10/12/09 02:54:40
10/12/09 02:54:42
10/12/09 02:54:44
10/12/09 02:54:46
10/12/09 02:54:48
10/12/09 02:54:50
10/12/09 02:54:52
10/12/09 02:54:54
10/12/09 02:54:56
10/12/09 02:54:58
10/12/09 02:55:00
10/12/09 02:55:02
10/12/09 02:55:04
10/12/09 02:55:06
10/12/09 02:55:08
10/12/09 02:55:10
10/12/09 02:55:12
Hz
59.998
59.995
59.994
59.992
59.993
59.988
59.985
59.986
59.988
59.988
59.985
59.983
59.983
59.985
59.986
59.987
59.99
59.986
59.985
59.984
59.983
59.982
59.982
59.98
59.978
59.977
59.975
59.973
59.975
59.976
59.976
59.979
59.982
59.979
59.979
59.977
59.977
59.978
59.978
59.978
59.979
59.983
3691.077
3690.588
3689.797
3688.483
3689.445
3689.553
3689.525
3689.736
3688.853
3688.24
3687.494
3687.475
3686.707
3685.66
3684.51
3684.333
3683.911
3683.735
3684.208
3683.811
3683.473
3684.258
3684.884
3685.092
3685.654
3685.087
3685.491
3685.196
3687.412
3688.417
3688.599
3687.848
3686.678
3685.782
3684.89
3685.143
3684.549
3684.093
3684.555
3682.814
3682.318
3682.366
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
627.5
628
628.5
629
629.5
630
630.5
631
631.5
632
632.5
633
633.5
634
634.5
635
635.5
636
636.5
637
637.5
638
638.5
639
639.5
640
640.5
641
641.5
642
642.5
643
643.5
644
644.5
645
645.5
646
646.5
647
647.5
648
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7914.15
7914.48
7914.81
7915.14
7915.47
7915.8
7916.13
7916.46
7916.79
7917.12
7917.45
7917.78
7918.11
7918.44
7918.77
7919.1
7919.43
7919.76
7920.09
7920.42
7920.75
7921.08
7921.41
7921.74
7922.07
7922.4
7922.73
7923.06
7923.39
7923.72
7924.05
7924.38
7924.71
7925.04
7925.37
7925.7
7926.03
7926.36
7926.69
7927.02
7927.35
7927.68
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.003
-0.001
-0.002
0.001
-0.005
-0.003
0.001
0.002
0.000
-0.003
-0.002
0.000
0.002
0.001
0.001
0.003
-0.004
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
-0.001
-0.002
-0.002
0.002
0.001
0.000
0.003
0.003
-0.003
0.000
-0.002
0.000
0.001
0.000
0.000
0.001
0.004
Rows of
data to
shift to
Highest
004397Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.003
0.001
0.002
0.001
0.005
0.003
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.001
0.001
0.003
0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.000
0.002
0.000
0.001
0.000
0.000
0.001
0.004
10/12/09 02:55:14
10/12/09 02:55:16
10/12/09 02:55:18
10/12/09 02:55:20
10/12/09 02:55:22
10/12/09 02:55:24
10/12/09 02:55:26
10/12/09 02:55:28
10/12/09 02:55:30
10/12/09 02:55:32
10/12/09 02:55:34
10/12/09 02:55:36
10/12/09 02:55:38
10/12/09 02:55:40
10/12/09 02:55:42
10/12/09 02:55:44
10/12/09 02:55:46
10/12/09 02:55:48
10/12/09 02:55:50
10/12/09 02:55:52
10/12/09 02:55:54
10/12/09 02:55:56
10/12/09 02:55:58
10/12/09 02:56:00
10/12/09 02:56:02
10/12/09 02:56:04
10/12/09 02:56:06
10/12/09 02:56:08
10/12/09 02:56:10
10/12/09 02:56:12
10/12/09 02:56:14
10/12/09 02:56:16
10/12/09 02:56:18
10/12/09 02:56:20
10/12/09 02:56:22
10/12/09 02:56:24
10/12/09 02:56:26
10/12/09 02:56:28
10/12/09 02:56:30
10/12/09 02:56:32
10/12/09 02:56:34
10/12/09 02:56:36
Hz
59.981
59.98
59.978
59.979
59.978
59.979
59.983
59.987
59.99
59.992
59.993
59.99
59.988
59.988
59.99
59.993
59.994
59.993
59.994
59.994
59.993
59.989
59.984
59.986
59.985
59.988
59.987
59.986
59.987
59.985
59.982
59.981
59.982
59.987
59.992
59.997
60
60.003
60.003
60.003
60.002
60.003
3682.647
3682.855
3683.557
3684.052
3684.318
3686.049
3686.629
3685.286
3683.415
3682.416
3681.403
3679.012
3679.436
3671.761
3670.717
3670.159
3679
3680.176
3681.799
3682.7
3684.116
3685.03
3684.878
3684.165
3684.478
3685.584
3685.148
3684.587
3684.976
3683.674
3684.872
3684.245
3684.711
3685.589
3683.736
3682.579
3682.234
3682.138
3682.224
3681.689
3681.458
3681.65
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
648.5
649
649.5
650
650.5
651
651.5
652
652.5
653
653.5
654
654.5
655
655.5
656
656.5
657
657.5
658
658.5
659
659.5
660
660.5
661
661.5
662
662.5
663
663.5
664
664.5
665
665.5
666
666.5
667
667.5
668
668.5
669
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7928.01
7928.34
7928.67
7929
7929.33
7929.66
7929.99
7930.32
7930.65
7930.98
7931.31
7931.64
7931.97
7932.3
7932.63
7932.96
7933.29
7933.62
7933.95
7934.28
7934.61
7934.94
7935.27
7935.6
7935.93
7936.26
7936.59
7936.92
7937.25
7937.58
7937.91
7938.24
7938.57
7938.9
7939.23
7939.56
7939.89
7940.22
7940.55
7940.88
7941.21
7941.54
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.001
-0.002
0.001
-0.001
0.001
0.004
0.004
0.003
0.002
0.001
-0.003
-0.002
0.000
0.002
0.003
0.001
-0.001
0.001
0.000
-0.001
-0.004
-0.005
0.002
-0.001
0.003
-0.001
-0.001
0.001
-0.002
-0.003
-0.001
0.001
0.005
0.005
0.005
0.003
0.003
0.000
0.000
-0.001
0.001
Rows of
data to
shift to
Highest
004398Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.001
0.002
0.001
0.001
0.001
0.004
0.004
0.003
0.002
0.001
0.003
0.002
0.000
0.002
0.003
0.001
0.001
0.001
0.000
0.001
0.004
0.005
0.002
0.001
0.003
0.001
0.001
0.001
0.002
0.003
0.001
0.001
0.005
0.005
0.005
0.003
0.003
0.000
0.000
0.001
0.001
10/12/09 02:56:38
10/12/09 02:56:40
10/12/09 02:56:42
10/12/09 02:56:44
10/12/09 02:56:46
10/12/09 02:56:48
10/12/09 02:56:50
10/12/09 02:56:52
10/12/09 02:56:54
10/12/09 02:56:56
10/12/09 02:56:58
10/12/09 02:57:00
10/12/09 02:57:02
10/12/09 02:57:04
10/12/09 02:57:06
10/12/09 02:57:08
10/12/09 02:57:10
10/12/09 02:57:12
10/12/09 02:57:14
10/12/09 02:57:16
10/12/09 02:57:18
10/12/09 02:57:20
10/12/09 02:57:22
10/12/09 02:57:24
10/12/09 02:57:26
10/12/09 02:57:28
10/12/09 02:57:30
10/12/09 02:57:32
10/12/09 02:57:34
10/12/09 02:57:36
10/12/09 02:57:38
10/12/09 02:57:40
10/12/09 02:57:42
10/12/09 02:57:44
10/12/09 02:57:46
10/12/09 02:57:48
10/12/09 02:57:50
10/12/09 02:57:52
10/12/09 02:57:54
10/12/09 02:57:56
10/12/09 02:57:58
10/12/09 02:58:00
Hz
60.002
60.003
60.004
60.005
60.006
60.009
60.012
60.017
60.021
60.022
60.021
60.02
60.018
60.021
60.02
60.02
60.018
60.018
60.019
60.019
60.018
60.017
60.016
60.016
60.016
60.015
60.014
60.014
60.013
60.013
60.015
60.017
60.016
60.019
60.021
60.021
60.02
60.022
60.024
60.026
60.025
60.026
3681.013
3680.167
3679.943
3679.429
3679.669
3678.981
3678.267
3676.796
3676.81
3674.798
3673.906
3671.145
3670.51
3673.648
3673.684
3675.865
3676.676
3676.404
3676.437
3677.185
3677.659
3678.828
3679.289
3678.915
3679.276
3678.599
3678.367
3678.25
3678.589
3677.251
3675.698
3674.669
3674.87
3674.402
3674.546
3672.969
3671.914
3671.982
3670.946
3670.821
3671.06
3671.539
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
669.5
670
670.5
671
671.5
672
672.5
673
673.5
674
674.5
675
675.5
676
676.5
677
677.5
678
678.5
679
679.5
680
680.5
681
681.5
682
682.5
683
683.5
684
684.5
685
685.5
686
686.5
687
687.5
688
688.5
689
689.5
690
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7941.87
7942.2
7942.53
7942.86
7943.19
7943.52
7943.85
7944.18
7944.51
7944.84
7945.17
7945.5
7945.83
7946.16
7946.49
7946.82
7947.15
7947.48
7947.81
7948.14
7948.47
7948.8
7949.13
7949.46
7949.79
7950.12
7950.45
7950.78
7951.11
7951.44
7951.77
7952.1
7952.43
7952.76
7953.09
7953.42
7953.75
7954.08
7954.41
7954.74
7955.07
7955.4
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
-0.001
-0.001
-0.002
0.003
-0.001
0.000
-0.002
0.000
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
-0.001
0.003
0.002
0.000
-0.001
0.002
0.002
0.002
-0.001
0.001
Rows of
data to
shift to
Highest
004399Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
0.001
0.001
0.002
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.002
0.001
0.001
10/12/09 02:58:02
10/12/09 02:58:04
10/12/09 02:58:06
10/12/09 02:58:08
10/12/09 02:58:10
10/12/09 02:58:12
10/12/09 02:58:14
10/12/09 02:58:16
10/12/09 02:58:18
10/12/09 02:58:20
10/12/09 02:58:22
10/12/09 02:58:24
10/12/09 02:58:26
10/12/09 02:58:28
10/12/09 02:58:30
10/12/09 02:58:32
10/12/09 02:58:34
10/12/09 02:58:36
10/12/09 02:58:38
10/12/09 02:58:40
10/12/09 02:58:42
10/12/09 02:58:44
10/12/09 02:58:46
10/12/09 02:58:48
10/12/09 02:58:50
10/12/09 02:58:52
10/12/09 02:58:54
10/12/09 02:58:56
10/12/09 02:58:58
10/12/09 02:59:00
10/12/09 02:59:02
10/12/09 02:59:04
10/12/09 02:59:06
10/12/09 02:59:08
10/12/09 02:59:10
10/12/09 02:59:12
10/12/09 02:59:14
10/12/09 02:59:16
10/12/09 02:59:18
10/12/09 02:59:20
10/12/09 02:59:22
10/12/09 02:59:24
Hz
60.022
60.021
60.022
60.024
60.027
60.029
60.028
60.028
60.032
60.035
60.03
60.028
60.021
60.021
60.024
60.025
60.024
60.022
60.023
60.021
60.02
60.02
60.02
60.02
60.017
60.014
60.012
60.01
60.011
60.01
60.01
60.01
60.012
60.012
60.013
60.014
60.013
60.012
60.011
60.01
60.008
60.01
3673.794
3674.01
3675.102
3675.284
3676.051
3675.704
3672.583
3671.343
3670.232
3668.654
3668.767
3666.312
3667.322
3657.164
3657.714
3668.637
3669.309
3670.112
3670.735
3671.332
3672.095
3672.683
3673.833
3674.645
3675.641
3675.971
3677.009
3678.314
3679.393
3680.02
3679.792
3679.597
3680.315
3680.11
3679.062
3679.127
3679.587
3679.637
3679.02
3678.418
3679.383
3679.681
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
690.5
691
691.5
692
692.5
693
693.5
694
694.5
695
695.5
696
696.5
697
697.5
698
698.5
699
699.5
700
700.5
701
701.5
702
702.5
703
703.5
704
704.5
705
705.5
706
706.5
707
707.5
708
708.5
709
709.5
710
710.5
711
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7955.73
7956.06
7956.39
7956.72
7957.05
7957.38
7957.71
7958.04
7958.37
7958.7
7959.03
7959.36
7959.69
7960.02
7960.35
7960.68
7961.01
7961.34
7961.67
7962
7962.33
7962.66
7962.99
7963.32
7963.65
7963.98
7964.31
7964.64
7964.97
7965.3
7965.63
7965.96
7966.29
7966.62
7966.95
7967.28
7967.61
7967.94
7968.27
7968.6
7968.93
7969.26
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.004
-0.001
0.001
0.002
0.003
0.002
-0.001
0.000
0.004
0.003
-0.005
-0.002
-0.007
0.000
0.003
0.001
-0.001
-0.002
0.001
-0.002
-0.001
0.000
0.000
0.000
-0.003
-0.003
-0.002
-0.002
0.001
-0.001
0.000
0.000
0.002
0.000
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.002
Rows of
data to
shift to
Highest
004400Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.004
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.004
0.003
0.005
0.002
0.007
0.000
0.003
0.001
0.001
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.002
10/12/09 02:59:26
10/12/09 02:59:28
10/12/09 02:59:30
10/12/09 02:59:32
10/12/09 02:59:34
10/12/09 02:59:36
10/12/09 02:59:38
10/12/09 02:59:40
10/12/09 02:59:42
10/12/09 02:59:44
10/12/09 02:59:46
10/12/09 02:59:48
10/12/09 02:59:50
10/12/09 02:59:52
10/12/09 02:59:54
10/12/09 02:59:56
10/12/09 02:59:58
10/12/09 03:00:00
10/12/09 03:00:02
10/12/09 03:00:04
10/12/09 03:00:06
10/12/09 03:00:08
10/12/09 03:00:10
10/12/09 03:00:12
10/12/09 03:00:14
10/12/09 03:00:16
10/12/09 03:00:18
10/12/09 03:00:20
10/12/09 03:00:22
10/12/09 03:00:24
10/12/09 03:00:26
10/12/09 03:00:28
10/12/09 03:00:30
10/12/09 03:00:32
10/12/09 03:00:34
10/12/09 03:00:36
10/12/09 03:00:38
10/12/09 03:00:40
10/12/09 03:00:42
10/12/09 03:00:44
10/12/09 03:00:46
10/12/09 03:00:48
Hz
60.011
60.013
60.016
60.018
60.019
60.019
60.019
60.02
60.02
60.018
60.018
60.016
60.016
60.019
60.023
60.022
60.018
60.015
60.016
60.017
60.015
60.01
60.004
59.999
59.995
59.99
59.982
59.974
59.97
59.97
59.968
59.968
59.968
59.972
59.967
59.966
59.964
59.965
59.966
59.963
59.963
59.965
3679.932
3679.138
3678.469
3678.499
3678.456
3677.615
3677.446
3677.431
3677.451
3677.315
3678.151
3678.362
3678.874
3680.771
3681.058
3680.353
3679.167
3679.553
3680.672
3682.73
3682.714
3681.915
3682.01
3682.483
3683.813
3685.306
3684.846
3684.643
3687.527
3689.404
3692.287
3692.966
3693.793
3694.397
3694.974
3697.407
3698.502
3698.617
3698.992
3699.85
3702.645
3701.989
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
711.5
712
712.5
713
713.5
714
714.5
715
715.5
716
716.5
717
717.5
718
718.5
719
719.5
720
720.5
721
721.5
722
722.5
723
723.5
724
724.5
725
725.5
726
726.5
727
727.5
728
728.5
729
729.5
730
730.5
731
731.5
732
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7969.59
7969.92
7970.25
7970.58
7970.91
7971.24
7971.57
7971.9
7972.23
7972.56
7972.89
7973.22
7973.55
7973.88
7974.21
7974.54
7974.87
7975.2
7975.53
7975.86
7976.19
7976.52
7976.85
7977.18
7977.51
7977.84
7978.17
7978.5
7978.83
7979.16
7979.49
7979.82
7980.15
7980.48
7980.81
7981.14
7981.47
7981.8
7982.13
7982.46
7982.79
7983.12
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.000
-0.002
0.000
-0.002
0.000
0.003
0.004
-0.001
-0.004
-0.003
0.001
0.001
-0.002
-0.005
-0.006
-0.005
-0.004
-0.005
-0.008
-0.008
-0.004
0.000
-0.002
0.000
0.000
0.004
-0.005
-0.001
-0.002
0.001
0.001
-0.003
0.000
0.002
Rows of
data to
shift to
Highest
004401Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.000
0.002
0.000
0.002
0.000
0.003
0.004
0.001
0.004
0.003
0.001
0.001
0.002
0.005
0.006
0.005
0.004
0.005
0.008
0.008
0.004
0.000
0.002
0.000
0.000
0.004
0.005
0.001
0.002
0.001
0.001
0.003
0.000
0.002
10/12/09 03:00:50
10/12/09 03:00:52
10/12/09 03:00:54
10/12/09 03:00:56
10/12/09 03:00:58
10/12/09 03:01:00
10/12/09 03:01:02
10/12/09 03:01:04
10/12/09 03:01:06
10/12/09 03:01:08
10/12/09 03:01:10
10/12/09 03:01:12
10/12/09 03:01:14
10/12/09 03:01:16
10/12/09 03:01:18
10/12/09 03:01:20
10/12/09 03:01:22
10/12/09 03:01:24
10/12/09 03:01:26
10/12/09 03:01:28
10/12/09 03:01:30
10/12/09 03:01:32
10/12/09 03:01:34
10/12/09 03:01:36
10/12/09 03:01:38
10/12/09 03:01:40
10/12/09 03:01:42
10/12/09 03:01:44
10/12/09 03:01:46
10/12/09 03:01:48
10/12/09 03:01:50
10/12/09 03:01:52
10/12/09 03:01:54
10/12/09 03:01:56
10/12/09 03:01:58
10/12/09 03:02:00
10/12/09 03:02:02
10/12/09 03:02:04
10/12/09 03:02:06
10/12/09 03:02:08
10/12/09 03:02:10
10/12/09 03:02:12
Hz
59.968
59.97
59.97
59.97
59.973
59.972
59.976
59.975
59.975
59.977
59.976
59.976
59.974
59.975
59.974
59.974
59.976
59.977
59.979
59.981
59.983
59.985
59.983
59.98
59.979
59.983
59.987
59.986
59.984
59.98
59.982
59.984
59.985
59.987
59.989
59.992
59.996
59.999
59.997
59.997
59.997
59.997
3702.218
3704.023
3703.365
3702.988
3703.814
3704.899
3705.625
3704.293
3702.094
3701.944
3703.142
3704.669
3705.376
3705.662
3705.855
3706.776
3707.514
3706.928
3706.446
3706.335
3706.771
3705.943
3704.127
3704.777
3705.974
3705.968
3705.356
3704.683
3703.913
3704.361
3704.988
3705.05
3704.893
3703.741
3701.831
3701.795
3700.07
3701.308
3700.429
3700.913
3700.541
3699.927
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
732.5
733
733.5
734
734.5
735
735.5
736
736.5
737
737.5
738
738.5
739
739.5
740
740.5
741
741.5
742
742.5
743
743.5
744
744.5
745
745.5
746
746.5
747
747.5
748
748.5
749
749.5
750
750.5
751
751.5
752
752.5
753
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7983.45
7983.78
7984.11
7984.44
7984.77
7985.1
7985.43
7985.76
7986.09
7986.42
7986.75
7987.08
7987.41
7987.74
7988.07
7988.4
7988.73
7989.06
7989.39
7989.72
7990.05
7990.38
7990.71
7991.04
7991.37
7991.7
7992.03
7992.36
7992.69
7993.02
7993.35
7993.68
7994.01
7994.34
7994.67
7995
7995.33
7995.66
7995.99
7996.32
7996.65
7996.98
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
0.000
0.000
0.003
-0.001
0.004
-0.001
0.000
0.002
-0.001
0.000
-0.002
0.001
-0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
-0.002
-0.003
-0.001
0.004
0.004
-0.001
-0.002
-0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
-0.002
0.000
0.000
0.000
Rows of
data to
shift to
Highest
004402Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.002
0.000
0.000
0.003
0.001
0.004
0.001
0.000
0.002
0.001
0.000
0.002
0.001
0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
0.002
0.003
0.001
0.004
0.004
0.001
0.002
0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
0.002
0.000
0.000
0.000
10/12/09 03:02:14
10/12/09 03:02:16
10/12/09 03:02:18
10/12/09 03:02:20
10/12/09 03:02:22
10/12/09 03:02:24
10/12/09 03:02:26
10/12/09 03:02:28
10/12/09 03:02:30
10/12/09 03:02:32
10/12/09 03:02:34
10/12/09 03:02:36
10/12/09 03:02:38
10/12/09 03:02:40
10/12/09 03:02:42
10/12/09 03:02:44
10/12/09 03:02:46
10/12/09 03:02:48
10/12/09 03:02:50
10/12/09 03:02:52
10/12/09 03:02:54
10/12/09 03:02:56
10/12/09 03:02:58
10/12/09 03:03:00
10/12/09 03:03:02
10/12/09 03:03:04
10/12/09 03:03:06
10/12/09 03:03:08
10/12/09 03:03:10
10/12/09 03:03:12
10/12/09 03:03:14
10/12/09 03:03:16
10/12/09 03:03:18
10/12/09 03:03:20
10/12/09 03:03:22
10/12/09 03:03:24
10/12/09 03:03:26
10/12/09 03:03:28
10/12/09 03:03:30
10/12/09 03:03:32
10/12/09 03:03:34
10/12/09 03:03:36
Hz
59.996
59.997
59.996
59.998
60.003
60.009
60.01
60.008
60.005
60.004
60.006
60.003
60.001
60.002
60.004
60.007
60.007
60.008
60.008
60.006
60.006
60.006
60.005
60
59.999
60
60
60.004
60.008
60.013
60.015
60.015
60.012
60.009
60.005
60.008
60.011
60.011
60.013
60.016
60.018
60.018
3700.858
3700.549
3700.614
3700.224
3699.5
3698.032
3697.96
3699.409
3699.241
3700.738
3701.11
3701.238
3699.998
3700.22
3701.823
3702.554
3702.276
3701.026
3701.923
3702.943
3704.093
3703.96
3703.819
3704.455
3704.346
3705.329
3704.93
3704.405
3703.675
3702.748
3702.669
3703.017
3703.416
3703.297
3705.189
3705.279
3704.646
3704.051
3703.438
3704.255
3703.708
3703.83
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
753.5
754
754.5
755
755.5
756
756.5
757
757.5
758
758.5
759
759.5
760
760.5
761
761.5
762
762.5
763
763.5
764
764.5
765
765.5
766
766.5
767
767.5
768
768.5
769
769.5
770
770.5
771
771.5
772
772.5
773
773.5
774
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
7997.31
7997.64
7997.97
7998.3
7998.63
7998.96
7999.29
7999.62
7999.95
8000.28
8000.61
8000.94
8001.27
8001.6
8001.93
8002.26
8002.59
8002.92
8003.25
8003.58
8003.91
8004.24
8004.57
8004.9
8005.23
8005.56
8005.89
8006.22
8006.55
8006.88
8007.21
8007.54
8007.87
8008.2
8008.53
8008.86
8009.19
8009.52
8009.85
8010.18
8010.51
8010.84
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.001
-0.001
0.002
0.005
0.006
0.001
-0.002
-0.003
-0.001
0.002
-0.003
-0.002
0.001
0.002
0.003
0.000
0.001
0.000
-0.002
0.000
0.000
-0.001
-0.005
-0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
-0.003
-0.003
-0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
Rows of
data to
shift to
Highest
004403Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.001
0.001
0.002
0.005
0.006
0.001
0.002
0.003
0.001
0.002
0.003
0.002
0.001
0.002
0.003
0.000
0.001
0.000
0.002
0.000
0.000
0.001
0.005
0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
0.003
0.003
0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
10/12/09 03:03:38
10/12/09 03:03:40
10/12/09 03:03:42
10/12/09 03:03:44
10/12/09 03:03:46
10/12/09 03:03:48
10/12/09 03:03:50
10/12/09 03:03:52
10/12/09 03:03:54
10/12/09 03:03:56
10/12/09 03:03:58
10/12/09 03:04:00
10/12/09 03:04:02
10/12/09 03:04:04
10/12/09 03:04:06
10/12/09 03:04:08
10/12/09 03:04:10
10/12/09 03:04:12
10/12/09 03:04:14
10/12/09 03:04:16
10/12/09 03:04:18
10/12/09 03:04:20
10/12/09 03:04:22
10/12/09 03:04:24
10/12/09 03:04:26
10/12/09 03:04:28
10/12/09 03:04:30
10/12/09 03:04:32
10/12/09 03:04:34
10/12/09 03:04:36
10/12/09 03:04:38
10/12/09 03:04:40
10/12/09 03:04:42
10/12/09 03:04:44
10/12/09 03:04:46
10/12/09 03:04:48
10/12/09 03:04:50
10/12/09 03:04:52
10/12/09 03:04:54
10/12/09 03:04:56
10/12/09 03:04:58
10/12/09 03:05:00
Hz
60.019
60.018
60.013
60.011
60.009
60.009
60.008
60.009
60.011
60.015
60.02
60.021
60.018
60.017
60.019
60.019
60.021
60.022
60.025
60.027
60.03
60.027
60.023
60.021
60.023
60.023
60.02
60.024
60.024
60.022
60.022
60.024
60.025
60.023
60.024
60.02
60.018
60.013
60.008
60.012
60.017
60.019
3704.524
3704.139
3704.27
3705.429
3705.942
3705.54
3705.634
3705.749
3707.267
3706.945
3706.63
3705.655
3703.895
3704.224
3703.887
3704.648
3704.795
3704.167
3702.764
3702.008
3700.36
3701.063
3700.34
3699.369
3701.568
3702.959
3704.25
3703.621
3703.374
3703.036
3703.931
3704.947
3704.208
3703.541
3703.16
3703.397
3704.376
3705.441
3706.995
3710.072
3707.971
3707.767
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
774.5
775
775.5
776
776.5
777
777.5
778
778.5
779
779.5
780
780.5
781
781.5
782
782.5
783
783.5
784
784.5
785
785.5
786
786.5
787
787.5
788
788.5
789
789.5
790
790.5
791
791.5
792
792.5
793
793.5
794
794.5
795
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8011.17
8011.5
8011.83
8012.16
8012.49
8012.82
8013.15
8013.48
8013.81
8014.14
8014.47
8014.8
8015.13
8015.46
8015.79
8016.12
8016.45
8016.78
8017.11
8017.44
8017.77
8018.1
8018.43
8018.76
8019.09
8019.42
8019.75
8020.08
8020.41
8020.74
8021.07
8021.4
8021.73
8022.06
8022.39
8022.72
8023.05
8023.38
8023.71
8024.04
8024.37
8024.7
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
-0.001
-0.005
-0.002
-0.002
0.000
-0.001
0.001
0.002
0.004
0.005
0.001
-0.003
-0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
-0.003
-0.004
-0.002
0.002
0.000
-0.003
0.004
0.000
-0.002
0.000
0.002
0.001
-0.002
0.001
-0.004
-0.002
-0.005
-0.005
0.004
0.005
0.002
Rows of
data to
shift to
Highest
004404Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.001
0.005
0.002
0.002
0.000
0.001
0.001
0.002
0.004
0.005
0.001
0.003
0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
0.003
0.004
0.002
0.002
0.000
0.003
0.004
0.000
0.002
0.000
0.002
0.001
0.002
0.001
0.004
0.002
0.005
0.005
0.004
0.005
0.002
10/12/09 03:05:02
10/12/09 03:05:04
10/12/09 03:05:06
10/12/09 03:05:08
10/12/09 03:05:10
10/12/09 03:05:12
10/12/09 03:05:14
10/12/09 03:05:16
10/12/09 03:05:18
10/12/09 03:05:20
10/12/09 03:05:22
10/12/09 03:05:24
10/12/09 03:05:26
10/12/09 03:05:28
10/12/09 03:05:30
10/12/09 03:05:32
10/12/09 03:05:34
10/12/09 03:05:36
10/12/09 03:05:38
10/12/09 03:05:40
10/12/09 03:05:42
10/12/09 03:05:44
10/12/09 03:05:46
10/12/09 03:05:48
10/12/09 03:05:50
10/12/09 03:05:52
10/12/09 03:05:54
10/12/09 03:05:56
10/12/09 03:05:58
10/12/09 03:06:00
10/12/09 03:06:02
10/12/09 03:06:04
10/12/09 03:06:06
10/12/09 03:06:08
10/12/09 03:06:10
10/12/09 03:06:12
10/12/09 03:06:14
10/12/09 03:06:16
10/12/09 03:06:18
10/12/09 03:06:20
10/12/09 03:06:22
10/12/09 03:06:24
Hz
60.019
60.015
60.016
60.015
60.016
60.014
60.016
60.018
60.019
60.016
60.014
60.014
60.018
60.022
60.023
60.024
60.026
60.026
60.024
60.022
60.02
60.019
60.022
60.025
60.028
60.03
60.031
60.029
60.026
60.026
60.029
60.03
60.033
60.03
60.022
60.016
60.019
60.03
60.028
60.021
60.015
60.015
3707.609
3708.831
3709.465
3709.813
3709.817
3709.99
3709.094
3709.642
3709.812
3709.933
3710.677
3710.591
3709.354
3707.696
3707.38
3707.12
3706.99
3705.848
3704.185
3704.406
3704.963
3706.567
3705.516
3704.869
3704.428
3704.773
3703.532
3702.686
3702.093
3703.169
3703.676
3701.52
3700.106
3698.222
3698.009
3700.28
3703.192
3703.815
3701.863
3699.956
3700.816
3703.802
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
795.5
796
796.5
797
797.5
798
798.5
799
799.5
800
800.5
801
801.5
802
802.5
803
803.5
804
804.5
805
805.5
806
806.5
807
807.5
808
808.5
809
809.5
810
810.5
811
811.5
812
812.5
813
813.5
814
814.5
815
815.5
816
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8025.03
8025.36
8025.69
8026.02
8026.35
8026.68
8027.01
8027.34
8027.67
8028
8028.33
8028.66
8028.99
8029.32
8029.65
8029.98
8030.31
8030.64
8030.97
8031.3
8031.63
8031.96
8032.29
8032.62
8032.95
8033.28
8033.61
8033.94
8034.27
8034.6
8034.93
8035.26
8035.59
8035.92
8036.25
8036.58
8036.91
8037.24
8037.57
8037.9
8038.23
8038.56
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.004
0.001
-0.001
0.001
-0.002
0.002
0.002
0.001
-0.003
-0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
-0.002
-0.002
-0.002
-0.001
0.003
0.003
0.003
0.002
0.001
-0.002
-0.003
0.000
0.003
0.001
0.003
-0.003
-0.008
-0.006
0.003
0.011
-0.002
-0.007
-0.006
0.000
Rows of
data to
shift to
Highest
004405Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.000
0.004
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.003
0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
0.002
0.002
0.002
0.001
0.003
0.003
0.003
0.002
0.001
0.002
0.003
0.000
0.003
0.001
0.003
0.003
0.008
0.006
0.003
0.011
0.002
0.007
0.006
0.000
10/12/09 03:06:26
10/12/09 03:06:28
10/12/09 03:06:30
10/12/09 03:06:32
10/12/09 03:06:34
10/12/09 03:06:36
10/12/09 03:06:38
10/12/09 03:06:40
10/12/09 03:06:42
10/12/09 03:06:44
10/12/09 03:06:46
10/12/09 03:06:48
10/12/09 03:06:50
10/12/09 03:06:52
10/12/09 03:06:54
10/12/09 03:06:56
10/12/09 03:06:58
10/12/09 03:07:00
10/12/09 03:07:02
10/12/09 03:07:04
10/12/09 03:07:06
10/12/09 03:07:08
10/12/09 03:07:10
10/12/09 03:07:12
10/12/09 03:07:14
10/12/09 03:07:16
10/12/09 03:07:18
10/12/09 03:07:20
10/12/09 03:07:22
10/12/09 03:07:24
10/12/09 03:07:26
10/12/09 03:07:28
10/12/09 03:07:30
10/12/09 03:07:32
10/12/09 03:07:34
10/12/09 03:07:36
10/12/09 03:07:38
10/12/09 03:07:40
10/12/09 03:07:42
10/12/09 03:07:44
10/12/09 03:07:46
10/12/09 03:07:48
Hz
60.012
60.011
60.014
60.013
60.014
60.016
60.016
60.015
60.013
60.007
59.997
59.994
59.993
59.99
59.993
59.994
59.993
59.994
59.993
59.996
59.988
59.985
59.983
59.982
59.98
59.977
59.981
59.982
59.978
59.98
59.98
59.977
59.98
59.983
59.984
59.981
59.981
59.98
59.981
59.981
59.981
59.98
3706.943
3708.527
3707.49
3707.647
3706.991
3707.495
3705.584
3705.398
3707.12
3709.144
3708.99
3708.291
3706.193
3707.304
3707.903
3706.76
3706.921
3706.683
3706.888
3704.934
3705.678
3706.481
3707.071
3706.696
3707.479
3708.246
3709.436
3710.419
3710.134
3708.708
3710.024
3709.192
3708.335
3709.399
3707.911
3709.004
3707.638
3709.689
3708.945
3706.541
3711.256
3711.362
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
816.5
817
817.5
818
818.5
819
819.5
820
820.5
821
821.5
822
822.5
823
823.5
824
824.5
825
825.5
826
826.5
827
827.5
828
828.5
829
829.5
830
830.5
831
831.5
832
832.5
833
833.5
834
834.5
835
835.5
836
836.5
837
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
10
0
-103
BA
Load
MW
8038.89
8039.22
8039.55
8039.88
8040.21
8040.54
8040.87
8041.2
8041.53
8041.86
8042.19
8042.52
8042.85
8043.18
8043.51
8043.84
8044.17
8044.5
8044.83
8045.16
8045.49
8045.82
8046.15
8046.48
8046.81
8047.14
8047.47
8047.8
8048.13
8048.46
8048.79
8049.12
8049.45
8049.78
8050.11
8050.44
8050.77
8051.1
8051.43
8051.76
8052.09
8052.42
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.001
0.003
-0.001
0.001
0.002
0.000
-0.001
-0.002
-0.006
-0.010
-0.003
-0.001
-0.003
0.003
0.001
-0.001
0.001
-0.001
0.003
-0.008
-0.003
-0.002
-0.001
-0.002
-0.003
0.004
0.001
-0.004
0.002
0.000
-0.003
0.003
0.003
0.001
-0.003
0.000
-0.001
0.001
0.000
0.000
-0.001
Rows of
data to
shift to
Highest
004406Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.001
0.003
0.001
0.001
0.002
0.000
0.001
0.002
0.006
0.010
0.003
0.001
0.003
0.003
0.001
0.001
0.001
0.001
0.003
0.008
0.003
0.002
0.001
0.002
0.003
0.004
0.001
0.004
0.002
0.000
0.003
0.003
0.003
0.001
0.003
0.000
0.001
0.001
0.000
0.000
0.001
10/12/09 03:07:50
10/12/09 03:07:52
10/12/09 03:07:54
10/12/09 03:07:56
10/12/09 03:07:58
10/12/09 03:08:00
10/12/09 03:08:02
10/12/09 03:08:04
10/12/09 03:08:06
10/12/09 03:08:08
10/12/09 03:08:10
10/12/09 03:08:12
10/12/09 03:08:14
10/12/09 03:08:16
10/12/09 03:08:18
10/12/09 03:08:20
10/12/09 03:08:22
10/12/09 03:08:24
10/12/09 03:08:26
10/12/09 03:08:28
10/12/09 03:08:30
10/12/09 03:08:32
10/12/09 03:08:34
10/12/09 03:08:36
10/12/09 03:08:38
10/12/09 03:08:40
10/12/09 03:08:42
10/12/09 03:08:44
10/12/09 03:08:46
10/12/09 03:08:48
10/12/09 03:08:50
10/12/09 03:08:52
10/12/09 03:08:54
10/12/09 03:08:56
10/12/09 03:08:58
10/12/09 03:09:00
10/12/09 03:09:02
10/12/09 03:09:04
10/12/09 03:09:06
10/12/09 03:09:08
10/12/09 03:09:10
10/12/09 03:09:12
Hz
59.978
59.978
59.979
59.978
59.976
59.976
59.975
59.976
59.975
59.979
59.978
59.975
59.976
59.981
59.977
59.975
59.976
59.979
59.98
59.979
59.978
59.979
59.982
59.983
59.987
59.988
59.984
59.98
59.979
59.98
59.979
59.978
59.975
59.979
59.982
59.983
59.983
59.985
59.99
59.987
59.984
59.976
3712.303
3712.012
3711.703
3712.093
3713.992
3714.612
3715.083
3715.323
3714.794
3714.717
3715.161
3715.001
3713.996
3714.063
3714.335
3715.631
3715.688
3715.567
3715.725
3714.848
3713.142
3713.358
3712.275
3712.619
3712.153
3710.05
3709.082
3710.472
3710.624
3710.946
3710.2
3710.475
3709.462
3710.803
3709.286
3710.573
3709.525
3708.371
3708.527
3706.512
3707.49
3708.962
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
837.5
838
838.5
839
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
0
-103
10
0
-103
10
0
-103
10
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8052.75
8053.08
8053.41
8053.74
8054.07
8054.4
8054.73
8055.06
8055.39
8055.72
8056.05
8056.38
8056.71
8057.04
8057.37
8057.7
8058.03
8058.36
8058.69
8059.02
8059.35
8059.68
8060.01
8060.34
8060.67
8061
8061.33
8061.66
8061.99
8062.32
8062.65
8062.98
8063.31
8063.64
8063.97
8064.3
8064.63
8064.96
8065.29
8065.62
8065.95
8066.28
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.001
-0.001
-0.002
0.000
-0.001
0.001
-0.001
0.004
-0.001
-0.003
0.001
0.005
-0.004
-0.002
0.001
0.003
0.001
-0.001
-0.001
0.001
0.003
0.001
0.004
0.001
-0.004
-0.004
-0.001
0.001
-0.001
-0.001
-0.003
0.004
0.003
0.001
0.000
0.002
0.005
-0.003
-0.003
-0.008
Rows of
data to
shift to
Highest
004407Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.001
0.001
0.002
0.000
0.001
0.001
0.001
0.004
0.001
0.003
0.001
0.005
0.004
0.002
0.001
0.003
0.001
0.001
0.001
0.001
0.003
0.001
0.004
0.001
0.004
0.004
0.001
0.001
0.001
0.001
0.003
0.004
0.003
0.001
0.000
0.002
0.005
0.003
0.003
0.008
10/12/09 03:09:14
10/12/09 03:09:16
10/12/09 03:09:18
10/12/09 03:09:20
10/12/09 03:09:22
10/12/09 03:09:24
10/12/09 03:09:26
10/12/09 03:09:28
10/12/09 03:09:30
10/12/09 03:09:32
10/12/09 03:09:34
10/12/09 03:09:36
10/12/09 03:09:38
10/12/09 03:09:40
10/12/09 03:09:42
10/12/09 03:09:44
10/12/09 03:09:46
10/12/09 03:09:48
10/12/09 03:09:50
10/12/09 03:09:52
10/12/09 03:09:54
10/12/09 03:09:56
10/12/09 03:09:58
10/12/09 03:10:00
10/12/09 03:10:02
10/12/09 03:10:04
10/12/09 03:10:06
10/12/09 03:10:08
10/12/09 03:10:10
10/12/09 03:10:12
10/12/09 03:10:14
10/12/09 03:10:16
10/12/09 03:10:18
10/12/09 03:10:20
10/12/09 03:10:22
10/12/09 03:10:24
10/12/09 03:10:26
10/12/09 03:10:28
10/12/09 03:10:30
10/12/09 03:10:32
10/12/09 03:10:34
10/12/09 03:10:36
Hz
59.979
59.985
59.983
59.979
59.981
59.978
59.975
59.978
59.989
59.999
59.994
59.989
59.986
59.984
59.983
59.982
59.98
59.99
59.995
59.995
59.99
59.989
59.991
59.996
60
60.002
60.004
60.004
60.002
59.999
59.998
59.995
59.996
60.001
60.002
60.001
60.003
60.005
60.004
60.004
60.004
60.006
3709.894
3712.303
3711.35
3711.627
3712.076
3712.393
3712.999
3713.51
3716.626
3715.443
3712.092
3713.906
3714.894
3714.953
3716.122
3716.308
3715.438
3714.764
3714.714
3715.068
3715.927
3715.791
3716.285
3715.324
3714.46
3711.708
3712.698
3712.851
3713.362
3716.641
3718.292
3719.079
3718.233
3717.815
3717.889
3718.56
3718.195
3719.021
3718.821
3719.897
3719.299
3719.643
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8066.61
8066.94
8067.27
8067.6
8067.93
8068.26
8068.59
8068.92
8069.25
8069.58
8069.91
8070.24
8070.57
8070.9
8071.23
8071.56
8071.89
8072.22
8072.55
8072.88
8073.21
8073.54
8073.87
8074.2
8074.53
8074.86
8075.19
8075.52
8075.85
8076.18
8076.51
8076.84
8077.17
8077.5
8077.83
8078.16
8078.49
8078.82
8079.15
8079.48
8079.81
8080.14
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.006
-0.002
-0.004
0.002
-0.003
-0.003
0.003
0.011
0.010
-0.005
-0.005
-0.003
-0.002
-0.001
-0.001
-0.002
0.010
0.005
0.000
-0.005
-0.001
0.002
0.005
0.004
0.002
0.002
0.000
-0.002
-0.003
-0.001
-0.003
0.001
0.005
0.001
-0.001
0.002
0.002
-0.001
0.000
0.000
0.002
Rows of
data to
shift to
Highest
004408Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.006
0.002
0.004
0.002
0.003
0.003
0.003
0.011
0.010
0.005
0.005
0.003
0.002
0.001
0.001
0.002
0.010
0.005
0.000
0.005
0.001
0.002
0.005
0.004
0.002
0.002
0.000
0.002
0.003
0.001
0.003
0.001
0.005
0.001
0.001
0.002
0.002
0.001
0.000
0.000
0.002
10/12/09 03:10:38
10/12/09 03:10:40
10/12/09 03:10:42
10/12/09 03:10:44
10/12/09 03:10:46
10/12/09 03:10:48
10/12/09 03:10:50
10/12/09 03:10:52
10/12/09 03:10:54
10/12/09 03:10:56
10/12/09 03:10:58
10/12/09 03:11:00
10/12/09 03:11:02
10/12/09 03:11:04
10/12/09 03:11:06
10/12/09 03:11:08
10/12/09 03:11:10
10/12/09 03:11:12
10/12/09 03:11:14
10/12/09 03:11:16
10/12/09 03:11:18
10/12/09 03:11:20
10/12/09 03:11:22
10/12/09 03:11:24
10/12/09 03:11:26
10/12/09 03:11:28
10/12/09 03:11:30
10/12/09 03:11:32
10/12/09 03:11:34
10/12/09 03:11:36
10/12/09 03:11:38
10/12/09 03:11:40
10/12/09 03:11:42
10/12/09 03:11:44
10/12/09 03:11:46
10/12/09 03:11:48
10/12/09 03:11:50
10/12/09 03:11:52
10/12/09 03:11:54
10/12/09 03:11:56
10/12/09 03:11:58
10/12/09 03:12:00
Hz
60.003
60.005
60.006
60.009
60.009
60.01
60.009
60.013
60.015
60.014
60.009
60.009
60.008
60.011
60.01
60.009
60.013
60.013
60.014
60.014
60.012
60.01
60.011
60.007
60.003
60.001
60
59.998
59.998
59.999
60.002
60.003
60.003
59.999
59.998
60.001
59.995
59.989
59.987
59.988
59.988
59.99
3719.527
3719.731
3720.279
3718.58
3718.976
3718.982
3720.034
3720.609
3720.811
3721.239
3720.38
3719.447
3720.807
3721.272
3720.592
3721.245
3721.594
3722.176
3721.999
3721.646
3721.678
3720.86
3721.645
3723.816
3725.07
3724.656
3724.869
3724.661
3723.696
3723.58
3723.405
3721.879
3722.401
3722.906
3724.142
3723.65
3723.201
3723.639
3723.881
3724.654
3725.361
3724.944
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8080.47
8080.8
8081.13
8081.46
8081.79
8082.12
8082.45
8082.78
8083.11
8083.44
8083.77
8084.1
8084.43
8084.76
8085.09
8085.42
8085.75
8086.08
8086.41
8086.74
8087.07
8087.4
8087.73
8088.06
8088.39
8088.72
8089.05
8089.38
8089.71
8090.04
8090.37
8090.7
8091.03
8091.36
8091.69
8092.02
8092.35
8092.68
8093.01
8093.34
8093.67
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
0
1
0
1
1
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
0.002
0.001
0.003
0.000
0.001
-0.001
0.004
0.002
-0.001
-0.005
0.000
-0.001
0.003
-0.001
-0.001
0.004
0.000
0.001
0.000
-0.002
-0.002
0.001
-0.004
-0.004
-0.002
-0.001
-0.002
0.000
0.001
0.003
0.001
0.000
-0.004
-0.001
0.003
-0.006
-0.006
-0.002
0.001
0.000
0.002
Rows of
data to
shift to
Highest
004409Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.003
0.002
0.001
0.003
0.000
0.001
0.001
0.004
0.002
0.001
0.005
0.000
0.001
0.003
0.001
0.001
0.004
0.000
0.001
0.000
0.002
0.002
0.001
0.004
0.004
0.002
0.001
0.002
0.000
0.001
0.003
0.001
0.000
0.004
0.001
0.003
0.006
0.006
0.002
0.001
0.000
0.002
10/12/09 03:12:02
10/12/09 03:12:04
10/12/09 03:12:06
10/12/09 03:12:08
10/12/09 03:12:10
10/12/09 03:12:12
10/12/09 03:12:14
10/12/09 03:12:16
10/12/09 03:12:18
10/12/09 03:12:20
10/12/09 03:12:22
10/12/09 03:12:24
10/12/09 03:12:26
10/12/09 03:12:28
10/12/09 03:12:30
10/12/09 03:12:32
10/12/09 03:12:34
10/12/09 03:12:36
10/12/09 03:12:38
10/12/09 03:12:40
10/12/09 03:12:42
10/12/09 03:12:44
10/12/09 03:12:46
10/12/09 03:12:48
10/12/09 03:12:50
10/12/09 03:12:52
10/12/09 03:12:54
10/12/09 03:12:56
10/12/09 03:12:58
10/12/09 03:13:00
10/12/09 03:13:02
10/12/09 03:13:04
10/12/09 03:13:06
10/12/09 03:13:08
10/12/09 03:13:10
10/12/09 03:13:12
10/12/09 03:13:14
10/12/09 03:13:16
10/12/09 03:13:18
10/12/09 03:13:20
10/12/09 03:13:22
10/12/09 03:13:24
Hz
59.999
60.001
60.003
60.0005
59.998
59.997
59.996
59.996
59.996
59.995
59.994
59.993
59.992
59.991
59.99
59.991
59.992
59.993
59.994
59.995
59.996
59.996
59.996
59.9965
59.997
59.997
59.997
59.997
59.997
59.999
60.001
60.001
60.001
60.004
60.007
60.009
60.011
60.0085
60.006
60.007
60.008
60.01
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.009
0.002
0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
-0.003
-0.002
0.001
0.001
0.002
Rows of
data to
shift to
Highest
004410Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.009
0.002
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
0.003
0.002
0.001
0.001
0.002
10/12/09 03:13:26
10/12/09 03:13:28
10/12/09 03:13:30
10/12/09 03:13:32
10/12/09 03:13:34
10/12/09 03:13:36
10/12/09 03:13:38
10/12/09 03:13:40
10/12/09 03:13:42
10/12/09 03:13:44
10/12/09 03:13:46
10/12/09 03:13:48
10/12/09 03:13:50
10/12/09 03:13:52
10/12/09 03:13:54
10/12/09 03:13:56
10/12/09 03:13:58
10/12/09 03:14:00
10/12/09 03:14:02
10/12/09 03:14:04
10/12/09 03:14:06
10/12/09 03:14:08
10/12/09 03:14:10
10/12/09 03:14:12
10/12/09 03:14:14
10/12/09 03:14:16
10/12/09 03:14:18
10/12/09 03:14:20
10/12/09 03:14:22
10/12/09 03:14:24
10/12/09 03:14:26
10/12/09 03:14:28
10/12/09 03:14:30
10/12/09 03:14:32
10/12/09 03:14:34
10/12/09 03:14:36
10/12/09 03:14:38
10/12/09 03:14:40
10/12/09 03:14:42
10/12/09 03:14:44
10/12/09 03:14:46
10/12/09 03:14:48
Hz
60.012
60.012
60.012
60.01
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.007
60.006
60.005
60.004
60.004
60.004
60.0025
60.001
59.9995
59.998
59.9965
59.995
59.995
59.995
59.996
59.997
59.995
59.993
59.9925
59.992
59.9905
59.989
59.99
59.991
59.989
59.987
59.9875
59.988
59.988
59.988
59.987
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
0.000
0.000
-0.002
-0.002
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.001
0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
-0.001
Rows of
data to
shift to
Highest
004411Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.000
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.002
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.001
10/12/09 03:14:50
10/12/09 03:14:52
10/12/09 03:14:54
10/12/09 03:14:56
10/12/09 03:14:58
10/12/09 03:15:00
10/12/09 03:15:02
10/12/09 03:15:04
10/12/09 03:15:06
10/12/09 03:15:08
10/12/09 03:15:10
10/12/09 03:15:12
10/12/09 03:15:14
10/12/09 03:15:16
10/12/09 03:15:18
10/12/09 03:15:20
10/12/09 03:15:22
10/12/09 03:15:24
10/12/09 03:15:26
10/12/09 03:15:28
10/12/09 03:15:30
10/12/09 03:15:32
10/12/09 03:15:34
10/12/09 03:15:36
10/12/09 03:15:38
10/12/09 03:15:40
10/12/09 03:15:42
10/12/09 03:15:44
10/12/09 03:15:46
10/12/09 03:15:48
10/12/09 03:15:50
10/12/09 03:15:52
10/12/09 03:15:54
10/12/09 03:15:56
10/12/09 03:15:58
10/12/09 03:15:59
10/12/09 03:16:01
10/12/09 03:16:03
10/12/09 03:16:05
10/12/09 03:16:07
10/12/09 03:16:09
10/12/09 03:16:11
Hz
59.986
59.9855
59.985
59.9845
59.984
59.984
59.984
59.985
59.986
59.987
59.988
59.992
59.996
59.9975
59.999
60.001
60.003
60.003
60.003
60.0055
60.008
60.01
60.012
60.0105
60.009
60.01
60.011
60.012
60.013
60.013
60.013
60.0145
60.016
60.0155
60.015
60.014
60.013
60.012
60.011
60.0105
60.01
60.008
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
-0.002
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
Rows of
data to
shift to
Highest
004412Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.002
10/12/09 03:16:13
10/12/09 03:16:15
10/12/09 03:16:17
10/12/09 03:16:19
10/12/09 03:16:21
10/12/09 03:16:23
10/12/09 03:16:25
10/12/09 03:16:27
10/12/09 03:16:29
10/12/09 03:16:31
10/12/09 03:16:33
10/12/09 03:16:35
10/12/09 03:16:37
10/12/09 03:16:39
10/12/09 03:16:41
10/12/09 03:16:43
10/12/09 03:16:45
10/12/09 03:16:47
10/12/09 03:16:49
10/12/09 03:16:51
10/12/09 03:16:53
10/12/09 03:16:55
10/12/09 03:16:57
10/12/09 03:16:59
10/12/09 03:17:01
10/12/09 03:17:03
10/12/09 03:17:05
10/12/09 03:17:07
10/12/09 03:17:09
10/12/09 03:17:11
10/12/09 03:17:13
10/12/09 03:17:15
10/12/09 03:17:17
10/12/09 03:17:19
10/12/09 03:17:21
10/12/09 03:17:23
10/12/09 03:17:25
Hz
60.006
60.006
60.006
60.0045
60.003
60.003
60.003
60.0035
60.004
60.0025
60.001
59.999
59.997
59.9965
59.996
59.9965
59.997
59.997
59.997
59.998
59.999
59.9985
59.998
59.9985
59.999
59.998
59.997
59.9985
60
60.001
60.002
60.0015
60.001
60.0035
60.006
60.0055
60.005
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
-223.015732
16
Not
Used
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
BA
Lost Generation
Bias
Load (-) Gen (+)
Setting
MW
MW/0.1 Hz
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
BA
Load
MW
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Net
Actual
Interchange
MW
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
Max Absolute Delta
Hz
0.126
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.126
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.000
-0.001
-0.002
0.000
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
-0.001
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
Rows of
data to
shift to
Highest
004413Delta
align T(0)
Hz
0.033
1
Absolute
Delta Hz
0.002
0.000
0.000
0.001
0.002
0.000
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after
(up to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns
A through R. You must also delete any un-used event detection formulas in columns N through R as
well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1
"BA Event Data" worksheet.
MyBA_091012_0227_FRS_Form2.9.xlsm
59.500 Hz
60.500 Hz
Auto Event Detection
2:27:26 1245 Manually selected row number of the Event Starting Time.
2:33:00 1442 Manually selected row number of the Event Ending Time.
2:27:26
Event Frequency Data
60.1
2:27:26
-0.153
Delta Hz Event Detected
60.05
2:33:00
60
59.95
59.9
59.85
59.8
Copy Form 2 data for
Pasting into Form 1
59.75
59.7
2:17:26 2:22:26 2:27:26 2:32:26 2:37:26 2:42:26 2:47:26 2:52:26 2:57:26 3:02:26 3:07:26 3:12:26 3:17:25
Hz
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_091012_0227_FRS_Form2.9.xlsm
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
004414
Auto
Manual
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Monday, October 12, 2009
2:27:26
2:33:00
60.042 Hz
59.889 Hz
-0.153 Hz
3645.73 MW
3788.35 MW
157.63 MW
-15.40 MW
-43.39 MW
114.21 MW
157.60 MW
Balancing Authority MyBA
Grid Nominal Frequency
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
A Point
FPointA
A Value
C Value
Delta F C
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
2:27:24
60.03900146
60.04212523
59.83599854
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
2:27:24
3.00000 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Monday, October 12, 2009
2:27:26
2:33:00
60.042 Hz
59.889 Hz
-0.153 Hz
3645.73 MW
3803.35 MW
157.63 MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
-43.39 MW
114.21 MW
157.60 MW
198.04 MW
350.00 MW
165.34 MW
0.00 MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
-4.21 MW
15.00 MW
526.12 MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
335.00 MW
214.13 MW
6.35 MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
11.09 MW
0.00 MW
566.57 MW
40.45 MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Low Hz Delta Hz Event
3764.66 Actual Interchange MW Average during frequency recovery period
3804.23 Target Interchange MW Average during frequency recovery period
3719.84 Interchange Average Ramp MW during frequency recovery period
3640.68 Actual MW @ T(-4)
103.04 Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
0:05:34 Event Duration (h:mm:ss)
No Target MW Average minus MW @ T(-4) less than zero
163.55 Interchange Target Relative Average Change - MW (Low Frequency Event)
123.97 Interchange Actual Relative Average Change - MW (Low Frequency Event)
No Interchange Actual Average minus MW @ T(-4) less than zero
Yes Interchange Average MW minus MW @ T(-4) greater than zero
Yes Interchange Target MW Average minus MW @ T(-4) greater than zero
60.52 Interchange Target Relative Average Change - MW (High Frequency Event)
20.94 Interchange Actual Relative Average Change - MW (High Frequency Event)
Up Ramp Direction during frequency recovery period
142.20 MW
Yes
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
Frequency
Hz
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
Interchange
MW
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.190
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3734.673
3737.157
3761.250
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.500
3784.962
3784.730
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.010
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.670
3769.630
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
1.109 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Value B
20 to 52 sec
Average
Average
Frequency
MW
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
-9.734
-15.700
-19.578
-20.657
-20.277
-19.308
-19.400
-19.820
-19.733
-20.397
-20.828
-21.109
-20.571
-19.861
-20.840
-24.721
-29.407
-32.452
-34.072
-35.485
-39.649
-43.076
-45.303
-44.948
-43.997
-43.379
-42.977
-41.995
-42.077
-42.852
-44.075
-45.232
-44.182
-43.499
-43.055
-42.046
-19.399
40.744
85.606
102.870
114.091
113.094
112.806
116.583
120.481
123.375
122.373
120.278
119.277
118.988
118.079
117.127
115.788
113.114
111.737
111.202
110.494
110.034
110.817
111.686
114.054
115.593
115.511
115.819
115.658
115.553
114.765
114.613
117.037
121.857
130.759
139.429
143.983
144.779
143.495
141.579
140.693
139.397
138.914
136.799
134.342
130.943
128.372
125.621
122.750
119.443
116.572
115.788
113.835
110.404
106.731
104.704
103.386
101.809
99.702
96.891
93.261
90.902
89.008
87.416
85.661
84.159
83.544
84.225
83.587
82.811
81.585
79.708
78.848
77.207
76.501
74.240
74.573
74.428
73.253
73.210
72.461
71.254
69.026
67.578
63.754
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period Recovery Recovery Period Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
0.000
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3666.787
3666.265
3666.251
3665.485
3664.952
3664.570
3665.006
3665.615
3664.533
3660.551
3655.763
3652.616
3650.895
3649.380
3645.114
3641.585
3639.256
3639.509
3640.359
3640.875
3641.176
3642.056
3641.872
3640.996
3639.670
3638.411
3639.360
3639.942
3640.284
3641.191
3663.838
3724.598
3770.077
3787.958
3799.796
3799.415
3799.745
3804.139
3808.654
3812.165
3811.779
3810.302
3809.918
3810.246
3809.953
3809.618
3808.896
3806.840
3806.079
3806.161
3806.070
3806.227
3807.627
3809.113
3812.098
3814.254
3814.790
3815.714
3816.170
3816.682
3816.511
3816.976
3820.017
3825.454
3834.973
3844.260
3849.431
3850.844
3850.177
3848.877
3848.609
3847.929
3848.064
3846.566
3844.726
3841.943
3839.990
3837.855
3835.601
3832.911
3830.658
3830.490
3829.154
3826.340
3823.284
3821.874
3821.174
3820.214
3818.723
3816.529
3813.516
3811.774
3810.497
3809.522
3808.384
3807.499
3807.501
3808.799
3808.778
3808.618
3808.010
3806.750
3806.507
3805.482
3805.394
3803.750
3804.700
3805.172
3804.614
3805.187
3805.055
3804.465
3802.855
3802.024
3798.816
3677.914
3696.910
3706.351
3712.015
3716.206
3722.640
3728.074
3732.310
3735.967
3739.054
3742.518
3745.523
3748.165
3750.618
3752.750
3754.613
3756.471
3758.148
3759.684
3761.055
3762.474
3763.805
3765.078
3766.452
3767.759
3768.952
3770.190
3771.319
3772.373
3773.406
3774.409
3775.354
3776.351
3777.355
3778.397
3779.410
3780.627
3781.792
3782.897
3783.986
3785.004
3785.975
3786.895
3787.758
3788.542
3789.265
3789.886
3790.461
3790.988
3791.459
3791.888
3792.265
3792.587
3792.848
3793.076
3793.271
3793.319
3793.330
3793.311
3793.281
3793.221
3793.140
3793.006
3792.853
3792.684
3792.440
3792.193
3791.938
3791.672
3791.423
3791.163
3790.896
3790.608
3790.316
3790.018
3789.719
3789.433
3789.147
3788.861
3788.574
3788.301
3788.011
3787.738
3787.446
3694.218
3719.504
3736.618
3749.253
3757.614
3763.632
3768.696
3773.136
3777.038
3780.197
3782.705
3784.799
3786.616
3788.172
3789.513
3790.653
3791.552
3792.317
3793.009
3793.631
3794.203
3794.787
3795.384
3796.053
3796.753
3797.421
3798.074
3798.698
3799.297
3799.853
3800.388
3800.983
3801.702
3802.653
3803.809
3805.042
3806.247
3807.373
3808.411
3809.392
3810.309
3811.187
3811.991
3812.719
3813.354
3813.921
3814.419
3814.852
3815.213
3815.516
3815.804
3816.055
3816.246
3816.374
3816.472
3816.555
3816.618
3816.653
3816.651
3816.600
3816.522
3816.426
3816.319
3816.197
3816.065
3815.937
3815.832
3815.730
3815.628
3815.521
3815.399
3815.277
3815.145
3815.015
3814.867
3814.735
3814.612
3814.485
3814.369
3814.254
3814.135
3813.999
3813.856
3813.679
3668.635
3669.252
3669.869
3670.486
3671.103
3671.720
3672.337
3672.954
3673.571
3674.188
3674.805
3675.422
3676.039
3676.656
3677.273
3677.890
3678.507
3679.124
3679.741
3680.358
3680.975
3681.592
3682.209
3682.826
3683.443
3684.060
3684.677
3685.293
3685.910
3686.527
3687.144
3687.761
3688.378
3688.995
3689.612
3690.229
3690.846
3691.463
3692.080
3692.697
3693.314
3693.931
3694.548
3695.165
3695.782
3696.399
3697.016
3697.633
3698.250
3698.867
3699.484
3700.101
3700.718
3701.335
3701.952
3702.569
3703.186
3703.803
3704.420
3705.037
3705.654
3706.271
3706.888
3707.504
3708.121
3708.738
3709.355
3709.972
3710.589
3711.206
3711.823
3712.440
3713.057
3713.674
3714.291
3714.908
3715.525
3716.142
3716.759
3717.376
3717.993
3718.610
3719.227
3719.844
3668.635
3668.944
3669.252
3669.561
3669.869
3670.178
3670.486
3670.795
3671.103
3671.412
3671.720
3672.029
3672.337
3672.646
3672.954
3673.263
3673.571
3673.879
3674.188
3674.496
3674.805
3675.113
3675.422
3675.730
3676.039
3676.347
3676.656
3676.964
3677.273
3677.581
3677.890
3678.198
3678.507
3678.815
3679.124
3679.432
3679.741
3680.049
3680.358
3680.666
3680.975
3681.283
3681.592
3681.900
3682.209
3682.517
3682.826
3683.134
3683.443
3683.751
3684.060
3684.368
3684.677
3684.985
3685.293
3685.602
3685.910
3686.219
3686.527
3686.836
3687.144
3687.453
3687.761
3688.070
3688.378
3688.687
3688.995
3689.304
3689.612
3689.921
3690.229
3690.538
3690.846
3691.155
3691.463
3691.772
3692.080
3692.389
3692.697
3693.006
3693.314
3693.623
3693.931
3694.240
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
Net
Actual
Frequency Interchange
Hz
MW
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.020
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.880
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.890
59.895
59.894
59.893
59.894
59.894
59.891
59.890
59.885
59.885
59.888
59.887
59.888
59.888
59.890
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.880
59.883
59.886
59.890
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.920
59.921
59.920
59.917
59.920
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
3671.19
3668.61
3665.23
3664.50
3666.06
3666.82
3666.79
3670.45
3670.27
3671.67
3672.49
3672.69
3672.86
3672.16
3671.41
3669.98
3666.47
3663.76
3661.60
3660.67
3651.49
3649.19
3650.03
3648.25
3649.51
3654.29
3655.01
3651.87
3651.06
3649.19
3648.24
3645.39
3644.63
3645.45
3640.68
3641.19
3659.46
3696.36
3734.90
3734.67
3734.67
3737.16
3761.25
3766.11
3766.19
3768.88
3769.93
3780.62
3781.59
3782.50
3784.96
3784.73
3784.42
3788.07
3788.33
3788.87
3788.47
3792.28
3793.07
3794.37
3799.43
3800.43
3799.96
3803.63
3802.93
3802.95
3804.39
3805.50
3805.62
3809.24
3811.50
3814.86
3815.89
3825.64
3826.05
3826.00
3827.52
3826.75
3826.78
3826.45
3825.71
3823.83
3822.51
3819.08
3818.06
3816.81
3815.01
3813.78
3811.84
3809.65
3806.97
3805.59
3804.19
3796.08
3793.98
3792.17
3791.50
3789.53
3788.13
3784.56
3783.03
3781.70
3776.36
3775.64
3774.60
3773.33
3773.96
3772.72
3771.67
3769.63
3768.71
3767.64
3767.02
3767.41
3766.79
3766.26
3765.67
3766.12
3764.24
3765.10
3762.94
JOU
NonDynamic
Conforming
Schedules
Load
Imp(-) Exp (+)
Load (-)
MW
MW
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
157.63
155.53
155.53
155.53
155.53
155.53
160.45
160.45
160.45
160.45
160.45
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
166.07
166.07
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
214.35
214.35
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
234.08
234.08
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
229.47
229.47
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
BA
Load
MW
7640.91
7641.24
7641.57
7641.90
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.20
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.50
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.80
7652.13
7652.46
7652.79
7616.00
7626.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7623.00
7621.00
7623.00
7625.00
7627.00
7628.00
7628.00
7629.00
7630.00
7631.00
7635.00
7638.00
7639.00
7642.00
7644.00
7645.00
7647.00
7648.00
7649.00
7650.00
7651.00
7652.00
7653.00
7654.00
7655.00
7655.00
7656.00
7656.00
7657.00
7657.00
7658.00
7658.00
7659.00
7659.00
7659.00
7660.00
7660.00
7661.00
7661.00
7662.00
7662.00
7663.00
7663.00
7664.00
7664.00
7665.00
7666.00
7666.00
7667.00
7668.00
Expected Primary
Freq Response
Based on Bias Setting
MW
T
-27.810
-26.781
-26.781
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
2:26:14
2:26:16
2:26:18
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Frequency Interchange Imp(-) Exp (+)
Load (-)
Hz
MW
MW
MW
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
7651.3 MW
7632.0 MW
-19.305 MW
-12.617 MW/0.1 Hz
12.25%
Average Bias Setting when Hz is greater than +/-0.036 Hz
-103.00 MW/0.1 Hz
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW/0.1 Hz
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
Actual
Primary
Freq Response
MW
158.51
182.41
164.54
129.49
119.99
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
1.000 P.U.
0.744 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
59.890 Hz
59.863 Hz
59.899 Hz
59.920 Hz
59.937 Hz
113.30 MW
141.11 MW
104.03 MW
82.40 MW
64.89 MW
Un-adjusted
P.U.
Performance
1.399
1.293
1.582
1.571
1.849
JOU
NonTransferred
Contingent
Dynamic
Conforming
Pumped
Frequency
BA
Adjusted
Schedules
Load
Hydro
Response Lost Generation
P.U.
Adjustment
Adjustment Adjustment Adjustment
Adjustment
Performance
-15.00
50.26
11.00
15.21
-15.00
0.856
-15.00
49.49
16.00
17.91
-15.00
0.808
-15.00
63.03
16.00
14.31
-15.00
0.829
-15.00
64.13
16.00
12.21
-15.00
0.633
-15.00
63.75
16.00
10.51
-15.00
0.689
004415
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-103.00 MW/0.1 Hz
Post-Perturbation Bias Setting
-103.00 MW/0.1 Hz
EPFR for Bias Setting Pre-Perturbation Average
-43.39 MW
EPFR for Bias Setting Post-Perturbation Average
114.21 MW
EPFR for Bias Setting Delta
157.60 MW
Primary Frequency Response Delivery % of Bias
100.02%
20 to 52 second Average Period Evaluation
0.758 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
BA
Load
MW
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
EPFR
MW
Expected
Net
Actual
Interchange
MW
Actual
Primary
Freq Response
MW
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
51.252
89.794
89.563
89.563
92.047
116.139
121.003
121.084
123.767
124.815
135.511
136.482
137.389
139.852
139.620
139.309
142.962
143.218
143.758
143.362
147.166
147.964
149.264
154.318
155.317
154.849
158.515
157.815
157.841
159.278
160.386
160.507
164.127
166.393
169.752
170.779
180.532
180.943
180.892
182.414
181.643
181.673
181.344
180.603
178.716
177.395
173.971
172.945
171.705
169.900
168.673
166.728
164.542
161.862
160.483
159.078
150.968
148.865
147.059
146.392
144.424
143.022
139.453
137.918
136.591
131.248
130.525
129.494
128.224
128.848
127.612
126.560
124.520
123.597
122.533
121.911
122.298
121.678
121.149
120.562
121.012
119.133
119.995
117.825
-26.96
-43.56
-51.73
-51.73
-61.31
-76.85
-74.64
-72.89
-74.06
-78.44
-87.36
-87.42
-87.44
-90.15
-90.59
-91.57
-97.17
-96.69
-96.40
-96.78
-99.35
-97.91
-98.12
-98.21
-98.85
-100.47
-102.19
-102.39
-102.41
-104.70
-104.74
-100.24
-97.05
-89.88
-87.90
-89.82
-98.05
-101.01
-102.71
-102.99
-103.72
-103.15
-105.97
-107.42
-109.56
-109.42
-109.33
-110.77
-112.87
-113.17
-110.15
-111.81
-114.96
-116.34
-114.53
-113.53
-109.30
-110.17
-112.15
-116.07
-114.51
-114.30
-112.35
-112.93
-112.77
-107.47
-104.32
-106.03
-105.86
-108.16
-109.89
-108.05
-109.11
-107.36
-111.27
-105.89
-107.16
-109.50
-107.09
-108.49
-110.89
-113.32
-114.15
-121.31
0.0270
0.0260
0.0260
0.0220
0.0190
0.0170
0.0190
0.0200
0.0190
0.0210
0.0210
0.0210
0.0190
0.0180
0.0220
0.0310
0.0370
0.0370
0.0360
0.0370
0.0460
0.0480
0.0480
0.0430
0.0410
0.0410
0.0410
0.0390
0.0410
0.0430
0.0450
0.0460
0.0410
0.0410
0.0410
0.0390
0.0220
0.1480
0.1640
0.1310
0.1310
0.1080
0.1090
0.1200
0.1240
0.1250
0.1170
0.1130
0.1140
0.1150
0.1130
0.1120
0.1100
0.1050
0.1060
0.1070
0.1060
0.1060
0.1090
0.1100
0.1150
0.1150
0.1120
0.1130
0.1120
0.1120
0.1100
0.1110
0.1180
0.1270
0.1430
0.1510
0.1480
0.1420
0.1370
0.1340
0.1350
0.1330
0.1340
0.1290
0.1260
0.1210
0.1200
0.1170
0.1140
0.1100
0.1080
0.1110
0.1070
0.1010
0.0970
0.0980
0.0980
0.0960
0.0930
0.0890
0.0840
0.0840
0.0830
0.0820
0.0800
0.0790
0.0800
0.0830
0.0800
0.0790
0.0770
0.0740
0.0750
0.0720
0.0730
0.0680
0.0730
0.0720
0.0690
0.0710
0.0690
0.0670
0.0630
0.0630
0.0550
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.810
3712.092
3714.623
3715.130
3716.168
3716.461
3716.980
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.130
3732.530
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.300
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.420
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.850
3786.304
3787.259
3787.516
3787.955
3788.030
3788.607
3789.216
3787.537
3785.842
3786.077
3787.930
3788.760
3786.875
3786.550
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.540
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.540
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.410
3790.467
3790.665
3790.420
3789.674
3789.267
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
59.825
57.993
58.604
59.361
59.493
58.498
56.769
56.007
54.790
53.278
51.935
50.701
50.620
50.207
49.939
49.764
48.569
48.874
48.351
48.733
48.620
48.547
48.860
48.342
48.006
45.985
45.391
45.366
46.071
45.808
45.997
45.039
43.335
41.866
40.911
38.129
37.041
36.334
35.153
33.664
31.255
31.130
31.410
31.591
31.349
30.831
29.774
29.087
27.558
25.843
24.729
24.725
24.002
24.253
23.695
23.693
22.611
21.186
20.621
20.614
20.969
20.840
21.117
19.854
19.033
18.139
16.117
14.442
14.074
13.835
12.237
10.477
9.694
9.545
10.170
11.658
13.705
15.036
14.100
11.689
9.040
6.597
4.648
2.661
2.090
1.719
1.478
0.240
-1.647
-3.594
-5.220
-7.359
-9.830
-12.518
-14.986
-17.312
-17.380
-17.425
-18.176
-20.106
-21.720
-23.131
-22.606
-21.544
-22.655
-23.377
-22.765
-22.008
-23.318
-23.808
-22.685
-21.956
-22.202
-22.362
-22.466
-22.173
-21.983
-22.580
-22.968
-22.860
-21.709
-19.878
-19.411
-19.106
-18.909
-19.141
-19.291
-18.307
-17.307
-17.017
-16.108
-15.157
-14.178
-13.542
-12.407
-10.588
-9.406
-9.358
-9.327
-9.667
-7.364
-4.426
-1.074
2.185
4.665
5.916
6.729
8.700
10.702
12.364
13.804
14.380
15.114
16.314
17.454
17.835
19.163
20.747
22.137
23.040
22.547
21.145
21.675
22.740
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3795.504
3794.290
3795.518
3796.892
3797.641
3797.263
3796.151
3796.005
3795.405
3794.510
3793.784
3793.167
3793.703
3793.907
3794.256
3794.698
3794.120
3795.042
3795.136
3796.135
3796.639
3797.183
3798.112
3798.212
3798.493
3797.088
3797.112
3797.704
3799.026
3799.380
3800.186
3799.845
3798.758
3797.906
3797.568
3795.403
3794.931
3794.841
3794.278
3793.406
3791.614
3792.106
3793.002
3793.800
3794.175
3794.274
3793.834
3793.764
3792.852
3791.754
3791.257
3791.870
3791.764
3792.632
3792.691
3793.306
3792.840
3792.033
3792.085
3792.695
3793.667
3794.155
3795.048
3794.402
3794.199
3793.922
3792.516
3791.459
3791.708
3792.085
3791.104
3789.962
3789.796
3790.264
3791.506
3793.610
3796.275
3798.223
3797.903
3796.109
3794.077
3792.251
3790.919
3788.932
3788.361
3787.990
3787.749
3786.511
3784.624
3782.677
3781.051
3778.912
3776.441
3773.754
3771.285
3768.960
3768.891
3768.846
3768.095
3766.166
3764.551
3763.140
3763.666
3764.728
3763.617
3762.894
3763.506
3764.264
3762.953
3762.463
3763.586
3764.316
3764.069
3763.909
3763.805
3764.098
3764.288
3763.691
3763.303
3763.411
3764.562
3766.393
3766.861
3767.165
3767.363
3767.131
3766.980
3767.964
3768.964
3769.254
3770.163
3771.114
3772.093
3772.729
3773.864
3775.683
3776.866
3776.913
3776.945
3776.605
3778.907
3781.845
3785.197
3788.457
3790.936
3792.187
3793.000
3794.972
3796.973
3798.635
3800.075
3800.651
3801.386
3802.585
3803.725
3804.106
3805.434
3807.018
3808.408
3809.312
3808.818
3807.416
3807.946
3809.011
3787.108
3786.727
3786.308
3785.865
3785.443
3785.049
3784.654
3784.245
3783.871
3783.438
3782.989
3782.506
3781.984
3781.437
3780.882
3780.306
3779.720
3779.121
3778.534
3777.937
3777.330
3776.734
3776.124
3775.525
3774.948
3774.404
3773.875
3773.364
3772.865
3772.379
3771.908
3771.485
3771.065
3770.659
3770.255
3769.859
3769.465
3769.088
3768.724
3768.362
3768.009
3767.673
3767.357
3767.052
3766.776
3766.514
3766.263
3766.039
3765.822
3765.607
3765.409
3765.223
3765.047
3764.880
3764.739
3764.611
3764.496
3764.399
3764.310
3764.230
3764.171
3764.119
3764.070
3764.046
3764.025
3764.008
3764.000
3763.994
3764.001
3764.014
3764.030
3764.050
3764.074
3764.102
3764.146
3764.198
3764.257
3764.321
3764.391
3764.457
3764.520
3764.586
3764.656
3764.738
3764.826
3764.922
3765.014
3765.118
3765.226
3765.336
3765.452
3765.565
3765.684
3765.800
3765.919
3766.038
3766.159
3766.278
3766.399
3766.523
3766.636
3766.738
3766.841
3766.953
3767.068
3767.171
3767.272
3767.376
3767.467
3767.560
3767.654
3767.746
3767.843
3767.938
3768.025
3768.113
3768.203
3768.290
3768.376
3768.463
3768.553
3768.645
3768.745
3768.845
3768.943
3769.036
3769.131
3769.226
3769.318
3769.408
3769.499
3769.596
3769.693
3769.788
3769.879
3769.977
3770.080
3770.174
3770.269
3770.363
3770.453
3770.541
3770.627
3770.710
3770.787
3770.862
3770.936
3771.010
3771.085
3771.159
3771.233
3771.304
3771.371
3771.434
3771.502
3771.574
3771.647
3771.715
3771.784
3771.860
3771.936
3772.011
3772.082
3772.151
3813.468
3813.248
3813.046
3812.865
3812.695
3812.526
3812.348
3812.172
3811.994
3811.810
3811.622
3811.432
3811.251
3811.076
3810.907
3810.747
3810.584
3810.433
3810.286
3810.151
3810.024
3809.904
3809.795
3809.688
3809.586
3809.474
3809.364
3809.260
3809.171
3809.085
3809.009
3808.930
3808.844
3808.752
3808.659
3808.549
3808.438
3808.327
3808.214
3808.096
3807.965
3807.840
3807.724
3807.616
3807.513
3807.412
3807.309
3807.207
3807.100
3806.986
3806.870
3806.761
3806.652
3806.551
3806.452
3806.359
3806.264
3806.164
3806.067
3805.974
3805.890
3805.810
3805.738
3805.662
3805.585
3805.508
3805.422
3805.331
3805.243
3805.158
3805.068
3804.971
3804.875
3804.784
3804.701
3804.632
3804.580
3804.541
3804.501
3804.450
3804.387
3804.315
3804.235
3804.144
3804.051
3803.958
3803.863
3803.763
3803.653
3803.533
3803.405
3803.267
3803.116
3802.952
3802.776
3802.590
3802.404
3802.221
3802.036
3801.842
3801.641
3801.435
3801.234
3801.041
3800.844
3800.646
3800.452
3800.265
3800.072
3799.879
3799.694
3799.515
3799.336
3799.158
3798.981
3798.807
3798.636
3798.464
3798.292
3798.122
3797.959
3797.806
3797.658
3797.512
3797.368
3797.225
3797.082
3796.945
3796.815
3796.686
3796.564
3796.446
3796.335
3796.227
3796.125
3796.033
3795.946
3795.861
3795.777
3795.691
3795.617
3795.556
3795.511
3795.480
3795.460
3795.446
3795.436
3795.434
3795.440
3795.454
3795.474
3795.495
3795.520
3795.550
3795.584
3795.619
3795.660
3795.706
3795.758
3795.814
3795.867
3795.913
3795.962
3796.014
3720.461
3721.078
3721.695
3722.312
3722.929
3723.546
3724.163
3724.780
3725.397
3726.014
3726.631
3727.248
3727.865
3728.482
3729.099
3729.715
3730.332
3730.949
3731.566
3732.183
3732.800
3733.417
3734.034
3734.651
3735.268
3735.885
3736.502
3737.119
3737.736
3738.353
3738.970
3739.587
3740.204
3740.821
3741.438
3742.055
3742.672
3743.289
3743.906
3744.523
3745.140
3745.757
3746.374
3746.991
3747.608
3748.225
3748.842
3749.459
3750.076
3750.693
3751.310
3751.927
3752.543
3753.160
3753.777
3754.394
3755.011
3755.628
3756.245
3756.862
3757.479
3758.096
3758.713
3759.330
3759.947
3760.564
3761.181
3761.798
3762.415
3763.032
3763.649
3764.266
3764.883
3765.500
3766.117
3766.734
3767.351
3767.968
3768.585
3769.202
3769.819
3770.436
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3694.548
3694.857
3695.165
3695.474
3695.782
3696.090
3696.399
3696.707
3697.016
3697.324
3697.633
3697.941
3698.250
3698.558
3698.867
3699.175
3699.484
3699.792
3700.101
3700.409
3700.718
3701.026
3701.335
3701.643
3701.952
3702.260
3702.569
3702.877
3703.186
3703.494
3703.803
3704.111
3704.420
3704.728
3705.037
3705.345
3705.654
3705.962
3706.271
3706.579
3706.888
3707.196
3707.504
3707.813
3708.121
3708.430
3708.738
3709.047
3709.355
3709.664
3709.972
3710.281
3710.589
3710.898
3711.206
3711.515
3711.823
3712.132
3712.440
3712.749
3713.057
3713.366
3713.674
3713.983
3714.291
3714.600
3714.908
3715.217
3715.525
3715.834
3716.142
3716.451
3716.759
3717.068
3717.376
3717.685
3717.993
3718.302
3718.610
3718.918
3719.227
3719.535
3719.844
3720.149
3720.450
3720.748
3721.042
3721.333
3721.620
3721.904
3722.185
3722.463
3722.737
3723.009
3723.277
3723.542
3723.805
3724.064
3724.321
3724.575
3724.826
3725.075
3725.321
3725.564
3725.805
3726.043
3726.279
3726.512
3726.743
3726.971
3727.197
3727.421
3727.642
3727.861
3728.079
3728.293
3728.506
3728.717
3728.925
3729.132
3729.336
3729.539
3729.739
3729.938
3730.135
3730.330
3730.523
3730.714
3730.903
3731.091
3731.277
3731.461
3731.643
3731.824
3732.003
3732.181
3732.356
3732.531
3732.704
3732.875
3733.044
3733.213
3733.379
3733.545
3733.708
3733.871
3734.032
3734.191
3734.349
3734.506
3734.662
3734.816
3734.969
3735.120
3735.271
3735.420
3735.568
3735.714
3735.860
3736.004
3736.147
3736.289
3736.430
3736.569
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.970
59.974
59.970
59.969
59.969
59.970
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.980
59.982
59.981
59.980
59.979
59.980
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.020
60.025
60.024
60.020
60.020
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.010
60.007
60.007
60.009
60.009
60.010
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
3758.39
3753.92
3749.87
3746.89
3747.88
3749.59
3748.66
3746.71
3749.08
3742.74
3740.26
3736.14
3731.38
3727.84
3725.95
3722.65
3720.58
3718.00
3718.14
3715.75
3713.69
3713.48
3710.85
3710.81
3712.09
3714.62
3715.13
3716.17
3716.46
3716.98
3717.76
3722.36
3721.97
3722.66
3722.27
3722.28
3721.79
3723.09
3723.98
3723.43
3723.89
3725.40
3727.12
3728.05
3731.13
3732.53
3733.33
3736.54
3736.91
3736.82
3738.70
3739.94
3740.88
3741.79
3745.23
3746.61
3748.30
3750.72
3751.56
3752.75
3755.60
3756.41
3756.98
3760.41
3760.98
3761.41
3762.74
3763.21
3764.96
3766.09
3766.43
3767.25
3767.79
3768.63
3771.15
3772.44
3773.69
3774.67
3775.84
3775.36
3774.87
3775.49
3776.42
3778.55
3779.69
3781.26
3780.59
3783.09
3783.90
3784.42
3785.77
3785.46
3786.85
3786.30
3787.26
3787.52
3787.96
3788.03
3788.61
3789.22
3787.54
3785.84
3786.08
3787.93
3788.76
3786.87
3786.55
3787.36
3785.02
3785.61
3785.95
3785.80
3786.86
3786.88
3785.25
3785.73
3786.35
3785.82
3785.80
3786.28
3786.94
3787.63
3789.44
3789.67
3789.40
3788.48
3789.18
3789.37
3789.00
3788.66
3788.93
3790.67
3790.81
3790.41
3789.77
3791.54
3792.95
3791.03
3791.44
3791.43
3790.60
3790.46
3790.22
3789.58
3788.46
3788.10
3788.06
3788.19
3788.50
3788.54
3788.57
3788.10
3787.13
3786.45
3787.73
3788.81
3789.29
3788.26
3788.41
3790.47
3790.66
3790.42
3789.67
3789.27
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
229.09
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
218.62
218.62
213.54
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
212.57
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
221.46
221.46
221.46
221.46
221.46
241.27
241.27
241.27
241.27
241.27
243.07
243.07
243.07
243.07
243.07
241.67
241.67
241.67
241.67
241.67
228.15
228.15
228.15
228.15
228.15
235.13
235.13
235.13
235.13
235.13
246.43
246.43
246.43
246.43
246.43
236.55
236.55
236.55
236.55
236.55
230.30
230.30
230.30
230.30
230.30
231.18
231.18
231.18
231.18
231.18
225.62
225.62
225.62
225.62
225.62
230.73
230.73
230.73
230.73
230.73
234.85
234.85
234.85
234.85
234.85
228.96
228.96
228.96
228.96
228.96
231.18
231.18
231.18
231.18
231.18
236.49
236.49
236.49
236.49
236.49
245.04
245.04
245.04
245.04
245.04
223.61
223.61
223.61
223.61
223.61
231.12
231.12
231.12
231.12
231.12
237.21
237.21
237.21
237.21
237.21
240.52
240.52
240.52
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7668.00
7669.00
7669.00
7670.00
7670.00
7671.00
7671.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7676.00
7677.00
7678.00
7679.00
7680.00
7681.00
7682.00
7684.00
7685.00
7687.00
7689.00
7690.00
7692.00
7692.00
7693.00
7693.00
7694.00
7694.00
7695.00
7695.00
7695.00
7696.00
7696.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.30
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.60
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.90
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.20
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.50
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.80
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.10
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.40
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.70
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731.00
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.30
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
23.689
24.718
24.718
21.630
18.542
22.659
24.718
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
113.277
108.812
104.757
101.779
102.765
104.483
103.551
101.596
103.967
97.631
95.149
91.029
86.272
82.728
80.842
77.539
75.468
72.886
73.032
70.643
68.584
68.374
65.738
65.700
66.982
69.512
70.020
71.058
71.351
71.870
72.649
77.251
76.863
77.548
77.157
77.168
76.677
77.981
78.874
78.324
78.783
80.293
82.011
82.943
86.020
87.420
88.217
91.425
91.797
91.712
93.589
94.834
95.767
96.684
100.124
101.498
103.190
105.606
106.448
107.637
110.489
111.297
111.865
115.295
115.872
116.297
117.627
118.102
119.847
120.975
121.323
122.141
122.682
123.523
126.036
127.335
128.585
129.558
130.731
130.253
129.756
130.382
131.310
132.827
133.965
135.529
134.868
137.365
138.168
138.694
140.041
139.736
141.123
140.577
141.532
141.789
142.228
142.303
142.880
143.489
141.810
140.115
140.350
142.203
143.033
141.148
140.823
141.631
139.291
139.887
140.222
140.077
141.137
141.150
139.527
139.999
140.620
140.094
140.071
140.557
141.212
141.900
143.717
143.946
143.677
142.752
143.456
143.642
143.278
142.938
143.206
144.940
145.078
144.684
144.042
145.813
147.218
145.300
145.716
145.699
144.876
144.730
144.489
143.858
142.730
142.378
142.330
142.462
142.770
142.813
142.844
142.374
141.406
140.726
142.005
143.086
143.558
142.529
142.683
144.740
144.938
144.693
143.947
143.540
-121.64
-114.39
-104.63
-100.65
-102.64
-107.58
-110.02
-106.80
-111.64
-107.14
-105.57
-102.14
-94.67
-91.79
-89.70
-86.03
-86.62
-80.87
-82.87
-78.38
-76.95
-76.72
-72.94
-74.55
-76.01
-83.62
-82.26
-82.51
-80.96
-83.45
-83.39
-91.83
-94.74
-96.79
-96.30
-104.10
-100.72
-102.44
-106.40
-108.60
-115.64
-111.33
-112.15
-113.43
-119.27
-122.91
-127.62
-132.26
-138.83
-143.02
-145.95
-143.42
-149.35
-146.22
-156.14
-155.85
-166.10
-175.64
-174.14
-173.26
-175.03
-179.15
-177.21
-195.01
-195.98
-200.08
-217.32
-222.30
-217.41
-219.45
-237.31
-248.63
-244.75
-241.61
-237.24
-226.88
-217.48
-219.13
-241.53
-265.15
-281.30
-295.49
-304.49
0.0510
0.0530
0.0580
0.0590
0.0580
0.0550
0.0520
0.0530
0.0510
0.0490
0.0480
0.0470
0.0490
0.0480
0.0480
0.0480
0.0450
0.0480
0.0460
0.0480
0.0470
0.0470
0.0480
0.0460
0.0460
0.0410
0.0430
0.0440
0.0460
0.0440
0.0450
0.0420
0.0390
0.0380
0.0380
0.0320
0.0340
0.0340
0.0320
0.0300
0.0260
0.0300
0.0310
0.0310
0.0300
0.0290
0.0270
0.0270
0.0240
0.0220
0.0220
0.0240
0.0220
0.0240
0.0220
0.0230
0.0200
0.0180
0.0190
0.0200
0.0210
0.0200
0.0210
0.0170
0.0170
0.0160
0.0120
0.0110
0.0130
0.0130
0.0090
0.0070
0.0080
0.0090
0.0110
0.0140
0.0170
0.0170
0.0120
0.0070
0.0040
0.0020
0.0010
0.0010
0.0010
0.0010
0.0010
0.0020
0.0050
0.0070
0.0080
0.0110
0.0140
0.0170
0.0190
0.0210
0.0170
0.0170
0.0190
0.0230
0.0240
0.0250
0.0210
0.0190
0.0240
0.0240
0.0210
0.0200
0.0250
0.0240
0.0200
0.0200
0.0220
0.0220
0.0220
0.0210
0.0210
0.0230
0.0230
0.0220
0.0190
0.0160
0.0180
0.0180
0.0180
0.0190
0.0190
0.0160
0.0150
0.0160
0.0140
0.0130
0.0120
0.0120
0.0100
0.0070
0.0070
0.0090
0.0090
0.0100
0.0030
0.0010
0.0050
0.0080
0.0090
0.0080
0.0080
0.0120
0.0140
0.0150
0.0160
0.0150
0.0160
0.0180
0.0190
0.0180
0.0210
0.0230
0.0240
0.0240
0.0210
0.0180
0.0220
0.0240
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004416
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
3789.148
3790.430
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.080
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.690
3784.831
3785.010
3784.320
3782.809
3782.110
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.170
3771.730
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.250
3758.041
3760.965
3762.022
3763.822
3763.100
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.570
3761.920
3759.627
3758.522
3752.429
3750.102
3753.830
3753.510
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.370
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.650
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.860
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.340
3750.700
3749.750
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.830
3737.583
3736.229
3734.897
3733.434
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
24.154
24.352
24.120
23.969
24.593
25.719
27.892
28.944
29.268
28.758
26.623
24.155
23.632
24.374
25.937
25.510
25.595
26.370
28.316
30.662
32.548
33.413
32.893
32.195
32.464
33.719
34.895
33.496
31.867
32.610
33.093
32.686
32.782
32.483
33.011
33.354
33.937
34.677
32.994
33.343
34.290
35.987
36.369
34.455
34.292
33.465
33.289
34.976
35.352
33.793
31.699
32.141
33.509
33.317
32.831
33.237
34.582
34.735
30.148
23.201
21.208
23.159
26.950
30.135
33.286
35.334
37.027
38.128
39.203
38.820
40.014
41.871
44.880
46.116
46.559
45.765
45.608
43.706
41.747
41.195
41.558
40.350
39.566
38.335
36.454
35.232
34.437
33.199
31.313
30.808
32.642
33.114
33.421
31.818
29.333
28.079
29.426
28.861
28.133
26.217
23.891
22.379
21.396
20.397
19.748
18.604
18.582
18.928
19.874
20.128
21.014
21.590
21.244
20.658
20.638
21.345
22.526
24.736
26.533
28.421
27.847
27.114
26.275
27.173
28.837
29.198
28.352
28.523
28.634
28.706
26.950
24.007
23.535
23.949
25.301
25.819
25.073
24.589
23.913
23.114
21.874
22.509
24.004
26.057
27.391
28.259
28.462
30.037
31.781
32.915
31.849
30.435
29.877
30.595
29.981
28.861
28.493
29.335
29.522
28.563
25.055
21.693
19.508
18.087
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3810.426
3810.623
3810.391
3810.240
3810.864
3811.990
3814.163
3815.216
3815.539
3815.029
3812.895
3810.426
3809.903
3810.645
3812.208
3811.782
3811.866
3812.641
3814.587
3816.933
3818.819
3819.685
3819.165
3818.467
3818.735
3819.990
3821.166
3819.767
3818.138
3818.881
3819.365
3818.957
3819.053
3818.754
3819.282
3819.625
3820.208
3820.948
3819.265
3819.614
3820.562
3822.258
3822.641
3820.726
3820.564
3819.736
3819.560
3821.247
3821.623
3820.064
3817.970
3818.412
3819.780
3819.589
3819.102
3819.508
3820.853
3821.007
3816.420
3809.472
3807.480
3809.430
3813.221
3816.406
3819.557
3821.606
3823.299
3824.399
3825.475
3825.091
3826.285
3828.142
3831.151
3832.387
3832.830
3832.036
3831.880
3829.977
3828.018
3827.467
3827.829
3826.622
3825.837
3824.606
3822.726
3821.503
3820.709
3819.470
3817.584
3817.079
3818.914
3819.386
3819.692
3818.089
3815.604
3814.351
3815.698
3815.132
3814.404
3812.488
3810.162
3808.650
3807.667
3806.668
3806.019
3804.875
3804.853
3805.199
3806.145
3806.399
3807.285
3807.861
3807.515
3806.929
3806.909
3807.617
3808.797
3811.007
3812.804
3814.692
3814.118
3813.385
3812.546
3813.444
3815.108
3815.470
3814.624
3814.794
3814.905
3814.977
3813.221
3810.278
3809.807
3810.221
3811.572
3812.090
3811.345
3810.860
3810.185
3809.385
3808.145
3808.780
3810.276
3812.328
3813.663
3814.530
3814.733
3816.308
3818.052
3819.186
3818.120
3816.707
3816.148
3816.866
3816.252
3815.132
3814.764
3815.606
3815.793
3814.834
3811.327
3807.964
3805.779
3804.359
3772.219
3772.292
3772.362
3772.417
3772.476
3772.541
3772.611
3772.686
3772.764
3772.840
3772.903
3772.961
3773.018
3773.071
3773.125
3773.177
3773.230
3773.280
3773.332
3773.391
3773.454
3773.520
3773.588
3773.652
3773.707
3773.763
3773.819
3773.868
3773.910
3773.950
3773.989
3774.026
3774.057
3774.085
3774.104
3774.121
3774.137
3774.155
3774.173
3774.181
3774.186
3774.194
3774.202
3774.208
3774.205
3774.196
3774.178
3774.159
3774.141
3774.119
3774.088
3774.042
3773.994
3773.954
3773.914
3773.870
3773.825
3773.780
3773.733
3773.682
3773.616
3773.550
3773.480
3773.417
3773.368
3773.323
3773.275
3773.236
3773.201
3773.171
3773.140
3773.111
3773.083
3773.062
3773.047
3773.032
3773.014
3772.992
3772.960
3772.926
3772.892
3772.852
3772.809
3772.748
3772.680
3772.624
3772.567
3772.510
3772.452
3772.395
3772.337
3772.281
3772.225
3772.167
3772.101
3772.029
3771.938
3771.849
3771.777
3771.702
3771.621
3771.536
3771.447
3771.354
3771.262
3771.167
3771.071
3770.974
3770.877
3770.778
3770.681
3770.589
3770.499
3770.406
3770.313
3770.220
3770.126
3770.035
3769.949
3769.865
3769.782
3769.698
3769.612
3769.525
3769.441
3769.362
3769.285
3769.213
3769.142
3769.072
3769.001
3768.930
3768.854
3768.780
3768.705
3768.633
3768.566
3768.495
3768.421
3768.346
3768.270
3768.194
3768.122
3768.046
3767.971
3767.909
3767.847
3767.790
3767.735
3767.684
3767.641
3767.597
3767.543
3767.487
3767.428
3767.368
3767.301
3767.233
3767.150
3767.064
3766.992
3766.917
3766.839
3766.758
3796.072
3796.130
3796.187
3796.242
3796.300
3796.361
3796.431
3796.504
3796.578
3796.649
3796.711
3796.764
3796.814
3796.867
3796.925
3796.981
3797.037
3797.095
3797.160
3797.234
3797.314
3797.396
3797.476
3797.553
3797.631
3797.712
3797.797
3797.876
3797.949
3798.024
3798.100
3798.175
3798.249
3798.321
3798.395
3798.469
3798.545
3798.623
3798.695
3798.768
3798.843
3798.923
3799.004
3799.079
3799.152
3799.221
3799.290
3799.364
3799.439
3799.508
3799.569
3799.632
3799.699
3799.764
3799.828
3799.892
3799.961
3800.029
3800.083
3800.113
3800.137
3800.167
3800.208
3800.260
3800.322
3800.389
3800.462
3800.537
3800.616
3800.692
3800.772
3800.858
3800.952
3801.049
3801.147
3801.242
3801.336
3801.424
3801.505
3801.584
3801.663
3801.739
3801.811
3801.880
3801.942
3802.001
3802.056
3802.108
3802.154
3802.198
3802.247
3802.297
3802.348
3802.394
3802.432
3802.467
3802.505
3802.541
3802.576
3802.604
3802.626
3802.643
3802.657
3802.668
3802.678
3802.684
3802.690
3802.697
3802.707
3802.717
3802.730
3802.744
3802.757
3802.769
3802.780
3802.793
3802.810
3802.832
3802.859
3802.891
3802.921
3802.950
3802.975
3803.004
3803.036
3803.069
3803.100
3803.131
3803.162
3803.193
3803.220
3803.238
3803.255
3803.273
3803.295
3803.318
3803.339
3803.358
3803.376
3803.391
3803.403
3803.417
3803.435
3803.457
3803.483
3803.511
3803.539
3803.572
3803.608
3803.647
3803.683
3803.716
3803.747
3803.779
3803.810
3803.838
3803.865
3803.894
3803.923
3803.950
3803.968
3803.977
3803.982
3803.983
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3736.708
3736.845
3736.982
3737.117
3737.251
3737.384
3737.516
3737.647
3737.777
3737.906
3738.034
3738.161
3738.287
3738.412
3738.536
3738.659
3738.781
3738.903
3739.023
3739.143
3739.261
3739.379
3739.496
3739.612
3739.727
3739.841
3739.955
3740.068
3740.180
3740.291
3740.401
3740.510
3740.619
3740.727
3740.834
3740.940
3741.046
3741.151
3741.255
3741.359
3741.461
3741.563
3741.665
3741.765
3741.865
3741.965
3742.063
3742.161
3742.259
3742.355
3742.451
3742.546
3742.641
3742.735
3742.829
3742.922
3743.014
3743.105
3743.196
3743.287
3743.377
3743.466
3743.555
3743.643
3743.730
3743.817
3743.904
3743.990
3744.075
3744.160
3744.244
3744.328
3744.411
3744.494
3744.576
3744.658
3744.739
3744.820
3744.900
3744.980
3745.059
3745.138
3745.216
3745.294
3745.371
3745.448
3745.525
3745.601
3745.676
3745.751
3745.826
3745.900
3745.974
3746.047
3746.120
3746.193
3746.265
3746.336
3746.408
3746.478
3746.549
3746.619
3746.688
3746.758
3746.826
3746.895
3746.963
3747.031
3747.098
3747.165
3747.231
3747.297
3747.363
3747.429
3747.494
3747.559
3747.623
3747.687
3747.751
3747.814
3747.877
3747.940
3748.002
3748.064
3748.125
3748.187
3748.248
3748.308
3748.369
3748.429
3748.488
3748.548
3748.607
3748.666
3748.724
3748.782
3748.840
3748.898
3748.955
3749.012
3749.068
3749.125
3749.181
3749.237
3749.292
3749.347
3749.402
3749.457
3749.511
3749.566
3749.619
3749.673
3749.726
3749.779
3749.832
3749.885
3749.937
3749.989
3750.041
3750.092
3750.143
3750.194
3750.245
3750.296
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.970
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.970
59.968
59.965
59.964
59.970
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.970
59.967
59.969
59.968
59.963
59.965
59.970
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.990
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.960
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
59.968
59.968
59.970
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.980
59.978
59.978
59.980
59.981
59.980
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.970
59.971
59.974
59.982
59.985
59.985
59.985
3789.15
3790.43
3789.91
3786.24
3787.44
3788.96
3790.60
3791.88
3792.91
3792.31
3789.13
3788.08
3787.84
3787.14
3787.16
3787.00
3787.40
3786.49
3787.08
3789.21
3790.51
3791.22
3792.22
3790.96
3788.82
3789.03
3789.17
3787.39
3785.69
3784.83
3785.01
3784.32
3782.81
3782.11
3779.35
3779.06
3778.63
3779.21
3779.33
3776.43
3775.65
3776.60
3776.56
3776.02
3773.17
3771.73
3768.79
3768.50
3768.92
3767.37
3764.79
3760.30
3759.59
3761.89
3761.78
3760.58
3760.16
3759.78
3759.49
3757.77
3753.28
3753.09
3751.64
3753.75
3758.22
3759.25
3758.04
3760.96
3762.02
3763.82
3763.10
3763.86
3764.16
3766.13
3768.34
3767.97
3767.44
3765.61
3762.69
3761.57
3761.92
3759.63
3758.52
3752.43
3750.10
3753.83
3753.51
3753.52
3752.74
3753.18
3752.73
3753.29
3752.87
3752.36
3749.40
3747.48
3740.37
3741.29
3746.65
3745.74
3743.35
3741.62
3740.31
3738.48
3738.90
3737.40
3737.27
3736.31
3736.27
3735.45
3735.65
3737.54
3738.01
3736.75
3736.69
3736.07
3736.09
3736.57
3738.57
3738.87
3738.93
3738.65
3737.68
3737.38
3737.89
3740.02
3740.33
3742.05
3742.42
3742.52
3742.25
3741.72
3740.09
3740.63
3739.96
3740.78
3742.83
3741.27
3739.78
3738.97
3738.71
3738.88
3739.86
3738.10
3738.56
3743.51
3743.42
3745.25
3745.74
3747.34
3750.70
3749.75
3746.22
3744.68
3743.75
3743.15
3740.30
3739.45
3733.38
3731.83
3737.58
3736.23
3734.90
3733.43
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
240.52
240.52
237.57
237.57
237.57
237.57
237.57
231.58
231.58
231.58
231.58
231.58
235.85
235.85
235.85
235.85
235.85
233.56
233.56
233.56
233.56
233.56
219.01
219.01
219.01
219.01
219.01
205.34
205.34
205.34
205.34
205.34
236.29
236.29
236.29
236.29
236.29
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.60
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.90
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.20
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.50
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.80
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.10
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.40
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.70
7761.03
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764.00
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.30
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.60
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.90
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.20
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.50
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.80
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.10
7787.43
7787.76
7788.09
7788.42
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
143.421
144.703
144.187
140.516
141.715
143.236
144.875
146.150
147.184
146.584
143.398
142.353
142.117
141.408
141.437
141.269
141.678
140.760
141.352
143.487
144.785
145.494
146.491
145.232
143.097
143.299
143.440
141.667
139.963
139.104
139.282
138.593
137.082
136.383
133.625
133.329
132.906
133.485
133.608
130.702
129.920
130.870
130.832
130.296
127.443
126.003
123.066
122.776
123.190
121.639
119.059
114.568
113.865
116.167
116.050
114.855
114.430
114.054
113.768
112.046
107.550
107.360
105.910
108.024
112.498
113.523
112.314
115.238
116.295
118.095
117.373
118.131
118.431
120.400
122.612
122.245
121.710
119.879
116.961
115.843
116.193
113.900
112.795
106.702
104.375
108.103
107.783
107.796
107.014
107.451
107.002
107.563
107.145
106.632
103.671
101.749
94.643
95.558
100.924
100.011
97.624
95.891
94.579
92.757
93.174
91.677
91.546
90.581
90.545
89.721
89.923
91.813
92.285
91.021
90.966
90.340
90.367
90.848
92.844
93.148
93.208
92.920
91.957
91.655
92.165
94.290
94.602
96.326
96.697
96.797
96.518
95.996
94.358
94.902
94.237
95.048
97.105
95.541
94.049
93.239
92.979
93.152
94.133
92.375
92.831
97.780
97.692
99.524
100.017
101.613
104.973
104.023
100.490
98.956
98.018
97.422
94.572
93.726
87.649
86.103
91.855
90.502
89.170
87.707
0.0260
0.0240
0.0230
0.0230
0.0250
0.0270
0.0310
0.0300
0.0290
0.0270
0.0220
0.0190
0.0220
0.0250
0.0280
0.0240
0.0250
0.0270
0.0310
0.0340
0.0350
0.0340
0.0310
0.0300
0.0320
0.0350
0.0360
0.0300
0.0280
0.0330
0.0330
0.0310
0.0320
0.0310
0.0330
0.0330
0.0340
0.0350
0.0290
0.0330
0.0350
0.0380
0.0360
0.0300
0.0330
0.0310
0.0320
0.0370
0.0350
0.0300
0.0270
0.0320
0.0350
0.0320
0.0310
0.0330
0.0360
0.0340
0.0210
0.0100
0.0170
0.0260
0.0330
0.0350
0.0380
0.0380
0.0390
0.0390
0.0400
0.0370
0.0410
0.0440
0.0490
0.0470
0.0460
0.0430
0.0440
0.0390
0.0370
0.0390
0.0410
0.0370
0.0370
0.0350
0.0320
0.0320
0.0320
0.0300
0.0270
0.0290
0.0350
0.0330
0.0330
0.0280
0.0240
0.0250
0.0310
0.0270
0.0260
0.0220
0.0190
0.0190
0.0190
0.0180
0.0180
0.0160
0.0180
0.0190
0.0210
0.0200
0.0220
0.0220
0.0200
0.0190
0.0200
0.0220
0.0240
0.0280
0.0290
0.0310
0.0260
0.0250
0.0240
0.0280
0.0310
0.0290
0.0260
0.0280
0.0280
0.0280
0.0230
0.0180
0.0220
0.0240
0.0270
0.0260
0.0230
0.0230
0.0220
0.0210
0.0190
0.0230
0.0260
0.0290
0.0290
0.0290
0.0280
0.0320
0.0340
0.0340
0.0290
0.0270
0.0280
0.0310
0.0280
0.0260
0.0270
0.0300
0.0290
0.0260
0.0180
0.0150
0.0150
0.0150
004417
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3733.115
3730.510
3729.180
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.560
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.100
3690.477
3696.865
3696.877
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
16.443
14.654
13.491
13.816
13.667
12.488
10.280
8.125
4.921
2.118
-0.066
-2.206
-5.760
-8.791
-12.564
-15.737
-19.242
-21.881
-23.956
-26.026
-27.371
-31.129
-33.212
-34.926
-36.040
-36.404
-38.443
-40.489
-42.179
-42.918
-44.480
-46.216
-46.624
-46.889
-45.979
-45.388
-45.364
-44.988
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3802.715
3800.926
3799.763
3800.088
3799.939
3798.759
3796.552
3794.396
3791.192
3788.389
3786.205
3784.065
3780.511
3777.480
3773.707
3770.534
3767.029
3764.390
3762.315
3760.245
3758.900
3755.142
3753.060
3751.346
3750.231
3749.868
3747.828
3745.782
3744.092
3743.353
3741.791
3740.055
3739.647
3739.382
3740.292
3740.884
3740.908
3741.284
3766.677
3766.590
3766.500
3766.401
3766.302
3766.192
3766.084
3765.988
3765.892
3765.802
3765.713
3765.623
3765.533
3765.438
3765.347
3765.255
3765.148
3765.035
3764.924
3764.815
3764.705
3764.591
3764.474
3764.350
3764.227
3764.079
3763.930
3763.796
3763.659
3763.521
3763.380
3763.240
3763.097
3762.955
3762.793
3762.632
3762.485
3762.340
3803.980
3803.972
3803.962
3803.953
3803.943
3803.931
3803.913
3803.891
3803.861
3803.824
3803.782
3803.736
3803.681
3803.620
3803.550
3803.473
3803.389
3803.298
3803.203
3803.104
3803.002
3802.892
3802.778
3802.660
3802.540
3802.420
3802.296
3802.168
3802.037
3801.904
3801.769
3801.630
3801.491
3801.352
3801.216
3801.082
3800.948
3800.816
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3750.346
3750.396
3750.446
3750.495
3750.545
3750.594
3750.642
3750.691
3750.739
3750.788
3750.835
3750.883
3750.931
3750.978
3751.025
3751.072
3751.118
3751.165
3751.211
3751.257
3751.302
3751.348
3751.393
3751.438
3751.483
3751.528
3751.572
3751.617
3751.661
3751.705
3751.748
3751.792
3751.835
3751.878
3751.921
3751.964
3752.006
3752.049
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
59.987
59.989
59.989
59.986
59.987
59.990
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3733.12
3730.51
3729.18
3725.46
3724.78
3720.11
3720.94
3725.66
3725.68
3727.75
3727.82
3727.68
3727.23
3725.01
3726.45
3726.02
3719.12
3716.37
3717.33
3717.56
3717.14
3715.17
3713.63
3710.28
3710.16
3699.36
3698.59
3704.59
3703.28
3702.48
3701.32
3700.83
3699.53
3699.73
3690.10
3690.48
3696.86
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7788.75
7789.08
7789.41
7789.74
7790.07
7790.40
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
7793.70
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797.00
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.30
7800.63
7800.96
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
87.388
84.783
83.453
79.732
79.058
74.381
75.211
79.934
79.950
82.027
82.098
81.956
81.504
79.285
80.719
80.289
73.396
70.647
71.605
71.833
71.415
69.439
67.905
64.556
64.431
53.629
52.864
58.864
57.548
56.755
55.589
55.099
53.802
53.999
44.373
44.750
51.137
51.150
0.0130
0.0110
0.0110
0.0140
0.0130
0.0100
0.0060
0.0040
0.0010
0.0030
0.0040
0.0060
0.0120
0.0140
0.0190
0.0210
0.0250
0.0260
0.0270
0.0290
0.0290
0.0370
0.0360
0.0370
0.0370
0.0360
0.0410
0.0430
0.0440
0.0430
0.0460
0.0480
0.0460
0.0460
0.0430
0.0430
0.0440
0.0430
004418
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
Balancing Authority
MyBA
60.08
60.06
1.000
0.744
004419
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
3900.0
20 to 52 second Average Period
60.042
3843.77
60.04
3850.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
60.02
3803.32
60
3800.0
59.98
3788.35
59.96
Frequency - Hz
59.92
59.9
3700.0
59.88
59.889
59.86
3650.0
59.84
3645.73
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
2:26:36
2:26:46
2:26:56
2:27:06
Hz
Average Frequency
2:27:16
MW
2:27:26
2:27:36
Average MW
2:27:46
2:27:56
EPFR Adjusted
2:28:06
2:28:16
EPFR Unadjusted
3500.0
2:28:26
NAI MW
3750.0
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
0.758
05:34
MyBA
60.08
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
Sustained P.U. Performance
Event Length mm:ss
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
59.88
59.86
59.84
59.82
59.8
59.78
3900.0
3850.0
3800.0
3750.0
3700.0
3650.0
3600.0
3550.0
59.76
59.74
59.72
2:26:26
3500.0
2:27:26
2:28:26
2:29:26
Hz
2:30:26
2:31:26
2:32:26
Interchange MW
2:33:26
2:34:26
2:35:26
2:36:26
Recovery Period Target MW
2:37:26
2:38:26
2:39:26
2:40:26
Recovery Period Ramp MW
2:41:26
2:42:26
NAI MW
Frequency - Hz
59.94
004420
-103.00
MyBA
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
Avg Bias While Hz >+/-0.036 Hz
100.0
60.08
60.06
50.0
60.04
60.02
60
0.0
59.98
59.96
-50.0
59.92
-100.0
59.9
59.88
-150.0
59.86
-200.0
59.84
59.82
59.8
-250.0
59.78
59.76
-300.0
59.74
59.72
-350.0
2:27:26
2:28:26
2:29:26
2:30:26
Hz
2:31:26
2:32:26
2:33:26
BA Bias Setting
2:34:26
2:35:26
2:36:26
2:37:26
2:38:26
Actual Primary Freq Response Beta
2:39:26
2:40:26
2:41:26
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
2:26:26
004421
Value A Data
Monday, October 12, 2009
A Value
Time
2:27:26
JOU
NonFPointA
A Value t(0) Time C Value
Net
Dynamic
Conforming
Pumped
Hz
Hz
Hz
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
Hz
MW
MW
MW
MW
60.039
60.042 2:27:26
59.836
60.042
3645.73
350.00
165.34
0.00
Value B
Transferred
Contingent
Not
Frequency
BA
BA
BA
Used
Response
Lost Generation
Bias
Load
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW
MW
MW/0.1 Hz
MW
0.00
-4.21
15.00
-103.00 7651.305
20 to 52 second Average Period Evaluation
JOU
NonBias
Net
Dynamic
Conforming 004422
Pumped
Setting
Actual
Schedules
Load
Hydro
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
MW
Hz
MW
MW
MW
MW
-43.39
59.889
3803.35
335.00
165.34
6.35
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Date
BA Performance
Not
Used
0.00
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Initial
Performance
Adjusted
P.U.
0.744
Initial
Performance
Unadjusted
P.U.
1.000
Sustained
Performance
BA
Bias
Setting
P.U.
MW/0.1 Hz
0.758
-103.00
BA
Load
MW
7632.00
Average
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
Bias
Bias While
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
004423
Setting Hz > +/-0.036 Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance Maximum
Minimum
EPFR
Hz
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
Bias Setting Bias Setting
MW
MW/0.1 Hz
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
MW/0.1 Hz MW/0.1 Hz
114.21
-103.00
1.399
1.293
1.582
1.571
1.849
0.856
0.808
0.829
0.633
0.689
-103.00
-103.00
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
11.09
0.00
2
3
4
5
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Not Used
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Steps
1
004424
Note: Columns D, E, F and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only rarely should
you have to use the "Manual" process.
6
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
B
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "NYISO".
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar to the slope of the NAI data.
When set appropriately, the "Target" trend on the "Sustained" graph will model what the Net Actua Interchange should have done during the event recovery period based on your Bias setting during the event.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
rksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
004425
Monday, October 12, 2009
60.08
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
B Value
59.88
350.00
59.86
59.84
59.82
59.8
335.00
355.0
350.0
345.0
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MyBA
340.0
Average Period
20 to 52 second
335.0
330.0
59.78
59.76
59.74
59.72
325.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
JOU Dynamic Schedules
004426
MyBA
NonConforming
60.08
Load
60.06
Load (-)
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
B Value
59.88
165.34
59.86
59.84
59.82
214.13
004427
300.0
250.0
200.0
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
150.0
Average Period
20 to 52 second
100.0
59.8
50.0
59.78
59.76
59.74
59.72
0.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Non- Conforming Load
MyBA
Pumped
Hydro
60.08
Load (-) Gen (+)
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
B Value
0.00
6.35
59.88
59.86
59.84
59.82
59.8
004428
18.0
16.0
14.0
12.0
10.0
Average Period
8.0
20 to 52 second
6.0
4.0
59.78
59.76
2.0
59.74
59.72
0.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Pumped Hydro
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
MyBA
Not
Used
60.08
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
59.88
B Value
004429
1.2
1.0
0.8
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
0.6
Average Period
20 to 52 second
59.86
59.84
59.82
0.4
59.8
0.2
59.78
59.76
59.74
59.72
0.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Pumped Hydro
Transferred
MyBA
Frequency
Response
60.08
60.06
Rec (-) Del (+)
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
B Value
59.88
-4.21
59.86
59.84
59.82
11.09
004430
12.0
10.0
8.0
6.0
Average Period
20 to 52 second
4.0
59.8
2.0
59.78
59.76
59.74
59.72
0.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Frequency Response
MW/0.1 Hz
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
Contingent
BA
Lost Generation
MyBA
60.08
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
59.88
59.86
59.84
59.82
A Value
15.00
B Value
0.00
004431
Load (-) Gen (+)
16.0
14.0
12.0
10.0
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
8.0
Average Period
20 to 52 second
6.0
4.0
59.8
59.78
59.76
2.0
59.74
59.72
0.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Lost Generation
BA
Load
MyBA
60.08
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
A Value
B Value
59.88
7651.3
59.86
59.84
59.82
7632.0
004432
7850.0
7800.0
7750.0
7700.0
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
Average Period
20 to 52 second
7650.0
7600.0
59.8
59.78
7550.0
59.76
59.74
59.72
7500.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Load
Expected Primary
Freq Response
Based on Bias Setting
MyBA
60.08
60.06
60.04
60.02
60
59.98
59.96
59.92
59.9
59.88
59.86
59.84
004433
200.0
150.0
100.0
MW
Frequency - Hz
59.94
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, October 12, 2009
50.0
0.0
59.82
59.8
59.78
-50.0
59.76
A Value
B Value
Average Period
59.74
-43.39
114.21
20 to 52 second
59.72
-100.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
Expected Primary Freq Response Based on Bias Setting
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Steps
1
004434
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6".
Only rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summar
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
004435
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Steps
1
004436
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6".
Only rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
004437
Time (T)
10/12/09 02:17:26
10/12/09 02:17:28
10/12/09 02:17:30
10/12/09 02:17:32
10/12/09 02:17:34
10/12/09 02:17:36
10/12/09 02:17:38
10/12/09 02:17:40
10/12/09 02:17:42
10/12/09 02:17:44
10/12/09 02:17:46
10/12/09 02:17:48
10/12/09 02:17:50
10/12/09 02:17:52
10/12/09 02:17:54
10/12/09 02:17:56
10/12/09 02:17:58
10/12/09 02:18:00
10/12/09 02:18:02
10/12/09 02:18:04
10/12/09 02:18:06
10/12/09 02:18:08
10/12/09 02:18:10
10/12/09 02:18:12
10/12/09 02:18:14
10/12/09 02:18:16
10/12/09 02:18:18
10/12/09 02:18:20
10/12/09 02:18:22
10/12/09 02:18:24
10/12/09 02:18:26
10/12/09 02:18:28
10/12/09 02:18:30
10/12/09 02:18:32
10/12/09 02:18:34
10/12/09 02:18:36
10/12/09 02:18:38
10/12/09 02:18:40
10/12/09 02:18:42
10/12/09 02:18:44
10/12/09 02:18:46
Hz
60.007
60.009
60.009
60.006
60.006
60.009
60.009
60.008
60.009
60.009
60.005
60.004
60.001
59.999
59.993
59.991
59.994
59.992
59.994
59.992
59.994
59.995
59.993
59.99
59.99
59.987
59.983
59.977
59.977
59.989
59.995
59.999
59.994
59.989
59.987
59.986
59.984
59.983
59.985
59.986
59.985
Net
Actual
Interchange
MW
3679.946
3679.44
3679.912
3679.517
3679.888
3679.608
3679.06
3679.261
3679.164
3679.025
3679.152
3678.572
3678.295
3678.249
3678.236
3677.83
3677.955
3677.772
3676.666
3677.093
3677.141
3676.401
3678.516
3679.872
3680.197
3678.743
3678.428
3677.921
3680.254
3682.07
3681.329
3678.656
3678.077
3677.78
3678.427
3678.473
3678.278
3677.822
3676.615
3677.397
3677.917
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
NonConforming
Pumped
Load
Hydro
Load (-)
Load (-) Gen (+)
MW
MW
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-331.852966
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-329.98822
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-255.444168
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-254.838303
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-257.146973
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-262.289368
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.647949
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-256.307251
0
-249.086395
0
Not
Used
81.5
82
82.5
83
83.5
84
84.5
85
85.5
86
86.5
87
87.5
88
88.5
89
89.5
90
90.5
91
91.5
92
92.5
93
93.5
94
94.5
95
95.5
96
96.5
97
97.5
98
98.5
99
99.5
100
100.5
101
101.5
Transferred
Contingent
Frequency
BA
BA
Response
Lost Generation
Bias
Rec (-) Del (+) Load (-) Gen (+)
Setting
MW/0.1 Hz
MW
MW/0.1 Hz
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
10
15
-103
BA
Load
MW
7553.79
7554.12
7554.45
7554.78
7555.11
7555.44
7555.77
7556.1
7556.43
7556.76
7557.09
7557.42
7557.75
7558.08
7558.41
7558.74
7559.07
7559.4
7559.73
7560.06
7560.39
7560.72
7561.05
7561.38
7561.71
7562.04
7562.37
7562.7
7563.03
7563.36
7563.69
7564.02
7564.35
7564.68
7565.01
7565.34
7565.67
7566
7566.33
7566.66
7566.99
Event
Recovery
Detection Target Freq:
Row
60.000
306
2:27:26
473
2:33:00
307
05:34
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lowest
Max Absolute Delta Hz Delta Hz
0.126
-0.126
t(0)
t(Recovery)
Delta
Event Length mm:ss
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.000
-0.003
0.000
0.003
0.000
-0.001
0.001
0.000
-0.004
-0.001
-0.003
-0.002
-0.006
-0.002
0.003
-0.002
0.002
-0.002
0.002
0.001
-0.002
-0.003
0.000
-0.003
-0.004
-0.006
0.000
0.012
0.006
0.004
-0.005
-0.005
-0.002
-0.001
-0.002
-0.001
0.002
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.033
1
Absolute
Delta Hz
0.002
0.000
0.003
0.000
0.003
0.000
0.001
0.001
0.000
0.004
0.001
0.003
0.002
0.006
0.002
0.003
0.002
0.002
0.002
0.002
0.001
0.002
0.003
0.000
0.003
0.004
0.006
0.000
0.012
0.006
0.004
0.005
0.005
0.002
0.001
0.002
0.001
0.002
0.001
0.001
004438
10/12/09 02:18:48
10/12/09 02:18:50
10/12/09 02:18:52
10/12/09 02:18:54
10/12/09 02:18:56
10/12/09 02:18:58
10/12/09 02:19:00
10/12/09 02:19:02
10/12/09 02:19:04
10/12/09 02:19:06
10/12/09 02:19:08
10/12/09 02:19:10
10/12/09 02:19:12
10/12/09 02:19:14
10/12/09 02:19:16
10/12/09 02:19:18
10/12/09 02:19:20
10/12/09 02:19:22
10/12/09 02:19:24
10/12/09 02:19:26
10/12/09 02:19:28
10/12/09 02:19:30
10/12/09 02:19:32
10/12/09 02:19:34
10/12/09 02:19:36
10/12/09 02:19:38
10/12/09 02:19:40
10/12/09 02:19:42
10/12/09 02:19:44
10/12/09 02:19:46
10/12/09 02:19:48
10/12/09 02:19:50
10/12/09 02:19:52
10/12/09 02:19:54
10/12/09 02:19:56
10/12/09 02:19:58
10/12/09 02:20:00
10/12/09 02:20:02
10/12/09 02:20:04
10/12/09 02:20:06
10/12/09 02:20:08
10/12/09 02:20:10
10/12/09 02:20:12
10/12/09 02:20:14
10/12/09 02:20:16
10/12/09 02:20:18
10/12/09 02:20:20
10/12/09 02:20:22
10/12/09 02:20:24
59.986
59.98
59.981
59.981
59.989
59.998
60.007
60.007
59.997
59.986
59.981
59.977
59.974
59.976
59.974
59.974
59.977
59.979
59.979
59.982
59.984
59.987
59.988
59.988
59.987
59.987
59.987
59.985
59.984
59.982
59.983
59.989
59.989
59.988
59.984
59.982
59.983
59.981
59.982
59.983
59.986
59.989
59.987
59.985
59.98
59.98
59.983
59.98
59.979
3677.95
3678.617
3678.963
3681.252
3680.737
3680.045
3678.161
3674.076
3676.222
3676.669
3677.497
3677.49
3675.186
3675.437
3680.451
3682.032
3683.829
3682.843
3681.108
3680.566
3678.229
3676.752
3675.759
3671.942
3671.166
3670.476
3670.129
3671.542
3672.048
3671.576
3672.104
3672.414
3671.882
3671.837
3671.336
3670.726
3670.372
3671.364
3671.401
3672.156
3672.181
3670.296
3668.071
3668.59
3669.908
3670.399
3670.263
3669.382
3670.102
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-249.086395
-249.086395
-249.086395
-249.086395
-253.742477
-253.742477
-253.742477
-253.742477
-253.742477
-257.421204
-257.421204
-257.421204
-257.421204
-257.421204
-261.73822
-261.73822
-261.73822
-261.73822
-261.73822
-271.875977
-271.875977
-271.875977
-271.875977
-271.875977
-262.073486
-262.073486
-262.073486
-262.073486
-262.073486
-260.36441
-260.36441
-260.36441
-260.36441
-260.36441
-352.644379
-352.644379
-352.644379
-352.644379
-352.644379
-354.89566
-354.89566
-354.89566
-354.89566
-354.89566
-340.46936
-340.46936
-340.46936
-340.46936
-340.46936
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
102
102.5
103
103.5
104
104.5
105
105.5
106
106.5
107
107.5
108
108.5
109
109.5
110
110.5
111
111.5
112
112.5
113
113.5
114
114.5
115
115.5
116
116.5
117
117.5
118
118.5
119
119.5
120
120.5
121
121.5
122
122.5
123
123.5
124
124.5
125
125.5
126
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7567.32
7567.65
7567.98
7568.31
7568.64
7568.97
7569.3
7569.63
7569.96
7570.29
7570.62
7570.95
7571.28
7571.61
7571.94
7572.27
7572.6
7572.93
7573.26
7573.59
7573.92
7574.25
7574.58
7574.91
7575.24
7575.57
7575.9
7576.23
7576.56
7576.89
7577.22
7577.55
7577.88
7578.21
7578.54
7578.87
7579.2
7579.53
7579.86
7580.19
7580.52
7580.85
7581.18
7581.51
7581.84
7582.17
7582.5
7582.83
7583.16
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
-0.006
0.001
0.000
0.008
0.009
0.009
0.000
-0.010
-0.011
-0.005
-0.004
-0.003
0.002
-0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.001
-0.002
0.001
0.006
0.000
-0.001
-0.004
-0.002
0.001
-0.002
0.001
0.001
0.003
0.003
-0.002
-0.002
-0.005
0.000
0.003
-0.003
-0.001
0.001
0.006
0.001
0.000
0.008
0.009
0.009
0.000
0.010
0.011
0.005
0.004
0.003
0.002
0.002
0.000
0.003
0.002
0.000
0.003
0.002
0.003
0.001
0.000
0.001
0.000
0.000
0.002
0.001
0.002
0.001
0.006
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.003
0.003
0.002
0.002
0.005
0.000
0.003
0.003
0.001
004439
10/12/09 02:20:26
10/12/09 02:20:28
10/12/09 02:20:30
10/12/09 02:20:32
10/12/09 02:20:34
10/12/09 02:20:36
10/12/09 02:20:38
10/12/09 02:20:40
10/12/09 02:20:42
10/12/09 02:20:44
10/12/09 02:20:46
10/12/09 02:20:48
10/12/09 02:20:50
10/12/09 02:20:52
10/12/09 02:20:54
10/12/09 02:20:56
10/12/09 02:20:58
10/12/09 02:21:00
10/12/09 02:21:02
10/12/09 02:21:04
10/12/09 02:21:06
10/12/09 02:21:08
10/12/09 02:21:10
10/12/09 02:21:12
10/12/09 02:21:14
10/12/09 02:21:16
10/12/09 02:21:18
10/12/09 02:21:20
10/12/09 02:21:22
10/12/09 02:21:24
10/12/09 02:21:26
10/12/09 02:21:28
10/12/09 02:21:30
10/12/09 02:21:32
10/12/09 02:21:34
10/12/09 02:21:36
10/12/09 02:21:38
10/12/09 02:21:40
10/12/09 02:21:42
10/12/09 02:21:44
10/12/09 02:21:46
10/12/09 02:21:48
10/12/09 02:21:50
10/12/09 02:21:52
10/12/09 02:21:54
10/12/09 02:21:56
10/12/09 02:21:58
10/12/09 02:22:00
10/12/09 02:22:02
59.979
59.981
59.981
59.98
59.98
59.981
59.98
59.98
59.977
59.979
59.981
59.979
59.976
59.977
59.972
59.971
59.973
59.973
59.973
59.974
59.971
59.975
59.977
59.977
59.975
59.976
59.98
59.979
59.981
59.982
59.982
59.982
59.982
59.981
59.982
59.984
59.985
59.987
59.989
59.993
59.996
59.998
59.998
60.004
60.007
60.01
60.013
60.014
60.013
3670.438
3671.403
3672.442
3672.372
3671.947
3670.938
3670.705
3670.137
3669.279
3672.391
3672.558
3674.052
3672.626
3671.8
3673.183
3673.874
3676.263
3676.623
3676.87
3676.543
3675.464
3675.752
3675.256
3674.87
3671.277
3671.593
3670.587
3669.963
3669.54
3669.497
3668.706
3667.677
3666.482
3666.599
3666.911
3666.442
3666.405
3667.456
3666.38
3665.262
3664.031
3663.825
3663.229
3662.055
3661.695
3662.076
3662.224
3662.959
3663.794
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-337.642914
-337.642914
-337.642914
-337.642914
-337.642914
-284.36084
-284.36084
-284.36084
-284.36084
-284.36084
-260.467987
-260.467987
-260.467987
-260.467987
-260.467987
-253.141541
-253.141541
-253.141541
-253.141541
-253.141541
-251.929871
-251.929871
-251.929871
-251.929871
-251.929871
-250.674194
-250.674194
-250.674194
-250.674194
-250.674194
-253.631866
-253.631866
-253.631866
-253.631866
-253.631866
-246.957306
-246.957306
-246.957306
-246.957306
-246.957306
-254.541779
-254.541779
-254.541779
-254.541779
-254.541779
-256.571594
-256.571594
-256.571594
-256.571594
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
126.5
127
127.5
128
128.5
129
129.5
130
130.5
131
131.5
132
132.5
133
133.5
134
134.5
135
135.5
136
136.5
137
137.5
138
138.5
139
139.5
140
140.5
141
141.5
142
142.5
143
143.5
144
144.5
145
145.5
146
146.5
147
147.5
148
148.5
149
149.5
150
150.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7583.49
7583.82
7584.15
7584.48
7584.81
7585.14
7585.47
7585.8
7586.13
7586.46
7586.79
7587.12
7587.45
7587.78
7588.11
7588.44
7588.77
7589.1
7589.43
7589.76
7590.09
7590.42
7590.75
7591.08
7591.41
7591.74
7592.07
7592.4
7592.73
7593.06
7593.39
7593.72
7594.05
7594.38
7594.71
7595.04
7595.37
7595.7
7596.03
7596.36
7596.69
7597.02
7597.35
7597.68
7598.01
7598.34
7598.67
7599
7599.33
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.002
0.000
-0.001
0.000
0.001
-0.001
0.000
-0.003
0.002
0.002
-0.002
-0.003
0.001
-0.005
-0.001
0.002
0.000
0.000
0.001
-0.003
0.004
0.002
0.000
-0.002
0.001
0.004
-0.001
0.002
0.001
0.000
0.000
0.000
-0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.003
0.002
0.002
0.002
0.003
0.001
0.005
0.001
0.002
0.000
0.000
0.001
0.003
0.004
0.002
0.000
0.002
0.001
0.004
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.001
0.002
0.002
0.004
0.003
0.002
0.000
0.006
0.003
0.003
0.003
0.001
0.001
004440
10/12/09 02:22:04
10/12/09 02:22:06
10/12/09 02:22:08
10/12/09 02:22:10
10/12/09 02:22:12
10/12/09 02:22:14
10/12/09 02:22:16
10/12/09 02:22:18
10/12/09 02:22:20
10/12/09 02:22:22
10/12/09 02:22:24
10/12/09 02:22:26
10/12/09 02:22:28
10/12/09 02:22:30
10/12/09 02:22:32
10/12/09 02:22:34
10/12/09 02:22:36
10/12/09 02:22:38
10/12/09 02:22:40
10/12/09 02:22:42
10/12/09 02:22:44
10/12/09 02:22:46
10/12/09 02:22:48
10/12/09 02:22:50
10/12/09 02:22:52
10/12/09 02:22:54
10/12/09 02:22:56
10/12/09 02:22:58
10/12/09 02:23:00
10/12/09 02:23:02
10/12/09 02:23:04
10/12/09 02:23:06
10/12/09 02:23:08
10/12/09 02:23:10
10/12/09 02:23:12
10/12/09 02:23:14
10/12/09 02:23:16
10/12/09 02:23:18
10/12/09 02:23:20
10/12/09 02:23:22
10/12/09 02:23:24
10/12/09 02:23:26
10/12/09 02:23:28
10/12/09 02:23:30
10/12/09 02:23:32
10/12/09 02:23:34
10/12/09 02:23:36
10/12/09 02:23:38
10/12/09 02:23:40
60.008
60.008
60.01
60.019
60.019
60.023
60.021
60.02
60.021
60.021
60.02
60.019
60.019
60.022
60.025
60.025
60.026
60.02
60.02
60.018
60.018
60.02
60.019
60.019
60.023
60.022
60.022
60.025
60.02
60.02
60.02
60.02
60.02
60.021
60.021
60.018
60.014
60.014
60.014
60.013
60.013
60.01
60.008
60.011
60.011
60.012
60.012
60.009
60.009
3664.139
3665.278
3664.159
3663.265
3663.184
3661.929
3661.512
3659.172
3658.661
3656.785
3657.571
3658.126
3657.71
3658.015
3660.228
3659.224
3658.698
3658.669
3658.155
3659.13
3659.778
3660.82
3662.531
3662.387
3662.079
3662.39
3662.678
3663.577
3663.539
3662.959
3662.552
3662.543
3663.601
3663.91
3663.69
3662.791
3663.396
3663.698
3664.315
3665.313
3665.798
3666.141
3666.726
3667.677
3667.545
3666.688
3666.449
3666.71
3667.696
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-256.571594
-258.37262
-258.37262
-258.37262
-258.37262
-258.37262
-263.047363
-263.047363
-263.047363
-263.047363
-263.047363
-260.984375
-260.984375
-260.984375
-260.984375
-260.984375
-261.318329
-261.318329
-261.318329
-261.318329
-261.318329
-262.1026
-262.1026
-262.1026
-262.1026
-262.1026
-262.71701
-262.71701
-262.71701
-262.71701
-262.71701
-260.016479
-260.016479
-260.016479
-260.016479
-260.016479
-263.87323
-263.87323
-263.87323
-263.87323
-263.87323
-264.5979
-264.5979
-264.5979
-264.5979
-264.5979
-262.415924
-262.415924
-262.415924
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
151
151.5
152
152.5
153
153.5
154
154.5
155
155.5
156
156.5
157
157.5
158
158.5
159
159.5
160
160.5
161
161.5
162
162.5
163
163.5
164
164.5
165
165.5
166
166.5
167
167.5
168
168.5
169
169.5
170
170.5
171
171.5
172
172.5
173
173.5
174
174.5
175
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7599.66
7599.99
7600.32
7600.65
7600.98
7601.31
7601.64
7601.97
7602.3
7602.63
7602.96
7603.29
7603.62
7603.95
7604.28
7604.61
7604.94
7605.27
7605.6
7605.93
7606.26
7606.59
7606.92
7607.25
7607.58
7607.91
7608.24
7608.57
7608.9
7609.23
7609.56
7609.89
7610.22
7610.55
7610.88
7611.21
7611.54
7611.87
7612.2
7612.53
7612.86
7613.19
7613.52
7613.85
7614.18
7614.51
7614.84
7615.17
7615.5
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.005
0.000
0.002
0.009
0.000
0.004
-0.002
-0.001
0.001
0.000
-0.001
-0.001
0.000
0.003
0.003
0.000
0.001
-0.006
0.000
-0.002
0.000
0.002
-0.001
0.000
0.004
-0.001
0.000
0.003
-0.005
0.000
0.000
0.000
0.000
0.001
0.000
-0.003
-0.004
0.000
0.000
-0.001
0.000
-0.003
-0.002
0.003
0.000
0.001
0.000
-0.003
0.000
0.005
0.000
0.002
0.009
0.000
0.004
0.002
0.001
0.001
0.000
0.001
0.001
0.000
0.003
0.003
0.000
0.001
0.006
0.000
0.002
0.000
0.002
0.001
0.000
0.004
0.001
0.000
0.003
0.005
0.000
0.000
0.000
0.000
0.001
0.000
0.003
0.004
0.000
0.000
0.001
0.000
0.003
0.002
0.003
0.000
0.001
0.000
0.003
0.000
004441
10/12/09 02:23:42
10/12/09 02:23:44
10/12/09 02:23:46
10/12/09 02:23:48
10/12/09 02:23:50
10/12/09 02:23:52
10/12/09 02:23:54
10/12/09 02:23:56
10/12/09 02:23:58
10/12/09 02:24:00
10/12/09 02:24:02
10/12/09 02:24:04
10/12/09 02:24:06
10/12/09 02:24:08
10/12/09 02:24:10
10/12/09 02:24:12
10/12/09 02:24:14
10/12/09 02:24:16
10/12/09 02:24:18
10/12/09 02:24:20
10/12/09 02:24:22
10/12/09 02:24:24
10/12/09 02:24:26
10/12/09 02:24:28
10/12/09 02:24:30
10/12/09 02:24:32
10/12/09 02:24:34
10/12/09 02:24:36
10/12/09 02:24:38
10/12/09 02:24:40
10/12/09 02:24:42
10/12/09 02:24:44
10/12/09 02:24:46
10/12/09 02:24:48
10/12/09 02:24:50
10/12/09 02:24:52
10/12/09 02:24:54
10/12/09 02:24:56
10/12/09 02:24:58
10/12/09 02:25:00
10/12/09 02:25:02
10/12/09 02:25:04
10/12/09 02:25:06
10/12/09 02:25:08
10/12/09 02:25:10
10/12/09 02:25:12
10/12/09 02:25:14
10/12/09 02:25:16
10/12/09 02:25:18
60.009
60.009
60.005
60.002
59.999
59.996
59.995
59.997
59.998
59.998
59.998
59.998
59.995
59.995
59.992
59.993
59.988
59.988
59.982
59.982
59.982
59.982
59.984
59.982
59.978
59.978
59.976
59.975
59.974
59.974
59.979
59.98
59.981
59.98
59.984
59.987
59.988
59.988
59.99
59.992
59.991
59.991
59.991
59.993
59.993
59.996
60.002
60.002
60.003
3667.398
3667.043
3666.624
3666.223
3665.88
3665.403
3665.802
3665.68
3665.352
3664.948
3665.065
3666.133
3666.64
3666.735
3667.084
3667.557
3667.337
3667.853
3668.116
3668.691
3669.399
3669.606
3671.228
3670.25
3670.265
3671.549
3673.243
3674.263
3675.824
3676.418
3676.306
3674.637
3675.329
3675.226
3674.768
3674.399
3673.514
3673.04
3672.442
3673.056
3671.68
3671.493
3669.53
3670.066
3670.028
3671.744
3671.578
3672.625
3672.674
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-262.415924
-262.415924
-259.685242
-259.685242
-259.685242
-259.685242
-259.685242
-255.911011
-255.911011
-255.911011
-255.911011
-255.911011
-258.148193
-258.148193
-258.148193
-258.148193
-258.148193
-258.873596
-258.873596
-258.873596
-258.873596
-258.873596
-249.33757
-249.33757
-249.33757
-249.33757
-249.33757
-258.278168
-258.278168
-258.278168
-258.278168
-258.278168
-258.406372
-258.406372
-258.406372
-258.406372
-258.406372
-260.538879
-260.538879
-260.538879
-260.538879
-260.538879
-257.88208
-257.88208
-257.88208
-257.88208
-257.88208
-258.588654
-258.588654
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
175.5
176
176.5
177
177.5
178
178.5
179
179.5
180
180.5
181
181.5
182
182.5
183
183.5
184
184.5
185
185.5
186
186.5
187
187.5
188
188.5
189
189.5
190
190.5
191
191.5
192
192.5
193
193.5
194
194.5
195
195.5
196
196.5
197
197.5
198
198.5
199
199.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7615.83
7616.16
7616.49
7616.82
7617.15
7617.48
7617.81
7618.14
7618.47
7618.8
7619.13
7619.46
7619.79
7620.12
7620.45
7620.78
7621.11
7621.44
7621.77
7622.1
7622.43
7622.76
7623.09
7623.42
7623.75
7624.08
7624.41
7624.74
7625.07
7625.4
7625.73
7626.06
7626.39
7626.72
7627.05
7627.38
7627.71
7628.04
7628.37
7628.7
7629.03
7629.36
7629.69
7630.02
7630.35
7630.68
7631.01
7631.34
7631.67
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
-0.004
-0.003
-0.003
-0.003
-0.001
0.002
0.001
0.000
0.000
0.000
-0.003
0.000
-0.003
0.001
-0.005
0.000
-0.006
0.000
0.000
0.000
0.002
-0.002
-0.004
0.000
-0.002
-0.001
-0.001
0.000
0.005
0.001
0.001
-0.001
0.004
0.003
0.001
0.000
0.002
0.002
-0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
0.000
0.000
0.004
0.003
0.003
0.003
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.000
0.003
0.001
0.005
0.000
0.006
0.000
0.000
0.000
0.002
0.002
0.004
0.000
0.002
0.001
0.001
0.000
0.005
0.001
0.001
0.001
0.004
0.003
0.001
0.000
0.002
0.002
0.001
0.000
0.000
0.002
0.000
0.003
0.006
0.000
0.001
004442
10/12/09 02:25:20
10/12/09 02:25:22
10/12/09 02:25:24
10/12/09 02:25:26
10/12/09 02:25:28
10/12/09 02:25:30
10/12/09 02:25:32
10/12/09 02:25:34
10/12/09 02:25:36
10/12/09 02:25:38
10/12/09 02:25:40
10/12/09 02:25:42
10/12/09 02:25:44
10/12/09 02:25:46
10/12/09 02:25:48
10/12/09 02:25:50
10/12/09 02:25:52
10/12/09 02:25:54
10/12/09 02:25:56
10/12/09 02:25:58
10/12/09 02:26:00
10/12/09 02:26:02
10/12/09 02:26:04
10/12/09 02:26:06
10/12/09 02:26:08
10/12/09 02:26:10
10/12/09 02:26:12
10/12/09 02:26:14
10/12/09 02:26:16
10/12/09 02:26:18
10/12/09 02:26:20
10/12/09 02:26:22
10/12/09 02:26:24
10/12/09 02:26:26
10/12/09 02:26:28
10/12/09 02:26:30
10/12/09 02:26:32
10/12/09 02:26:34
10/12/09 02:26:36
10/12/09 02:26:38
10/12/09 02:26:40
10/12/09 02:26:42
10/12/09 02:26:44
10/12/09 02:26:46
10/12/09 02:26:48
10/12/09 02:26:50
10/12/09 02:26:52
10/12/09 02:26:54
10/12/09 02:26:56
60.004
60.005
60.004
60.002
60.004
60.008
60.01
60.01
60.01
60.011
60.013
60.014
60.013
60.012
60.011
60.011
60.017
60.022
60.017
60.014
60.013
60.014
60.017
60.017
60.019
60.019
60.019
60.027
60.026
60.026
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
3673.819
3673.25
3673.182
3673.496
3672.418
3672.363
3672.217
3672.261
3673.182
3673.603
3673.553
3674.312
3674.537
3673.813
3673.204
3672.563
3673.068
3672.388
3672.52
3671.25
3671.288
3672.989
3672.982
3672.915
3671.952
3671.193
3671.627
3671.189
3668.611
3665.232
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.19
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-258.588654
-258.588654
-258.588654
-261.906158
-261.906158
-261.906158
-261.906158
-261.906158
-256.747803
-256.747803
-256.747803
-256.747803
-256.747803
-167.431976
-167.431976
-167.431976
-167.431976
-167.431976
-164.973404
-164.973404
-164.973404
-164.973404
-164.973404
-157.628082
-157.628082
-157.628082
-157.628082
-157.628082
-155.531708
-155.531708
-155.531708
-155.531708
-155.531708
-160.447235
-160.447235
-160.447235
-160.447235
-160.447235
-163.958603
-163.958603
-163.958603
-163.958603
-163.958603
-166.072449
-166.072449
-166.072449
-166.072449
-166.072449
-163.766586
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
200
200.5
201
201.5
202
202.5
203
203.5
204
204.5
205
205.5
206
206.5
207
207.5
208
208.5
209
209.5
210
210.5
211
211.5
212
212.5
213
213.5
214
214.5
215
215.5
216
216.5
217
217.5
218
218.5
219
219.5
220
220.5
221
221.5
222
222.5
223
223.5
224
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7632
7632.33
7632.66
7632.99
7633.32
7633.65
7633.98
7634.31
7634.64
7634.97
7635.3
7635.63
7635.96
7636.29
7636.62
7636.95
7637.28
7637.61
7637.94
7638.27
7638.6
7638.93
7639.26
7639.59
7639.92
7640.25
7640.58
7640.91
7641.24
7641.57
7641.9
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.2
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.001
-0.001
-0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
-0.001
-0.001
-0.001
0.000
0.006
0.005
-0.005
-0.003
-0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
-0.001
0.000
-0.004
-0.003
-0.002
0.002
0.001
-0.001
0.002
0.000
0.000
-0.002
-0.001
0.004
0.009
0.006
0.000
-0.001
0.001
0.009
0.002
0.001
0.001
0.001
0.002
0.002
0.004
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.006
0.005
0.005
0.003
0.001
0.001
0.003
0.000
0.002
0.000
0.000
0.008
0.001
0.000
0.004
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.000
0.002
0.001
0.004
0.009
0.006
0.000
0.001
0.001
0.009
0.002
004443
10/12/09 02:26:58
10/12/09 02:27:00
10/12/09 02:27:02
10/12/09 02:27:04
10/12/09 02:27:06
10/12/09 02:27:08
10/12/09 02:27:10
10/12/09 02:27:12
10/12/09 02:27:14
10/12/09 02:27:16
10/12/09 02:27:18
10/12/09 02:27:20
10/12/09 02:27:22
10/12/09 02:27:24
10/12/09 02:27:26
10/12/09 02:27:28
10/12/09 02:27:30
10/12/09 02:27:32
10/12/09 02:27:34
10/12/09 02:27:36
10/12/09 02:27:38
10/12/09 02:27:40
10/12/09 02:27:42
10/12/09 02:27:44
10/12/09 02:27:46
10/12/09 02:27:48
10/12/09 02:27:50
10/12/09 02:27:52
10/12/09 02:27:54
10/12/09 02:27:56
10/12/09 02:27:58
10/12/09 02:28:00
10/12/09 02:28:02
10/12/09 02:28:04
10/12/09 02:28:06
10/12/09 02:28:08
10/12/09 02:28:10
10/12/09 02:28:12
10/12/09 02:28:14
10/12/09 02:28:16
10/12/09 02:28:18
10/12/09 02:28:20
10/12/09 02:28:22
10/12/09 02:28:24
10/12/09 02:28:26
10/12/09 02:28:28
10/12/09 02:28:30
10/12/09 02:28:32
10/12/09 02:28:34
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3737.157
3761.25
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
3782.5
3784.962
3784.73
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-163.766586
-163.766586
-163.766586
-163.766586
-165.101685
-165.101685
-165.101685
-165.101685
-165.101685
-165.476395
-165.476395
-165.476395
-165.476395
-165.476395
-206.459106
-206.459106
-206.459106
-206.459106
-206.459106
-211.256042
-211.256042
-211.256042
-211.256042
-211.256042
-214.346695
-214.346695
-214.346695
-214.346695
-214.346695
-212.172699
-212.172699
-212.172699
-212.172699
-212.172699
-215.598175
-215.598175
-215.598175
-215.598175
-215.598175
-218.327255
-218.327255
-218.327255
-218.327255
-218.327255
-217.379425
-217.379425
-217.379425
-217.379425
-217.379425
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
16
16
16
16
16
16
16
224.5
225
225.5
226
226.5
227
227.5
228
228.5
229
229.5
230
230.5
231
231.5
232
232.5
233
233.5
234
234.5
235
235.5
236
236.5
237
237.5
238
238.5
239
239.5
240
240.5
241
241.5
242
242.5
243
243.5
244
244.5
245
245.5
246
246.5
247
247.5
248
248.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7648.17
7648.5
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.8
7652.13
7652.46
7652.79
7616
7626
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7632
7631
7625
7623
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.005
-0.002
0.000
0.000
-0.002
0.002
0.002
0.002
0.001
-0.005
0.000
0.000
-0.002
-0.061
-0.126
-0.016
0.033
0.023
-0.001
-0.011
-0.004
-0.001
0.008
0.004
-0.001
-0.001
0.002
0.001
0.002
0.005
-0.001
-0.001
0.001
0.000
-0.003
-0.001
-0.005
0.000
0.003
-0.001
0.001
0.000
0.002
-0.001
-0.007
-0.009
-0.016
-0.008
0.000
0.005
0.002
0.000
0.000
0.002
0.002
0.002
0.002
0.001
0.005
0.000
0.000
0.002
0.061
0.126
0.016
0.033
0.023
0.001
0.011
0.004
0.001
0.008
0.004
0.001
0.001
0.002
0.001
0.002
0.005
0.001
0.001
0.001
0.000
0.003
0.001
0.005
0.000
0.003
0.001
0.001
0.000
0.002
0.001
0.007
0.009
0.016
0.008
004444
10/12/09 02:28:36
10/12/09 02:28:38
10/12/09 02:28:40
10/12/09 02:28:42
10/12/09 02:28:44
10/12/09 02:28:46
10/12/09 02:28:48
10/12/09 02:28:50
10/12/09 02:28:52
10/12/09 02:28:54
10/12/09 02:28:56
10/12/09 02:28:58
10/12/09 02:29:00
10/12/09 02:29:02
10/12/09 02:29:04
10/12/09 02:29:06
10/12/09 02:29:08
10/12/09 02:29:10
10/12/09 02:29:12
10/12/09 02:29:14
10/12/09 02:29:16
10/12/09 02:29:18
10/12/09 02:29:20
10/12/09 02:29:22
10/12/09 02:29:24
10/12/09 02:29:26
10/12/09 02:29:28
10/12/09 02:29:30
10/12/09 02:29:32
10/12/09 02:29:34
10/12/09 02:29:36
10/12/09 02:29:38
10/12/09 02:29:40
10/12/09 02:29:42
10/12/09 02:29:44
10/12/09 02:29:46
10/12/09 02:29:48
10/12/09 02:29:50
10/12/09 02:29:52
10/12/09 02:29:54
10/12/09 02:29:56
10/12/09 02:29:58
10/12/09 02:30:00
10/12/09 02:30:02
10/12/09 02:30:04
10/12/09 02:30:06
10/12/09 02:30:08
10/12/09 02:30:10
10/12/09 02:30:12
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.01
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.67
3769.63
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
335
-214.830353
-214.830353
-214.830353
-214.830353
-214.830353
-227.655914
-227.655914
-227.655914
-227.655914
-227.655914
-225.018082
-225.018082
-225.018082
-225.018082
-225.018082
-228.365158
-228.365158
-228.365158
-228.365158
-228.365158
-234.075333
-234.075333
-234.075333
-234.075333
-234.075333
-228.798157
-228.798157
-228.798157
-228.798157
-228.798157
-229.466965
-229.466965
-229.466965
-229.466965
-229.466965
-228.980164
-228.980164
-228.980164
-228.980164
-228.980164
-219.975555
-219.975555
-219.975555
-219.975555
-219.975555
-229.089249
-229.089249
-229.089249
-229.089249
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
249
249.5
250
250.5
251
251.5
252
252.5
253
253.5
254
254.5
255
255.5
256
256.5
257
257.5
258
258.5
259
259.5
260
260.5
261
261.5
262
262.5
263
263.5
264
264.5
265
265.5
266
266.5
267
267.5
268
268.5
269
269.5
270
270.5
271
271.5
272
272.5
273
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7621
7623
7625
7627
7628
7628
7629
7630
7631
7635
7638
7639
7642
7644
7645
7647
7648
7649
7650
7651
7652
7653
7654
7655
7655
7656
7656
7657
7657
7658
7658
7659
7659
7659
7660
7660
7661
7661
7662
7662
7663
7663
7664
7664
7665
7666
7666
7667
7668
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.006
0.005
0.003
-0.001
0.002
-0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
-0.003
0.004
0.006
0.004
-0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
-0.001
-0.003
0.003
0.001
0.002
0.003
-0.001
0.003
-0.001
0.005
-0.005
0.001
0.003
-0.002
0.002
0.002
0.004
0.000
0.008
0.003
0.006
0.005
0.003
0.001
0.002
0.001
0.005
0.003
0.005
0.001
0.003
0.003
0.004
0.002
0.003
0.004
0.006
0.004
0.001
0.000
0.002
0.003
0.004
0.005
0.000
0.001
0.001
0.002
0.001
0.001
0.003
0.003
0.001
0.002
0.003
0.001
0.003
0.001
0.005
0.005
0.001
0.003
0.002
0.002
0.002
0.004
0.000
0.008
004445
10/12/09 02:30:14
10/12/09 02:30:16
10/12/09 02:30:18
10/12/09 02:30:20
10/12/09 02:30:22
10/12/09 02:30:24
10/12/09 02:30:26
10/12/09 02:30:28
10/12/09 02:30:30
10/12/09 02:30:32
10/12/09 02:30:34
10/12/09 02:30:36
10/12/09 02:30:38
10/12/09 02:30:40
10/12/09 02:30:42
10/12/09 02:30:44
10/12/09 02:30:46
10/12/09 02:30:48
10/12/09 02:30:50
10/12/09 02:30:52
10/12/09 02:30:54
10/12/09 02:30:56
10/12/09 02:30:58
10/12/09 02:31:00
10/12/09 02:31:02
10/12/09 02:31:04
10/12/09 02:31:06
10/12/09 02:31:08
10/12/09 02:31:10
10/12/09 02:31:12
10/12/09 02:31:14
10/12/09 02:31:16
10/12/09 02:31:18
10/12/09 02:31:20
10/12/09 02:31:22
10/12/09 02:31:24
10/12/09 02:31:26
10/12/09 02:31:28
10/12/09 02:31:30
10/12/09 02:31:32
10/12/09 02:31:34
10/12/09 02:31:36
10/12/09 02:31:38
10/12/09 02:31:40
10/12/09 02:31:42
10/12/09 02:31:44
10/12/09 02:31:46
10/12/09 02:31:48
10/12/09 02:31:50
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3715.753
3713.694
3713.484
3710.848
3710.81
3712.092
3714.623
3715.13
3716.168
3716.461
3716.98
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.13
3732.53
3733.327
3736.535
3736.907
335
335
335
335
335
335
335
335
335
335
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-229.089249
-229.663269
-229.663269
-229.663269
-229.663269
-229.663269
-229.233856
-229.233856
-229.233856
-229.233856
-229.233856
-231.409882
-231.409882
-231.409882
-231.409882
-231.409882
-218.622284
-218.622284
-218.622284
-218.622284
-218.622284
-213.535858
-213.535858
-213.535858
-213.535858
-213.535858
-225.651855
-225.651855
-225.651855
-225.651855
-225.651855
-212.573639
-212.573639
-212.573639
-212.573639
-212.573639
-219.897293
-219.897293
-219.897293
-219.897293
-219.897293
-231.1754
-231.1754
-231.1754
-231.1754
-231.1754
-226.634125
-226.634125
-226.634125
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
273.5
274
274.5
275
275.5
276
276.5
277
277.5
278
278.5
279
279.5
280
280.5
281
281.5
282
282.5
283
283.5
284
284.5
285
285.5
286
286.5
287
287.5
288
288.5
289
289.5
290
290.5
291
291.5
292
292.5
293
293.5
294
294.5
295
295.5
296
296.5
297
297.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7668
7669
7669
7670
7670
7671
7671
7672
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7673
7674
7675
7676
7677
7678
7679
7680
7681
7682
7684
7685
7687
7689
7690
7692
7692
7693
7693
7694
7694
7695
7695
7695
7696
7696
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
-0.002
-0.005
-0.001
0.001
0.003
0.003
-0.001
0.002
0.002
0.001
0.001
-0.002
0.001
0.000
0.000
0.003
-0.003
0.002
-0.002
0.001
0.000
-0.001
0.002
0.000
0.005
-0.002
-0.001
-0.002
0.002
-0.001
0.003
0.003
0.001
0.000
0.006
-0.002
0.000
0.002
0.002
0.004
-0.004
-0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.004
0.002
0.005
0.001
0.001
0.003
0.003
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.000
0.001
0.002
0.000
0.005
0.002
0.001
0.002
0.002
0.001
0.003
0.003
0.001
0.000
0.006
0.002
0.000
0.002
0.002
0.004
0.004
0.001
0.000
0.001
0.001
0.002
0.000
0.003
004446
10/12/09 02:31:52
10/12/09 02:31:54
10/12/09 02:31:56
10/12/09 02:31:58
10/12/09 02:32:00
10/12/09 02:32:02
10/12/09 02:32:04
10/12/09 02:32:06
10/12/09 02:32:08
10/12/09 02:32:10
10/12/09 02:32:12
10/12/09 02:32:14
10/12/09 02:32:16
10/12/09 02:32:18
10/12/09 02:32:20
10/12/09 02:32:22
10/12/09 02:32:24
10/12/09 02:32:26
10/12/09 02:32:28
10/12/09 02:32:30
10/12/09 02:32:32
10/12/09 02:32:34
10/12/09 02:32:36
10/12/09 02:32:38
10/12/09 02:32:40
10/12/09 02:32:42
10/12/09 02:32:44
10/12/09 02:32:46
10/12/09 02:32:48
10/12/09 02:32:50
10/12/09 02:32:52
10/12/09 02:32:54
10/12/09 02:32:56
10/12/09 02:32:58
10/12/09 02:33:00
10/12/09 02:33:02
10/12/09 02:33:04
10/12/09 02:33:06
10/12/09 02:33:08
10/12/09 02:33:10
10/12/09 02:33:12
10/12/09 02:33:14
10/12/09 02:33:16
10/12/09 02:33:18
10/12/09 02:33:20
10/12/09 02:33:22
10/12/09 02:33:24
10/12/09 02:33:26
10/12/09 02:33:28
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.3
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.42
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.85
3786.304
3787.259
3787.516
3787.955
3788.03
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-226.634125
-226.634125
-227.255066
-227.255066
-227.255066
-227.255066
-227.255066
-229.290222
-229.290222
-229.290222
-229.290222
-229.290222
-221.461365
-221.461365
-221.461365
-221.461365
-221.461365
-241.274368
-241.274368
-241.274368
-241.274368
-241.274368
-243.071854
-243.071854
-243.071854
-243.071854
-243.071854
-241.670212
-241.670212
-241.670212
-241.670212
-241.670212
-228.149307
-228.149307
-228.149307
-228.149307
-228.149307
-235.128983
-235.128983
-235.128983
-235.128983
-235.128983
-246.433136
-246.433136
-246.433136
-246.433136
-246.433136
-236.553543
-236.553543
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
298
298.5
299
299.5
300
300.5
301
301.5
302
302.5
303
303.5
304
304.5
305
305.5
306
306.5
307
307.5
308
308.5
309
309.5
310
310.5
311
311.5
312
312.5
313
313.5
314
314.5
315
315.5
316
316.5
317
317.5
318
318.5
319
319.5
320
320.5
321
321.5
322
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7697
7697
7697
7698
7698
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.3
7701.63
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.6
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.9
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.2
7711.53
7711.86
7712.19
7712.52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.000
-0.002
0.002
-0.002
0.002
-0.001
0.003
0.002
-0.001
-0.001
-0.001
0.001
-0.001
0.004
0.000
0.001
0.004
0.001
-0.002
0.000
0.004
0.002
-0.001
-0.001
-0.002
-0.003
-0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
-0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
-0.004
0.000
0.002
0.000
0.002
0.002
0.002
0.002
0.001
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.004
0.000
0.001
0.004
0.001
0.002
0.000
0.004
0.002
0.001
0.001
0.002
0.003
0.003
0.000
0.005
0.005
0.003
0.002
0.001
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.001
0.003
0.003
0.003
0.002
0.002
0.004
0.000
004447
10/12/09 02:33:30
10/12/09 02:33:32
10/12/09 02:33:34
10/12/09 02:33:36
10/12/09 02:33:38
10/12/09 02:33:40
10/12/09 02:33:42
10/12/09 02:33:44
10/12/09 02:33:46
10/12/09 02:33:48
10/12/09 02:33:50
10/12/09 02:33:52
10/12/09 02:33:54
10/12/09 02:33:56
10/12/09 02:33:58
10/12/09 02:34:00
10/12/09 02:34:02
10/12/09 02:34:04
10/12/09 02:34:06
10/12/09 02:34:08
10/12/09 02:34:10
10/12/09 02:34:12
10/12/09 02:34:14
10/12/09 02:34:16
10/12/09 02:34:18
10/12/09 02:34:20
10/12/09 02:34:22
10/12/09 02:34:24
10/12/09 02:34:26
10/12/09 02:34:28
10/12/09 02:34:30
10/12/09 02:34:32
10/12/09 02:34:34
10/12/09 02:34:36
10/12/09 02:34:38
10/12/09 02:34:40
10/12/09 02:34:42
10/12/09 02:34:44
10/12/09 02:34:46
10/12/09 02:34:48
10/12/09 02:34:50
10/12/09 02:34:52
10/12/09 02:34:54
10/12/09 02:34:56
10/12/09 02:34:58
10/12/09 02:35:00
10/12/09 02:35:02
10/12/09 02:35:04
10/12/09 02:35:06
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
3788.607
3789.216
3787.537
3785.842
3786.077
3787.93
3788.76
3786.875
3786.55
3787.358
3785.018
3785.614
3785.949
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.54
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-236.553543
-236.553543
-236.553543
-230.297562
-230.297562
-230.297562
-230.297562
-230.297562
-231.175537
-231.175537
-231.175537
-231.175537
-231.175537
-225.61763
-225.61763
-225.61763
-225.61763
-225.61763
-230.734421
-230.734421
-230.734421
-230.734421
-230.734421
-234.847107
-234.847107
-234.847107
-234.847107
-234.847107
-228.960922
-228.960922
-228.960922
-228.960922
-228.960922
-231.177917
-231.177917
-231.177917
-231.177917
-231.177917
-236.489288
-236.489288
-236.489288
-236.489288
-236.489288
-245.038925
-245.038925
-245.038925
-245.038925
-245.038925
-223.605682
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
322.5
323
323.5
324
324.5
325
325.5
326
326.5
327
327.5
328
328.5
329
329.5
330
330.5
331
331.5
332
332.5
333
333.5
334
334.5
335
335.5
336
336.5
337
337.5
338
338.5
339
339.5
340
340.5
341
341.5
342
342.5
343
343.5
344
344.5
345
345.5
346
346.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7712.85
7713.18
7713.51
7713.84
7714.17
7714.5
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
7717.14
7717.47
7717.8
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.1
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.4
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.7
7728.03
7728.36
7728.69
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.004
0.001
0.001
-0.004
-0.002
0.005
0.000
-0.003
-0.001
0.005
-0.001
-0.004
0.000
0.002
0.000
0.000
-0.001
0.000
0.002
0.000
-0.001
-0.003
-0.003
0.002
0.000
0.000
0.001
0.000
-0.003
-0.001
0.001
-0.002
-0.001
-0.001
0.000
-0.002
-0.003
0.000
0.002
0.000
0.001
-0.007
-0.004
-0.004
-0.003
-0.001
0.001
0.000
0.002
0.004
0.001
0.001
0.004
0.002
0.005
0.000
0.003
0.001
0.005
0.001
0.004
0.000
0.002
0.000
0.000
0.001
0.000
0.002
0.000
0.001
0.003
0.003
0.002
0.000
0.000
0.001
0.000
0.003
0.001
0.001
0.002
0.001
0.001
0.000
0.002
0.003
0.000
0.002
0.000
0.001
0.007
0.004
0.004
0.003
0.001
0.001
0.000
004448
10/12/09 02:35:08
10/12/09 02:35:10
10/12/09 02:35:12
10/12/09 02:35:14
10/12/09 02:35:16
10/12/09 02:35:18
10/12/09 02:35:20
10/12/09 02:35:22
10/12/09 02:35:24
10/12/09 02:35:26
10/12/09 02:35:28
10/12/09 02:35:30
10/12/09 02:35:32
10/12/09 02:35:34
10/12/09 02:35:36
10/12/09 02:35:38
10/12/09 02:35:40
10/12/09 02:35:42
10/12/09 02:35:44
10/12/09 02:35:46
10/12/09 02:35:48
10/12/09 02:35:50
10/12/09 02:35:52
10/12/09 02:35:54
10/12/09 02:35:56
10/12/09 02:35:58
10/12/09 02:36:00
10/12/09 02:36:02
10/12/09 02:36:04
10/12/09 02:36:06
10/12/09 02:36:08
10/12/09 02:36:10
10/12/09 02:36:12
10/12/09 02:36:14
10/12/09 02:36:16
10/12/09 02:36:18
10/12/09 02:36:20
10/12/09 02:36:22
10/12/09 02:36:24
10/12/09 02:36:26
10/12/09 02:36:28
10/12/09 02:36:30
10/12/09 02:36:32
10/12/09 02:36:34
10/12/09 02:36:36
10/12/09 02:36:38
10/12/09 02:36:40
10/12/09 02:36:42
10/12/09 02:36:44
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
3788.189
3788.497
3788.54
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3788.256
3788.41
3790.467
3790.665
3790.42
3789.674
3789.267
3789.148
3790.43
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.08
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.69
3784.831
3785.01
3784.32
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.605682
-223.605682
-223.605682
-223.605682
-231.119354
-231.119354
-231.119354
-231.119354
-231.119354
-237.20665
-237.20665
-237.20665
-237.20665
-237.20665
-240.516373
-240.516373
-240.516373
-240.516373
-240.516373
-237.566055
-237.566055
-237.566055
-237.566055
-237.566055
-231.581421
-231.581421
-231.581421
-231.581421
-231.581421
-235.850845
-235.850845
-235.850845
-235.850845
-235.850845
-233.559982
-233.559982
-233.559982
-233.559982
-233.559982
-219.009995
-219.009995
-219.009995
-219.009995
-219.009995
-205.338913
-205.338913
-205.338913
-205.338913
-205.338913
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
347
347.5
348
348.5
349
349.5
350
350.5
351
351.5
352
352.5
353
353.5
354
354.5
355
355.5
356
356.5
357
357.5
358
358.5
359
359.5
360
360.5
361
361.5
362
362.5
363
363.5
364
364.5
365
365.5
366
366.5
367
367.5
368
368.5
369
369.5
370
370.5
371
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731
7731.33
7731.66
7731.99
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.3
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.6
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.9
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.2
7744.53
7744.86
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.004
-0.002
-0.001
-0.001
0.001
-0.001
-0.002
-0.001
0.001
-0.003
-0.002
-0.001
0.000
0.003
0.003
-0.004
-0.002
-0.002
0.002
0.001
0.000
-0.002
-0.002
-0.004
0.001
0.001
0.002
0.005
0.003
-0.003
-0.003
-0.003
0.004
-0.001
-0.002
-0.004
-0.003
-0.001
0.001
0.003
0.001
-0.002
-0.003
-0.001
0.006
0.002
-0.005
0.000
0.002
0.004
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.003
0.002
0.001
0.000
0.003
0.003
0.004
0.002
0.002
0.002
0.001
0.000
0.002
0.002
0.004
0.001
0.001
0.002
0.005
0.003
0.003
0.003
0.003
0.004
0.001
0.002
0.004
0.003
0.001
0.001
0.003
0.001
0.002
0.003
0.001
0.006
0.002
0.005
0.000
0.002
004449
10/12/09 02:36:46
10/12/09 02:36:48
10/12/09 02:36:50
10/12/09 02:36:52
10/12/09 02:36:54
10/12/09 02:36:56
10/12/09 02:36:58
10/12/09 02:37:00
10/12/09 02:37:02
10/12/09 02:37:04
10/12/09 02:37:06
10/12/09 02:37:08
10/12/09 02:37:10
10/12/09 02:37:12
10/12/09 02:37:14
10/12/09 02:37:16
10/12/09 02:37:18
10/12/09 02:37:20
10/12/09 02:37:22
10/12/09 02:37:24
10/12/09 02:37:26
10/12/09 02:37:28
10/12/09 02:37:30
10/12/09 02:37:32
10/12/09 02:37:34
10/12/09 02:37:36
10/12/09 02:37:38
10/12/09 02:37:40
10/12/09 02:37:42
10/12/09 02:37:44
10/12/09 02:37:46
10/12/09 02:37:48
10/12/09 02:37:50
10/12/09 02:37:52
10/12/09 02:37:54
10/12/09 02:37:56
10/12/09 02:37:58
10/12/09 02:38:00
10/12/09 02:38:02
10/12/09 02:38:04
10/12/09 02:38:06
10/12/09 02:38:08
10/12/09 02:38:10
10/12/09 02:38:12
10/12/09 02:38:14
10/12/09 02:38:16
10/12/09 02:38:18
10/12/09 02:38:20
10/12/09 02:38:22
59.968
59.969
59.967
59.967
59.966
59.965
59.971
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
3782.809
3782.11
3779.352
3779.056
3778.633
3779.212
3779.335
3776.429
3775.647
3776.597
3776.559
3776.023
3773.17
3771.73
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.25
3758.041
3760.965
3762.022
3763.822
3763.1
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.57
3761.92
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-236.285355
-236.285355
-236.285355
-236.285355
-236.285355
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
371.5
372
372.5
373
373.5
374
374.5
375
375.5
376
376.5
377
377.5
378
378.5
379
379.5
380
380.5
381
381.5
382
382.5
383
383.5
384
384.5
385
385.5
386
386.5
387
387.5
388
388.5
389
389.5
390
390.5
391
391.5
392
392.5
393
393.5
394
394.5
395
395.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
7747.5
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.8
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.1
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.4
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.7
7761.03
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.001
-0.002
0.000
-0.001
-0.001
0.006
-0.004
-0.002
-0.003
0.002
0.006
-0.003
0.002
-0.001
-0.005
0.002
0.005
0.003
-0.005
-0.003
0.003
0.001
-0.002
-0.003
0.002
0.013
0.011
-0.007
-0.009
-0.007
-0.002
-0.003
0.000
-0.001
0.000
-0.001
0.003
-0.004
-0.003
-0.005
0.002
0.001
0.003
-0.001
0.005
0.002
-0.002
-0.002
0.001
0.001
0.002
0.000
0.001
0.001
0.006
0.004
0.002
0.003
0.002
0.006
0.003
0.002
0.001
0.005
0.002
0.005
0.003
0.005
0.003
0.003
0.001
0.002
0.003
0.002
0.013
0.011
0.007
0.009
0.007
0.002
0.003
0.000
0.001
0.000
0.001
0.003
0.004
0.003
0.005
0.002
0.001
0.003
0.001
0.005
0.002
0.002
0.002
004450
10/12/09 02:38:24
10/12/09 02:38:26
10/12/09 02:38:28
10/12/09 02:38:30
10/12/09 02:38:32
10/12/09 02:38:34
10/12/09 02:38:36
10/12/09 02:38:38
10/12/09 02:38:40
10/12/09 02:38:42
10/12/09 02:38:44
10/12/09 02:38:46
10/12/09 02:38:48
10/12/09 02:38:50
10/12/09 02:38:52
10/12/09 02:38:54
10/12/09 02:38:56
10/12/09 02:38:58
10/12/09 02:39:00
10/12/09 02:39:02
10/12/09 02:39:04
10/12/09 02:39:06
10/12/09 02:39:08
10/12/09 02:39:10
10/12/09 02:39:12
10/12/09 02:39:14
10/12/09 02:39:16
10/12/09 02:39:18
10/12/09 02:39:20
10/12/09 02:39:22
10/12/09 02:39:24
10/12/09 02:39:26
10/12/09 02:39:28
10/12/09 02:39:30
10/12/09 02:39:32
10/12/09 02:39:34
10/12/09 02:39:36
10/12/09 02:39:38
10/12/09 02:39:40
10/12/09 02:39:42
10/12/09 02:39:44
10/12/09 02:39:46
10/12/09 02:39:48
10/12/09 02:39:50
10/12/09 02:39:52
10/12/09 02:39:54
10/12/09 02:39:56
10/12/09 02:39:58
10/12/09 02:40:00
59.963
59.963
59.965
59.968
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
3759.627
3758.522
3752.429
3750.102
3753.83
3753.51
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.37
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.65
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
396
396.5
397
397.5
398
398.5
399
399.5
400
400.5
401
401.5
402
402.5
403
403.5
404
404.5
405
405.5
406
406.5
407
407.5
408
408.5
409
409.5
410
410.5
411
411.5
412
412.5
413
413.5
414
414.5
415
415.5
416
416.5
417
417.5
418
418.5
419
419.5
420
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7761.36
7761.69
7762.02
7762.35
7762.68
7763.01
7763.34
7763.67
7764
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.3
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.6
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.9
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
-0.002
-0.006
0.002
0.000
0.005
0.004
-0.001
-0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
-0.002
-0.001
-0.002
0.001
-0.002
0.000
0.002
0.001
-0.001
-0.002
-0.002
-0.004
-0.001
-0.002
0.005
0.001
0.001
-0.004
-0.003
0.002
0.003
-0.002
0.000
0.000
0.004
0.000
0.002
0.003
0.000
0.000
0.002
0.003
0.002
0.006
0.002
0.000
0.005
0.004
0.001
0.006
0.004
0.001
0.004
0.003
0.000
0.000
0.001
0.000
0.002
0.002
0.001
0.002
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.002
0.004
0.001
0.002
0.005
0.001
0.001
0.004
0.003
0.002
0.003
0.002
0.000
0.000
004451
10/12/09 02:40:02
10/12/09 02:40:04
10/12/09 02:40:06
10/12/09 02:40:08
10/12/09 02:40:10
10/12/09 02:40:12
10/12/09 02:40:14
10/12/09 02:40:16
10/12/09 02:40:18
10/12/09 02:40:20
10/12/09 02:40:22
10/12/09 02:40:24
10/12/09 02:40:26
10/12/09 02:40:28
10/12/09 02:40:30
10/12/09 02:40:32
10/12/09 02:40:34
10/12/09 02:40:36
10/12/09 02:40:38
10/12/09 02:40:40
10/12/09 02:40:42
10/12/09 02:40:44
10/12/09 02:40:46
10/12/09 02:40:48
10/12/09 02:40:50
10/12/09 02:40:52
10/12/09 02:40:54
10/12/09 02:40:56
10/12/09 02:40:58
10/12/09 02:41:00
10/12/09 02:41:02
10/12/09 02:41:04
10/12/09 02:41:06
10/12/09 02:41:08
10/12/09 02:41:10
10/12/09 02:41:12
10/12/09 02:41:14
10/12/09 02:41:16
10/12/09 02:41:18
10/12/09 02:41:20
10/12/09 02:41:22
10/12/09 02:41:24
10/12/09 02:41:26
10/12/09 02:41:28
10/12/09 02:41:30
10/12/09 02:41:32
10/12/09 02:41:34
10/12/09 02:41:36
10/12/09 02:41:38
59.977
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
60.014
60.019
3742.245
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.86
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.34
3750.7
3749.75
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.83
3737.583
3736.229
3734.897
3733.434
3733.115
3730.51
3729.18
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3725.012
3726.446
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
420.5
421
421.5
422
422.5
423
423.5
424
424.5
425
425.5
426
426.5
427
427.5
428
428.5
429
429.5
430
430.5
431
431.5
432
432.5
433
433.5
434
434.5
435
435.5
436
436.5
437
437.5
438
438.5
439
439.5
440
440.5
441
441.5
442
442.5
443
443.5
444
444.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7777.53
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.5
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.8
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.1
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.4
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
7793.04
7793.37
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.005
-0.004
-0.002
-0.003
0.001
0.003
0.000
0.001
0.001
0.002
-0.004
-0.003
-0.003
0.000
0.000
0.001
-0.004
-0.002
0.000
0.005
0.002
-0.001
-0.003
0.003
0.002
-0.001
-0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
-0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
0.005
0.005
0.004
0.002
0.003
0.001
0.003
0.000
0.001
0.001
0.002
0.004
0.003
0.003
0.000
0.000
0.001
0.004
0.002
0.000
0.005
0.002
0.001
0.003
0.003
0.002
0.001
0.003
0.001
0.003
0.008
0.003
0.000
0.000
0.002
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.005
0.002
0.001
0.002
0.006
0.002
0.005
004452
10/12/09 02:41:40
10/12/09 02:41:42
10/12/09 02:41:44
10/12/09 02:41:46
10/12/09 02:41:48
10/12/09 02:41:50
10/12/09 02:41:52
10/12/09 02:41:54
10/12/09 02:41:56
10/12/09 02:41:58
10/12/09 02:42:00
10/12/09 02:42:02
10/12/09 02:42:04
10/12/09 02:42:06
10/12/09 02:42:08
10/12/09 02:42:10
10/12/09 02:42:12
10/12/09 02:42:14
10/12/09 02:42:16
10/12/09 02:42:18
10/12/09 02:42:20
10/12/09 02:42:22
10/12/09 02:42:24
10/12/09 02:42:26
10/12/09 02:42:28
10/12/09 02:42:30
10/12/09 02:42:32
10/12/09 02:42:34
10/12/09 02:42:36
10/12/09 02:42:38
10/12/09 02:42:40
10/12/09 02:42:42
10/12/09 02:42:44
10/12/09 02:42:46
10/12/09 02:42:48
10/12/09 02:42:50
10/12/09 02:42:52
10/12/09 02:42:54
10/12/09 02:42:56
10/12/09 02:42:58
10/12/09 02:43:00
10/12/09 02:43:02
10/12/09 02:43:04
10/12/09 02:43:06
10/12/09 02:43:08
10/12/09 02:43:10
10/12/09 02:43:12
10/12/09 02:43:14
10/12/09 02:43:16
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
60.043
60.045
60.04
60.041
60.039
60.039
60.036
60.038
60.033
60.034
60.037
60.037
60.035
60.03
60.033
60.036
60.033
60.034
60.032
60.032
60.034
60.033
60.037
60.035
60.035
60.036
3726.016
3719.123
3716.375
3717.333
3717.56
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.1
3690.477
3696.865
3696.877
3696.182
3696.541
3696.968
3698.686
3699.631
3698.787
3699.712
3700.106
3699.968
3701.122
3701.865
3701.614
3701.998
3702.913
3703.909
3705.522
3704.967
3704.087
3702.771
3703.706
3704.905
3705.435
3704.36
3702.588
3702.204
3701.942
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
445
445.5
446
446.5
447
447.5
448
448.5
449
449.5
450
450.5
451
451.5
452
452.5
453
453.5
454
454.5
455
455.5
456
456.5
457
457.5
458
458.5
459
459.5
460
460.5
461
461.5
462
462.5
463
463.5
464
464.5
465
465.5
466
466.5
467
467.5
468
468.5
469
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7793.7
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.3
7800.63
7800.96
7801.29
7801.62
7801.95
7802.28
7802.61
7802.94
7803.27
7803.6
7803.93
7804.26
7804.59
7804.92
7805.25
7805.58
7805.91
7806.24
7806.57
7806.9
7807.23
7807.56
7807.89
7808.22
7808.55
7808.88
7809.21
7809.54
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.004
0.001
0.001
0.002
0.000
0.008
-0.001
0.001
0.000
-0.001
0.005
0.002
0.001
-0.001
0.003
0.002
-0.002
0.000
-0.003
0.000
0.001
-0.001
0.000
0.002
-0.005
0.001
-0.002
0.000
-0.003
0.002
-0.005
0.001
0.003
0.000
-0.002
-0.005
0.003
0.003
-0.003
0.001
-0.002
0.000
0.002
-0.001
0.004
-0.002
0.000
0.001
0.002
0.004
0.001
0.001
0.002
0.000
0.008
0.001
0.001
0.000
0.001
0.005
0.002
0.001
0.001
0.003
0.002
0.002
0.000
0.003
0.000
0.001
0.001
0.000
0.002
0.005
0.001
0.002
0.000
0.003
0.002
0.005
0.001
0.003
0.000
0.002
0.005
0.003
0.003
0.003
0.001
0.002
0.000
0.002
0.001
0.004
0.002
0.000
0.001
004453
10/12/09 02:43:18
10/12/09 02:43:20
10/12/09 02:43:22
10/12/09 02:43:24
10/12/09 02:43:26
10/12/09 02:43:28
10/12/09 02:43:30
10/12/09 02:43:32
10/12/09 02:43:34
10/12/09 02:43:36
10/12/09 02:43:38
10/12/09 02:43:40
10/12/09 02:43:42
10/12/09 02:43:44
10/12/09 02:43:46
10/12/09 02:43:48
10/12/09 02:43:50
10/12/09 02:43:52
10/12/09 02:43:54
10/12/09 02:43:56
10/12/09 02:43:58
10/12/09 02:44:00
10/12/09 02:44:02
10/12/09 02:44:04
10/12/09 02:44:06
10/12/09 02:44:08
10/12/09 02:44:10
10/12/09 02:44:12
10/12/09 02:44:14
10/12/09 02:44:16
10/12/09 02:44:18
10/12/09 02:44:20
10/12/09 02:44:22
10/12/09 02:44:24
10/12/09 02:44:26
10/12/09 02:44:28
10/12/09 02:44:30
10/12/09 02:44:32
10/12/09 02:44:34
10/12/09 02:44:36
10/12/09 02:44:38
10/12/09 02:44:40
10/12/09 02:44:42
10/12/09 02:44:44
10/12/09 02:44:46
10/12/09 02:44:48
10/12/09 02:44:50
10/12/09 02:44:52
10/12/09 02:44:54
60.039
60.037
60.039
60.036
60.034
60.038
60.037
60.037
60.037
60.038
60.04
60.043
60.045
60.045
60.042
60.043
60.04
60.044
60.046
60.042
60.034
60.039
60.039
60.036
60.037
60.034
60.033
60.032
60.031
60.033
60.027
60.031
60.032
60.031
60.031
60.033
60.039
60.039
60.038
60.037
60.035
60.037
60.04
60.042
60.035
60.036
60.04
60.045
60.045
3702.25
3703.318
3702.457
3702.525
3703.269
3703.844
3702.865
3702.518
3702.28
3692.427
3692.178
3700.276
3698.755
3697.729
3696.916
3697.368
3697.346
3698.429
3694.763
3693.584
3693.241
3696.798
3699.364
3701.791
3700.708
3700.753
3702.148
3705.213
3707.521
3707.287
3706.988
3707.34
3707.917
3707.384
3706.857
3707.615
3706.823
3703.746
3701.582
3700.847
3701.208
3702.212
3701.686
3700.397
3699.69
3700.366
3700.827
3700.662
3696.935
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
469.5
470
470.5
471
471.5
472
472.5
473
473.5
474
474.5
475
475.5
476
476.5
477
477.5
478
478.5
479
479.5
480
480.5
481
481.5
482
482.5
483
483.5
484
484.5
485
485.5
486
486.5
487
487.5
488
488.5
489
489.5
490
490.5
491
491.5
492
492.5
493
493.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7809.87
7810.2
7810.53
7810.86
7811.19
7811.52
7811.85
7812.18
7812.51
7812.84
7813.17
7813.5
7813.83
7814.16
7814.49
7814.82
7815.15
7815.48
7815.81
7816.14
7816.47
7816.8
7817.13
7817.46
7817.79
7818.12
7818.45
7818.78
7819.11
7819.44
7819.77
7820.1
7820.43
7820.76
7821.09
7821.42
7821.75
7822.08
7822.41
7822.74
7823.07
7823.4
7823.73
7824.06
7824.39
7824.72
7825.05
7825.38
7825.71
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.002
0.002
-0.003
-0.002
0.004
-0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
-0.003
0.001
-0.003
0.004
0.002
-0.004
-0.008
0.005
0.000
-0.003
0.001
-0.003
-0.001
-0.001
-0.001
0.002
-0.006
0.004
0.001
-0.001
0.000
0.002
0.006
0.000
-0.001
-0.001
-0.002
0.002
0.003
0.002
-0.007
0.001
0.004
0.005
0.000
0.003
0.002
0.002
0.003
0.002
0.004
0.001
0.000
0.000
0.001
0.002
0.003
0.002
0.000
0.003
0.001
0.003
0.004
0.002
0.004
0.008
0.005
0.000
0.003
0.001
0.003
0.001
0.001
0.001
0.002
0.006
0.004
0.001
0.001
0.000
0.002
0.006
0.000
0.001
0.001
0.002
0.002
0.003
0.002
0.007
0.001
0.004
0.005
0.000
004454
10/12/09 02:44:56
10/12/09 02:44:58
10/12/09 02:45:00
10/12/09 02:45:02
10/12/09 02:45:04
10/12/09 02:45:06
10/12/09 02:45:08
10/12/09 02:45:10
10/12/09 02:45:12
10/12/09 02:45:14
10/12/09 02:45:16
10/12/09 02:45:18
10/12/09 02:45:20
10/12/09 02:45:22
10/12/09 02:45:24
10/12/09 02:45:26
10/12/09 02:45:28
10/12/09 02:45:30
10/12/09 02:45:32
10/12/09 02:45:34
10/12/09 02:45:36
10/12/09 02:45:38
10/12/09 02:45:40
10/12/09 02:45:42
10/12/09 02:45:44
10/12/09 02:45:46
10/12/09 02:45:48
10/12/09 02:45:50
10/12/09 02:45:52
10/12/09 02:45:54
10/12/09 02:45:56
10/12/09 02:45:58
10/12/09 02:46:00
10/12/09 02:46:02
10/12/09 02:46:04
10/12/09 02:46:06
10/12/09 02:46:08
10/12/09 02:46:10
10/12/09 02:46:12
10/12/09 02:46:14
10/12/09 02:46:16
10/12/09 02:46:18
10/12/09 02:46:20
10/12/09 02:46:22
10/12/09 02:46:24
10/12/09 02:46:26
10/12/09 02:46:28
10/12/09 02:46:30
10/12/09 02:46:32
60.048
60.042
60.044
60.044
60.044
60.041
60.04
60.04
60.045
60.044
60.042
60.039
60.042
60.042
60.041
60.038
60.036
60.037
60.039
60.038
60.04
60.039
60.037
60.038
60.039
60.04
60.037
60.037
60.037
60.039
60.038
60.036
60.035
60.033
60.031
60.03
60.032
60.032
60.037
60.042
60.041
60.036
60.031
60.032
60.031
60.034
60.034
60.032
60.038
3695.688
3695.819
3693.824
3694.799
3696.897
3696.023
3697.502
3698.424
3699.427
3700.177
3699.806
3697.577
3697.681
3698.507
3698.359
3698.466
3699.077
3700.262
3701.592
3700.902
3700.143
3700.27
3701.139
3701.586
3700.264
3699.458
3699.721
3700.458
3699.505
3698.794
3699.216
3699.4
3700.661
3702.173
3702.968
3705.195
3704.952
3705.775
3705.621
3703.744
3701.981
3700.756
3700.747
3702.213
3705.059
3705.514
3704.449
3703.831
3703.62
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
494
494.5
495
495.5
496
496.5
497
497.5
498
498.5
499
499.5
500
500.5
501
501.5
502
502.5
503
503.5
504
504.5
505
505.5
506
506.5
507
507.5
508
508.5
509
509.5
510
510.5
511
511.5
512
512.5
513
513.5
514
514.5
515
515.5
516
516.5
517
517.5
518
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7826.04
7826.37
7826.7
7827.03
7827.36
7827.69
7828.02
7828.35
7828.68
7829.01
7829.34
7829.67
7830
7830.33
7830.66
7830.99
7831.32
7831.65
7831.98
7832.31
7832.64
7832.97
7833.3
7833.63
7833.96
7834.29
7834.62
7834.95
7835.28
7835.61
7835.94
7836.27
7836.6
7836.93
7837.26
7837.59
7837.92
7838.25
7838.58
7838.91
7839.24
7839.57
7839.9
7840.23
7840.56
7840.89
7841.22
7841.55
7841.88
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.006
0.002
0.000
0.000
-0.003
-0.001
0.000
0.005
-0.001
-0.002
-0.003
0.003
0.000
-0.001
-0.003
-0.002
0.001
0.002
-0.001
0.002
-0.001
-0.002
0.001
0.001
0.001
-0.003
0.000
0.000
0.002
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.002
0.000
0.005
0.005
-0.001
-0.005
-0.005
0.001
-0.001
0.003
0.000
-0.002
0.006
0.003
0.006
0.002
0.000
0.000
0.003
0.001
0.000
0.005
0.001
0.002
0.003
0.003
0.000
0.001
0.003
0.002
0.001
0.002
0.001
0.002
0.001
0.002
0.001
0.001
0.001
0.003
0.000
0.000
0.002
0.001
0.002
0.001
0.002
0.002
0.001
0.002
0.000
0.005
0.005
0.001
0.005
0.005
0.001
0.001
0.003
0.000
0.002
0.006
004455
10/12/09 02:46:34
10/12/09 02:46:36
10/12/09 02:46:38
10/12/09 02:46:40
10/12/09 02:46:42
10/12/09 02:46:44
10/12/09 02:46:46
10/12/09 02:46:48
10/12/09 02:46:50
10/12/09 02:46:52
10/12/09 02:46:54
10/12/09 02:46:56
10/12/09 02:46:58
10/12/09 02:47:00
10/12/09 02:47:02
10/12/09 02:47:04
10/12/09 02:47:06
10/12/09 02:47:08
10/12/09 02:47:10
10/12/09 02:47:12
10/12/09 02:47:14
10/12/09 02:47:16
10/12/09 02:47:18
10/12/09 02:47:20
10/12/09 02:47:22
10/12/09 02:47:24
10/12/09 02:47:26
10/12/09 02:47:28
10/12/09 02:47:30
10/12/09 02:47:32
10/12/09 02:47:34
10/12/09 02:47:36
10/12/09 02:47:38
10/12/09 02:47:40
10/12/09 02:47:42
10/12/09 02:47:44
10/12/09 02:47:46
10/12/09 02:47:48
10/12/09 02:47:50
10/12/09 02:47:52
10/12/09 02:47:54
10/12/09 02:47:56
10/12/09 02:47:58
10/12/09 02:48:00
10/12/09 02:48:02
10/12/09 02:48:04
10/12/09 02:48:06
10/12/09 02:48:08
10/12/09 02:48:10
60.043
60.044
60.042
60.045
60.04
60.04
60.043
60.043
60.041
60.04
60.038
60.043
60.044
60.042
60.036
60.043
60.041
60.042
60.043
60.043
60.036
60.039
60.039
60.037
60.034
60.035
60.035
60.035
60.036
60.03
60.03
60.03
60.031
60.031
60.032
60.031
60.032
60.032
60.032
60.033
60.037
60.04
60.039
60.042
60.036
60.039
60.041
60.04
60.035
3702.795
3701.432
3697.38
3696.25
3696.302
3693.518
3693.577
3695.197
3695.186
3693.786
3694.753
3694.926
3694.938
3694.159
3691.33
3692.686
3693.238
3693.39
3692.357
3690.951
3690.836
3692.042
3693.114
3694.117
3695.258
3695.581
3695.949
3695.491
3696.305
3696.486
3697.336
3699.171
3699.357
3699.251
3699.117
3699.105
3699.126
3698.954
3698.136
3698.277
3697.412
3695.94
3693.736
3693.224
3691.759
3691.919
3692.798
3691.582
3692.374
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
518.5
519
519.5
520
520.5
521
521.5
522
522.5
523
523.5
524
524.5
525
525.5
526
526.5
527
527.5
528
528.5
529
529.5
530
530.5
531
531.5
532
532.5
533
533.5
534
534.5
535
535.5
536
536.5
537
537.5
538
538.5
539
539.5
540
540.5
541
541.5
542
542.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7842.21
7842.54
7842.87
7843.2
7843.53
7843.86
7844.19
7844.52
7844.85
7845.18
7845.51
7845.84
7846.17
7846.5
7846.83
7847.16
7847.49
7847.82
7848.15
7848.48
7848.81
7849.14
7849.47
7849.8
7850.13
7850.46
7850.79
7851.12
7851.45
7851.78
7852.11
7852.44
7852.77
7853.1
7853.43
7853.76
7854.09
7854.42
7854.75
7855.08
7855.41
7855.74
7856.07
7856.4
7856.73
7857.06
7857.39
7857.72
7858.05
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.001
-0.002
0.003
-0.005
0.000
0.003
0.000
-0.002
-0.001
-0.002
0.005
0.001
-0.002
-0.006
0.007
-0.002
0.001
0.001
0.000
-0.007
0.003
0.000
-0.002
-0.003
0.001
0.000
0.000
0.001
-0.006
0.000
0.000
0.001
0.000
0.001
-0.001
0.001
0.000
0.000
0.001
0.004
0.003
-0.001
0.003
-0.006
0.003
0.002
-0.001
-0.005
0.005
0.001
0.002
0.003
0.005
0.000
0.003
0.000
0.002
0.001
0.002
0.005
0.001
0.002
0.006
0.007
0.002
0.001
0.001
0.000
0.007
0.003
0.000
0.002
0.003
0.001
0.000
0.000
0.001
0.006
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.004
0.003
0.001
0.003
0.006
0.003
0.002
0.001
0.005
004456
10/12/09 02:48:12
10/12/09 02:48:14
10/12/09 02:48:16
10/12/09 02:48:18
10/12/09 02:48:20
10/12/09 02:48:22
10/12/09 02:48:24
10/12/09 02:48:26
10/12/09 02:48:28
10/12/09 02:48:30
10/12/09 02:48:32
10/12/09 02:48:34
10/12/09 02:48:36
10/12/09 02:48:38
10/12/09 02:48:40
10/12/09 02:48:42
10/12/09 02:48:44
10/12/09 02:48:46
10/12/09 02:48:48
10/12/09 02:48:50
10/12/09 02:48:52
10/12/09 02:48:54
10/12/09 02:48:56
10/12/09 02:48:58
10/12/09 02:49:00
10/12/09 02:49:02
10/12/09 02:49:04
10/12/09 02:49:06
10/12/09 02:49:08
10/12/09 02:49:10
10/12/09 02:49:12
10/12/09 02:49:14
10/12/09 02:49:16
10/12/09 02:49:18
10/12/09 02:49:20
10/12/09 02:49:22
10/12/09 02:49:24
10/12/09 02:49:26
10/12/09 02:49:28
10/12/09 02:49:30
10/12/09 02:49:32
10/12/09 02:49:34
10/12/09 02:49:36
10/12/09 02:49:38
10/12/09 02:49:40
10/12/09 02:49:42
10/12/09 02:49:44
10/12/09 02:49:46
10/12/09 02:49:48
60.036
60.038
60.037
60.041
60.04
60.036
60.033
60.034
60.038
60.04
60.041
60.037
60.037
60.036
60.037
60.038
60.039
60.038
60.034
60.033
60.031
60.034
60.029
60.029
60.031
60.03
60.03
60.026
60.022
60.021
60.024
60.023
60.02
60.021
60.023
60.025
60.026
60.026
60.025
60.024
60.024
60.025
60.023
60.023
60.022
60.026
60.029
60.026
60.024
3693.302
3694.71
3694.331
3693.815
3693.617
3694.324
3694.27
3694.66
3693.748
3692.532
3691.445
3691.012
3691.799
3693.077
3693.727
3693.117
3692.641
3688.159
3689.02
3688.208
3690.092
3693.172
3693.321
3694.593
3695.225
3694.609
3693.412
3693.509
3696.026
3698.012
3699.062
3699.414
3698.935
3700.084
3700.544
3700.486
3698.596
3697.961
3699.914
3700.802
3701.301
3701.45
3701.349
3701.094
3701.702
3702.07
3701.965
3700.269
3700.241
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
543
543.5
544
544.5
545
545.5
546
546.5
547
547.5
548
548.5
549
549.5
550
550.5
551
551.5
552
552.5
553
553.5
554
554.5
555
555.5
556
556.5
557
557.5
558
558.5
559
559.5
560
560.5
561
561.5
562
562.5
563
563.5
564
564.5
565
565.5
566
566.5
567
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7858.38
7858.71
7859.04
7859.37
7859.7
7860.03
7860.36
7860.69
7861.02
7861.35
7861.68
7862.01
7862.34
7862.67
7863
7863.33
7863.66
7863.99
7864.32
7864.65
7864.98
7865.31
7865.64
7865.97
7866.3
7866.63
7866.96
7867.29
7867.62
7867.95
7868.28
7868.61
7868.94
7869.27
7869.6
7869.93
7870.26
7870.59
7870.92
7871.25
7871.58
7871.91
7872.24
7872.57
7872.9
7873.23
7873.56
7873.89
7874.22
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.002
-0.001
0.004
-0.001
-0.004
-0.003
0.001
0.004
0.002
0.001
-0.004
0.000
-0.001
0.001
0.001
0.001
-0.001
-0.004
-0.001
-0.002
0.003
-0.005
0.000
0.002
-0.001
0.000
-0.004
-0.004
-0.001
0.003
-0.001
-0.003
0.001
0.002
0.002
0.001
0.000
-0.001
-0.001
0.000
0.001
-0.002
0.000
-0.001
0.004
0.003
-0.003
-0.002
0.001
0.002
0.001
0.004
0.001
0.004
0.003
0.001
0.004
0.002
0.001
0.004
0.000
0.001
0.001
0.001
0.001
0.001
0.004
0.001
0.002
0.003
0.005
0.000
0.002
0.001
0.000
0.004
0.004
0.001
0.003
0.001
0.003
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.002
0.000
0.001
0.004
0.003
0.003
0.002
004457
10/12/09 02:49:50
10/12/09 02:49:52
10/12/09 02:49:54
10/12/09 02:49:56
10/12/09 02:49:58
10/12/09 02:50:00
10/12/09 02:50:02
10/12/09 02:50:04
10/12/09 02:50:06
10/12/09 02:50:08
10/12/09 02:50:10
10/12/09 02:50:12
10/12/09 02:50:14
10/12/09 02:50:16
10/12/09 02:50:18
10/12/09 02:50:20
10/12/09 02:50:22
10/12/09 02:50:24
10/12/09 02:50:26
10/12/09 02:50:28
10/12/09 02:50:30
10/12/09 02:50:32
10/12/09 02:50:34
10/12/09 02:50:36
10/12/09 02:50:38
10/12/09 02:50:40
10/12/09 02:50:42
10/12/09 02:50:44
10/12/09 02:50:46
10/12/09 02:50:48
10/12/09 02:50:50
10/12/09 02:50:52
10/12/09 02:50:54
10/12/09 02:50:56
10/12/09 02:50:58
10/12/09 02:51:00
10/12/09 02:51:02
10/12/09 02:51:04
10/12/09 02:51:06
10/12/09 02:51:08
10/12/09 02:51:10
10/12/09 02:51:12
10/12/09 02:51:14
10/12/09 02:51:16
10/12/09 02:51:18
10/12/09 02:51:20
10/12/09 02:51:22
10/12/09 02:51:24
10/12/09 02:51:26
60.021
60.025
60.025
60.025
60.023
60.026
60.024
60.022
60.023
60.026
60.025
60.02
60.02
60.019
60.015
60.016
60.017
60.015
60.015
60.017
60.017
60.012
60.01
60.008
60.002
59.999
59.999
60.002
60.003
60.004
60.001
59.996
59.993
59.992
59.989
59.987
59.985
59.985
59.986
59.984
59.981
59.98
59.977
59.975
59.976
59.972
59.974
59.977
59.975
3701.09
3701.268
3701.205
3700.587
3700.532
3700.177
3700.295
3700.277
3700.841
3700.863
3700.26
3700.052
3699.926
3700.965
3702.581
3703.516
3703.824
3703.672
3703.689
3703.003
3702.921
3703
3703.167
3703.918
3703.616
3703.775
3703.751
3701.534
3700.617
3700.88
3700.625
3701.389
3701.737
3700.671
3700.826
3700.977
3700.7
3699.854
3700.237
3700.342
3700.77
3700.789
3701.625
3703.166
3704.187
3704.785
3705.811
3706.958
3706.688
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
567.5
568
568.5
569
569.5
570
570.5
571
571.5
572
572.5
573
573.5
574
574.5
575
575.5
576
576.5
577
577.5
578
578.5
579
579.5
580
580.5
581
581.5
582
582.5
583
583.5
584
584.5
585
585.5
586
586.5
587
587.5
588
588.5
589
589.5
590
590.5
591
591.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7874.55
7874.88
7875.21
7875.54
7875.87
7876.2
7876.53
7876.86
7877.19
7877.52
7877.85
7878.18
7878.51
7878.84
7879.17
7879.5
7879.83
7880.16
7880.49
7880.82
7881.15
7881.48
7881.81
7882.14
7882.47
7882.8
7883.13
7883.46
7883.79
7884.12
7884.45
7884.78
7885.11
7885.44
7885.77
7886.1
7886.43
7886.76
7887.09
7887.42
7887.75
7888.08
7888.41
7888.74
7889.07
7889.4
7889.73
7890.06
7890.39
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
0.004
0.000
0.000
-0.002
0.003
-0.002
-0.002
0.001
0.003
-0.001
-0.005
0.000
-0.001
-0.004
0.001
0.001
-0.002
0.000
0.002
0.000
-0.005
-0.002
-0.002
-0.006
-0.003
0.000
0.003
0.001
0.001
-0.003
-0.005
-0.003
-0.001
-0.003
-0.002
-0.002
0.000
0.001
-0.002
-0.003
-0.001
-0.003
-0.002
0.001
-0.004
0.002
0.003
-0.002
0.003
0.004
0.000
0.000
0.002
0.003
0.002
0.002
0.001
0.003
0.001
0.005
0.000
0.001
0.004
0.001
0.001
0.002
0.000
0.002
0.000
0.005
0.002
0.002
0.006
0.003
0.000
0.003
0.001
0.001
0.003
0.005
0.003
0.001
0.003
0.002
0.002
0.000
0.001
0.002
0.003
0.001
0.003
0.002
0.001
0.004
0.002
0.003
0.002
004458
10/12/09 02:51:28
10/12/09 02:51:30
10/12/09 02:51:32
10/12/09 02:51:34
10/12/09 02:51:36
10/12/09 02:51:38
10/12/09 02:51:40
10/12/09 02:51:42
10/12/09 02:51:44
10/12/09 02:51:46
10/12/09 02:51:48
10/12/09 02:51:50
10/12/09 02:51:52
10/12/09 02:51:54
10/12/09 02:51:56
10/12/09 02:51:58
10/12/09 02:52:00
10/12/09 02:52:02
10/12/09 02:52:04
10/12/09 02:52:06
10/12/09 02:52:08
10/12/09 02:52:10
10/12/09 02:52:12
10/12/09 02:52:14
10/12/09 02:52:16
10/12/09 02:52:18
10/12/09 02:52:20
10/12/09 02:52:22
10/12/09 02:52:24
10/12/09 02:52:26
10/12/09 02:52:28
10/12/09 02:52:30
10/12/09 02:52:32
10/12/09 02:52:34
10/12/09 02:52:36
10/12/09 02:52:38
10/12/09 02:52:40
10/12/09 02:52:42
10/12/09 02:52:44
10/12/09 02:52:46
10/12/09 02:52:48
10/12/09 02:52:50
10/12/09 02:52:52
10/12/09 02:52:54
10/12/09 02:52:56
10/12/09 02:52:58
10/12/09 02:53:00
10/12/09 02:53:02
10/12/09 02:53:04
59.973
59.971
59.971
59.976
59.979
59.98
59.979
59.982
59.982
59.983
59.981
59.979
59.978
59.976
59.978
59.977
59.976
59.978
59.975
59.971
59.97
59.97
59.971
59.99
59.998
59.999
59.999
59.998
59.999
60.003
60.005
60.005
60.01
60.013
60.02
60.022
60.024
60.025
60.025
60.024
60.023
60.029
60.029
60.029
60.028
60.028
60.031
60.032
60.033
3706.543
3706.257
3707.027
3710.118
3710.531
3708.701
3708.018
3706.942
3706.343
3706.125
3706.311
3706.119
3706.19
3707.721
3709.409
3708.971
3708.531
3708.071
3707.24
3709.213
3709.961
3711.75
3711.98
3710.695
3707.867
3704.912
3705.639
3703.787
3703.191
3702.071
3699.51
3698.658
3698.137
3697.882
3698.668
3698.604
3697.868
3694.672
3693.912
3693.418
3688.301
3688.021
3689.143
3688.237
3687.878
3687.026
3686.683
3685.276
3685.576
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
592
592.5
593
593.5
594
594.5
595
595.5
596
596.5
597
597.5
598
598.5
599
599.5
600
600.5
601
601.5
602
602.5
603
603.5
604
604.5
605
605.5
606
606.5
607
607.5
608
608.5
609
609.5
610
610.5
611
611.5
612
612.5
613
613.5
614
614.5
615
615.5
616
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7890.72
7891.05
7891.38
7891.71
7892.04
7892.37
7892.7
7893.03
7893.36
7893.69
7894.02
7894.35
7894.68
7895.01
7895.34
7895.67
7896
7896.33
7896.66
7896.99
7897.32
7897.65
7897.98
7898.31
7898.64
7898.97
7899.3
7899.63
7899.96
7900.29
7900.62
7900.95
7901.28
7901.61
7901.94
7902.27
7902.6
7902.93
7903.26
7903.59
7903.92
7904.25
7904.58
7904.91
7905.24
7905.57
7905.9
7906.23
7906.56
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
0.000
0.005
0.003
0.001
-0.001
0.003
0.000
0.001
-0.002
-0.002
-0.001
-0.002
0.002
-0.001
-0.001
0.002
-0.003
-0.004
-0.001
0.000
0.001
0.019
0.008
0.001
0.000
-0.001
0.001
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
-0.001
-0.001
0.006
0.000
0.000
-0.001
0.000
0.003
0.001
0.001
0.002
0.002
0.000
0.005
0.003
0.001
0.001
0.003
0.000
0.001
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.002
0.003
0.004
0.001
0.000
0.001
0.019
0.008
0.001
0.000
0.001
0.001
0.004
0.002
0.000
0.005
0.003
0.007
0.002
0.002
0.001
0.000
0.001
0.001
0.006
0.000
0.000
0.001
0.000
0.003
0.001
0.001
004459
10/12/09 02:53:06
10/12/09 02:53:08
10/12/09 02:53:10
10/12/09 02:53:12
10/12/09 02:53:14
10/12/09 02:53:16
10/12/09 02:53:18
10/12/09 02:53:20
10/12/09 02:53:22
10/12/09 02:53:24
10/12/09 02:53:26
10/12/09 02:53:28
10/12/09 02:53:30
10/12/09 02:53:32
10/12/09 02:53:34
10/12/09 02:53:36
10/12/09 02:53:38
10/12/09 02:53:40
10/12/09 02:53:42
10/12/09 02:53:44
10/12/09 02:53:46
10/12/09 02:53:48
10/12/09 02:53:50
10/12/09 02:53:52
10/12/09 02:53:54
10/12/09 02:53:56
10/12/09 02:53:58
10/12/09 02:54:00
10/12/09 02:54:02
10/12/09 02:54:04
10/12/09 02:54:06
10/12/09 02:54:08
10/12/09 02:54:10
10/12/09 02:54:12
10/12/09 02:54:14
10/12/09 02:54:16
10/12/09 02:54:18
10/12/09 02:54:20
10/12/09 02:54:22
10/12/09 02:54:24
10/12/09 02:54:26
10/12/09 02:54:28
10/12/09 02:54:30
10/12/09 02:54:32
10/12/09 02:54:34
10/12/09 02:54:36
10/12/09 02:54:38
10/12/09 02:54:40
10/12/09 02:54:42
60.031
60.03
60.022
60.021
60.019
60.017
60.017
60.017
60.016
60.015
60.015
60.012
60.009
60.008
60.008
60.005
60.005
60.003
59.999
59.997
59.999
60
59.998
59.995
59.994
59.992
59.993
59.988
59.985
59.986
59.988
59.988
59.985
59.983
59.983
59.985
59.986
59.987
59.99
59.986
59.985
59.984
59.983
59.982
59.982
59.98
59.978
59.977
59.975
3685.985
3686.418
3687.159
3687.873
3688.997
3690.426
3690.776
3692.715
3692.578
3692.462
3693.173
3693.249
3693.743
3695.124
3694.681
3694.741
3694.199
3693.75
3693.624
3692.806
3691.15
3691.407
3691.077
3690.588
3689.797
3688.483
3689.445
3689.553
3689.525
3689.736
3688.853
3688.24
3687.494
3687.475
3686.707
3685.66
3684.51
3684.333
3683.911
3683.735
3684.208
3683.811
3683.473
3684.258
3684.884
3685.092
3685.654
3685.087
3685.491
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
616.5
617
617.5
618
618.5
619
619.5
620
620.5
621
621.5
622
622.5
623
623.5
624
624.5
625
625.5
626
626.5
627
627.5
628
628.5
629
629.5
630
630.5
631
631.5
632
632.5
633
633.5
634
634.5
635
635.5
636
636.5
637
637.5
638
638.5
639
639.5
640
640.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7906.89
7907.22
7907.55
7907.88
7908.21
7908.54
7908.87
7909.2
7909.53
7909.86
7910.19
7910.52
7910.85
7911.18
7911.51
7911.84
7912.17
7912.5
7912.83
7913.16
7913.49
7913.82
7914.15
7914.48
7914.81
7915.14
7915.47
7915.8
7916.13
7916.46
7916.79
7917.12
7917.45
7917.78
7918.11
7918.44
7918.77
7919.1
7919.43
7919.76
7920.09
7920.42
7920.75
7921.08
7921.41
7921.74
7922.07
7922.4
7922.73
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.001
-0.008
-0.001
-0.002
-0.002
0.000
0.000
-0.001
-0.001
0.000
-0.003
-0.003
-0.001
0.000
-0.003
0.000
-0.002
-0.004
-0.002
0.002
0.001
-0.002
-0.003
-0.001
-0.002
0.001
-0.005
-0.003
0.001
0.002
0.000
-0.003
-0.002
0.000
0.002
0.001
0.001
0.003
-0.004
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
-0.001
-0.002
0.002
0.001
0.008
0.001
0.002
0.002
0.000
0.000
0.001
0.001
0.000
0.003
0.003
0.001
0.000
0.003
0.000
0.002
0.004
0.002
0.002
0.001
0.002
0.003
0.001
0.002
0.001
0.005
0.003
0.001
0.002
0.000
0.003
0.002
0.000
0.002
0.001
0.001
0.003
0.004
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.002
004460
10/12/09 02:54:44
10/12/09 02:54:46
10/12/09 02:54:48
10/12/09 02:54:50
10/12/09 02:54:52
10/12/09 02:54:54
10/12/09 02:54:56
10/12/09 02:54:58
10/12/09 02:55:00
10/12/09 02:55:02
10/12/09 02:55:04
10/12/09 02:55:06
10/12/09 02:55:08
10/12/09 02:55:10
10/12/09 02:55:12
10/12/09 02:55:14
10/12/09 02:55:16
10/12/09 02:55:18
10/12/09 02:55:20
10/12/09 02:55:22
10/12/09 02:55:24
10/12/09 02:55:26
10/12/09 02:55:28
10/12/09 02:55:30
10/12/09 02:55:32
10/12/09 02:55:34
10/12/09 02:55:36
10/12/09 02:55:38
10/12/09 02:55:40
10/12/09 02:55:42
10/12/09 02:55:44
10/12/09 02:55:46
10/12/09 02:55:48
10/12/09 02:55:50
10/12/09 02:55:52
10/12/09 02:55:54
10/12/09 02:55:56
10/12/09 02:55:58
10/12/09 02:56:00
10/12/09 02:56:02
10/12/09 02:56:04
10/12/09 02:56:06
10/12/09 02:56:08
10/12/09 02:56:10
10/12/09 02:56:12
10/12/09 02:56:14
10/12/09 02:56:16
10/12/09 02:56:18
10/12/09 02:56:20
59.973
59.975
59.976
59.976
59.979
59.982
59.979
59.979
59.977
59.977
59.978
59.978
59.978
59.979
59.983
59.981
59.98
59.978
59.979
59.978
59.979
59.983
59.987
59.99
59.992
59.993
59.99
59.988
59.988
59.99
59.993
59.994
59.993
59.994
59.994
59.993
59.989
59.984
59.986
59.985
59.988
59.987
59.986
59.987
59.985
59.982
59.981
59.982
59.987
3685.196
3687.412
3688.417
3688.599
3687.848
3686.678
3685.782
3684.89
3685.143
3684.549
3684.093
3684.555
3682.814
3682.318
3682.366
3682.647
3682.855
3683.557
3684.052
3684.318
3686.049
3686.629
3685.286
3683.415
3682.416
3681.403
3679.012
3679.436
3671.761
3670.717
3670.159
3679
3680.176
3681.799
3682.7
3684.116
3685.03
3684.878
3684.165
3684.478
3685.584
3685.148
3684.587
3684.976
3683.674
3684.872
3684.245
3684.711
3685.589
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
641
641.5
642
642.5
643
643.5
644
644.5
645
645.5
646
646.5
647
647.5
648
648.5
649
649.5
650
650.5
651
651.5
652
652.5
653
653.5
654
654.5
655
655.5
656
656.5
657
657.5
658
658.5
659
659.5
660
660.5
661
661.5
662
662.5
663
663.5
664
664.5
665
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7923.06
7923.39
7923.72
7924.05
7924.38
7924.71
7925.04
7925.37
7925.7
7926.03
7926.36
7926.69
7927.02
7927.35
7927.68
7928.01
7928.34
7928.67
7929
7929.33
7929.66
7929.99
7930.32
7930.65
7930.98
7931.31
7931.64
7931.97
7932.3
7932.63
7932.96
7933.29
7933.62
7933.95
7934.28
7934.61
7934.94
7935.27
7935.6
7935.93
7936.26
7936.59
7936.92
7937.25
7937.58
7937.91
7938.24
7938.57
7938.9
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
0.002
0.001
0.000
0.003
0.003
-0.003
0.000
-0.002
0.000
0.001
0.000
0.000
0.001
0.004
-0.002
-0.001
-0.002
0.001
-0.001
0.001
0.004
0.004
0.003
0.002
0.001
-0.003
-0.002
0.000
0.002
0.003
0.001
-0.001
0.001
0.000
-0.001
-0.004
-0.005
0.002
-0.001
0.003
-0.001
-0.001
0.001
-0.002
-0.003
-0.001
0.001
0.005
0.002
0.002
0.001
0.000
0.003
0.003
0.003
0.000
0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.002
0.001
0.002
0.001
0.001
0.001
0.004
0.004
0.003
0.002
0.001
0.003
0.002
0.000
0.002
0.003
0.001
0.001
0.001
0.000
0.001
0.004
0.005
0.002
0.001
0.003
0.001
0.001
0.001
0.002
0.003
0.001
0.001
0.005
004461
10/12/09 02:56:22
10/12/09 02:56:24
10/12/09 02:56:26
10/12/09 02:56:28
10/12/09 02:56:30
10/12/09 02:56:32
10/12/09 02:56:34
10/12/09 02:56:36
10/12/09 02:56:38
10/12/09 02:56:40
10/12/09 02:56:42
10/12/09 02:56:44
10/12/09 02:56:46
10/12/09 02:56:48
10/12/09 02:56:50
10/12/09 02:56:52
10/12/09 02:56:54
10/12/09 02:56:56
10/12/09 02:56:58
10/12/09 02:57:00
10/12/09 02:57:02
10/12/09 02:57:04
10/12/09 02:57:06
10/12/09 02:57:08
10/12/09 02:57:10
10/12/09 02:57:12
10/12/09 02:57:14
10/12/09 02:57:16
10/12/09 02:57:18
10/12/09 02:57:20
10/12/09 02:57:22
10/12/09 02:57:24
10/12/09 02:57:26
10/12/09 02:57:28
10/12/09 02:57:30
10/12/09 02:57:32
10/12/09 02:57:34
10/12/09 02:57:36
10/12/09 02:57:38
10/12/09 02:57:40
10/12/09 02:57:42
10/12/09 02:57:44
10/12/09 02:57:46
10/12/09 02:57:48
10/12/09 02:57:50
10/12/09 02:57:52
10/12/09 02:57:54
10/12/09 02:57:56
10/12/09 02:57:58
59.992
59.997
60
60.003
60.003
60.003
60.002
60.003
60.002
60.003
60.004
60.005
60.006
60.009
60.012
60.017
60.021
60.022
60.021
60.02
60.018
60.021
60.02
60.02
60.018
60.018
60.019
60.019
60.018
60.017
60.016
60.016
60.016
60.015
60.014
60.014
60.013
60.013
60.015
60.017
60.016
60.019
60.021
60.021
60.02
60.022
60.024
60.026
60.025
3683.736
3682.579
3682.234
3682.138
3682.224
3681.689
3681.458
3681.65
3681.013
3680.167
3679.943
3679.429
3679.669
3678.981
3678.267
3676.796
3676.81
3674.798
3673.906
3671.145
3670.51
3673.648
3673.684
3675.865
3676.676
3676.404
3676.437
3677.185
3677.659
3678.828
3679.289
3678.915
3679.276
3678.599
3678.367
3678.25
3678.589
3677.251
3675.698
3674.669
3674.87
3674.402
3674.546
3672.969
3671.914
3671.982
3670.946
3670.821
3671.06
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
665.5
666
666.5
667
667.5
668
668.5
669
669.5
670
670.5
671
671.5
672
672.5
673
673.5
674
674.5
675
675.5
676
676.5
677
677.5
678
678.5
679
679.5
680
680.5
681
681.5
682
682.5
683
683.5
684
684.5
685
685.5
686
686.5
687
687.5
688
688.5
689
689.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7939.23
7939.56
7939.89
7940.22
7940.55
7940.88
7941.21
7941.54
7941.87
7942.2
7942.53
7942.86
7943.19
7943.52
7943.85
7944.18
7944.51
7944.84
7945.17
7945.5
7945.83
7946.16
7946.49
7946.82
7947.15
7947.48
7947.81
7948.14
7948.47
7948.8
7949.13
7949.46
7949.79
7950.12
7950.45
7950.78
7951.11
7951.44
7951.77
7952.1
7952.43
7952.76
7953.09
7953.42
7953.75
7954.08
7954.41
7954.74
7955.07
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.005
0.005
0.003
0.003
0.000
0.000
-0.001
0.001
-0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
-0.001
-0.001
-0.002
0.003
-0.001
0.000
-0.002
0.000
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.002
-0.001
0.003
0.002
0.000
-0.001
0.002
0.002
0.002
-0.001
0.005
0.005
0.003
0.003
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.005
0.004
0.001
0.001
0.001
0.002
0.003
0.001
0.000
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.002
0.002
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.002
0.001
004462
10/12/09 02:58:00
10/12/09 02:58:02
10/12/09 02:58:04
10/12/09 02:58:06
10/12/09 02:58:08
10/12/09 02:58:10
10/12/09 02:58:12
10/12/09 02:58:14
10/12/09 02:58:16
10/12/09 02:58:18
10/12/09 02:58:20
10/12/09 02:58:22
10/12/09 02:58:24
10/12/09 02:58:26
10/12/09 02:58:28
10/12/09 02:58:30
10/12/09 02:58:32
10/12/09 02:58:34
10/12/09 02:58:36
10/12/09 02:58:38
10/12/09 02:58:40
10/12/09 02:58:42
10/12/09 02:58:44
10/12/09 02:58:46
10/12/09 02:58:48
10/12/09 02:58:50
10/12/09 02:58:52
10/12/09 02:58:54
10/12/09 02:58:56
10/12/09 02:58:58
10/12/09 02:59:00
10/12/09 02:59:02
10/12/09 02:59:04
10/12/09 02:59:06
10/12/09 02:59:08
10/12/09 02:59:10
10/12/09 02:59:12
10/12/09 02:59:14
10/12/09 02:59:16
10/12/09 02:59:18
10/12/09 02:59:20
10/12/09 02:59:22
10/12/09 02:59:24
10/12/09 02:59:26
10/12/09 02:59:28
10/12/09 02:59:30
10/12/09 02:59:32
10/12/09 02:59:34
10/12/09 02:59:36
60.026
60.022
60.021
60.022
60.024
60.027
60.029
60.028
60.028
60.032
60.035
60.03
60.028
60.021
60.021
60.024
60.025
60.024
60.022
60.023
60.021
60.02
60.02
60.02
60.02
60.017
60.014
60.012
60.01
60.011
60.01
60.01
60.01
60.012
60.012
60.013
60.014
60.013
60.012
60.011
60.01
60.008
60.01
60.011
60.013
60.016
60.018
60.019
60.019
3671.539
3673.794
3674.01
3675.102
3675.284
3676.051
3675.704
3672.583
3671.343
3670.232
3668.654
3668.767
3666.312
3667.322
3657.164
3657.714
3668.637
3669.309
3670.112
3670.735
3671.332
3672.095
3672.683
3673.833
3674.645
3675.641
3675.971
3677.009
3678.314
3679.393
3680.02
3679.792
3679.597
3680.315
3680.11
3679.062
3679.127
3679.587
3679.637
3679.02
3678.418
3679.383
3679.681
3679.932
3679.138
3678.469
3678.499
3678.456
3677.615
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
690
690.5
691
691.5
692
692.5
693
693.5
694
694.5
695
695.5
696
696.5
697
697.5
698
698.5
699
699.5
700
700.5
701
701.5
702
702.5
703
703.5
704
704.5
705
705.5
706
706.5
707
707.5
708
708.5
709
709.5
710
710.5
711
711.5
712
712.5
713
713.5
714
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7955.4
7955.73
7956.06
7956.39
7956.72
7957.05
7957.38
7957.71
7958.04
7958.37
7958.7
7959.03
7959.36
7959.69
7960.02
7960.35
7960.68
7961.01
7961.34
7961.67
7962
7962.33
7962.66
7962.99
7963.32
7963.65
7963.98
7964.31
7964.64
7964.97
7965.3
7965.63
7965.96
7966.29
7966.62
7966.95
7967.28
7967.61
7967.94
7968.27
7968.6
7968.93
7969.26
7969.59
7969.92
7970.25
7970.58
7970.91
7971.24
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.004
-0.001
0.001
0.002
0.003
0.002
-0.001
0.000
0.004
0.003
-0.005
-0.002
-0.007
0.000
0.003
0.001
-0.001
-0.002
0.001
-0.002
-0.001
0.000
0.000
0.000
-0.003
-0.003
-0.002
-0.002
0.001
-0.001
0.000
0.000
0.002
0.000
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.004
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.004
0.003
0.005
0.002
0.007
0.000
0.003
0.001
0.001
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.003
0.003
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.001
0.000
004463
10/12/09 02:59:38
10/12/09 02:59:40
10/12/09 02:59:42
10/12/09 02:59:44
10/12/09 02:59:46
10/12/09 02:59:48
10/12/09 02:59:50
10/12/09 02:59:52
10/12/09 02:59:54
10/12/09 02:59:56
10/12/09 02:59:58
10/12/09 03:00:00
10/12/09 03:00:02
10/12/09 03:00:04
10/12/09 03:00:06
10/12/09 03:00:08
10/12/09 03:00:10
10/12/09 03:00:12
10/12/09 03:00:14
10/12/09 03:00:16
10/12/09 03:00:18
10/12/09 03:00:20
10/12/09 03:00:22
10/12/09 03:00:24
10/12/09 03:00:26
10/12/09 03:00:28
10/12/09 03:00:30
10/12/09 03:00:32
10/12/09 03:00:34
10/12/09 03:00:36
10/12/09 03:00:38
10/12/09 03:00:40
10/12/09 03:00:42
10/12/09 03:00:44
10/12/09 03:00:46
10/12/09 03:00:48
10/12/09 03:00:50
10/12/09 03:00:52
10/12/09 03:00:54
10/12/09 03:00:56
10/12/09 03:00:58
10/12/09 03:01:00
10/12/09 03:01:02
10/12/09 03:01:04
10/12/09 03:01:06
10/12/09 03:01:08
10/12/09 03:01:10
10/12/09 03:01:12
10/12/09 03:01:14
60.019
60.02
60.02
60.018
60.018
60.016
60.016
60.019
60.023
60.022
60.018
60.015
60.016
60.017
60.015
60.01
60.004
59.999
59.995
59.99
59.982
59.974
59.97
59.97
59.968
59.968
59.968
59.972
59.967
59.966
59.964
59.965
59.966
59.963
59.963
59.965
59.968
59.97
59.97
59.97
59.973
59.972
59.976
59.975
59.975
59.977
59.976
59.976
59.974
3677.446
3677.431
3677.451
3677.315
3678.151
3678.362
3678.874
3680.771
3681.058
3680.353
3679.167
3679.553
3680.672
3682.73
3682.714
3681.915
3682.01
3682.483
3683.813
3685.306
3684.846
3684.643
3687.527
3689.404
3692.287
3692.966
3693.793
3694.397
3694.974
3697.407
3698.502
3698.617
3698.992
3699.85
3702.645
3701.989
3702.218
3704.023
3703.365
3702.988
3703.814
3704.899
3705.625
3704.293
3702.094
3701.944
3703.142
3704.669
3705.376
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
714.5
715
715.5
716
716.5
717
717.5
718
718.5
719
719.5
720
720.5
721
721.5
722
722.5
723
723.5
724
724.5
725
725.5
726
726.5
727
727.5
728
728.5
729
729.5
730
730.5
731
731.5
732
732.5
733
733.5
734
734.5
735
735.5
736
736.5
737
737.5
738
738.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7971.57
7971.9
7972.23
7972.56
7972.89
7973.22
7973.55
7973.88
7974.21
7974.54
7974.87
7975.2
7975.53
7975.86
7976.19
7976.52
7976.85
7977.18
7977.51
7977.84
7978.17
7978.5
7978.83
7979.16
7979.49
7979.82
7980.15
7980.48
7980.81
7981.14
7981.47
7981.8
7982.13
7982.46
7982.79
7983.12
7983.45
7983.78
7984.11
7984.44
7984.77
7985.1
7985.43
7985.76
7986.09
7986.42
7986.75
7987.08
7987.41
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.000
-0.002
0.000
-0.002
0.000
0.003
0.004
-0.001
-0.004
-0.003
0.001
0.001
-0.002
-0.005
-0.006
-0.005
-0.004
-0.005
-0.008
-0.008
-0.004
0.000
-0.002
0.000
0.000
0.004
-0.005
-0.001
-0.002
0.001
0.001
-0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
-0.001
0.004
-0.001
0.000
0.002
-0.001
0.000
-0.002
0.000
0.001
0.000
0.002
0.000
0.002
0.000
0.003
0.004
0.001
0.004
0.003
0.001
0.001
0.002
0.005
0.006
0.005
0.004
0.005
0.008
0.008
0.004
0.000
0.002
0.000
0.000
0.004
0.005
0.001
0.002
0.001
0.001
0.003
0.000
0.002
0.003
0.002
0.000
0.000
0.003
0.001
0.004
0.001
0.000
0.002
0.001
0.000
0.002
004464
10/12/09 03:01:16
10/12/09 03:01:18
10/12/09 03:01:20
10/12/09 03:01:22
10/12/09 03:01:24
10/12/09 03:01:26
10/12/09 03:01:28
10/12/09 03:01:30
10/12/09 03:01:32
10/12/09 03:01:34
10/12/09 03:01:36
10/12/09 03:01:38
10/12/09 03:01:40
10/12/09 03:01:42
10/12/09 03:01:44
10/12/09 03:01:46
10/12/09 03:01:48
10/12/09 03:01:50
10/12/09 03:01:52
10/12/09 03:01:54
10/12/09 03:01:56
10/12/09 03:01:58
10/12/09 03:02:00
10/12/09 03:02:02
10/12/09 03:02:04
10/12/09 03:02:06
10/12/09 03:02:08
10/12/09 03:02:10
10/12/09 03:02:12
10/12/09 03:02:14
10/12/09 03:02:16
10/12/09 03:02:18
10/12/09 03:02:20
10/12/09 03:02:22
10/12/09 03:02:24
10/12/09 03:02:26
10/12/09 03:02:28
10/12/09 03:02:30
10/12/09 03:02:32
10/12/09 03:02:34
10/12/09 03:02:36
10/12/09 03:02:38
10/12/09 03:02:40
10/12/09 03:02:42
10/12/09 03:02:44
10/12/09 03:02:46
10/12/09 03:02:48
10/12/09 03:02:50
10/12/09 03:02:52
59.975
59.974
59.974
59.976
59.977
59.979
59.981
59.983
59.985
59.983
59.98
59.979
59.983
59.987
59.986
59.984
59.98
59.982
59.984
59.985
59.987
59.989
59.992
59.996
59.999
59.997
59.997
59.997
59.997
59.996
59.997
59.996
59.998
60.003
60.009
60.01
60.008
60.005
60.004
60.006
60.003
60.001
60.002
60.004
60.007
60.007
60.008
60.008
60.006
3705.662
3705.855
3706.776
3707.514
3706.928
3706.446
3706.335
3706.771
3705.943
3704.127
3704.777
3705.974
3705.968
3705.356
3704.683
3703.913
3704.361
3704.988
3705.05
3704.893
3703.741
3701.831
3701.795
3700.07
3701.308
3700.429
3700.913
3700.541
3699.927
3700.858
3700.549
3700.614
3700.224
3699.5
3698.032
3697.96
3699.409
3699.241
3700.738
3701.11
3701.238
3699.998
3700.22
3701.823
3702.554
3702.276
3701.026
3701.923
3702.943
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
739
739.5
740
740.5
741
741.5
742
742.5
743
743.5
744
744.5
745
745.5
746
746.5
747
747.5
748
748.5
749
749.5
750
750.5
751
751.5
752
752.5
753
753.5
754
754.5
755
755.5
756
756.5
757
757.5
758
758.5
759
759.5
760
760.5
761
761.5
762
762.5
763
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
7987.74
7988.07
7988.4
7988.73
7989.06
7989.39
7989.72
7990.05
7990.38
7990.71
7991.04
7991.37
7991.7
7992.03
7992.36
7992.69
7993.02
7993.35
7993.68
7994.01
7994.34
7994.67
7995
7995.33
7995.66
7995.99
7996.32
7996.65
7996.98
7997.31
7997.64
7997.97
7998.3
7998.63
7998.96
7999.29
7999.62
7999.95
8000.28
8000.61
8000.94
8001.27
8001.6
8001.93
8002.26
8002.59
8002.92
8003.25
8003.58
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
-0.002
-0.003
-0.001
0.004
0.004
-0.001
-0.002
-0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
-0.002
0.000
0.000
0.000
-0.001
0.001
-0.001
0.002
0.005
0.006
0.001
-0.002
-0.003
-0.001
0.002
-0.003
-0.002
0.001
0.002
0.003
0.000
0.001
0.000
-0.002
0.001
0.001
0.000
0.002
0.001
0.002
0.002
0.002
0.002
0.002
0.003
0.001
0.004
0.004
0.001
0.002
0.004
0.002
0.002
0.001
0.002
0.002
0.003
0.004
0.003
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.005
0.006
0.001
0.002
0.003
0.001
0.002
0.003
0.002
0.001
0.002
0.003
0.000
0.001
0.000
0.002
004465
10/12/09 03:02:54
10/12/09 03:02:56
10/12/09 03:02:58
10/12/09 03:03:00
10/12/09 03:03:02
10/12/09 03:03:04
10/12/09 03:03:06
10/12/09 03:03:08
10/12/09 03:03:10
10/12/09 03:03:12
10/12/09 03:03:14
10/12/09 03:03:16
10/12/09 03:03:18
10/12/09 03:03:20
10/12/09 03:03:22
10/12/09 03:03:24
10/12/09 03:03:26
10/12/09 03:03:28
10/12/09 03:03:30
10/12/09 03:03:32
10/12/09 03:03:34
10/12/09 03:03:36
10/12/09 03:03:38
10/12/09 03:03:40
10/12/09 03:03:42
10/12/09 03:03:44
10/12/09 03:03:46
10/12/09 03:03:48
10/12/09 03:03:50
10/12/09 03:03:52
10/12/09 03:03:54
10/12/09 03:03:56
10/12/09 03:03:58
10/12/09 03:04:00
10/12/09 03:04:02
10/12/09 03:04:04
10/12/09 03:04:06
10/12/09 03:04:08
10/12/09 03:04:10
10/12/09 03:04:12
10/12/09 03:04:14
10/12/09 03:04:16
10/12/09 03:04:18
10/12/09 03:04:20
10/12/09 03:04:22
10/12/09 03:04:24
10/12/09 03:04:26
10/12/09 03:04:28
10/12/09 03:04:30
60.006
60.006
60.005
60
59.999
60
60
60.004
60.008
60.013
60.015
60.015
60.012
60.009
60.005
60.008
60.011
60.011
60.013
60.016
60.018
60.018
60.019
60.018
60.013
60.011
60.009
60.009
60.008
60.009
60.011
60.015
60.02
60.021
60.018
60.017
60.019
60.019
60.021
60.022
60.025
60.027
60.03
60.027
60.023
60.021
60.023
60.023
60.02
3704.093
3703.96
3703.819
3704.455
3704.346
3705.329
3704.93
3704.405
3703.675
3702.748
3702.669
3703.017
3703.416
3703.297
3705.189
3705.279
3704.646
3704.051
3703.438
3704.255
3703.708
3703.83
3704.524
3704.139
3704.27
3705.429
3705.942
3705.54
3705.634
3705.749
3707.267
3706.945
3706.63
3705.655
3703.895
3704.224
3703.887
3704.648
3704.795
3704.167
3702.764
3702.008
3700.36
3701.063
3700.34
3699.369
3701.568
3702.959
3704.25
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
763.5
764
764.5
765
765.5
766
766.5
767
767.5
768
768.5
769
769.5
770
770.5
771
771.5
772
772.5
773
773.5
774
774.5
775
775.5
776
776.5
777
777.5
778
778.5
779
779.5
780
780.5
781
781.5
782
782.5
783
783.5
784
784.5
785
785.5
786
786.5
787
787.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8003.91
8004.24
8004.57
8004.9
8005.23
8005.56
8005.89
8006.22
8006.55
8006.88
8007.21
8007.54
8007.87
8008.2
8008.53
8008.86
8009.19
8009.52
8009.85
8010.18
8010.51
8010.84
8011.17
8011.5
8011.83
8012.16
8012.49
8012.82
8013.15
8013.48
8013.81
8014.14
8014.47
8014.8
8015.13
8015.46
8015.79
8016.12
8016.45
8016.78
8017.11
8017.44
8017.77
8018.1
8018.43
8018.76
8019.09
8019.42
8019.75
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
-0.001
-0.005
-0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
-0.003
-0.003
-0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
-0.001
-0.005
-0.002
-0.002
0.000
-0.001
0.001
0.002
0.004
0.005
0.001
-0.003
-0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
-0.003
-0.004
-0.002
0.002
0.000
-0.003
0.000
0.000
0.001
0.005
0.001
0.001
0.000
0.004
0.004
0.005
0.002
0.000
0.003
0.003
0.004
0.003
0.003
0.000
0.002
0.003
0.002
0.000
0.001
0.001
0.005
0.002
0.002
0.000
0.001
0.001
0.002
0.004
0.005
0.001
0.003
0.001
0.002
0.000
0.002
0.001
0.003
0.002
0.003
0.003
0.004
0.002
0.002
0.000
0.003
004466
10/12/09 03:04:32
10/12/09 03:04:34
10/12/09 03:04:36
10/12/09 03:04:38
10/12/09 03:04:40
10/12/09 03:04:42
10/12/09 03:04:44
10/12/09 03:04:46
10/12/09 03:04:48
10/12/09 03:04:50
10/12/09 03:04:52
10/12/09 03:04:54
10/12/09 03:04:56
10/12/09 03:04:58
10/12/09 03:05:00
10/12/09 03:05:02
10/12/09 03:05:04
10/12/09 03:05:06
10/12/09 03:05:08
10/12/09 03:05:10
10/12/09 03:05:12
10/12/09 03:05:14
10/12/09 03:05:16
10/12/09 03:05:18
10/12/09 03:05:20
10/12/09 03:05:22
10/12/09 03:05:24
10/12/09 03:05:26
10/12/09 03:05:28
10/12/09 03:05:30
10/12/09 03:05:32
10/12/09 03:05:34
10/12/09 03:05:36
10/12/09 03:05:38
10/12/09 03:05:40
10/12/09 03:05:42
10/12/09 03:05:44
10/12/09 03:05:46
10/12/09 03:05:48
10/12/09 03:05:50
10/12/09 03:05:52
10/12/09 03:05:54
10/12/09 03:05:56
10/12/09 03:05:58
10/12/09 03:06:00
10/12/09 03:06:02
10/12/09 03:06:04
10/12/09 03:06:06
10/12/09 03:06:08
60.024
60.024
60.022
60.022
60.024
60.025
60.023
60.024
60.02
60.018
60.013
60.008
60.012
60.017
60.019
60.019
60.015
60.016
60.015
60.016
60.014
60.016
60.018
60.019
60.016
60.014
60.014
60.018
60.022
60.023
60.024
60.026
60.026
60.024
60.022
60.02
60.019
60.022
60.025
60.028
60.03
60.031
60.029
60.026
60.026
60.029
60.03
60.033
60.03
3703.621
3703.374
3703.036
3703.931
3704.947
3704.208
3703.541
3703.16
3703.397
3704.376
3705.441
3706.995
3710.072
3707.971
3707.767
3707.609
3708.831
3709.465
3709.813
3709.817
3709.99
3709.094
3709.642
3709.812
3709.933
3710.677
3710.591
3709.354
3707.696
3707.38
3707.12
3706.99
3705.848
3704.185
3704.406
3704.963
3706.567
3705.516
3704.869
3704.428
3704.773
3703.532
3702.686
3702.093
3703.169
3703.676
3701.52
3700.106
3698.222
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
788
788.5
789
789.5
790
790.5
791
791.5
792
792.5
793
793.5
794
794.5
795
795.5
796
796.5
797
797.5
798
798.5
799
799.5
800
800.5
801
801.5
802
802.5
803
803.5
804
804.5
805
805.5
806
806.5
807
807.5
808
808.5
809
809.5
810
810.5
811
811.5
812
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8020.08
8020.41
8020.74
8021.07
8021.4
8021.73
8022.06
8022.39
8022.72
8023.05
8023.38
8023.71
8024.04
8024.37
8024.7
8025.03
8025.36
8025.69
8026.02
8026.35
8026.68
8027.01
8027.34
8027.67
8028
8028.33
8028.66
8028.99
8029.32
8029.65
8029.98
8030.31
8030.64
8030.97
8031.3
8031.63
8031.96
8032.29
8032.62
8032.95
8033.28
8033.61
8033.94
8034.27
8034.6
8034.93
8035.26
8035.59
8035.92
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.004
0.000
-0.002
0.000
0.002
0.001
-0.002
0.001
-0.004
-0.002
-0.005
-0.005
0.004
0.005
0.002
0.000
-0.004
0.001
-0.001
0.001
-0.002
0.002
0.002
0.001
-0.003
-0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
-0.002
-0.002
-0.002
-0.001
0.003
0.003
0.003
0.002
0.001
-0.002
-0.003
0.000
0.003
0.001
0.003
-0.003
0.004
0.000
0.002
0.000
0.002
0.001
0.002
0.001
0.004
0.002
0.005
0.005
0.004
0.005
0.002
0.000
0.004
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.003
0.002
0.000
0.004
0.004
0.001
0.001
0.002
0.000
0.002
0.002
0.002
0.001
0.003
0.003
0.003
0.002
0.001
0.002
0.003
0.000
0.003
0.001
0.003
0.003
004467
10/12/09 03:06:10
10/12/09 03:06:12
10/12/09 03:06:14
10/12/09 03:06:16
10/12/09 03:06:18
10/12/09 03:06:20
10/12/09 03:06:22
10/12/09 03:06:24
10/12/09 03:06:26
10/12/09 03:06:28
10/12/09 03:06:30
10/12/09 03:06:32
10/12/09 03:06:34
10/12/09 03:06:36
10/12/09 03:06:38
10/12/09 03:06:40
10/12/09 03:06:42
10/12/09 03:06:44
10/12/09 03:06:46
10/12/09 03:06:48
10/12/09 03:06:50
10/12/09 03:06:52
10/12/09 03:06:54
10/12/09 03:06:56
10/12/09 03:06:58
10/12/09 03:07:00
10/12/09 03:07:02
10/12/09 03:07:04
10/12/09 03:07:06
10/12/09 03:07:08
10/12/09 03:07:10
10/12/09 03:07:12
10/12/09 03:07:14
10/12/09 03:07:16
10/12/09 03:07:18
10/12/09 03:07:20
10/12/09 03:07:22
10/12/09 03:07:24
10/12/09 03:07:26
10/12/09 03:07:28
10/12/09 03:07:30
10/12/09 03:07:32
10/12/09 03:07:34
10/12/09 03:07:36
10/12/09 03:07:38
10/12/09 03:07:40
10/12/09 03:07:42
10/12/09 03:07:44
10/12/09 03:07:46
60.022
60.016
60.019
60.03
60.028
60.021
60.015
60.015
60.012
60.011
60.014
60.013
60.014
60.016
60.016
60.015
60.013
60.007
59.997
59.994
59.993
59.99
59.993
59.994
59.993
59.994
59.993
59.996
59.988
59.985
59.983
59.982
59.98
59.977
59.981
59.982
59.978
59.98
59.98
59.977
59.98
59.983
59.984
59.981
59.981
59.98
59.981
59.981
59.981
3698.009
3700.28
3703.192
3703.815
3701.863
3699.956
3700.816
3703.802
3706.943
3708.527
3707.49
3707.647
3706.991
3707.495
3705.584
3705.398
3707.12
3709.144
3708.99
3708.291
3706.193
3707.304
3707.903
3706.76
3706.921
3706.683
3706.888
3704.934
3705.678
3706.481
3707.071
3706.696
3707.479
3708.246
3709.436
3710.419
3710.134
3708.708
3710.024
3709.192
3708.335
3709.399
3707.911
3709.004
3707.638
3709.689
3708.945
3706.541
3711.256
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
812.5
813
813.5
814
814.5
815
815.5
816
816.5
817
817.5
818
818.5
819
819.5
820
820.5
821
821.5
822
822.5
823
823.5
824
824.5
825
825.5
826
826.5
827
827.5
828
828.5
829
829.5
830
830.5
831
831.5
832
832.5
833
833.5
834
834.5
835
835.5
836
836.5
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8036.25
8036.58
8036.91
8037.24
8037.57
8037.9
8038.23
8038.56
8038.89
8039.22
8039.55
8039.88
8040.21
8040.54
8040.87
8041.2
8041.53
8041.86
8042.19
8042.52
8042.85
8043.18
8043.51
8043.84
8044.17
8044.5
8044.83
8045.16
8045.49
8045.82
8046.15
8046.48
8046.81
8047.14
8047.47
8047.8
8048.13
8048.46
8048.79
8049.12
8049.45
8049.78
8050.11
8050.44
8050.77
8051.1
8051.43
8051.76
8052.09
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.008
-0.006
0.003
0.011
-0.002
-0.007
-0.006
0.000
-0.003
-0.001
0.003
-0.001
0.001
0.002
0.000
-0.001
-0.002
-0.006
-0.010
-0.003
-0.001
-0.003
0.003
0.001
-0.001
0.001
-0.001
0.003
-0.008
-0.003
-0.002
-0.001
-0.002
-0.003
0.004
0.001
-0.004
0.002
0.000
-0.003
0.003
0.003
0.001
-0.003
0.000
-0.001
0.001
0.000
0.000
0.008
0.006
0.003
0.011
0.002
0.007
0.006
0.000
0.003
0.001
0.003
0.001
0.001
0.002
0.000
0.001
0.002
0.006
0.010
0.003
0.001
0.003
0.003
0.001
0.001
0.001
0.001
0.003
0.008
0.003
0.002
0.001
0.002
0.003
0.004
0.001
0.004
0.002
0.000
0.003
0.003
0.003
0.001
0.003
0.000
0.001
0.001
0.000
0.000
004468
10/12/09 03:07:48
10/12/09 03:07:50
10/12/09 03:07:52
10/12/09 03:07:54
10/12/09 03:07:56
10/12/09 03:07:58
10/12/09 03:08:00
10/12/09 03:08:02
10/12/09 03:08:04
10/12/09 03:08:06
10/12/09 03:08:08
10/12/09 03:08:10
10/12/09 03:08:12
10/12/09 03:08:14
10/12/09 03:08:16
10/12/09 03:08:18
10/12/09 03:08:20
10/12/09 03:08:22
10/12/09 03:08:24
10/12/09 03:08:26
10/12/09 03:08:28
10/12/09 03:08:30
10/12/09 03:08:32
10/12/09 03:08:34
10/12/09 03:08:36
10/12/09 03:08:38
10/12/09 03:08:40
10/12/09 03:08:42
10/12/09 03:08:44
10/12/09 03:08:46
10/12/09 03:08:48
10/12/09 03:08:50
10/12/09 03:08:52
10/12/09 03:08:54
10/12/09 03:08:56
10/12/09 03:08:58
10/12/09 03:09:00
10/12/09 03:09:02
10/12/09 03:09:04
10/12/09 03:09:06
10/12/09 03:09:08
10/12/09 03:09:10
10/12/09 03:09:12
10/12/09 03:09:14
10/12/09 03:09:16
10/12/09 03:09:18
10/12/09 03:09:20
10/12/09 03:09:22
10/12/09 03:09:24
59.98
59.978
59.978
59.979
59.978
59.976
59.976
59.975
59.976
59.975
59.979
59.978
59.975
59.976
59.981
59.977
59.975
59.976
59.979
59.98
59.979
59.978
59.979
59.982
59.983
59.987
59.988
59.984
59.98
59.979
59.98
59.979
59.978
59.975
59.979
59.982
59.983
59.983
59.985
59.99
59.987
59.984
59.976
59.979
59.985
59.983
59.979
59.981
59.978
3711.362
3712.303
3712.012
3711.703
3712.093
3713.992
3714.612
3715.083
3715.323
3714.794
3714.717
3715.161
3715.001
3713.996
3714.063
3714.335
3715.631
3715.688
3715.567
3715.725
3714.848
3713.142
3713.358
3712.275
3712.619
3712.153
3710.05
3709.082
3710.472
3710.624
3710.946
3710.2
3710.475
3709.462
3710.803
3709.286
3710.573
3709.525
3708.371
3708.527
3706.512
3707.49
3708.962
3709.894
3712.303
3711.35
3711.627
3712.076
3712.393
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
837
837.5
838
838.5
839
10
10
10
10
10
0
0
0
0
0
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8052.42
8052.75
8053.08
8053.41
8053.74
8054.07
8054.4
8054.73
8055.06
8055.39
8055.72
8056.05
8056.38
8056.71
8057.04
8057.37
8057.7
8058.03
8058.36
8058.69
8059.02
8059.35
8059.68
8060.01
8060.34
8060.67
8061
8061.33
8061.66
8061.99
8062.32
8062.65
8062.98
8063.31
8063.64
8063.97
8064.3
8064.63
8064.96
8065.29
8065.62
8065.95
8066.28
8066.61
8066.94
8067.27
8067.6
8067.93
8068.26
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.002
0.000
0.001
-0.001
-0.002
0.000
-0.001
0.001
-0.001
0.004
-0.001
-0.003
0.001
0.005
-0.004
-0.002
0.001
0.003
0.001
-0.001
-0.001
0.001
0.003
0.001
0.004
0.001
-0.004
-0.004
-0.001
0.001
-0.001
-0.001
-0.003
0.004
0.003
0.001
0.000
0.002
0.005
-0.003
-0.003
-0.008
0.003
0.006
-0.002
-0.004
0.002
-0.003
0.001
0.002
0.000
0.001
0.001
0.002
0.000
0.001
0.001
0.001
0.004
0.001
0.003
0.001
0.005
0.004
0.002
0.001
0.003
0.001
0.001
0.001
0.001
0.003
0.001
0.004
0.001
0.004
0.004
0.001
0.001
0.001
0.001
0.003
0.004
0.003
0.001
0.000
0.002
0.005
0.003
0.003
0.008
0.003
0.006
0.002
0.004
0.002
0.003
004469
10/12/09 03:09:26
10/12/09 03:09:28
10/12/09 03:09:30
10/12/09 03:09:32
10/12/09 03:09:34
10/12/09 03:09:36
10/12/09 03:09:38
10/12/09 03:09:40
10/12/09 03:09:42
10/12/09 03:09:44
10/12/09 03:09:46
10/12/09 03:09:48
10/12/09 03:09:50
10/12/09 03:09:52
10/12/09 03:09:54
10/12/09 03:09:56
10/12/09 03:09:58
10/12/09 03:10:00
10/12/09 03:10:02
10/12/09 03:10:04
10/12/09 03:10:06
10/12/09 03:10:08
10/12/09 03:10:10
10/12/09 03:10:12
10/12/09 03:10:14
10/12/09 03:10:16
10/12/09 03:10:18
10/12/09 03:10:20
10/12/09 03:10:22
10/12/09 03:10:24
10/12/09 03:10:26
10/12/09 03:10:28
10/12/09 03:10:30
10/12/09 03:10:32
10/12/09 03:10:34
10/12/09 03:10:36
10/12/09 03:10:38
10/12/09 03:10:40
10/12/09 03:10:42
10/12/09 03:10:44
10/12/09 03:10:46
10/12/09 03:10:48
10/12/09 03:10:50
10/12/09 03:10:52
10/12/09 03:10:54
10/12/09 03:10:56
10/12/09 03:10:58
10/12/09 03:11:00
10/12/09 03:11:02
59.975
59.978
59.989
59.999
59.994
59.989
59.986
59.984
59.983
59.982
59.98
59.99
59.995
59.995
59.99
59.989
59.991
59.996
60
60.002
60.004
60.004
60.002
59.999
59.998
59.995
59.996
60.001
60.002
60.001
60.003
60.005
60.004
60.004
60.004
60.006
60.003
60.005
60.006
60.009
60.009
60.01
60.009
60.013
60.015
60.014
60.009
60.009
60.008
3712.999
3713.51
3716.626
3715.443
3712.092
3713.906
3714.894
3714.953
3716.122
3716.308
3715.438
3714.764
3714.714
3715.068
3715.927
3715.791
3716.285
3715.324
3714.46
3711.708
3712.698
3712.851
3713.362
3716.641
3718.292
3719.079
3718.233
3717.815
3717.889
3718.56
3718.195
3719.021
3718.821
3719.897
3719.299
3719.643
3719.527
3719.731
3720.279
3718.58
3718.976
3718.982
3720.034
3720.609
3720.811
3721.239
3720.38
3719.447
3720.807
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8068.59
8068.92
8069.25
8069.58
8069.91
8070.24
8070.57
8070.9
8071.23
8071.56
8071.89
8072.22
8072.55
8072.88
8073.21
8073.54
8073.87
8074.2
8074.53
8074.86
8075.19
8075.52
8075.85
8076.18
8076.51
8076.84
8077.17
8077.5
8077.83
8078.16
8078.49
8078.82
8079.15
8079.48
8079.81
8080.14
8080.47
8080.8
8081.13
8081.46
8081.79
8082.12
8082.45
8082.78
8083.11
8083.44
8083.77
8084.1
8084.43
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.003
0.003
0.011
0.010
-0.005
-0.005
-0.003
-0.002
-0.001
-0.001
-0.002
0.010
0.005
0.000
-0.005
-0.001
0.002
0.005
0.004
0.002
0.002
0.000
-0.002
-0.003
-0.001
-0.003
0.001
0.005
0.001
-0.001
0.002
0.002
-0.001
0.000
0.000
0.002
-0.003
0.002
0.001
0.003
0.000
0.001
-0.001
0.004
0.002
-0.001
-0.005
0.000
-0.001
0.003
0.003
0.011
0.010
0.005
0.005
0.003
0.002
0.001
0.001
0.002
0.010
0.005
0.000
0.005
0.001
0.002
0.005
0.004
0.002
0.002
0.000
0.002
0.003
0.001
0.003
0.001
0.005
0.001
0.001
0.002
0.002
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.003
0.000
0.001
0.001
0.004
0.002
0.001
0.005
0.000
0.001
004470
10/12/09 03:11:04
10/12/09 03:11:06
10/12/09 03:11:08
10/12/09 03:11:10
10/12/09 03:11:12
10/12/09 03:11:14
10/12/09 03:11:16
10/12/09 03:11:18
10/12/09 03:11:20
10/12/09 03:11:22
10/12/09 03:11:24
10/12/09 03:11:26
10/12/09 03:11:28
10/12/09 03:11:30
10/12/09 03:11:32
10/12/09 03:11:34
10/12/09 03:11:36
10/12/09 03:11:38
10/12/09 03:11:40
10/12/09 03:11:42
10/12/09 03:11:44
10/12/09 03:11:46
10/12/09 03:11:48
10/12/09 03:11:50
10/12/09 03:11:52
10/12/09 03:11:54
10/12/09 03:11:56
10/12/09 03:11:58
10/12/09 03:12:00
10/12/09 03:12:02
10/12/09 03:12:04
10/12/09 03:12:06
10/12/09 03:12:08
10/12/09 03:12:10
10/12/09 03:12:12
10/12/09 03:12:14
10/12/09 03:12:16
10/12/09 03:12:18
10/12/09 03:12:20
10/12/09 03:12:22
10/12/09 03:12:24
10/12/09 03:12:26
10/12/09 03:12:28
10/12/09 03:12:30
10/12/09 03:12:32
10/12/09 03:12:34
10/12/09 03:12:36
10/12/09 03:12:38
10/12/09 03:12:40
60.011
60.01
60.009
60.013
60.013
60.014
60.014
60.012
60.01
60.011
60.007
60.003
60.001
60
59.998
59.998
59.999
60.002
60.003
60.003
59.999
59.998
60.001
59.995
59.989
59.987
59.988
59.988
59.99
59.999
60.001
60.003
60.0005
59.998
59.997
59.996
59.996
59.996
59.995
59.994
59.993
59.992
59.991
59.99
59.991
59.992
59.993
59.994
59.995
3721.272
3720.592
3721.245
3721.594
3722.176
3721.999
3721.646
3721.678
3720.86
3721.645
3723.816
3725.07
3724.656
3724.869
3724.661
3723.696
3723.58
3723.405
3721.879
3722.401
3722.906
3724.142
3723.65
3723.201
3723.639
3723.881
3724.654
3725.361
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8084.76
8085.09
8085.42
8085.75
8086.08
8086.41
8086.74
8087.07
8087.4
8087.73
8088.06
8088.39
8088.72
8089.05
8089.38
8089.71
8090.04
8090.37
8090.7
8091.03
8091.36
8091.69
8092.02
8092.35
8092.68
8093.01
8093.34
8093.67
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
1
1
1
0
0
1
0
0
0
0
0
0
0
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
-0.001
-0.001
0.004
0.000
0.001
0.000
-0.002
-0.002
0.001
-0.004
-0.004
-0.002
-0.001
-0.002
0.000
0.001
0.003
0.001
0.000
-0.004
-0.001
0.003
-0.006
-0.006
-0.002
0.001
0.000
0.002
0.009
0.002
0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.001
0.001
0.004
0.000
0.001
0.000
0.002
0.002
0.001
0.004
0.004
0.002
0.001
0.002
0.000
0.001
0.003
0.001
0.000
0.004
0.001
0.003
0.006
0.006
0.002
0.001
0.000
0.002
0.009
0.002
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
004471
10/12/09 03:12:42
10/12/09 03:12:44
10/12/09 03:12:46
10/12/09 03:12:48
10/12/09 03:12:50
10/12/09 03:12:52
10/12/09 03:12:54
10/12/09 03:12:56
10/12/09 03:12:58
10/12/09 03:13:00
10/12/09 03:13:02
10/12/09 03:13:04
10/12/09 03:13:06
10/12/09 03:13:08
10/12/09 03:13:10
10/12/09 03:13:12
10/12/09 03:13:14
10/12/09 03:13:16
10/12/09 03:13:18
10/12/09 03:13:20
10/12/09 03:13:22
10/12/09 03:13:24
10/12/09 03:13:26
10/12/09 03:13:28
10/12/09 03:13:30
10/12/09 03:13:32
10/12/09 03:13:34
10/12/09 03:13:36
10/12/09 03:13:38
10/12/09 03:13:40
10/12/09 03:13:42
10/12/09 03:13:44
10/12/09 03:13:46
10/12/09 03:13:48
10/12/09 03:13:50
10/12/09 03:13:52
10/12/09 03:13:54
10/12/09 03:13:56
10/12/09 03:13:58
10/12/09 03:14:00
10/12/09 03:14:02
10/12/09 03:14:04
10/12/09 03:14:06
10/12/09 03:14:08
10/12/09 03:14:10
10/12/09 03:14:12
10/12/09 03:14:14
10/12/09 03:14:16
10/12/09 03:14:18
59.996
59.996
59.996
59.9965
59.997
59.997
59.997
59.997
59.997
59.999
60.001
60.001
60.001
60.004
60.007
60.009
60.011
60.0085
60.006
60.007
60.008
60.01
60.012
60.012
60.012
60.01
60.008
60.008
60.008
60.008
60.008
60.008
60.008
60.007
60.006
60.005
60.004
60.004
60.004
60.0025
60.001
59.9995
59.998
59.9965
59.995
59.995
59.995
59.996
59.997
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
-0.003
-0.002
0.001
0.001
0.002
0.002
0.000
0.000
-0.002
-0.002
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.000
0.000
0.003
0.003
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.002
0.000
0.000
0.002
0.002
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
004472
10/12/09 03:14:20
10/12/09 03:14:22
10/12/09 03:14:24
10/12/09 03:14:26
10/12/09 03:14:28
10/12/09 03:14:30
10/12/09 03:14:32
10/12/09 03:14:34
10/12/09 03:14:36
10/12/09 03:14:38
10/12/09 03:14:40
10/12/09 03:14:42
10/12/09 03:14:44
10/12/09 03:14:46
10/12/09 03:14:48
10/12/09 03:14:50
10/12/09 03:14:52
10/12/09 03:14:54
10/12/09 03:14:56
10/12/09 03:14:58
10/12/09 03:15:00
10/12/09 03:15:02
10/12/09 03:15:04
10/12/09 03:15:06
10/12/09 03:15:08
10/12/09 03:15:10
10/12/09 03:15:12
10/12/09 03:15:14
10/12/09 03:15:16
10/12/09 03:15:18
10/12/09 03:15:20
10/12/09 03:15:22
10/12/09 03:15:24
10/12/09 03:15:26
10/12/09 03:15:28
10/12/09 03:15:30
10/12/09 03:15:32
10/12/09 03:15:34
10/12/09 03:15:36
10/12/09 03:15:38
10/12/09 03:15:40
10/12/09 03:15:42
10/12/09 03:15:44
10/12/09 03:15:46
10/12/09 03:15:48
10/12/09 03:15:50
10/12/09 03:15:52
10/12/09 03:15:54
10/12/09 03:15:56
59.995
59.993
59.9925
59.992
59.9905
59.989
59.99
59.991
59.989
59.987
59.9875
59.988
59.988
59.988
59.987
59.986
59.9855
59.985
59.9845
59.984
59.984
59.984
59.985
59.986
59.987
59.988
59.992
59.996
59.9975
59.999
60.001
60.003
60.003
60.003
60.0055
60.008
60.01
60.012
60.0105
60.009
60.01
60.011
60.012
60.013
60.013
60.013
60.0145
60.016
60.0155
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.001
0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
-0.002
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.002
0.000
0.000
0.001
0.002
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.004
0.001
0.002
0.002
0.002
0.000
0.000
0.003
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
004473
10/12/09 03:15:58
10/12/09 03:15:59
10/12/09 03:16:01
10/12/09 03:16:03
10/12/09 03:16:05
10/12/09 03:16:07
10/12/09 03:16:09
10/12/09 03:16:11
10/12/09 03:16:13
10/12/09 03:16:15
10/12/09 03:16:17
10/12/09 03:16:19
10/12/09 03:16:21
10/12/09 03:16:23
10/12/09 03:16:25
10/12/09 03:16:27
10/12/09 03:16:29
10/12/09 03:16:31
10/12/09 03:16:33
10/12/09 03:16:35
10/12/09 03:16:37
10/12/09 03:16:39
10/12/09 03:16:41
10/12/09 03:16:43
10/12/09 03:16:45
10/12/09 03:16:47
10/12/09 03:16:49
10/12/09 03:16:51
10/12/09 03:16:53
10/12/09 03:16:55
10/12/09 03:16:57
10/12/09 03:16:59
10/12/09 03:17:01
10/12/09 03:17:03
10/12/09 03:17:05
10/12/09 03:17:07
10/12/09 03:17:09
10/12/09 03:17:11
10/12/09 03:17:13
10/12/09 03:17:15
10/12/09 03:17:17
10/12/09 03:17:19
10/12/09 03:17:21
10/12/09 03:17:23
10/12/09 03:17:25
60.015
60.014
60.013
60.012
60.011
60.0105
60.01
60.008
60.006
60.006
60.006
60.0045
60.003
60.003
60.003
60.0035
60.004
60.0025
60.001
59.999
59.997
59.9965
59.996
59.9965
59.997
59.997
59.997
59.998
59.999
59.9985
59.998
59.9985
59.999
59.998
59.997
59.9985
60
60.001
60.002
60.0015
60.001
60.0035
60.006
60.0055
60.005
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
3724.944
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
350
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
-223.015732
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
8094
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
-0.002
-0.002
0.000
0.000
-0.001
-0.002
0.000
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
-0.001
-0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.000
0.000
0.001
0.002
0.000
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.003
0.002
0.000
0.000
004474
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1 "BA
Event Data" worksheet.
MyBA_091012_0227_FRS_Form2.9.xlsm
59.500 Hz
60.500 Hz
Auto
Event Detection
2:27:26
1245 Manually selected row number of the Event Starting Time.
2:33:00
1442 Manually selected row number of the Event Ending Time.
Event Frequency Data
2:27:26
60.1
-0.153
2:27:26
Delta Hz Event Detected
60.05
2:33:00
60
59.95
59.9
59.85
59.8
Copy Form 2 data for
Pasting into Form 1
59.75
59.7
2:17:26
2:22:26
2:27:26
2:32:26
2:37:26
2:42:26
2:47:26
Hz
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
09/10/12 Date yymmdd
2:27 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_091012_0227_FRS_Form2.9.xlsm
2:52:26
2:57:26
3:02:26
3:07:26
3:12:26
3:17:25
004475
Auto
Manual
004476
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3788.35
157.63
-15.40
-43.39
114.21
157.60
Balancing Authority MyBA
Grid Nominal Frequency
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
142.20 MW
Yes
Initial Response P.U. Performance
1.109 P.U.
T
T-72 sec
T-70 sec
T-68 sec
2:26:14
2:26:16
2:26:18
Frequency
Hz
60.027
60.026
60.026
Interchange
MW
3671.189
3668.611
3665.232
Value B
20 to 52 sec
Average
Frequency
Droop Setting
Deadband Setting
Hz Span
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
TC (frequency response filter constant)
Low Hz
3764.66
3804.23
3719.84
3640.68
103.04
0:05:34
No
163.55
123.97
No
Yes
Yes
60.52
20.94
Up
3090
3090
3090
5.00% 3.00000 Hz
0.000 Hz
-27.810
-26.781
-26.781
(TC)
Delayed
Delivery
Frequency
Response
-9.734
-15.700
-19.578
Initial
Measure
Final
Expected
Primary
Frequency
Response
A Point
FPointA
A Value
C Value
Delta FC
3.00000 Hz
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ram
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
0.758 P.U. Sustianed Response P.U. Performance
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
60.000 Hz
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Average
Period
Recovery Recovery
Period
Recovery
Ramp
Target
Period
Period
Ramp
Period
MW/scan
MW
MW
MW
MW
MW
004477
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
60.022
60.019
60.017
60.019
60.02
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.88
59.876
59.875
59.883
59.887
59.886
3664.495
3666.062
3666.821
3666.787
3670.454
3670.267
3671.668
3672.493
3672.685
3672.857
3672.164
3671.413
3669.983
3666.467
3663.758
3661.599
3660.672
3651.492
3649.190
3650.025
3648.246
3649.512
3654.294
3655.007
3651.874
3651.059
3649.187
3648.236
3645.387
3644.628
3645.446
3640.682
3641.191
3659.465
3696.362
3734.904
3734.673
3734.673
3737.157
3761.250
3766.113
3766.194
3768.877
3769.925
3780.621
3781.592
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
-20.657
-20.277
-19.308
-19.400
-19.820
-19.733
-20.397
-20.828
-21.109
-20.571
-19.861
-20.840
-24.721
-29.407
-32.452
-34.072
-35.485
-39.649
-43.076
-45.303
-44.948
-43.997
-43.379
-42.977
-41.995
-42.077
-42.852
-44.075
-45.232
-44.182
-43.499
-43.055
-42.046
-19.399
40.744
85.606
102.870
114.091
113.094
112.806
116.583
120.481
123.375
122.373
120.278
119.277
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
-0.102
3803.32
3803.32
3803.32
0.000
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3666.787
3666.265
3666.251
3665.485
3664.952
3664.570
3665.006
3665.615
3664.533
3660.551
3655.763
3652.616
3650.895
3649.380
3645.114
3641.585
3639.256
3639.509
3640.359
3640.875
3641.176
3642.056
3641.872
3640.996
3639.670
3638.411
3639.360
3639.942
3640.284
3641.191
3663.838
3724.598
3770.077
3787.958
3799.796
3799.415
3799.745
3804.139
3808.654
3812.165
3811.779
3810.302
3809.918
3677.914
3696.910
3706.351
3712.015
3716.206
3722.640
3728.074
3732.310
3735.967
3739.054
3742.518
3745.523
3694.218
3719.504
3736.618
3749.253
3757.614
3763.632
3768.696
3773.136
3777.038
3780.197
3782.705
3784.799
3668.635
3669.252
3669.869
3670.486
3671.103
3671.720
3672.337
3672.954
3673.571
3674.188
3674.805
3675.422
3668.635
3668.944
3669.252
3669.561
3669.869
3670.178
3670.486
3670.795
3671.103
3671.412
3671.720
3672.029
004478
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
59.885
59.887
59.888
59.89
59.895
59.894
59.893
59.894
59.894
59.891
59.89
59.885
59.885
59.888
59.887
59.888
59.888
59.89
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.88
59.883
59.886
59.89
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
3782.500
3784.962
3784.730
3784.419
3788.072
3788.328
3788.868
3788.472
3792.276
3793.074
3794.374
3799.428
3800.427
3799.959
3803.625
3802.925
3802.951
3804.388
3805.496
3805.617
3809.237
3811.503
3814.862
3815.889
3825.643
3826.053
3826.002
3827.524
3826.753
3826.783
3826.454
3825.713
3823.826
3822.505
3819.081
3818.055
3816.815
3815.010
3813.783
3811.838
3809.652
3806.972
3805.593
3804.188
3796.078
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
118.988
118.079
117.127
115.788
113.114
111.737
111.202
110.494
110.034
110.817
111.686
114.054
115.593
115.511
115.819
115.658
115.553
114.765
114.613
117.037
121.857
130.759
139.429
143.983
144.779
143.495
141.579
140.693
139.397
138.914
136.799
134.342
130.943
128.372
125.621
122.750
119.443
116.572
115.788
113.835
110.404
106.731
104.704
103.386
101.809
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
3803.32
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3810.246
3809.953
3809.618
3808.896
3806.840
3806.079
3806.161
3806.070
3806.227
3807.627
3809.113
3812.098
3814.254
3814.790
3815.714
3816.170
3816.682
3816.511
3816.976
3820.017
3825.454
3834.973
3844.260
3849.431
3850.844
3850.177
3848.877
3848.609
3847.929
3848.064
3846.566
3844.726
3841.943
3839.990
3837.855
3835.601
3832.911
3830.658
3830.490
3829.154
3826.340
3823.284
3821.874
3821.174
3820.214
3748.165
3750.618
3752.750
3754.613
3756.471
3758.148
3759.684
3761.055
3762.474
3763.805
3765.078
3766.452
3767.759
3768.952
3770.190
3771.319
3772.373
3773.406
3774.409
3775.354
3776.351
3777.355
3778.397
3779.410
3780.627
3781.792
3782.897
3783.986
3785.004
3785.975
3786.895
3787.758
3788.542
3789.265
3789.886
3790.461
3790.988
3791.459
3791.888
3792.265
3792.587
3792.848
3793.076
3793.271
3793.319
3786.616
3788.172
3789.513
3790.653
3791.552
3792.317
3793.009
3793.631
3794.203
3794.787
3795.384
3796.053
3796.753
3797.421
3798.074
3798.698
3799.297
3799.853
3800.388
3800.983
3801.702
3802.653
3803.809
3805.042
3806.247
3807.373
3808.411
3809.392
3810.309
3811.187
3811.991
3812.719
3813.354
3813.921
3814.419
3814.852
3815.213
3815.516
3815.804
3816.055
3816.246
3816.374
3816.472
3816.555
3816.618
3676.039
3676.656
3677.273
3677.890
3678.507
3679.124
3679.741
3680.358
3680.975
3681.592
3682.209
3682.826
3683.443
3684.060
3684.677
3685.293
3685.910
3686.527
3687.144
3687.761
3688.378
3688.995
3689.612
3690.229
3690.846
3691.463
3692.080
3692.697
3693.314
3693.931
3694.548
3695.165
3695.782
3696.399
3697.016
3697.633
3698.250
3698.867
3699.484
3700.101
3700.718
3701.335
3701.952
3702.569
3703.186
3672.337
3672.646
3672.954
3673.263
3673.571
3673.879
3674.188
3674.496
3674.805
3675.113
3675.422
3675.730
3676.039
3676.347
3676.656
3676.964
3677.273
3677.581
3677.890
3678.198
3678.507
3678.815
3679.124
3679.432
3679.741
3680.049
3680.358
3680.666
3680.975
3681.283
3681.592
3681.900
3682.209
3682.517
3682.826
3683.134
3683.443
3683.751
3684.060
3684.368
3684.677
3684.985
3685.293
3685.602
3685.910
004479
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
59.907
59.911
59.916
59.916
59.917
59.918
59.92
59.921
59.92
59.917
59.92
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
3793.975
3792.169
3791.502
3789.534
3788.132
3784.563
3783.028
3781.701
3776.358
3775.635
3774.604
3773.334
3773.958
3772.722
3771.670
3769.630
3768.707
3767.643
3767.021
3767.408
3766.788
3766.259
3765.672
3766.123
3764.243
3765.105
3762.935
3758.387
3753.922
3749.867
3746.889
3747.875
3749.593
3748.661
3746.706
3749.077
3742.741
3740.259
3736.139
3731.382
3727.838
3725.952
3722.649
3720.578
3717.996
3718.142
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
99.702
96.891
93.261
90.902
89.008
87.416
85.661
84.159
83.544
84.225
83.587
82.811
81.585
79.708
78.848
77.207
76.501
74.240
74.573
74.428
73.253
73.210
72.461
71.254
69.026
67.578
63.754
59.825
57.993
58.604
59.361
59.493
58.498
56.769
56.007
54.790
53.278
51.935
50.701
50.620
50.207
49.939
49.764
48.569
48.874
48.351
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3818.723
3816.529
3813.516
3811.774
3810.497
3809.522
3808.384
3807.499
3807.501
3808.799
3808.778
3808.618
3808.010
3806.750
3806.507
3805.482
3805.394
3803.750
3804.700
3805.172
3804.614
3805.187
3805.055
3804.465
3802.855
3802.024
3798.816
3795.504
3794.290
3795.518
3796.892
3797.641
3797.263
3796.151
3796.005
3795.405
3794.510
3793.784
3793.167
3793.703
3793.907
3794.256
3794.698
3794.120
3795.042
3795.136
3793.330
3793.311
3793.281
3793.221
3793.140
3793.006
3792.853
3792.684
3792.440
3792.193
3791.938
3791.672
3791.423
3791.163
3790.896
3790.608
3790.316
3790.018
3789.719
3789.433
3789.147
3788.861
3788.574
3788.301
3788.011
3787.738
3787.446
3787.108
3786.727
3786.308
3785.865
3785.443
3785.049
3784.654
3784.245
3783.871
3783.438
3782.989
3782.506
3781.984
3781.437
3780.882
3780.306
3779.720
3779.121
3778.534
3816.653
3816.651
3816.600
3816.522
3816.426
3816.319
3816.197
3816.065
3815.937
3815.832
3815.730
3815.628
3815.521
3815.399
3815.277
3815.145
3815.015
3814.867
3814.735
3814.612
3814.485
3814.369
3814.254
3814.135
3813.999
3813.856
3813.679
3813.468
3813.248
3813.046
3812.865
3812.695
3812.526
3812.348
3812.172
3811.994
3811.810
3811.622
3811.432
3811.251
3811.076
3810.907
3810.747
3810.584
3810.433
3810.286
3703.803
3704.420
3705.037
3705.654
3706.271
3706.888
3707.504
3708.121
3708.738
3709.355
3709.972
3710.589
3711.206
3711.823
3712.440
3713.057
3713.674
3714.291
3714.908
3715.525
3716.142
3716.759
3717.376
3717.993
3718.610
3719.227
3719.844
3720.461
3721.078
3721.695
3722.312
3722.929
3723.546
3724.163
3724.780
3725.397
3726.014
3726.631
3727.248
3727.865
3728.482
3729.099
3729.715
3730.332
3730.949
3731.566
3686.219
3686.527
3686.836
3687.144
3687.453
3687.761
3688.070
3688.378
3688.687
3688.995
3689.304
3689.612
3689.921
3690.229
3690.538
3690.846
3691.155
3691.463
3691.772
3692.080
3692.389
3692.697
3693.006
3693.314
3693.623
3693.931
3694.240
3694.548
3694.857
3695.165
3695.474
3695.782
3696.090
3696.399
3696.707
3697.016
3697.324
3697.633
3697.941
3698.250
3698.558
3698.867
3699.175
3699.484
3699.792
3700.101
004480
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.97
59.974
59.97
59.969
59.969
59.97
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.98
59.982
59.981
59.98
59.979
59.98
59.979
59.983
59.983
3715.753
3713.694
3713.484
3710.848
3710.810
3712.092
3714.623
3715.130
3716.168
3716.461
3716.980
3717.759
3722.361
3721.973
3722.658
3722.267
3722.278
3721.787
3723.091
3723.984
3723.435
3723.893
3725.403
3727.121
3728.053
3731.130
3732.530
3733.327
3736.535
3736.907
3736.822
3738.699
3739.944
3740.877
3741.794
3745.234
3746.608
3748.300
3750.716
3751.558
3752.748
3755.599
3756.407
3756.975
3760.405
3760.982
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
48.733
48.620
48.547
48.860
48.342
48.006
45.985
45.391
45.366
46.071
45.808
45.997
45.039
43.335
41.866
40.911
38.129
37.041
36.334
35.153
33.664
31.255
31.130
31.410
31.591
31.349
30.831
29.774
29.087
27.558
25.843
24.729
24.725
24.002
24.253
23.695
23.693
22.611
21.186
20.621
20.614
20.969
20.840
21.117
19.854
19.033
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
3796.135
3796.639
3797.183
3798.112
3798.212
3798.493
3797.088
3797.112
3797.704
3799.026
3799.380
3800.186
3799.845
3798.758
3797.906
3797.568
3795.403
3794.931
3794.841
3794.278
3793.406
3791.614
3792.106
3793.002
3793.800
3794.175
3794.274
3793.834
3793.764
3792.852
3791.754
3791.257
3791.870
3791.764
3792.632
3792.691
3793.306
3792.840
3792.033
3792.085
3792.695
3793.667
3794.155
3795.048
3794.402
3794.199
3777.937
3777.330
3776.734
3776.124
3775.525
3774.948
3774.404
3773.875
3773.364
3772.865
3772.379
3771.908
3771.485
3771.065
3770.659
3770.255
3769.859
3769.465
3769.088
3768.724
3768.362
3768.009
3767.673
3767.357
3767.052
3766.776
3766.514
3766.263
3766.039
3765.822
3765.607
3765.409
3765.223
3765.047
3764.880
3764.739
3764.611
3764.496
3764.399
3764.310
3764.230
3764.171
3764.119
3764.070
3764.046
3764.025
3810.151
3810.024
3809.904
3809.795
3809.688
3809.586
3809.474
3809.364
3809.260
3809.171
3809.085
3809.009
3808.930
3808.844
3808.752
3808.659
3808.549
3808.438
3808.327
3808.214
3808.096
3807.965
3807.840
3807.724
3807.616
3807.513
3807.412
3807.309
3807.207
3807.100
3806.986
3806.870
3806.761
3806.652
3806.551
3806.452
3806.359
3806.264
3806.164
3806.067
3805.974
3805.890
3805.810
3805.738
3805.662
3805.585
3732.183
3732.800
3733.417
3734.034
3734.651
3735.268
3735.885
3736.502
3737.119
3737.736
3738.353
3738.970
3739.587
3740.204
3740.821
3741.438
3742.055
3742.672
3743.289
3743.906
3744.523
3745.140
3745.757
3746.374
3746.991
3747.608
3748.225
3748.842
3749.459
3750.076
3750.693
3751.310
3751.927
3752.543
3753.160
3753.777
3754.394
3755.011
3755.628
3756.245
3756.862
3757.479
3758.096
3758.713
3759.330
3759.947
3700.409
3700.718
3701.026
3701.335
3701.643
3701.952
3702.260
3702.569
3702.877
3703.186
3703.494
3703.803
3704.111
3704.420
3704.728
3705.037
3705.345
3705.654
3705.962
3706.271
3706.579
3706.888
3707.196
3707.504
3707.813
3708.121
3708.430
3708.738
3709.047
3709.355
3709.664
3709.972
3710.281
3710.589
3710.898
3711.206
3711.515
3711.823
3712.132
3712.440
3712.749
3713.057
3713.366
3713.674
3713.983
3714.291
004481
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.02
60.025
60.024
60.02
3761.407
3762.737
3763.212
3764.958
3766.085
3766.433
3767.251
3767.792
3768.634
3771.146
3772.445
3773.695
3774.668
3775.841
3775.363
3774.866
3775.492
3776.420
3778.554
3779.692
3781.256
3780.595
3783.092
3783.896
3784.421
3785.768
3785.463
3786.850
3786.304
3787.259
3787.516
3787.955
3788.030
3788.607
3789.216
3787.537
3785.842
3786.077
3787.930
3788.760
3786.875
3786.550
3787.358
3785.018
3785.614
3785.949
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
18.139
16.117
14.442
14.074
13.835
12.237
10.477
9.694
9.545
10.170
11.658
13.705
15.036
14.100
11.689
9.040
6.597
4.648
2.661
2.090
1.719
1.478
0.240
-1.647
-3.594
-5.220
-7.359
-9.830
-12.518
-14.986
-17.312
-17.380
-17.425
-18.176
-20.106
-21.720
-23.131
-22.606
-21.544
-22.655
-23.377
-22.765
-22.008
-23.318
-23.808
-22.685
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.617
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3793.922
3792.516
3791.459
3791.708
3792.085
3791.104
3789.962
3789.796
3790.264
3791.506
3793.610
3796.275
3798.223
3797.903
3796.109
3794.077
3792.251
3790.919
3788.932
3788.361
3787.990
3787.749
3786.511
3784.624
3782.677
3781.051
3778.912
3776.441
3773.754
3771.285
3768.960
3768.891
3768.846
3768.095
3766.166
3764.551
3763.140
3763.666
3764.728
3763.617
3762.894
3763.506
3764.264
3762.953
3762.463
3763.586
3764.008
3764.000
3763.994
3764.001
3764.014
3764.030
3764.050
3764.074
3764.102
3764.146
3764.198
3764.257
3764.321
3764.391
3764.457
3764.520
3764.586
3764.656
3764.738
3764.826
3764.922
3765.014
3765.118
3765.226
3765.336
3765.452
3765.565
3765.684
3765.800
3765.919
3766.038
3766.159
3766.278
3766.399
3766.523
3766.636
3766.738
3766.841
3766.953
3767.068
3767.171
3767.272
3767.376
3767.467
3767.560
3767.654
3805.508
3805.422
3805.331
3805.243
3805.158
3805.068
3804.971
3804.875
3804.784
3804.701
3804.632
3804.580
3804.541
3804.501
3804.450
3804.387
3804.315
3804.235
3804.144
3804.051
3803.958
3803.863
3803.763
3803.653
3803.533
3803.405
3803.267
3803.116
3802.952
3802.776
3802.590
3802.404
3802.221
3802.036
3801.842
3801.641
3801.435
3801.234
3801.041
3800.844
3800.646
3800.452
3800.265
3800.072
3799.879
3799.694
3760.564
3761.181
3761.798
3762.415
3763.032
3763.649
3764.266
3764.883
3765.500
3766.117
3766.734
3767.351
3767.968
3768.585
3769.202
3769.819
3770.436
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3714.600
3714.908
3715.217
3715.525
3715.834
3716.142
3716.451
3716.759
3717.068
3717.376
3717.685
3717.993
3718.302
3718.610
3718.918
3719.227
3719.535
3719.844
3720.149
3720.450
3720.748
3721.042
3721.333
3721.620
3721.904
3722.185
3722.463
3722.737
3723.009
3723.277
3723.542
3723.805
3724.064
3724.321
3724.575
3724.826
3725.075
3725.321
3725.564
3725.805
3726.043
3726.279
3726.512
3726.743
3726.971
3727.197
004482
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
60.02
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.01
60.007
60.007
60.009
60.009
60.01
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
3785.804
3786.864
3786.877
3785.254
3785.726
3786.347
3785.821
3785.798
3786.284
3786.939
3787.627
3789.444
3789.673
3789.404
3788.479
3789.183
3789.369
3789.005
3788.665
3788.933
3790.667
3790.805
3790.411
3789.769
3791.540
3792.945
3791.027
3791.443
3791.426
3790.603
3790.457
3790.216
3789.585
3788.457
3788.105
3788.057
3788.189
3788.497
3788.540
3788.571
3788.101
3787.133
3786.453
3787.732
3788.813
3789.285
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
-21.956
-22.202
-22.362
-22.466
-22.173
-21.983
-22.580
-22.968
-22.860
-21.709
-19.878
-19.411
-19.106
-18.909
-19.141
-19.291
-18.307
-17.307
-17.017
-16.108
-15.157
-14.178
-13.542
-12.407
-10.588
-9.406
-9.358
-9.327
-9.667
-7.364
-4.426
-1.074
2.185
4.665
5.916
6.729
8.700
10.702
12.364
13.804
14.380
15.114
16.314
17.454
17.835
19.163
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3764.316
3764.069
3763.909
3763.805
3764.098
3764.288
3763.691
3763.303
3763.411
3764.562
3766.393
3766.861
3767.165
3767.363
3767.131
3766.980
3767.964
3768.964
3769.254
3770.163
3771.114
3772.093
3772.729
3773.864
3775.683
3776.866
3776.913
3776.945
3776.605
3778.907
3781.845
3785.197
3788.457
3790.936
3792.187
3793.000
3794.972
3796.973
3798.635
3800.075
3800.651
3801.386
3802.585
3803.725
3804.106
3805.434
3767.746
3767.843
3767.938
3768.025
3768.113
3768.203
3768.290
3768.376
3768.463
3768.553
3768.645
3768.745
3768.845
3768.943
3769.036
3769.131
3769.226
3769.318
3769.408
3769.499
3769.596
3769.693
3769.788
3769.879
3769.977
3770.080
3770.174
3770.269
3770.363
3770.453
3770.541
3770.627
3770.710
3770.787
3770.862
3770.936
3771.010
3771.085
3771.159
3771.233
3771.304
3771.371
3771.434
3771.502
3771.574
3771.647
3799.515
3799.336
3799.158
3798.981
3798.807
3798.636
3798.464
3798.292
3798.122
3797.959
3797.806
3797.658
3797.512
3797.368
3797.225
3797.082
3796.945
3796.815
3796.686
3796.564
3796.446
3796.335
3796.227
3796.125
3796.033
3795.946
3795.861
3795.777
3795.691
3795.617
3795.556
3795.511
3795.480
3795.460
3795.446
3795.436
3795.434
3795.440
3795.454
3795.474
3795.495
3795.520
3795.550
3795.584
3795.619
3795.660
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3727.421
3727.642
3727.861
3728.079
3728.293
3728.506
3728.717
3728.925
3729.132
3729.336
3729.539
3729.739
3729.938
3730.135
3730.330
3730.523
3730.714
3730.903
3731.091
3731.277
3731.461
3731.643
3731.824
3732.003
3732.181
3732.356
3732.531
3732.704
3732.875
3733.044
3733.213
3733.379
3733.545
3733.708
3733.871
3734.032
3734.191
3734.349
3734.506
3734.662
3734.816
3734.969
3735.120
3735.271
3735.420
3735.568
004483
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.97
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.97
59.968
59.965
59.964
59.97
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
3788.256
3788.410
3790.467
3790.665
3790.420
3789.674
3789.267
3789.148
3790.430
3789.914
3786.243
3787.442
3788.963
3790.602
3791.877
3792.911
3792.311
3789.125
3788.080
3787.844
3787.135
3787.164
3786.996
3787.405
3786.487
3787.079
3789.214
3790.512
3791.221
3792.218
3790.959
3788.824
3789.026
3789.167
3787.394
3785.690
3784.831
3785.010
3784.320
3782.809
3782.110
3779.352
3779.056
3778.633
3779.212
3779.335
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
20.747
22.137
23.040
22.547
21.145
21.675
22.740
24.154
24.352
24.120
23.969
24.593
25.719
27.892
28.944
29.268
28.758
26.623
24.155
23.632
24.374
25.937
25.510
25.595
26.370
28.316
30.662
32.548
33.413
32.893
32.195
32.464
33.719
34.895
33.496
31.867
32.610
33.093
32.686
32.782
32.483
33.011
33.354
33.937
34.677
32.994
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3807.018
3808.408
3809.312
3808.818
3807.416
3807.946
3809.011
3810.426
3810.623
3810.391
3810.240
3810.864
3811.990
3814.163
3815.216
3815.539
3815.029
3812.895
3810.426
3809.903
3810.645
3812.208
3811.782
3811.866
3812.641
3814.587
3816.933
3818.819
3819.685
3819.165
3818.467
3818.735
3819.990
3821.166
3819.767
3818.138
3818.881
3819.365
3818.957
3819.053
3818.754
3819.282
3819.625
3820.208
3820.948
3819.265
3771.715
3771.784
3771.860
3771.936
3772.011
3772.082
3772.151
3772.219
3772.292
3772.362
3772.417
3772.476
3772.541
3772.611
3772.686
3772.764
3772.840
3772.903
3772.961
3773.018
3773.071
3773.125
3773.177
3773.230
3773.280
3773.332
3773.391
3773.454
3773.520
3773.588
3773.652
3773.707
3773.763
3773.819
3773.868
3773.910
3773.950
3773.989
3774.026
3774.057
3774.085
3774.104
3774.121
3774.137
3774.155
3774.173
3795.706
3795.758
3795.814
3795.867
3795.913
3795.962
3796.014
3796.072
3796.130
3796.187
3796.242
3796.300
3796.361
3796.431
3796.504
3796.578
3796.649
3796.711
3796.764
3796.814
3796.867
3796.925
3796.981
3797.037
3797.095
3797.160
3797.234
3797.314
3797.396
3797.476
3797.553
3797.631
3797.712
3797.797
3797.876
3797.949
3798.024
3798.100
3798.175
3798.249
3798.321
3798.395
3798.469
3798.545
3798.623
3798.695
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3735.714
3735.860
3736.004
3736.147
3736.289
3736.430
3736.569
3736.708
3736.845
3736.982
3737.117
3737.251
3737.384
3737.516
3737.647
3737.777
3737.906
3738.034
3738.161
3738.287
3738.412
3738.536
3738.659
3738.781
3738.903
3739.023
3739.143
3739.261
3739.379
3739.496
3739.612
3739.727
3739.841
3739.955
3740.068
3740.180
3740.291
3740.401
3740.510
3740.619
3740.727
3740.834
3740.940
3741.046
3741.151
3741.255
004484
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
59.967
59.965
59.962
59.964
59.97
59.967
59.969
59.968
59.963
59.965
59.97
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.99
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.96
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
3776.429
3775.647
3776.597
3776.559
3776.023
3773.170
3771.730
3768.793
3768.503
3768.917
3767.366
3764.786
3760.295
3759.592
3761.894
3761.777
3760.583
3760.157
3759.781
3759.495
3757.773
3753.277
3753.087
3751.637
3753.751
3758.225
3759.250
3758.041
3760.965
3762.022
3763.822
3763.100
3763.858
3764.158
3766.127
3768.339
3767.972
3767.438
3765.606
3762.688
3761.570
3761.920
3759.627
3758.522
3752.429
3750.102
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
33.343
34.290
35.987
36.369
34.455
34.292
33.465
33.289
34.976
35.352
33.793
31.699
32.141
33.509
33.317
32.831
33.237
34.582
34.735
30.148
23.201
21.208
23.159
26.950
30.135
33.286
35.334
37.027
38.128
39.203
38.820
40.014
41.871
44.880
46.116
46.559
45.765
45.608
43.706
41.747
41.195
41.558
40.350
39.566
38.335
36.454
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3819.614
3820.562
3822.258
3822.641
3820.726
3820.564
3819.736
3819.560
3821.247
3821.623
3820.064
3817.970
3818.412
3819.780
3819.589
3819.102
3819.508
3820.853
3821.007
3816.420
3809.472
3807.480
3809.430
3813.221
3816.406
3819.557
3821.606
3823.299
3824.399
3825.475
3825.091
3826.285
3828.142
3831.151
3832.387
3832.830
3832.036
3831.880
3829.977
3828.018
3827.467
3827.829
3826.622
3825.837
3824.606
3822.726
3774.181
3774.186
3774.194
3774.202
3774.208
3774.205
3774.196
3774.178
3774.159
3774.141
3774.119
3774.088
3774.042
3773.994
3773.954
3773.914
3773.870
3773.825
3773.780
3773.733
3773.682
3773.616
3773.550
3773.480
3773.417
3773.368
3773.323
3773.275
3773.236
3773.201
3773.171
3773.140
3773.111
3773.083
3773.062
3773.047
3773.032
3773.014
3772.992
3772.960
3772.926
3772.892
3772.852
3772.809
3772.748
3772.680
3798.768
3798.843
3798.923
3799.004
3799.079
3799.152
3799.221
3799.290
3799.364
3799.439
3799.508
3799.569
3799.632
3799.699
3799.764
3799.828
3799.892
3799.961
3800.029
3800.083
3800.113
3800.137
3800.167
3800.208
3800.260
3800.322
3800.389
3800.462
3800.537
3800.616
3800.692
3800.772
3800.858
3800.952
3801.049
3801.147
3801.242
3801.336
3801.424
3801.505
3801.584
3801.663
3801.739
3801.811
3801.880
3801.942
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3741.359
3741.461
3741.563
3741.665
3741.765
3741.865
3741.965
3742.063
3742.161
3742.259
3742.355
3742.451
3742.546
3742.641
3742.735
3742.829
3742.922
3743.014
3743.105
3743.196
3743.287
3743.377
3743.466
3743.555
3743.643
3743.730
3743.817
3743.904
3743.990
3744.075
3744.160
3744.244
3744.328
3744.411
3744.494
3744.576
3744.658
3744.739
3744.820
3744.900
3744.980
3745.059
3745.138
3745.216
3745.294
3745.371
004485
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
59.968
59.968
59.97
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.98
59.978
59.978
59.98
59.981
59.98
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
3753.830
3753.510
3753.523
3752.741
3753.178
3752.729
3753.291
3752.872
3752.359
3749.398
3747.476
3740.370
3741.285
3746.651
3745.738
3743.351
3741.618
3740.306
3738.484
3738.901
3737.404
3737.273
3736.308
3736.272
3735.448
3735.650
3737.541
3738.012
3736.748
3736.693
3736.067
3736.094
3736.575
3738.571
3738.875
3738.935
3738.647
3737.684
3737.382
3737.892
3740.017
3740.329
3742.053
3742.424
3742.524
3742.245
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
35.232
34.437
33.199
31.313
30.808
32.642
33.114
33.421
31.818
29.333
28.079
29.426
28.861
28.133
26.217
23.891
22.379
21.396
20.397
19.748
18.604
18.582
18.928
19.874
20.128
21.014
21.590
21.244
20.658
20.638
21.345
22.526
24.736
26.533
28.421
27.847
27.114
26.275
27.173
28.837
29.198
28.352
28.523
28.634
28.706
26.950
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3821.503
3820.709
3819.470
3817.584
3817.079
3818.914
3819.386
3819.692
3818.089
3815.604
3814.351
3815.698
3815.132
3814.404
3812.488
3810.162
3808.650
3807.667
3806.668
3806.019
3804.875
3804.853
3805.199
3806.145
3806.399
3807.285
3807.861
3807.515
3806.929
3806.909
3807.617
3808.797
3811.007
3812.804
3814.692
3814.118
3813.385
3812.546
3813.444
3815.108
3815.470
3814.624
3814.794
3814.905
3814.977
3813.221
3772.624
3772.567
3772.510
3772.452
3772.395
3772.337
3772.281
3772.225
3772.167
3772.101
3772.029
3771.938
3771.849
3771.777
3771.702
3771.621
3771.536
3771.447
3771.354
3771.262
3771.167
3771.071
3770.974
3770.877
3770.778
3770.681
3770.589
3770.499
3770.406
3770.313
3770.220
3770.126
3770.035
3769.949
3769.865
3769.782
3769.698
3769.612
3769.525
3769.441
3769.362
3769.285
3769.213
3769.142
3769.072
3769.001
3802.001
3802.056
3802.108
3802.154
3802.198
3802.247
3802.297
3802.348
3802.394
3802.432
3802.467
3802.505
3802.541
3802.576
3802.604
3802.626
3802.643
3802.657
3802.668
3802.678
3802.684
3802.690
3802.697
3802.707
3802.717
3802.730
3802.744
3802.757
3802.769
3802.780
3802.793
3802.810
3802.832
3802.859
3802.891
3802.921
3802.950
3802.975
3803.004
3803.036
3803.069
3803.100
3803.131
3803.162
3803.193
3803.220
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3745.448
3745.525
3745.601
3745.676
3745.751
3745.826
3745.900
3745.974
3746.047
3746.120
3746.193
3746.265
3746.336
3746.408
3746.478
3746.549
3746.619
3746.688
3746.758
3746.826
3746.895
3746.963
3747.031
3747.098
3747.165
3747.231
3747.297
3747.363
3747.429
3747.494
3747.559
3747.623
3747.687
3747.751
3747.814
3747.877
3747.940
3748.002
3748.064
3748.125
3748.187
3748.248
3748.308
3748.369
3748.429
3748.488
004486
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.97
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.99
59.994
59.996
60.001
60.003
60.004
60.006
60.012
3741.723
3740.085
3740.629
3739.964
3740.775
3742.833
3741.268
3739.776
3738.966
3738.706
3738.879
3739.860
3738.102
3738.558
3743.507
3743.419
3745.251
3745.744
3747.340
3750.700
3749.750
3746.217
3744.683
3743.745
3743.149
3740.299
3739.453
3733.376
3731.830
3737.583
3736.229
3734.897
3733.434
3733.115
3730.510
3729.180
3725.459
3724.785
3720.108
3720.938
3725.661
3725.677
3727.754
3727.825
3727.683
3727.231
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
24.007
23.535
23.949
25.301
25.819
25.073
24.589
23.913
23.114
21.874
22.509
24.004
26.057
27.391
28.259
28.462
30.037
31.781
32.915
31.849
30.435
29.877
30.595
29.981
28.861
28.493
29.335
29.522
28.563
25.055
21.693
19.508
18.087
16.443
14.654
13.491
13.816
13.667
12.488
10.280
8.125
4.921
2.118
-0.066
-2.206
-5.760
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3810.278
3809.807
3810.221
3811.572
3812.090
3811.345
3810.860
3810.185
3809.385
3808.145
3808.780
3810.276
3812.328
3813.663
3814.530
3814.733
3816.308
3818.052
3819.186
3818.120
3816.707
3816.148
3816.866
3816.252
3815.132
3814.764
3815.606
3815.793
3814.834
3811.327
3807.964
3805.779
3804.359
3802.715
3800.926
3799.763
3800.088
3799.939
3798.759
3796.552
3794.396
3791.192
3788.389
3786.205
3784.065
3780.511
3768.930
3768.854
3768.780
3768.705
3768.633
3768.566
3768.495
3768.421
3768.346
3768.270
3768.194
3768.122
3768.046
3767.971
3767.909
3767.847
3767.790
3767.735
3767.684
3767.641
3767.597
3767.543
3767.487
3767.428
3767.368
3767.301
3767.233
3767.150
3767.064
3766.992
3766.917
3766.839
3766.758
3766.677
3766.590
3766.500
3766.401
3766.302
3766.192
3766.084
3765.988
3765.892
3765.802
3765.713
3765.623
3765.533
3803.238
3803.255
3803.273
3803.295
3803.318
3803.339
3803.358
3803.376
3803.391
3803.403
3803.417
3803.435
3803.457
3803.483
3803.511
3803.539
3803.572
3803.608
3803.647
3803.683
3803.716
3803.747
3803.779
3803.810
3803.838
3803.865
3803.894
3803.923
3803.950
3803.968
3803.977
3803.982
3803.983
3803.980
3803.972
3803.962
3803.953
3803.943
3803.931
3803.913
3803.891
3803.861
3803.824
3803.782
3803.736
3803.681
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3748.548
3748.607
3748.666
3748.724
3748.782
3748.840
3748.898
3748.955
3749.012
3749.068
3749.125
3749.181
3749.237
3749.292
3749.347
3749.402
3749.457
3749.511
3749.566
3749.619
3749.673
3749.726
3749.779
3749.832
3749.885
3749.937
3749.989
3750.041
3750.092
3750.143
3750.194
3750.245
3750.296
3750.346
3750.396
3750.446
3750.495
3750.545
3750.594
3750.642
3750.691
3750.739
3750.788
3750.835
3750.883
3750.931
004487
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3725.012
3726.446
3726.016
3719.123
3716.375
3717.333
3717.560
3717.142
3715.166
3713.632
3710.283
3710.158
3699.356
3698.591
3704.591
3703.275
3702.482
3701.316
3700.826
3699.529
3699.726
3690.100
3690.477
3696.865
3696.877
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
3090
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
-8.791
-12.564
-15.737
-19.242
-21.881
-23.956
-26.026
-27.371
-31.129
-33.212
-34.926
-36.040
-36.404
-38.443
-40.489
-42.179
-42.918
-44.480
-46.216
-46.624
-46.889
-45.979
-45.388
-45.364
-44.988
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
3777.480
3773.707
3770.534
3767.029
3764.390
3762.315
3760.245
3758.900
3755.142
3753.060
3751.346
3750.231
3749.868
3747.828
3745.782
3744.092
3743.353
3741.791
3740.055
3739.647
3739.382
3740.292
3740.884
3740.908
3741.284
3765.438
3765.347
3765.255
3765.148
3765.035
3764.924
3764.815
3764.705
3764.591
3764.474
3764.350
3764.227
3764.079
3763.930
3763.796
3763.659
3763.521
3763.380
3763.240
3763.097
3762.955
3762.793
3762.632
3762.485
3762.340
3803.620
3803.550
3803.473
3803.389
3803.298
3803.203
3803.104
3803.002
3802.892
3802.778
3802.660
3802.540
3802.420
3802.296
3802.168
3802.037
3801.904
3801.769
3801.630
3801.491
3801.352
3801.216
3801.082
3800.948
3800.816
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3771.053
3750.978
3751.025
3751.072
3751.118
3751.165
3751.211
3751.257
3751.302
3751.348
3751.393
3751.438
3751.483
3751.528
3751.572
3751.617
3751.661
3751.705
3751.748
3751.792
3751.835
3751.878
3751.921
3751.964
3752.006
3752.049
004488
2:27:24
60.03900146
60.04212523
59.83599854
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
2:27:24
Time of Frequency R
Value A Pre-Perturba
Value B Post-Perturbat
Value A Pre-Perturbation Av
Value B Post-Perturbation Ave
ncy recovery period (indicates ramp direction during recovery period)
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
T
T-72 sec
T-70 sec
T-68 sec
2:26:14
2:26:16
2:26:18
Frequency
Hz
Net
Actual
Interchange
MW
60.027
60.026
60.026
3671.19
3668.61
3665.23
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MW
350.00
350.00
350.00
NonConforming
Load
Load (-)
MW
157.63
155.53
155.53
Pumped
Hydro
Load (-) Gen (+)
MW
0.00
0.00
0.00
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
10.00
10.00
10.00
20 to 52 second Ave
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
15.00
15.00
15.00
BA
Bias
Setting
MW/0.1 Hz
-103.00
-103.00
-103.00
BA
Load
MW
7640.91
7641.24
7641.57
Expected Primary
Freq Response
Based on Bias Setting
MW
-27.810 T-72 sec
-26.781 T-70 sec
-26.781 T-68 sec
T
2:26:14
2:26:16
2:26:18
004489
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
60.022
60.019
60.017
60.019
60.020
60.019
60.021
60.021
60.021
60.019
60.018
60.022
60.031
60.037
60.037
60.036
60.037
60.046
60.048
60.048
60.043
60.041
60.041
60.041
60.039
60.041
60.043
60.045
60.046
60.041
60.041
60.041
60.039
59.978
59.852
59.836
59.869
59.869
59.892
59.891
59.880
59.876
59.875
59.883
59.887
59.886
3664.50
3666.06
3666.82
3666.79
3670.45
3670.27
3671.67
3672.49
3672.69
3672.86
3672.16
3671.41
3669.98
3666.47
3663.76
3661.60
3660.67
3651.49
3649.19
3650.03
3648.25
3649.51
3654.29
3655.01
3651.87
3651.06
3649.19
3648.24
3645.39
3644.63
3645.45
3640.68
3641.19
3659.46
3696.36
3734.90
3734.67
3734.67
3737.16
3761.25
3766.11
3766.19
3768.88
3769.93
3780.62
3781.59
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
155.53
155.53
155.53
160.45
160.45
160.45
160.45
160.45
163.96
163.96
163.96
163.96
163.96
166.07
166.07
166.07
166.07
166.07
163.77
163.77
163.77
163.77
163.77
165.10
165.10
165.10
165.10
165.10
165.48
165.48
165.48
165.48
165.48
206.46
206.46
206.46
206.46
206.46
206.46
211.26
211.26
211.26
211.26
211.26
214.35
214.35
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
1.00
1.00
1.00
1.00
1.00
1.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
15.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7641.90
7642.23
7642.56
7642.89
7643.22
7643.55
7643.88
7644.21
7644.54
7644.87
7645.20
7645.53
7645.86
7646.19
7646.52
7646.85
7647.18
7647.51
7647.84
7648.17
7648.50
7648.83
7649.16
7649.49
7649.82
7650.15
7650.48
7650.81
7651.14
7651.47
7651.80
7652.13
7652.46
7652.79
7616.00
7626.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
-22.659
-19.571
-17.508
-19.571
-20.600
-19.571
-21.630
-21.630
-21.630
-19.571
-18.542
-22.659
-31.928
-38.109
-38.109
-37.079
-38.109
-47.381
-49.440
-49.440
-44.289
-42.230
-42.230
-42.230
-40.172
-42.230
-44.289
-46.348
-47.381
-42.230
-42.230
-42.230
-40.172
22.659
152.439
168.922
134.931
134.931
111.242
112.271
123.599
127.721
128.750
120.511
116.389
117.418
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
2:26:20
2:26:22
2:26:24
2:26:26
2:26:28
2:26:30
2:26:32
2:26:34
2:26:36
2:26:38
2:26:40
2:26:42
2:26:44
2:26:46
2:26:48
2:26:50
2:26:52
2:26:54
2:26:56
2:26:58
2:27:00
2:27:02
2:27:04
2:27:06
2:27:08
2:27:10
2:27:12
2:27:14
2:27:16
2:27:18
2:27:20
2:27:22
2:27:24
2:27:26
2:27:28
2:27:30
2:27:32
2:27:34
2:27:36
2:27:38
2:27:40
2:27:42
2:27:44
2:27:46
2:27:48
2:27:50
004490
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
59.885
59.887
59.888
59.890
59.895
59.894
59.893
59.894
59.894
59.891
59.890
59.885
59.885
59.888
59.887
59.888
59.888
59.890
59.889
59.882
59.873
59.857
59.849
59.852
59.858
59.863
59.866
59.865
59.867
59.866
59.871
59.874
59.879
59.880
59.883
59.886
59.890
59.892
59.889
59.893
59.899
59.903
59.902
59.902
59.904
3782.50
3784.96
3784.73
3784.42
3788.07
3788.33
3788.87
3788.47
3792.28
3793.07
3794.37
3799.43
3800.43
3799.96
3803.63
3802.93
3802.95
3804.39
3805.50
3805.62
3809.24
3811.50
3814.86
3815.89
3825.64
3826.05
3826.00
3827.52
3826.75
3826.78
3826.45
3825.71
3823.83
3822.51
3819.08
3818.06
3816.81
3815.01
3813.78
3811.84
3809.65
3806.97
3805.59
3804.19
3796.08
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
214.35
214.35
214.35
212.17
212.17
212.17
212.17
212.17
215.60
215.60
215.60
215.60
215.60
218.33
218.33
218.33
218.33
218.33
217.38
217.38
217.38
217.38
217.38
214.83
214.83
214.83
214.83
214.83
227.66
227.66
227.66
227.66
227.66
225.02
225.02
225.02
225.02
225.02
228.37
228.37
228.37
228.37
228.37
234.08
234.08
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
10.00
11.00
12.00
13.00
14.00
15.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7631.00
7625.00
7623.00
7621.00
7623.00
7625.00
7627.00
7628.00
7628.00
7629.00
7630.00
7631.00
7635.00
7638.00
7639.00
7642.00
7644.00
7645.00
7647.00
7648.00
7649.00
7650.00
7651.00
7652.00
7653.00
118.452
116.389
115.359
113.301
108.150
109.179
110.208
109.179
109.179
112.271
113.301
118.452
118.452
115.359
116.389
115.359
115.359
113.301
114.330
121.540
130.809
147.292
155.531
152.439
146.258
141.111
138.019
139.048
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
136.989
138.019
132.872
129.779
124.628
123.599
120.511
117.418
113.301
111.242
114.330
110.208
104.032
99.910
100.940
100.940
98.881
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
2:27:52
2:27:54
2:27:56
2:27:58
2:28:00
2:28:02
2:28:04
2:28:06
2:28:08
2:28:10
2:28:12
2:28:14
2:28:16
2:28:18
2:28:20
2:28:22
2:28:24
2:28:26
2:28:28
2:28:30
2:28:32
2:28:34
2:28:36
2:28:38
2:28:40
2:28:42
2:28:44
2:28:46
2:28:48
2:28:50
2:28:52
2:28:54
2:28:56
2:28:58
2:29:00
2:29:02
2:29:04
2:29:06
2:29:08
2:29:10
2:29:12
2:29:14
2:29:16
2:29:18
2:29:20
004491
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
2:30:28
2:30:30
2:30:32
2:30:34
2:30:36
2:30:38
2:30:40
2:30:42
2:30:44
2:30:46
2:30:48
2:30:50
2:30:52
59.907
59.911
59.916
59.916
59.917
59.918
59.920
59.921
59.920
59.917
59.920
59.921
59.923
59.926
59.925
59.928
59.927
59.932
59.927
59.928
59.931
59.929
59.931
59.933
59.937
59.937
59.945
59.949
59.947
59.942
59.941
59.942
59.945
59.948
59.947
59.949
59.951
59.952
59.953
59.951
59.952
59.952
59.952
59.955
59.952
59.954
3793.98
3792.17
3791.50
3789.53
3788.13
3784.56
3783.03
3781.70
3776.36
3775.64
3774.60
3773.33
3773.96
3772.72
3771.67
3769.63
3768.71
3767.64
3767.02
3767.41
3766.79
3766.26
3765.67
3766.12
3764.24
3765.10
3762.94
3758.39
3753.92
3749.87
3746.89
3747.88
3749.59
3748.66
3746.71
3749.08
3742.74
3740.26
3736.14
3731.38
3727.84
3725.95
3722.65
3720.58
3718.00
3718.14
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
335.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
234.08
234.08
234.08
228.80
228.80
228.80
228.80
228.80
229.47
229.47
229.47
229.47
229.47
228.98
228.98
228.98
228.98
228.98
219.98
219.98
219.98
219.98
219.98
229.09
229.09
229.09
229.09
229.09
229.66
229.66
229.66
229.66
229.66
229.23
229.23
229.23
229.23
229.23
231.41
231.41
231.41
231.41
231.41
218.62
218.62
218.62
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7654.00
7655.00
7655.00
7656.00
7656.00
7657.00
7657.00
7658.00
7658.00
7659.00
7659.00
7659.00
7660.00
7660.00
7661.00
7661.00
7662.00
7662.00
7663.00
7663.00
7664.00
7664.00
7665.00
7666.00
7666.00
7667.00
7668.00
7668.00
7669.00
7669.00
7670.00
7670.00
7671.00
7671.00
7672.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
7673.00
95.788
91.671
86.520
86.520
85.490
84.461
82.402
81.369
82.402
85.490
82.402
81.369
79.310
76.221
77.251
74.159
75.192
70.041
75.192
74.159
71.070
73.129
71.070
69.011
64.890
64.890
56.650
52.529
54.591
59.739
60.768
59.739
56.650
53.558
54.591
52.529
50.470
49.440
48.411
50.470
49.440
49.440
49.440
46.348
49.440
47.381
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
2:29:22
2:29:24
2:29:26
2:29:28
2:29:30
2:29:32
2:29:34
2:29:36
2:29:38
2:29:40
2:29:42
2:29:44
2:29:46
2:29:48
2:29:50
2:29:52
2:29:54
2:29:56
2:29:58
2:30:00
2:30:02
2:30:04
2:30:06
2:30:08
2:30:10
2:30:12
2:30:14
2:30:16
2:30:18
2:30:20
2:30:22
2:30:24
2:30:26
004492
2:30:54
2:30:56
2:30:58
2:31:00
2:31:02
2:31:04
2:31:06
2:31:08
2:31:10
2:31:12
2:31:14
2:31:16
2:31:18
2:31:20
2:31:22
2:31:24
2:31:26
2:31:28
2:31:30
2:31:32
2:31:34
2:31:36
2:31:38
2:31:40
2:31:42
2:31:44
2:31:46
2:31:48
2:31:50
2:31:52
2:31:54
2:31:56
2:31:58
2:32:00
2:32:02
2:32:04
2:32:06
2:32:08
2:32:10
2:32:12
2:32:14
2:32:16
2:32:18
2:32:20
2:32:22
2:32:24
59.952
59.953
59.953
59.952
59.954
59.954
59.959
59.957
59.956
59.954
59.956
59.955
59.958
59.961
59.962
59.962
59.968
59.966
59.966
59.968
59.970
59.974
59.970
59.969
59.969
59.970
59.971
59.973
59.973
59.976
59.978
59.978
59.976
59.978
59.976
59.978
59.977
59.980
59.982
59.981
59.980
59.979
59.980
59.979
59.983
59.983
3715.75
3713.69
3713.48
3710.85
3710.81
3712.09
3714.62
3715.13
3716.17
3716.46
3716.98
3717.76
3722.36
3721.97
3722.66
3722.27
3722.28
3721.79
3723.09
3723.98
3723.43
3723.89
3725.40
3727.12
3728.05
3731.13
3732.53
3733.33
3736.54
3736.91
3736.82
3738.70
3739.94
3740.88
3741.79
3745.23
3746.61
3748.30
3750.72
3751.56
3752.75
3755.60
3756.41
3756.98
3760.41
3760.98
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
218.62
218.62
213.54
213.54
213.54
213.54
213.54
225.65
225.65
225.65
225.65
225.65
212.57
212.57
212.57
212.57
212.57
219.90
219.90
219.90
219.90
219.90
231.18
231.18
231.18
231.18
231.18
226.63
226.63
226.63
226.63
226.63
227.26
227.26
227.26
227.26
227.26
229.29
229.29
229.29
229.29
229.29
221.46
221.46
221.46
221.46
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7673.00
7673.00
7673.00
7673.00
7673.00
7674.00
7675.00
7676.00
7677.00
7678.00
7679.00
7680.00
7681.00
7682.00
7684.00
7685.00
7687.00
7689.00
7690.00
7692.00
7692.00
7693.00
7693.00
7694.00
7694.00
7695.00
7695.00
7695.00
7696.00
7696.00
7697.00
7697.00
7697.00
7698.00
7698.00
7698.33
7698.66
7698.99
7699.32
7699.65
7699.98
7700.31
7700.64
7700.97
7701.30
7701.63
49.440
48.411
48.411
49.440
47.381
47.381
42.230
44.289
45.319
47.381
45.319
46.348
43.260
40.172
39.138
39.138
32.962
35.020
35.020
32.962
30.899
26.781
30.899
31.928
31.928
30.899
29.869
27.810
27.810
24.718
22.659
22.659
24.718
22.659
24.718
22.659
23.689
20.600
18.542
19.571
20.600
21.630
20.600
21.630
17.508
17.508
004493
2:32:26
2:32:28
2:32:30
2:32:32
2:32:34
2:32:36
2:32:38
2:32:40
2:32:42
2:32:44
2:32:46
2:32:48
2:32:50
2:32:52
2:32:54
2:32:56
2:32:58
2:33:00
2:33:02
2:33:04
2:33:06
2:33:08
2:33:10
2:33:12
2:33:14
2:33:16
2:33:18
2:33:20
2:33:22
2:33:24
2:33:26
2:33:28
2:33:30
2:33:32
2:33:34
2:33:36
2:33:38
2:33:40
2:33:42
2:33:44
2:33:46
2:33:48
2:33:50
2:33:52
2:33:54
2:33:56
59.984
59.988
59.989
59.987
59.987
59.991
59.993
59.992
59.991
59.989
59.986
59.983
59.983
59.988
59.993
59.996
59.998
59.999
60.001
59.999
59.999
59.999
60.002
60.005
60.007
60.008
60.011
60.014
60.017
60.019
60.021
60.017
60.017
60.019
60.023
60.024
60.025
60.021
60.019
60.024
60.024
60.021
60.020
60.025
60.024
60.020
3761.41
3762.74
3763.21
3764.96
3766.09
3766.43
3767.25
3767.79
3768.63
3771.15
3772.44
3773.69
3774.67
3775.84
3775.36
3774.87
3775.49
3776.42
3778.55
3779.69
3781.26
3780.59
3783.09
3783.90
3784.42
3785.77
3785.46
3786.85
3786.30
3787.26
3787.52
3787.96
3788.03
3788.61
3789.22
3787.54
3785.84
3786.08
3787.93
3788.76
3786.87
3786.55
3787.36
3785.02
3785.61
3785.95
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
221.46
241.27
241.27
241.27
241.27
241.27
243.07
243.07
243.07
243.07
243.07
241.67
241.67
241.67
241.67
241.67
228.15
228.15
228.15
228.15
228.15
235.13
235.13
235.13
235.13
235.13
246.43
246.43
246.43
246.43
246.43
236.55
236.55
236.55
236.55
236.55
230.30
230.30
230.30
230.30
230.30
231.18
231.18
231.18
231.18
231.18
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7701.96
7702.29
7702.62
7702.95
7703.28
7703.61
7703.94
7704.27
7704.60
7704.93
7705.26
7705.59
7705.92
7706.25
7706.58
7706.91
7707.24
7707.57
7707.90
7708.23
7708.56
7708.89
7709.22
7709.55
7709.88
7710.21
7710.54
7710.87
7711.20
7711.53
7711.86
7712.19
7712.52
7712.85
7713.18
7713.51
7713.84
7714.17
7714.50
7714.83
7715.16
7715.49
7715.82
7716.15
7716.48
7716.81
16.479
12.361
11.332
13.391
13.391
9.269
7.210
8.239
9.269
11.332
14.420
17.508
17.508
12.361
7.210
4.122
2.059
1.029
-1.029
1.029
1.029
1.029
-2.059
-5.151
-7.210
-8.239
-11.332
-14.420
-17.508
-19.571
-21.630
-17.508
-17.508
-19.571
-23.689
-24.718
-25.752
-21.630
-19.571
-24.718
-24.718
-21.630
-20.600
-25.752
-24.718
-20.600
004494
2:33:58
2:34:00
2:34:02
2:34:04
2:34:06
2:34:08
2:34:10
2:34:12
2:34:14
2:34:16
2:34:18
2:34:20
2:34:22
2:34:24
2:34:26
2:34:28
2:34:30
2:34:32
2:34:34
2:34:36
2:34:38
2:34:40
2:34:42
2:34:44
2:34:46
2:34:48
2:34:50
2:34:52
2:34:54
2:34:56
2:34:58
2:35:00
2:35:02
2:35:04
2:35:06
2:35:08
2:35:10
2:35:12
2:35:14
2:35:16
2:35:18
2:35:20
2:35:22
2:35:24
2:35:26
2:35:28
60.020
60.022
60.022
60.022
60.021
60.021
60.023
60.023
60.022
60.019
60.016
60.018
60.018
60.018
60.019
60.019
60.016
60.015
60.016
60.014
60.013
60.012
60.012
60.010
60.007
60.007
60.009
60.009
60.010
60.003
59.999
59.995
59.992
59.991
59.992
59.992
59.988
59.986
59.985
59.984
59.985
59.984
59.982
59.981
59.982
59.979
3785.80
3786.86
3786.88
3785.25
3785.73
3786.35
3785.82
3785.80
3786.28
3786.94
3787.63
3789.44
3789.67
3789.40
3788.48
3789.18
3789.37
3789.00
3788.66
3788.93
3790.67
3790.81
3790.41
3789.77
3791.54
3792.95
3791.03
3791.44
3791.43
3790.60
3790.46
3790.22
3789.58
3788.46
3788.10
3788.06
3788.19
3788.50
3788.54
3788.57
3788.10
3787.13
3786.45
3787.73
3788.81
3789.29
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
225.62
225.62
225.62
225.62
225.62
230.73
230.73
230.73
230.73
230.73
234.85
234.85
234.85
234.85
234.85
228.96
228.96
228.96
228.96
228.96
231.18
231.18
231.18
231.18
231.18
236.49
236.49
236.49
236.49
236.49
245.04
245.04
245.04
245.04
245.04
223.61
223.61
223.61
223.61
223.61
231.12
231.12
231.12
231.12
231.12
237.21
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7717.14
7717.47
7717.80
7718.13
7718.46
7718.79
7719.12
7719.45
7719.78
7720.11
7720.44
7720.77
7721.10
7721.43
7721.76
7722.09
7722.42
7722.75
7723.08
7723.41
7723.74
7724.07
7724.40
7724.73
7725.06
7725.39
7725.72
7726.05
7726.38
7726.71
7727.04
7727.37
7727.70
7728.03
7728.36
7728.69
7729.02
7729.35
7729.68
7730.01
7730.34
7730.67
7731.00
7731.33
7731.66
7731.99
-20.600
-22.659
-22.659
-22.659
-21.630
-21.630
-23.689
-23.689
-22.659
-19.571
-16.479
-18.542
-18.542
-18.542
-19.571
-19.571
-16.479
-15.449
-16.479
-14.420
-13.391
-12.361
-12.361
-10.298
-7.210
-7.210
-9.269
-9.269
-10.298
-3.088
1.029
5.151
8.239
9.269
8.239
8.239
12.361
14.420
15.449
16.479
15.449
16.479
18.542
19.571
18.542
21.630
004495
2:35:30
2:35:32
2:35:34
2:35:36
2:35:38
2:35:40
2:35:42
2:35:44
2:35:46
2:35:48
2:35:50
2:35:52
2:35:54
2:35:56
2:35:58
2:36:00
2:36:02
2:36:04
2:36:06
2:36:08
2:36:10
2:36:12
2:36:14
2:36:16
2:36:18
2:36:20
2:36:22
2:36:24
2:36:26
2:36:28
2:36:30
2:36:32
2:36:34
2:36:36
2:36:38
2:36:40
2:36:42
2:36:44
2:36:46
2:36:48
2:36:50
2:36:52
2:36:54
2:36:56
2:36:58
2:37:00
59.977
59.976
59.976
59.979
59.982
59.978
59.976
59.974
59.976
59.977
59.977
59.975
59.973
59.969
59.970
59.971
59.973
59.978
59.981
59.978
59.975
59.972
59.976
59.975
59.973
59.969
59.966
59.965
59.966
59.969
59.970
59.968
59.965
59.964
59.970
59.972
59.967
59.967
59.969
59.968
59.969
59.967
59.967
59.966
59.965
59.971
3788.26
3788.41
3790.47
3790.66
3790.42
3789.67
3789.27
3789.15
3790.43
3789.91
3786.24
3787.44
3788.96
3790.60
3791.88
3792.91
3792.31
3789.13
3788.08
3787.84
3787.14
3787.16
3787.00
3787.40
3786.49
3787.08
3789.21
3790.51
3791.22
3792.22
3790.96
3788.82
3789.03
3789.17
3787.39
3785.69
3784.83
3785.01
3784.32
3782.81
3782.11
3779.35
3779.06
3778.63
3779.21
3779.33
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
237.21
237.21
237.21
237.21
240.52
240.52
240.52
240.52
240.52
237.57
237.57
237.57
237.57
237.57
231.58
231.58
231.58
231.58
231.58
235.85
235.85
235.85
235.85
235.85
233.56
233.56
233.56
233.56
233.56
219.01
219.01
219.01
219.01
219.01
205.34
205.34
205.34
205.34
205.34
236.29
236.29
236.29
236.29
236.29
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7732.32
7732.65
7732.98
7733.31
7733.64
7733.97
7734.30
7734.63
7734.96
7735.29
7735.62
7735.95
7736.28
7736.61
7736.94
7737.27
7737.60
7737.93
7738.26
7738.59
7738.92
7739.25
7739.58
7739.91
7740.24
7740.57
7740.90
7741.23
7741.56
7741.89
7742.22
7742.55
7742.88
7743.21
7743.54
7743.87
7744.20
7744.53
7744.86
7745.19
7745.52
7745.85
7746.18
7746.51
7746.84
7747.17
23.689
24.718
24.718
21.630
18.542
22.659
24.718
26.781
24.718
23.689
23.689
25.752
27.810
31.928
30.899
29.869
27.810
22.659
19.571
22.659
25.752
28.840
24.718
25.752
27.810
31.928
35.020
36.050
35.020
31.928
30.899
32.962
36.050
37.079
30.899
28.840
33.991
33.991
31.928
32.962
31.928
33.991
33.991
35.020
36.050
29.869
004496
2:37:02
2:37:04
2:37:06
2:37:08
2:37:10
2:37:12
2:37:14
2:37:16
2:37:18
2:37:20
2:37:22
2:37:24
2:37:26
2:37:28
2:37:30
2:37:32
2:37:34
2:37:36
2:37:38
2:37:40
2:37:42
2:37:44
2:37:46
2:37:48
2:37:50
2:37:52
2:37:54
2:37:56
2:37:58
2:38:00
2:38:02
2:38:04
2:38:06
2:38:08
2:38:10
2:38:12
2:38:14
2:38:16
2:38:18
2:38:20
2:38:22
2:38:24
2:38:26
2:38:28
2:38:30
2:38:32
59.967
59.965
59.962
59.964
59.970
59.967
59.969
59.968
59.963
59.965
59.970
59.973
59.968
59.965
59.968
59.969
59.967
59.964
59.966
59.979
59.990
59.983
59.974
59.967
59.965
59.962
59.962
59.961
59.961
59.960
59.963
59.959
59.956
59.951
59.953
59.954
59.957
59.956
59.961
59.963
59.961
59.959
59.963
59.963
59.965
59.968
3776.43
3775.65
3776.60
3776.56
3776.02
3773.17
3771.73
3768.79
3768.50
3768.92
3767.37
3764.79
3760.30
3759.59
3761.89
3761.78
3760.58
3760.16
3759.78
3759.49
3757.77
3753.28
3753.09
3751.64
3753.75
3758.22
3759.25
3758.04
3760.96
3762.02
3763.82
3763.10
3763.86
3764.16
3766.13
3768.34
3767.97
3767.44
3765.61
3762.69
3761.57
3761.92
3759.63
3758.52
3752.43
3750.10
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7747.50
7747.83
7748.16
7748.49
7748.82
7749.15
7749.48
7749.81
7750.14
7750.47
7750.80
7751.13
7751.46
7751.79
7752.12
7752.45
7752.78
7753.11
7753.44
7753.77
7754.10
7754.43
7754.76
7755.09
7755.42
7755.75
7756.08
7756.41
7756.74
7757.07
7757.40
7757.73
7758.06
7758.39
7758.72
7759.05
7759.38
7759.71
7760.04
7760.37
7760.70
7761.03
7761.36
7761.69
7762.02
7762.35
33.991
36.050
39.138
37.079
30.899
33.991
31.928
32.962
38.109
36.050
30.899
27.810
32.962
36.050
32.962
31.928
33.991
37.079
35.020
21.630
10.298
17.508
26.781
33.991
36.050
39.138
39.138
40.172
40.172
41.201
38.109
42.230
45.319
50.470
48.411
47.381
44.289
45.319
40.172
38.109
40.172
42.230
38.109
38.109
36.050
32.962
004497
2:38:34
2:38:36
2:38:38
2:38:40
2:38:42
2:38:44
2:38:46
2:38:48
2:38:50
2:38:52
2:38:54
2:38:56
2:38:58
2:39:00
2:39:02
2:39:04
2:39:06
2:39:08
2:39:10
2:39:12
2:39:14
2:39:16
2:39:18
2:39:20
2:39:22
2:39:24
2:39:26
2:39:28
2:39:30
2:39:32
2:39:34
2:39:36
2:39:38
2:39:40
2:39:42
2:39:44
2:39:46
2:39:48
2:39:50
2:39:52
2:39:54
2:39:56
2:39:58
2:40:00
2:40:02
2:40:04
59.968
59.968
59.970
59.973
59.971
59.965
59.967
59.967
59.972
59.976
59.975
59.969
59.973
59.974
59.978
59.981
59.981
59.981
59.982
59.982
59.984
59.982
59.981
59.979
59.980
59.978
59.978
59.980
59.981
59.980
59.978
59.976
59.972
59.971
59.969
59.974
59.975
59.976
59.972
59.969
59.971
59.974
59.972
59.972
59.972
59.977
3753.83
3753.51
3753.52
3752.74
3753.18
3752.73
3753.29
3752.87
3752.36
3749.40
3747.48
3740.37
3741.29
3746.65
3745.74
3743.35
3741.62
3740.31
3738.48
3738.90
3737.40
3737.27
3736.31
3736.27
3735.45
3735.65
3737.54
3738.01
3736.75
3736.69
3736.07
3736.09
3736.57
3738.57
3738.87
3738.93
3738.65
3737.68
3737.38
3737.89
3740.02
3740.33
3742.05
3742.42
3742.52
3742.25
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7762.68
7763.01
7763.34
7763.67
7764.00
7764.33
7764.66
7764.99
7765.32
7765.65
7765.98
7766.31
7766.64
7766.97
7767.30
7767.63
7767.96
7768.29
7768.62
7768.95
7769.28
7769.61
7769.94
7770.27
7770.60
7770.93
7771.26
7771.59
7771.92
7772.25
7772.58
7772.91
7773.24
7773.57
7773.90
7774.23
7774.56
7774.89
7775.22
7775.55
7775.88
7776.21
7776.54
7776.87
7777.20
7777.53
32.962
32.962
30.899
27.810
29.869
36.050
33.991
33.991
28.840
24.718
25.752
31.928
27.810
26.781
22.659
19.571
19.571
19.571
18.542
18.542
16.479
18.542
19.571
21.630
20.600
22.659
22.659
20.600
19.571
20.600
22.659
24.718
28.840
29.869
31.928
26.781
25.752
24.718
28.840
31.928
29.869
26.781
28.840
28.840
28.840
23.689
004498
2:40:06
2:40:08
2:40:10
2:40:12
2:40:14
2:40:16
2:40:18
2:40:20
2:40:22
2:40:24
2:40:26
2:40:28
2:40:30
2:40:32
2:40:34
2:40:36
2:40:38
2:40:40
2:40:42
2:40:44
2:40:46
2:40:48
2:40:50
2:40:52
2:40:54
2:40:56
2:40:58
2:41:00
2:41:02
2:41:04
2:41:06
2:41:08
2:41:10
2:41:12
2:41:14
2:41:16
2:41:18
2:41:20
2:41:22
2:41:24
2:41:26
2:41:28
2:41:30
2:41:32
2:41:34
2:41:36
59.982
59.978
59.976
59.973
59.974
59.977
59.977
59.978
59.979
59.981
59.977
59.974
59.971
59.971
59.971
59.972
59.968
59.966
59.966
59.971
59.973
59.972
59.969
59.972
59.974
59.973
59.970
59.971
59.974
59.982
59.985
59.985
59.985
59.987
59.989
59.989
59.986
59.987
59.990
59.994
59.996
60.001
60.003
60.004
60.006
60.012
3741.72
3740.09
3740.63
3739.96
3740.78
3742.83
3741.27
3739.78
3738.97
3738.71
3738.88
3739.86
3738.10
3738.56
3743.51
3743.42
3745.25
3745.74
3747.34
3750.70
3749.75
3746.22
3744.68
3743.75
3743.15
3740.30
3739.45
3733.38
3731.83
3737.58
3736.23
3734.90
3733.43
3733.12
3730.51
3729.18
3725.46
3724.78
3720.11
3720.94
3725.66
3725.68
3727.75
3727.82
3727.68
3727.23
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7777.86
7778.19
7778.52
7778.85
7779.18
7779.51
7779.84
7780.17
7780.50
7780.83
7781.16
7781.49
7781.82
7782.15
7782.48
7782.81
7783.14
7783.47
7783.80
7784.13
7784.46
7784.79
7785.12
7785.45
7785.78
7786.11
7786.44
7786.77
7787.10
7787.43
7787.76
7788.09
7788.42
7788.75
7789.08
7789.41
7789.74
7790.07
7790.40
7790.73
7791.06
7791.39
7791.72
7792.05
7792.38
7792.71
18.542
22.659
24.718
27.810
26.781
23.689
23.689
22.659
21.630
19.571
23.689
26.781
29.869
29.869
29.869
28.840
32.962
35.020
35.020
29.869
27.810
28.840
31.928
28.840
26.781
27.810
30.899
29.869
26.781
18.542
15.449
15.449
15.449
13.391
11.332
11.332
14.420
13.391
10.298
6.181
4.122
-1.029
-3.088
-4.122
-6.181
-12.361
004499
2:41:38
2:41:40
2:41:42
2:41:44
2:41:46
2:41:48
2:41:50
2:41:52
2:41:54
2:41:56
2:41:58
2:42:00
2:42:02
2:42:04
2:42:06
2:42:08
2:42:10
2:42:12
2:42:14
2:42:16
2:42:18
2:42:20
2:42:22
2:42:24
2:42:26
60.014
60.019
60.021
60.025
60.026
60.027
60.029
60.029
60.037
60.036
60.037
60.037
60.036
60.041
60.043
60.044
60.043
60.046
60.048
60.046
60.046
60.043
60.043
60.044
60.043
3725.01
3726.45
3726.02
3719.12
3716.37
3717.33
3717.56
3717.14
3715.17
3713.63
3710.28
3710.16
3699.36
3698.59
3704.59
3703.28
3702.48
3701.32
3700.83
3699.53
3699.73
3690.10
3690.48
3696.86
3696.88
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
350.00
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
223.02
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
16.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
10.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7793.04
7793.37
7793.70
7794.03
7794.36
7794.69
7795.02
7795.35
7795.68
7796.01
7796.34
7796.67
7797.00
7797.33
7797.66
7797.99
7798.32
7798.65
7798.98
7799.31
7799.64
7799.97
7800.30
7800.63
7800.96
-14.420
-19.571
-21.630
-25.752
-26.781
-27.810
-29.869
-29.869
-38.109
-37.079
-38.109
-38.109
-37.079
-42.230
-44.289
-45.319
-44.289
-47.381
-49.440
-47.381
-47.381
-44.289
-44.289
-45.319
-44.289
004500
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Po
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Interchange MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Interchange MW [T(+20 to T(+52)]
Pre to Post Perturbation Interchange Delta MW Actual
Monday, October 12, 2009
2:27:26
2:33:00
60.042
59.889
-0.153
3645.73
3803.35
157.63
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre JOU Dynamic Schedules MW
Pre Non-Conforming Load MW
Pre Pumped Hydro MW
-43.39
114.21
157.60
198.04
350.00
165.34
0.00
MW
MW
MW
MW
MW
MW
MW
Pre Transferred Frequency Response MW
Pre Contingent BA Lost Generation MW
Sum of Pre Perturbation Adjustments
-4.21 MW
15.00 MW
526.12 MW
Post JOU Dynamic Schedules MW
Post Non-Conforming Load MW
Post Pumped Hydro MW
335.00 MW
214.13 MW
6.35 MW
Post Transferred Frequency Response MW
Post Contingent BA Lost Generation MW
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
11.09
0.00
566.57
40.45
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.890
59.863
59.899
59.920
59.937
113.30
141.11
104.03
82.40
64.89
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-103.00
Post-Perturbation Bias Setting
-103.00
EPFR for Bias Setting Pre-Perturbation Average
-43.39
EPFR for Bias Setting Post-Perturbation Average
114.21
EPFR for Bias Setting Delta
157.60
Primary Frequency Response Delivery % of Bias
100.02%
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
Average Bias Setting when Hz is greater than +/-0.036 Hz
7651.3
7632.0
-19.305
-12.617
12.25%
Hz
Hz
Hz
Hz
Hz
MW
MW
MW
MW
MW
Actual
Primary
Freq Response
MW
158.51
182.41
164.54
129.49
119.99
Un-adjusted
P.U.
Performance
1.399
1.293
1.582
1.571
1.849
JOU
NonDynamic
Conforming
Schedules
Load
Adjustment
Adjustment
-15.00
50.26
-15.00
49.49
-15.00
63.03
-15.00
64.13
-15.00
63.75
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
-103.00 MW/0.1 Hz
20 to 52 second Average Period Evaluation
Frequency
Hz
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
JOU
NonNet
Dynamic
Conforming
Actual
Schedules
Load
Interchange Imp(-) Exp (+)
Load (-)
MW
MW
MW
1.000 P.U.
0.744 P.U.
Pumped
Hydro
Load (-) Gen (+)
MW
Transferred
Frequency
Response
Rec (-) Del (+)
MW/0.1 Hz
Contingent
BA
Lost Generation
Load (-) Gen (+)
MW
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
EPFR
MW
Expected
Net
Actual
Interchange
MW
Actual
Primary
Freq Response
MW
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
0.0270
0.0260
0.0260
004501
60.042
60.042
60.042
60.042
60.042
60.042
60.042
60.042
59.889
59.889
59.889
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3645.73
3788.35
3788.35
3788.35
350.000
350.000
350.000
350.000
350.000
350.000
350.000
350.000
335.000
335.000
335.000
165.336
165.336
165.336
165.336
165.336
165.336
165.336
165.336
214.128
214.128
214.128
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
6.353
6.353
6.353
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
15.000
0.000
0.000
0.000
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7651.31
7632.00
7632.00
7632.00
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
-43.389
114.209
114.209
114.209
3843.77
3843.77
3843.77
51.252
89.794
89.563
89.563
92.047
116.139
121.003
121.084
123.767
124.815
135.511
136.482
-26.96
-43.56
-51.73
-51.73
-61.31
-76.85
-74.64
-72.89
-74.06
-78.44
-87.36
-87.42
0.0220
0.0190
0.0170
0.0190
0.0200
0.0190
0.0210
0.0210
0.0210
0.0190
0.0180
0.0220
0.0310
0.0370
0.0370
0.0360
0.0370
0.0460
0.0480
0.0480
0.0430
0.0410
0.0410
0.0410
0.0390
0.0410
0.0430
0.0450
0.0460
0.0410
0.0410
0.0410
0.0390
0.0220
0.1480
0.1640
0.1310
0.1310
0.1080
0.1090
0.1200
0.1240
0.1250
0.1170
0.1130
0.1140
004502
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
59.889
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
3788.35
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
335.000
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
214.128
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
6.353
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
10.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
-103.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
7632.00
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
114.209
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
3843.77
137.389
139.852
139.620
139.309
142.962
143.218
143.758
143.362
147.166
147.964
149.264
154.318
155.317
154.849
158.515
157.815
157.841
159.278
160.386
160.507
164.127
166.393
169.752
170.779
180.532
180.943
180.892
182.414
181.643
181.673
181.344
180.603
178.716
177.395
173.971
172.945
171.705
169.900
168.673
166.728
164.542
161.862
160.483
159.078
150.968
-87.44
-90.15
-90.59
-91.57
-97.17
-96.69
-96.40
-96.78
-99.35
-97.91
-98.12
-98.21
-98.85
-100.47
-102.19
-102.39
-102.41
-104.70
-104.74
-100.24
-97.05
-89.88
-87.90
-89.82
-98.05
-101.01
-102.71
-102.99
-103.72
-103.15
-105.97
-107.42
-109.56
-109.42
-109.33
-110.77
-112.87
-113.17
-110.15
-111.81
-114.96
-116.34
-114.53
-113.53
-109.30
0.1150
0.1130
0.1120
0.1100
0.1050
0.1060
0.1070
0.1060
0.1060
0.1090
0.1100
0.1150
0.1150
0.1120
0.1130
0.1120
0.1120
0.1100
0.1110
0.1180
0.1270
0.1430
0.1510
0.1480
0.1420
0.1370
0.1340
0.1350
0.1330
0.1340
0.1290
0.1260
0.1210
0.1200
0.1170
0.1140
0.1100
0.1080
0.1110
0.1070
0.1010
0.0970
0.0980
0.0980
0.0960
004503
148.865
147.059
146.392
144.424
143.022
139.453
137.918
136.591
131.248
130.525
129.494
128.224
128.848
127.612
126.560
124.520
123.597
122.533
121.911
122.298
121.678
121.149
120.562
121.012
119.133
119.995
117.825
113.277
108.812
104.757
101.779
102.765
104.483
103.551
101.596
103.967
97.631
95.149
91.029
86.272
82.728
80.842
77.539
75.468
72.886
73.032
-110.17
-112.15
-116.07
-114.51
-114.30
-112.35
-112.93
-112.77
-107.47
-104.32
-106.03
-105.86
-108.16
-109.89
-108.05
-109.11
-107.36
-111.27
-105.89
-107.16
-109.50
-107.09
-108.49
-110.89
-113.32
-114.15
-121.31
-121.64
-114.39
-104.63
-100.65
-102.64
-107.58
-110.02
-106.80
-111.64
-107.14
-105.57
-102.14
-94.67
-91.79
-89.70
-86.03
-86.62
-80.87
-82.87
0.0930
0.0890
0.0840
0.0840
0.0830
0.0820
0.0800
0.0790
0.0800
0.0830
0.0800
0.0790
0.0770
0.0740
0.0750
0.0720
0.0730
0.0680
0.0730
0.0720
0.0690
0.0710
0.0690
0.0670
0.0630
0.0630
0.0550
0.0510
0.0530
0.0580
0.0590
0.0580
0.0550
0.0520
0.0530
0.0510
0.0490
0.0480
0.0470
0.0490
0.0480
0.0480
0.0480
0.0450
0.0480
0.0460
004504
70.643
68.584
68.374
65.738
65.700
66.982
69.512
70.020
71.058
71.351
71.870
72.649
77.251
76.863
77.548
77.157
77.168
76.677
77.981
78.874
78.324
78.783
80.293
82.011
82.943
86.020
87.420
88.217
91.425
91.797
91.712
93.589
94.834
95.767
96.684
100.124
101.498
103.190
105.606
106.448
107.637
110.489
111.297
111.865
115.295
115.872
-78.38
-76.95
-76.72
-72.94
-74.55
-76.01
-83.62
-82.26
-82.51
-80.96
-83.45
-83.39
-91.83
-94.74
-96.79
-96.30
-104.10
-100.72
-102.44
-106.40
-108.60
-115.64
-111.33
-112.15
-113.43
-119.27
-122.91
-127.62
-132.26
-138.83
-143.02
-145.95
-143.42
-149.35
-146.22
-156.14
-155.85
-166.10
-175.64
-174.14
-173.26
-175.03
-179.15
-177.21
-195.01
-195.98
0.0480
0.0470
0.0470
0.0480
0.0460
0.0460
0.0410
0.0430
0.0440
0.0460
0.0440
0.0450
0.0420
0.0390
0.0380
0.0380
0.0320
0.0340
0.0340
0.0320
0.0300
0.0260
0.0300
0.0310
0.0310
0.0300
0.0290
0.0270
0.0270
0.0240
0.0220
0.0220
0.0240
0.0220
0.0240
0.0220
0.0230
0.0200
0.0180
0.0190
0.0200
0.0210
0.0200
0.0210
0.0170
0.0170
004505
116.297
117.627
118.102
119.847
120.975
121.323
122.141
122.682
123.523
126.036
127.335
128.585
129.558
130.731
130.253
129.756
130.382
131.310
132.827
133.965
135.529
134.868
137.365
138.168
138.694
140.041
139.736
141.123
140.577
141.532
141.789
142.228
142.303
142.880
143.489
141.810
140.115
140.350
142.203
143.033
141.148
140.823
141.631
139.291
139.887
140.222
-200.08
-217.32
-222.30
-217.41
-219.45
-237.31
-248.63
-244.75
-241.61
-237.24
-226.88
-217.48
-219.13
-241.53
-265.15
-281.30
-295.49
-304.49
0.0160
0.0120
0.0110
0.0130
0.0130
0.0090
0.0070
0.0080
0.0090
0.0110
0.0140
0.0170
0.0170
0.0120
0.0070
0.0040
0.0020
0.0010
0.0010
0.0010
0.0010
0.0010
0.0020
0.0050
0.0070
0.0080
0.0110
0.0140
0.0170
0.0190
0.0210
0.0170
0.0170
0.0190
0.0230
0.0240
0.0250
0.0210
0.0190
0.0240
0.0240
0.0210
0.0200
0.0250
0.0240
0.0200
004506
140.077
141.137
141.150
139.527
139.999
140.620
140.094
140.071
140.557
141.212
141.900
143.717
143.946
143.677
142.752
143.456
143.642
143.278
142.938
143.206
144.940
145.078
144.684
144.042
145.813
147.218
145.300
145.716
145.699
144.876
144.730
144.489
143.858
142.730
142.378
142.330
142.462
142.770
142.813
142.844
142.374
141.406
140.726
142.005
143.086
143.558
0.0200
0.0220
0.0220
0.0220
0.0210
0.0210
0.0230
0.0230
0.0220
0.0190
0.0160
0.0180
0.0180
0.0180
0.0190
0.0190
0.0160
0.0150
0.0160
0.0140
0.0130
0.0120
0.0120
0.0100
0.0070
0.0070
0.0090
0.0090
0.0100
0.0030
0.0010
0.0050
0.0080
0.0090
0.0080
0.0080
0.0120
0.0140
0.0150
0.0160
0.0150
0.0160
0.0180
0.0190
0.0180
0.0210
004507
142.529
142.683
144.740
144.938
144.693
143.947
143.540
143.421
144.703
144.187
140.516
141.715
143.236
144.875
146.150
147.184
146.584
143.398
142.353
142.117
141.408
141.437
141.269
141.678
140.760
141.352
143.487
144.785
145.494
146.491
145.232
143.097
143.299
143.440
141.667
139.963
139.104
139.282
138.593
137.082
136.383
133.625
133.329
132.906
133.485
133.608
0.0230
0.0240
0.0240
0.0210
0.0180
0.0220
0.0240
0.0260
0.0240
0.0230
0.0230
0.0250
0.0270
0.0310
0.0300
0.0290
0.0270
0.0220
0.0190
0.0220
0.0250
0.0280
0.0240
0.0250
0.0270
0.0310
0.0340
0.0350
0.0340
0.0310
0.0300
0.0320
0.0350
0.0360
0.0300
0.0280
0.0330
0.0330
0.0310
0.0320
0.0310
0.0330
0.0330
0.0340
0.0350
0.0290
004508
130.702
129.920
130.870
130.832
130.296
127.443
126.003
123.066
122.776
123.190
121.639
119.059
114.568
113.865
116.167
116.050
114.855
114.430
114.054
113.768
112.046
107.550
107.360
105.910
108.024
112.498
113.523
112.314
115.238
116.295
118.095
117.373
118.131
118.431
120.400
122.612
122.245
121.710
119.879
116.961
115.843
116.193
113.900
112.795
106.702
104.375
0.0330
0.0350
0.0380
0.0360
0.0300
0.0330
0.0310
0.0320
0.0370
0.0350
0.0300
0.0270
0.0320
0.0350
0.0320
0.0310
0.0330
0.0360
0.0340
0.0210
0.0100
0.0170
0.0260
0.0330
0.0350
0.0380
0.0380
0.0390
0.0390
0.0400
0.0370
0.0410
0.0440
0.0490
0.0470
0.0460
0.0430
0.0440
0.0390
0.0370
0.0390
0.0410
0.0370
0.0370
0.0350
0.0320
004509
108.103
107.783
107.796
107.014
107.451
107.002
107.563
107.145
106.632
103.671
101.749
94.643
95.558
100.924
100.011
97.624
95.891
94.579
92.757
93.174
91.677
91.546
90.581
90.545
89.721
89.923
91.813
92.285
91.021
90.966
90.340
90.367
90.848
92.844
93.148
93.208
92.920
91.957
91.655
92.165
94.290
94.602
96.326
96.697
96.797
96.518
0.0320
0.0320
0.0300
0.0270
0.0290
0.0350
0.0330
0.0330
0.0280
0.0240
0.0250
0.0310
0.0270
0.0260
0.0220
0.0190
0.0190
0.0190
0.0180
0.0180
0.0160
0.0180
0.0190
0.0210
0.0200
0.0220
0.0220
0.0200
0.0190
0.0200
0.0220
0.0240
0.0280
0.0290
0.0310
0.0260
0.0250
0.0240
0.0280
0.0310
0.0290
0.0260
0.0280
0.0280
0.0280
0.0230
004510
95.996
94.358
94.902
94.237
95.048
97.105
95.541
94.049
93.239
92.979
93.152
94.133
92.375
92.831
97.780
97.692
99.524
100.017
101.613
104.973
104.023
100.490
98.956
98.018
97.422
94.572
93.726
87.649
86.103
91.855
90.502
89.170
87.707
87.388
84.783
83.453
79.732
79.058
74.381
75.211
79.934
79.950
82.027
82.098
81.956
81.504
0.0180
0.0220
0.0240
0.0270
0.0260
0.0230
0.0230
0.0220
0.0210
0.0190
0.0230
0.0260
0.0290
0.0290
0.0290
0.0280
0.0320
0.0340
0.0340
0.0290
0.0270
0.0280
0.0310
0.0280
0.0260
0.0270
0.0300
0.0290
0.0260
0.0180
0.0150
0.0150
0.0150
0.0130
0.0110
0.0110
0.0140
0.0130
0.0100
0.0060
0.0040
0.0010
0.0030
0.0040
0.0060
0.0120
004511
79.285
80.719
80.289
73.396
70.647
71.605
71.833
71.415
69.439
67.905
64.556
64.431
53.629
52.864
58.864
57.548
56.755
55.589
55.099
53.802
53.999
44.373
44.750
51.137
51.150
0.0140
0.0190
0.0210
0.0250
0.0260
0.0270
0.0290
0.0290
0.0370
0.0360
0.0370
0.0370
0.0360
0.0410
0.0430
0.0440
0.0430
0.0460
0.0480
0.0460
0.0460
0.0430
0.0430
0.0440
0.0430
004512
ncy Response Evaluation Points
Transferred
Contingent
Pumped
Frequency
BA
Adjusted
Hydro
Response
Lost Generation
P.U.
Adjustment Adjustment
Adjustment
Performance
11.00
15.21
-15.00
0.856
16.00
17.91
-15.00
0.808
16.00
14.31
-15.00
0.829
16.00
12.21
-15.00
0.633
16.00
10.51
-15.00
0.689
004513
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004514
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004515
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004516
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004517
004518
004519
004520
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004521
004522
004523
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
-103
004524
Monday, October 12, 2009
Balancing Authority
MyBA
60.08
60.06
1.000
0.744
Initial P.U. Performance
Initial P.U. Performance Adjusted
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
3900.0
20 to 52 second Average Period
60.042
3843.77
60.04
3850.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
60.02
3803.32
60
3800.0
59.98
3788.35
59.96
Frequency - Hz
59.92
59.9
3700.0
59.88
59.889
59.86
3650.0
NAI MW
3750.0
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
59.84
3645.73
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
2:26:36
2:26:46
Hz
2:26:56
2:27:06
Average Frequency
2:27:16
MW
2:27:26
2:27:36
Average MW
2:27:46
2:27:56
EPFR Adjusted
2:28:06
2:28:16
EPFR Unadjusted
3500.0
2:28:26
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
004525
Monday, October 12, 2009
0.758
05:34
MyBA
60.08
Sustained P.U. Performance
Event Length mm:ss
3900.0
60.06
60.04
3850.0
60.02
60
3800.0
59.98
59.96
3750.0
59.92
59.9
3700.0
59.88
59.86
3650.0
59.84
59.82
3600.0
59.8
59.78
3550.0
59.76
59.74
59.72
2:26:26
3500.0
2:27:26
2:28:26
2:29:26
Hz
2:30:26
2:31:26
2:32:26
Interchange MW
2:33:26
2:34:26
2:35:26
2:36:26
Recovery Period Target MW
2:37:26
2:38:26
2:39:26
2:40:26
Recovery Period Ramp MW
2:41:26
2:42:26
NAI MW
Frequency - Hz
59.94
004526
Monday, October 12, 2009
-103.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
100.0
60.06
60.04
50.0
60.02
60
0.0
59.98
59.96
-50.0
59.92
-100.0
59.9
59.88
-150.0
59.86
59.84
-200.0
59.82
59.8
-250.0
59.78
59.76
-300.0
59.74
59.72
2:26:26
-350.0
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
Hz
2:32:26
2:33:26
BA Bias Setting
2:34:26
2:35:26
2:36:26
2:37:26
2:38:26
Actual Primary Freq Response Beta
2:39:26
2:40:26
2:41:26
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
004527
Value A Data
Date
Monday, October 12, 2009
A Value
Time
2:27:26
FPointA
Hz
60.039
A Value
Hz
60.042
t(0) Time
2:27:26
BA Performance
JOU
NonNet
Dynamic
Conforming
Pumped
Actual
Schedules
Load
Hydro
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
Hz
MW
MW
MW
MW
59.836
60.042
3645.73
350.00
165.34
0.00
C Value
Hz
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+) Load (-) Gen (+)
MW
MW
0.00
-4.21
15.00
Not
Used
004528
Value B
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
-103.00 7651.305
20 to 52 second Average Period Evaluation
JOU
NonBias
Net
Dynamic
Conforming
Pumped
Setting
Actual
Schedules
Load
Hydro
EPFR
Frequency Interchange Imp(-) Exp (+)
Load (-)
Load (-) Gen (+)
MW
Hz
MW
MW
MW
MW
-43.39
59.889
3803.35
335.00
165.34
6.35
Not
Used
0.00
Transferred
Contingent
Frequency
BA
Response
Lost Generation
Rec (-) Del (+)
Load (-) Gen (+)
MW
MW
11.09
0.00
Initial
Performance
Adjusted
P.U.
0.744
Initial
Performance
Unadjusted
P.U.
1.000
Sustained
Performance
P.U.
0.758
004529
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
BA
Bias
Setting
MW/0.1 Hz
-103.00
BA
Load
MW
7632.00
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
114.21
-103.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
1.399
1.293
1.582
1.571
1.849
0.856
0.808
0.829
0.633
0.689
004530
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz
MW/0.1 Hz
-103.00
-103.00
004531
Steps
1
2
3
4
5
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Net Actual Interchange
Column D: Joint Owned Unit dynamic schedule
Column E: Non Conforming Load
Column F: Pumped Hydro
Column G: Not Used
Column H: Transferred Frequency Response
Column I: Contingent BA Lost load or generation
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D, E, F and H are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only rarely should
you have to use the "Manual" process.
6
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
B
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "NYISO".
For informational and educational purposes, a "Sustained" performance evaluation is provided in the "Evaluation" worksheet and in the "Sustained" Graph. This evaluation uses a Time Constant (TC) to model the frequency response of your BA.
The time constant is located in cell "L13" of the "Evaluation" spreadsheet and should be edited for the types of generators in your BA. Presently this time constant is set at 0.35.
The higher the value of the time constant, the faster the delivery of frequency response is expected. Setting the TC to 1.0 effectively turns off the delay and instantaneous frequency response will be modeled. Do not set higher than 1.0.
This time constant is only used in the "Sustained" evaluation and is not used for the Field Trial evaluation of performance to the FRO.
A typical setting for this time constant is 0.08 to 0.15 for hydro units, 0.10 to 0.20 for large steam turbines and 0.20 to 0.40 for combustion turbines.
By observing the slope of your "Interchange Actual" on the "Sustained" Graph, adjust the time constant until the initial slope of the "Target" is similar to the slope of the NAI data.
When set appropriately, the "Target" trend on the "Sustained" graph will model what the Net Actua Interchange should have done during the event recovery period based on your Bias setting during the event.
004532
Monday, October 12, 2009
JOU
Dynamic
Schedules
Imp(-) Exp (+)
MyBA
60.08
355.0
60.06
60.04
60.02
350.0
60
59.98
59.96
345.0
59.92
MW
Frequency - Hz
59.94
59.9
340.0
A Value
B Value
Average Period
59.88
350.00
59.86
335.00
20 to 52 second
59.84
335.0
59.82
59.8
59.78
330.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
JOU Dynamic Schedules
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
325.0
2:42:26
004533
Monday, October 12, 2009
MyBA
NonConforming
60.08
300.0
Load
60.06
Load (-)
60.04
60.02
250.0
60
59.98
59.96
200.0
59.92
MW
Frequency - Hz
59.94
59.9
150.0
A Value
B Value
59.88
165.34
214.13
Average Period
20 to 52 second
59.86
59.84
100.0
59.82
59.8
59.78
50.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Non- Conforming Load
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
004534
Monday, October 12, 2009
MyBA
Pumped
Hydro
60.08
Load (-) Gen (+)
18.0
60.06
60.04
16.0
60.02
60
14.0
59.98
59.96
12.0
59.92
10.0
59.9
A Value
B Value
0.00
6.35
Average Period
59.88
8.0
20 to 52 second
59.86
59.84
6.0
59.82
59.8
4.0
59.78
59.76
2.0
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW
Frequency - Hz
59.94
004535
Monday, October 12, 2009
MyBA
Not
Used
60.08
1.2
60.06
60.04
60.02
1.0
60
59.98
59.96
0.8
59.92
MW
Frequency - Hz
59.94
59.9
0.6
A Value
B Value
59.88
Average Period
20 to 52 second
59.86
59.84
0.4
59.82
59.8
59.78
0.2
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
Pumped Hydro
2:36:26
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
004536
Monday, October 12, 2009
Transferred
MyBA
Frequency
Response
60.08
60.06
12.0
Rec (-) Del (+)
60.04
60.02
10.0
60
59.98
59.96
8.0
59.92
59.9
6.0
A Value
B Value
59.88
11.09
-4.21
Average Period
20 to 52 second
59.86
59.84
4.0
59.82
59.8
59.78
2.0
59.76
59.74
59.72
2:26:26
2:27:26
2:28:26
2:29:26
2:30:26
2:31:26
2:32:26
2:33:26
Hz
2:34:26
2:35:26
2:36:26
Frequency Response
2:37:26
2:38:26
2:39:26
2:40:26
2:41:26
0.0
2:42:26
MW/0.1 Hz
Frequency - Hz
59.94
004537
Monday, October 12, 2009
Contingent
BA
Lost Generation
MyBA
60.08
Load (-) Gen (+)
16.0
60.06
60.04
14.0
60.02
60
12.0
59.98
59.96
10.0
MW
Frequency - Hz
59.94
59.92
59.9
A Value
59.88
15.00
B Value
0.00
59.86
Average Period
8.0
20 to 52 second
6.0
59.84
59.82
4.0
59.8
59.78
2.0
59.76
59.74
59.72
2:26:26 2:27:26
2:28:26 2:29:26 2:30:26 2:31:26
2:32:26 2:33:26 2:34:26
Hz
2:35:26
2:36:26 2:37:26 2:38:26
BA Lost Generation
2:39:26
0.0
2:40:26 2:41:26 2:42:26
004538
Monday, October 12, 2009
BA
Load
MyBA
60.08
7850.0
60.06
60.04
7800.0
60.02
60
59.98
7750.0
59.96
7700.0
59.92
59.9
A Value
B Value
Average Period
59.88
7651.3
59.86
7632.0
20 to 52 second
7650.0
59.84
7600.0
59.82
59.8
59.78
7550.0
59.76
59.74
59.72
7500.0
2:26:26 2:27:26 2:28:26 2:29:26 2:30:26 2:31:26 2:32:26 2:33:26 2:34:26 2:35:26 2:36:26 2:37:26 2:38:26 2:39:26 2:40:26 2:41:26 2:42:26
Hz
BA Load
MW
Frequency - Hz
59.94
004539
Monday, October 12, 2009
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
200.0
60.06
60.04
60.02
150.0
60
59.98
59.96
100.0
59.92
MW
Frequency - Hz
59.94
59.9
50.0
59.88
59.86
59.84
0.0
59.82
59.8
59.78
-50.0
59.76
A Value
B Value
59.74
-43.39
59.72
2:26:26 2:27:26
2:28:26 2:29:26
2:30:26 2:31:26 2:32:26
Hz
2:33:26 2:34:26
114.21
2:35:26 2:36:26 2:37:26
Average Period
20 to 52 second
2:38:26 2:39:26
Expected Primary Freq Response Based on Bias Setting
-100.0
2:40:26 2:41:26 2:42:26
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
05/16/11 07:41:16
05/16/11 07:41:18
05/16/11 07:41:20
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
59.98578
59.9874
59.98868
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
29782.73
29782.73
29782.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004540
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
0.003
0.002
0.001
05/16/11 07:41:22
05/16/11 07:41:24
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
05/16/11 07:42:40
05/16/11 07:42:42
Hz
59.98999
59.99191
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
60.0152
60.0152
60.01486
60.01422
60.01358
60.01227
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.73
29782.82
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
29787.84
29813.39
29813.39
29813.39
29813.39
29813.39
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004541
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.001
0.002
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
Absolute
Delta Hz
0.001
0.002
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
Hz
60.01099
60.00873
60.00647
60.00485
60.00354
60.00195
60
59.99774
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
59.98514
59.98416
59.98352
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29813.33
29813.33
29813.33
29813.33
29813.33
29797.46
29797.46
29797.46
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004542
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
-0.002
-0.002
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
Absolute
Delta Hz
0.001
0.002
0.002
0.002
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
Hz
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
60.01227
60.01163
60.01065
60.0097
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004543
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
-0.001
-0.001
-0.001
-0.001
Absolute
Delta Hz
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.001
0.001
0.001
0.001
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
05/16/11 07:46:16
05/16/11 07:46:18
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
Hz
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
60.01422
60.01227
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
59.99646
59.99579
59.99417
59.99225
59.9903
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
29782.35
29782.35
29782.44
29782.44
29782.44
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004544
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
-0.001
-0.001
-0.002
-0.002
-0.002
Absolute
Delta Hz
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.002
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
0.001
0.001
0.002
0.002
0.002
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
Hz
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
60.02164
60.01971
60.01907
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
29794.69
29794.69
29794.69
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004545
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
-0.002
-0.001
-0.002
0.000
0.001
-0.001
-0.003
-0.001
Absolute
Delta Hz
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
0.002
0.001
0.002
0.000
0.001
0.001
0.003
0.001
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
05/16/11 07:49:32
Hz
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
60
60
60.00452
60.00583
60.00613
60.00583
60.00516
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
29795.55
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004546
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
-0.001
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
0.001
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
Hz
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
59.99225
59.99484
59.99646
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004547
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
0.000
0.003
0.002
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
Absolute
Delta Hz
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
0.000
0.003
0.002
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
05/16/11 07:51:24
05/16/11 07:51:26
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
Hz
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
59.97189
59.97125
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
29756.18
29756.18
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004548
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
Absolute
Delta Hz
0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
Hz
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
59.98868
59.98868
59.9874
59.98611
59.98611
59.98709
59.98837
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
29795.02
29795.02
29795.05
29795.05
29795.05
29795.05
29795.05
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004549
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
Absolute
Delta Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
Hz
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
60.00064
60.00098
60.00064
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
29823.76
29823.76
29818.41
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004550
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
Absolute
Delta Hz
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
05/16/11 07:56:00
05/16/11 07:56:02
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
Hz
59.98547
59.98547
59.98514
59.9845
59.9845
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
59.97641
59.9761
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29826.47
29826.41
29826.41
29826.41
29826.41
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004551
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
Absolute
Delta Hz
0.000
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.004
0.002
0.002
0.002
0.003
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
05/16/11 07:56:24
05/16/11 07:56:26
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
05/16/11 07:57:42
05/16/11 07:57:44
Hz
59.97803
59.97867
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
60.01938
60.02036
60.02197
60.02423
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
60.02261
60.02164
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29856.55
29856.55
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29889.67
29889.67
29889.67
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
29891.67
29891.64
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004552
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
-0.001
-0.001
Absolute
Delta Hz
0.000
0.001
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.001
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
05/16/11 07:58:38
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
Hz
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
60.02069
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
59.99451
59.99127
59.98965
59.98868
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
29887.14
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
29862.1
29862.1
29861.95
29861.95
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004553
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
-0.001
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
-0.005
-0.003
-0.002
-0.001
Absolute
Delta Hz
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
0.005
0.003
0.002
0.001
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
05/16/11 08:00:00
05/16/11 08:00:02
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
Hz
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
59.97287
59.97287
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
29905.8
29905.8
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004554
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
-0.001
-0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
Absolute
Delta Hz
0.002
0.002
0.002
0.002
0.003
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
0.001
0.005
0.000
0.001
0.001
0.004
0.000
0.000
0.004
0.000
0.001
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
05/16/11 08:01:30
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
Hz
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
59.98709
59.98773
59.98965
59.99161
59.99255
59.99323
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
29951.05
29951.05
29955.09
29955.09
29955.09
29955.09
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004555
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
05/16/11 08:02:36
05/16/11 08:02:38
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
Hz
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
59.96512
59.96512
59.96576
59.96704
59.96994
59.97253
59.97415
59.9761
59.97739
59.97931
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
30055.73
30055.73
30055.73
30055.73
30068.76
30068.76
30068.76
30068.76
30068.76
30068.21
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004556
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
Absolute
Delta Hz
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
05/16/11 08:04:00
05/16/11 08:04:02
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
Hz
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
59.98029
59.979
59.97867
59.97931
59.97998
59.97931
59.979
59.97803
59.97675
59.97739
59.979
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
30118.77
30118.77
30118.74
30118.74
30118.74
30118.74
30118.74
30106.93
30106.93
30106.93
30106.93
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004557
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
Absolute
Delta Hz
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.000
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
05/16/11 08:05:48
05/16/11 08:05:50
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
Hz
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471.3000183
471.3000183
471.3000183
471.3000183
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004558
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Delta
Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.000
0.001
Absolute
Delta Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
05/16/11 08:06:36
05/16/11 08:06:38
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
Hz
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
470.8999939
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Load
Resources
Tripped
MW
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004559
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
0.000
-0.042
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
Absolute
Delta Hz
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
0.000
0.042
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
05/16/11 08:08:40
Hz
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004560
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
0.000
0.000
-0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
0.000
Absolute
Delta Hz
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
0.000
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
Hz
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004561
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
-0.001
-0.001
-0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
0.001
0.001
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
05/16/11 08:10:04
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
Hz
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
30300.1
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004562
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
-0.001
-0.004
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
Absolute
Delta Hz
0.002
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
0.001
0.004
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
Hz
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004563
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
0.001
-0.001
-0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
Absolute
Delta Hz
0.003
0.002
0.001
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
05/16/11 08:12:56
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
Hz
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30372.38
30372.38
30372.38
30349.1
30349.1
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004564
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.000
0.000
-0.001
-0.002
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
-0.001
-0.001
0.000
-0.001
Absolute
Delta Hz
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.001
05/16/11 08:14:10
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
05/16/11 08:15:28
05/16/11 08:15:30
Hz
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004565
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
-0.001
0.004
Absolute
Delta Hz
0.000
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
0.001
0.004
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
Hz
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004566
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
0.000
0.001
-0.002
0.000
0.001
0.000
0.000
-0.001
-0.004
-0.001
0.000
-0.002
-0.002
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
-0.001
-0.003
-0.003
0.000
0.002
Absolute
Delta Hz
0.002
0.000
0.001
0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.001
0.000
0.002
0.002
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
0.001
0.003
0.003
0.000
0.002
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
05/16/11 08:17:16
05/16/11 08:17:18
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
Hz
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004567
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
Absolute
Delta Hz
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
05/16/11 08:18:40
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
Hz
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004568
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
Absolute
Delta Hz
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
0.003
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
05/16/11 08:20:32
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
Hz
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004569
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
0.000
-0.001
-0.003
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
Absolute
Delta Hz
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
0.000
0.001
0.003
0.002
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
Hz
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
60.03717
60.03781
60.03781
60.03748
60.0365
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
30452.43
30473.21
30473.21
30473.21
30473.21
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004570
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
-0.001
Absolute
Delta Hz
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
05/16/11 08:23:00
05/16/11 08:23:02
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
Hz
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
60.03101
60.03232
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
30485.47
30505.49
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004571
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
Absolute
Delta Hz
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
Hz
60.03458
60.03488
60.0336
60.03326
60.03232
60.03134
60.03168
60.03326
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
60.03134
60.03168
60.03134
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30529.28
30529.08
30529.08
30529.08
30529.08
30529.52
30529.52
30529.52
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
30521.82
30533.64
30533.64
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004572
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.001
0.000
-0.001
0.000
-0.001
-0.001
0.000
0.002
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
Absolute
Delta Hz
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
Hz
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
60.0365
60.03488
60.0336
60.03232
60.03134
60.03101
60.03101
60.0307
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
30556.84
30557.42
30557.42
30557.43
30557.43
30557.43
30557.43
30566.39
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004573
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.000
0.001
0.002
0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
Absolute
Delta Hz
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
Hz
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004574
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.001
0.001
0.001
-0.001
0.000
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
Hz
60.00388
60.00128
59.99936
59.99805
59.99741
59.9971
59.99677
59.9971
59.99646
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30543.34
30543.34
30554.42
30554.42
30554.42
30554.42
30534.33
30534.33
30533.84
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004575
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
Absolute
Delta Hz
0.003
0.003
0.002
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
05/16/11 08:29:20
05/16/11 08:29:22
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
Hz
59.97675
59.9761
59.9761
59.97641
59.97705
59.97803
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30570.97
30593.17
30593.17
30593.17
30593.17
30575.07
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004576
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
-0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
Absolute
Delta Hz
0.000
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.006
0.000
0.004
0.001
0.002
0.001
0.000
0.003
0.003
0.003
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
Hz
59.97479
59.97479
59.97641
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30603.96
30603.96
30603.96
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004577
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
0.000
0.002
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
Absolute
Delta Hz
0.002
0.000
0.002
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
05/16/11 08:31:56
05/16/11 08:31:58
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
Hz
60.0184
60.02069
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
60.0152
60.01648
60.01614
60.0152
60.01486
60.01453
60.01291
60.01099
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30661.87
30661.87
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
30648.14
30648.29
30648.29
30648.29
30648.29
30648.29
30652.04
30652.04
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004578
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
0.000
0.002
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
-0.001
0.000
0.000
-0.002
-0.002
Absolute
Delta Hz
0.000
0.002
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.002
05/16/11 08:33:18
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
Hz
60.00775
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30652.04
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004579
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.003
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
0.003
0.002
0.001
0.000
0.000
-0.001
Absolute
Delta Hz
0.003
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
05/16/11 08:36:00
Hz
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
59.99966
60.00064
60.00098
60.00064
60
59.99936
59.99741
59.99484
59.99289
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
30686.83
30686.83
30686.83
30686.83
30686.83
30678.05
30678.05
30678.05
30678.05
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004580
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.002
Absolute
Delta Hz
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
05/16/11 08:37:20
05/16/11 08:37:22
Hz
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
60.01227
60.01163
60.01132
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
60.0126
60.01132
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
30726.76
30726.76
30726.76
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
30720.93
30720.93
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004581
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
Absolute
Delta Hz
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
Hz
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
60.00388
60.00485
60.00549
60.00613
60.00647
60.00677
60.00677
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
30757.92
30752.27
30752.27
30752.27
30752.27
30752.27
30752.33
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
1
0
1
0
1
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004582
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
Absolute
Delta Hz
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
05/16/11 08:40:00
Hz
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
60.02618
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
30803.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Time (T)
Contingent
Resource
Lost
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
004583
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Delta
Hz
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
Absolute
Delta Hz
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after
(up to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns
A through R. You must also delete any un-used event detection formulas in columns N through R as
well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1
"BA Event Data" worksheet.
MyBA_110516_0806_FRS_Form2.9.xlsm
59.300 Hz
60.700 Hz
Auto Event Detection
8:06:38 1245 Manually selected row number of the Event Starting Time.
8:10:30 1442 Manually selected row number of the Event Ending Time.
8:06:38
Event Frequency Data
60.1
8:06:38
-0.101
Delta Hz Event Detected
60.05
60
8:10:30
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00 7:45:00 7:50:00 7:55:00 8:00:00 8:05:00 8:10:00 8:15:00 8:20:00 8:25:00 8:30:00 8:35:00 8:40:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
Hz
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
004584
Auto
Manual
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
Balancing Authority MyBA
Grid Nominal Frequency
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
662.51 MW
Yes
A Point
FPointA
A Value
C Value
Delta FC
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
8:06:36
60.00195313
59.99862671
59.87011337
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
3.00000 Hz
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingency MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingency Delta MW Actual
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
Frequency
Hz
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
Contingent
Resource
Lost
MW
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.711 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Value B
20 to 52 sec
Average
Average
Frequency
MW
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
45.057
69.880
83.086
86.509
85.036
82.615
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
708.959
705.229
702.804
696.067
685.829
675.477
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
325.933
321.849
315.567
307.788
301.197
295.448
288.014
275.789
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
Initial
Measure
Final
Expected
Primary
Frequency
Response
Average
Ramp
MW/scan
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
Average Average
Average
Output
Target
Ramp
Recovery During
During Recovery During
Period Recovery Recovery Period Recovery
Target
Period
Period
Ramp
Period
MW
MW
MW
MW
MW
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
509.957
501.609
491.064
479.021
468.166
458.153
446.456
429.967
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
872.238
866.943
861.649
856.335
851.017
845.708
840.385
834.985
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
420.514
416.250
411.986
407.723
403.459
399.195
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
186.012
181.748
177.484
173.221
168.957
164.693
160.430
156.166
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
446.096
443.964
441.832
439.700
437.568
435.437
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
328.845
326.713
324.581
322.449
320.317
318.186
316.054
313.922
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
Frequency
Hz
59.980
59.982
59.984
59.986
59.987
59.988
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
59.893
59.893
59.893
59.895
59.898
59.900
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
59.952
59.952
59.953
59.955
59.956
59.956
59.958
59.961
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
Contingent
Resource
Lost
MW
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
0.00 MW
0.00 MW
0.00 MW
0.00 MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
Expected Primary
Freq Response
Based on Bias Setting
MW
T
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
T+140 sec
T+142 sec
T+144 sec
T+146 sec
T+148 sec
T+150 sec
T+152 sec
T+154 sec
T+156 sec
T+158 sec
T+160 sec
T+162 sec
T+164 sec
T+166 sec
T+168 sec
T+170 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
Frequency
Hz
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonContingent
Load
Conforming
Resource
Resources
Load
Lost
Tripped
Load (-)
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
Average Bias Setting when Hz is greater than +/-0.036 Hz
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.711 P.U.
0.711 P.U.
Not
Used
Not
Used
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
20 to 52 second Average Period Evaluation
0.738 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Spare
Spare
Sum of Pre Perturbation Adjustments
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
Not
Used
Not
Used
MW/0.1 Hz
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30202.7
30136.8
-65.973
-65.020
14.00%
Hz
Hz
Actual
Hz
Primary
Hz
Freq Response
Hz
MW/0.1 Hz
MW/0.1 Hz
-481.62
MW/0.1 Hz
-561.31
MW/0.1 Hz
-863.83
MW/0.1 Hz
-1000.43
MW/0.1 Hz
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
004585
Load
NonResources
Conforming
Tripped
Load
Spare
Spare
Adjustment
Adjustment Adjustment Adjustment
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
MW
MW
MW
MW/0.1 Hz
-653.00 MW/0.1 Hz
BA
Load
MW
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
EPFR
MW
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
446.26
446.26
446.26
456.01
467.62
475.25
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
1000.43
1007.61
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
0.0197
0.0178
0.0165
0.0142
0.0126
0.0120
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
0.0485
0.0481
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
Adjusted
Spare
P.U.
Adjustment
Performance
0.00
0.738
0.00
0.860
0.00
1.323
0.00
1.532
0.00
2.309
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
-67.789
-55.851
-46.626
-44.326
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
-88.422
-76.483
-67.258
-64.958
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
241.944
240.477
239.065
237.677
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
113.628
113.016
112.409
111.808
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
60.008
60.005
60.005
60.006
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
T+172 sec
T+174 sec
T+176 sec
T+178 sec
T+180 sec
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
0.0078
0.0052
0.0045
0.0061
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
004586
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
-13.275
-13.790
-16.357
-20.257
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
42.028
50.963
67.093
83.506
103.730
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
-33.908
-34.423
-36.989
-40.890
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
21.395
30.330
46.461
62.874
83.098
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
147.518
147.032
146.542
146.058
145.591
145.147
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
139.601
139.146
138.686
138.218
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
126.560
126.327
126.134
125.982
125.879
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
59.915
59.699
59.483
59.269
59.057
58.845
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
56.194
55.997
55.802
55.608
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
50.549
50.381
50.214
50.048
49.882
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
60.003
60.004
60.003
60.001
59.999
59.997
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
60.002
60.002
60.003
60.004
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
59.992
59.990
59.985
59.983
59.978
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
81245.24
9243.47
7757.08
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
38591.49
25305.89
25305.89
30873.19
53229.64
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
7385.93
5250.54
3492.44
2929.15
2324.79
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
0.0023
0.0023
0.0032
0.0042
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
0.0078
0.0103
0.0149
0.0175
0.0216
004587
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
004588
Balancing Authority
MyBA
60.02
0.711
0.711
"Auto" Event Detection adjustment of T(0).
004589
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
59.94
Frequency - Hz
400.0
59.92
59.9
300.0
59.897
59.88
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
8:05:48
Hz
8:05:58
8:06:08
8:06:18
Actual Average Primary Freq Response
8:06:28
8:06:38
Average Frequency
EPFR Adjusted
8:06:48
8:06:58
0.0
8:07:08
8:07:18
8:07:28
8:07:38
Actual Primary Freq Response Beta
MW/0.1 Hz
464.954
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
EPFR Unadjusted
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
-653.00
MyBA
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
0.0
8:06:38
8:07:38
8:08:38
8:09:38
Hz
8:10:38
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
8:05:38
004590
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Contingent
Resource
Frequency
Lost
Hz
MW
59.870
59.999
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Value B
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
0.00
BA
BA
Bias
Load
Spare
Setting
MW
MW/0.1 Hz
MW
0.00
-653.00 30202.74
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Value A Data
20 to 52 second Average Period Evaluation
Bias
Contingent
Setting
Resource
EPFR
Frequency
Lost
MW
Hz
MW
8.97
59.897
0.00
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
004591
Spare
MW
0.00
Spare
MW
0.00
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
BA
BA
Bias
Load
Setting
P.U.
MW/0.1 Hz
MW
0.738
-653.00 30136.77
004592
Average
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
Bias
Bias While
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Setting Hz > +/-0.036 Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance Maximum
Minimum
EPFR
Hz
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
Bias Setting Bias Setting
MW
MW/0.1 Hz
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
MW/0.1 Hz MW/0.1 Hz
671.54
-653.00
0.738
0.860
1.323
1.532
2.309
0.738
0.860
1.323
1.532
2.309
-653.00
-653.00
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Steps
1
004593
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6".
Only rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
MyBA
Load
Resources
Tripped
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
A Value
59.9
0.00
59.88
59.86
B Value
0.00
1.0
0.9
0.8
0.7
0.6
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
004594
0.5
Average Period
20 to 52 second
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Initial Load Resources
MyBA
NonConforming
60.08
Load
60.06
Load (-)
60.04
60.02
60
59.98
59.94
59.92
A Value
59.9
0.00
59.88
59.86
59.84
B Value
0.00
004595
1.0
0.9
0.8
0.7
0.6
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
0.5
Average Period
20 to 52 second
0.4
0.3
0.2
59.82
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Non- Conforming Load
MyBA
Not
Used
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
59.9
59.88
59.86
59.84
A Value
B Value
0.00
0.00
004596
1.0
0.9
0.8
0.7
0.6
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
0.5
Average Period
20 to 52 second
0.4
0.3
0.2
59.82
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Not Used
MyBA
Not
Used
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
A Value
59.9
0.00
59.88
59.86
59.84
59.82
B Value
0.00
004597
1.2
1.0
0.8
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
0.6
Average Period
20 to 52 second
0.4
0.2
59.8
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Not Used
MyBA
Not
Used
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
59.9
59.88
59.86
59.84
A Value
B Value
0.00
0.00
004598
1.0
0.9
0.8
0.7
0.6
0.5
Average Period
20 to 52 second
0.4
0.3
0.2
59.82
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Not Used
MW/0.1 Hz
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
MyBA
Not
Used
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
59.9
59.88
59.86
A Value
15.00
B Value
0.00
004599
1.0
0.9
0.8
0.7
0.6
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
0.5
Average Period
20 to 52 second
0.4
0.3
59.84
59.82
0.2
59.8
0.1
59.78
59.76
0.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Not Used
BA
Load
MyBA
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
A Value
59.9
7651.305
59.88
59.86
59.84
B Value
30136.8
004600
30600.0
30500.0
30400.0
30300.0
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
30200.0
Average Period
20 to 52 second
30100.0
30000.0
59.82
59.8
29900.0
59.78
59.76
29800.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
Expected Primary
Freq Response
Based on Bias Setting
MyBA
60.08
60.06
60.04
60.02
60
59.98
59.94
59.92
59.9
59.88
59.86
59.84
004601
1000.0
800.0
600.0
400.0
MW
Frequency - Hz
59.96
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Monday, May 16, 2011
200.0
0.0
59.82
-200.0
59.8
A Value
59.78
8.97
B Value
671.54
Average Period
20 to 52 second
59.76
-400.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Expected Primary Freq Response Based on Bias Setting
004602
Time (T)
05/16/11 07:40:00
05/16/11 07:40:02
05/16/11 07:40:04
05/16/11 07:40:06
05/16/11 07:40:08
05/16/11 07:40:10
05/16/11 07:40:12
05/16/11 07:40:14
05/16/11 07:40:16
05/16/11 07:40:18
05/16/11 07:40:20
05/16/11 07:40:22
05/16/11 07:40:24
05/16/11 07:40:26
05/16/11 07:40:28
05/16/11 07:40:30
05/16/11 07:40:32
05/16/11 07:40:34
05/16/11 07:40:36
05/16/11 07:40:38
05/16/11 07:40:40
05/16/11 07:40:42
05/16/11 07:40:44
05/16/11 07:40:46
05/16/11 07:40:48
05/16/11 07:40:50
05/16/11 07:40:52
05/16/11 07:40:54
05/16/11 07:40:56
05/16/11 07:40:58
05/16/11 07:41:00
05/16/11 07:41:02
05/16/11 07:41:04
05/16/11 07:41:06
05/16/11 07:41:08
05/16/11 07:41:10
05/16/11 07:41:12
05/16/11 07:41:14
Hz
60.0097
60.00745
60.00452
60.00259
60.00034
59.99872
59.9971
59.99548
59.99353
59.99063
59.9874
59.98416
59.98093
59.97867
59.97836
59.97836
59.97836
59.97577
59.97382
59.97223
59.97223
59.97318
59.97351
59.97415
59.97287
59.97287
59.97287
59.96832
59.96768
59.96899
59.97028
59.97223
59.97382
59.97479
59.9761
59.97769
59.97998
59.98318
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.85
29756.85
29756.82
29756.82
29756.82
29756.82
29756.82
29766.46
29766.46
29766.46
29766.46
29766.46
29766.37
29766.37
29766.37
29766.37
29766.37
29780.98
29780.98
29780.98
29780.98
29780.98
29780.95
29780.95
29780.95
29780.95
29780.95
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29770.34
29782.73
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.002
-0.003
-0.002
-0.002
-0.002
-0.002
-0.002
-0.002
-0.003
-0.003
-0.003
-0.003
-0.002
0.000
0.000
0.000
-0.003
-0.002
-0.002
0.000
0.001
0.000
0.001
-0.001
0.000
0.000
-0.005
-0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.002
0.002
0.002
0.002
0.003
0.003
0.003
0.003
0.002
0.000
0.000
0.000
0.003
0.002
0.002
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.005
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.002
0.003
004603
Time (T)
05/16/11 07:41:16
05/16/11 07:41:18
05/16/11 07:41:20
05/16/11 07:41:22
05/16/11 07:41:24
05/16/11 07:41:26
05/16/11 07:41:28
05/16/11 07:41:30
05/16/11 07:41:32
05/16/11 07:41:34
05/16/11 07:41:36
05/16/11 07:41:38
05/16/11 07:41:40
05/16/11 07:41:42
05/16/11 07:41:44
05/16/11 07:41:46
05/16/11 07:41:48
05/16/11 07:41:50
05/16/11 07:41:52
05/16/11 07:41:54
05/16/11 07:41:56
05/16/11 07:41:58
05/16/11 07:42:00
05/16/11 07:42:02
05/16/11 07:42:04
05/16/11 07:42:06
05/16/11 07:42:08
05/16/11 07:42:10
05/16/11 07:42:12
05/16/11 07:42:14
05/16/11 07:42:16
05/16/11 07:42:18
05/16/11 07:42:20
05/16/11 07:42:22
05/16/11 07:42:24
05/16/11 07:42:26
05/16/11 07:42:28
05/16/11 07:42:30
Hz
59.98578
59.9874
59.98868
59.98999
59.99191
59.99353
59.99612
59.99805
59.99902
59.99902
59.99774
59.99646
59.99579
59.99612
59.9971
59.99774
59.99838
59.99936
60
60.00064
60.00128
60.00226
60.00388
60.00647
60.0097
60.01358
60.01614
60.01776
60.01776
60.01486
60.01163
60.00903
60.00775
60.00775
60.00903
60.00903
60.01324
60.01486
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29782.73
29782.73
29782.73
29782.73
29782.82
29782.82
29782.82
29782.82
29782.82
29786.15
29786.15
29786.15
29786.15
29786.15
29786.21
29786.21
29786.21
29786.21
29786.21
29778.98
29778.98
29778.98
29778.98
29778.98
29778.92
29778.92
29778.92
29778.92
29778.92
29787.9
29787.9
29787.9
29787.9
29787.9
29787.84
29787.84
29787.84
29787.84
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.003
0.002
0.001
0.001
0.002
0.002
0.003
0.002
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
-0.003
-0.003
-0.003
-0.001
0.000
0.001
0.000
0.004
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.003
0.002
0.001
0.001
0.002
0.002
0.003
0.002
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.003
0.003
0.004
0.003
0.002
0.000
0.003
0.003
0.003
0.001
0.000
0.001
0.000
0.004
0.002
004604
Time (T)
05/16/11 07:42:32
05/16/11 07:42:34
05/16/11 07:42:36
05/16/11 07:42:38
05/16/11 07:42:40
05/16/11 07:42:42
05/16/11 07:42:44
05/16/11 07:42:46
05/16/11 07:42:48
05/16/11 07:42:50
05/16/11 07:42:52
05/16/11 07:42:54
05/16/11 07:42:56
05/16/11 07:42:58
05/16/11 07:43:00
05/16/11 07:43:02
05/16/11 07:43:04
05/16/11 07:43:06
05/16/11 07:43:08
05/16/11 07:43:10
05/16/11 07:43:12
05/16/11 07:43:14
05/16/11 07:43:16
05/16/11 07:43:18
05/16/11 07:43:20
05/16/11 07:43:22
05/16/11 07:43:24
05/16/11 07:43:26
05/16/11 07:43:28
05/16/11 07:43:30
05/16/11 07:43:32
05/16/11 07:43:34
05/16/11 07:43:36
05/16/11 07:43:38
05/16/11 07:43:40
05/16/11 07:43:42
05/16/11 07:43:44
05/16/11 07:43:46
Hz
60.0152
60.0152
60.01486
60.01422
60.01358
60.01227
60.01099
60.00873
60.00647
60.00485
60.00354
60.00195
60
59.99774
59.99612
59.99646
59.99741
59.99838
59.99936
59.99902
59.99872
59.99774
59.99646
59.99677
59.99677
59.99774
59.99805
59.99774
59.99579
59.99387
59.99255
59.99127
59.98999
59.98965
59.98837
59.98709
59.98642
59.98642
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29787.84
29813.39
29813.39
29813.39
29813.39
29813.39
29813.33
29813.33
29813.33
29813.33
29813.33
29797.46
29797.46
29797.46
29797.46
29797.46
29797.52
29797.52
29797.52
29797.52
29797.52
29780.33
29780.33
29780.33
29780.33
29780.33
29780.27
29780.27
29780.27
29780.27
29780.27
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
29785.63
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
-0.001
-0.001
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
004605
Time (T)
05/16/11 07:43:48
05/16/11 07:43:50
05/16/11 07:43:52
05/16/11 07:43:54
05/16/11 07:43:56
05/16/11 07:43:58
05/16/11 07:44:00
05/16/11 07:44:02
05/16/11 07:44:04
05/16/11 07:44:06
05/16/11 07:44:08
05/16/11 07:44:10
05/16/11 07:44:12
05/16/11 07:44:14
05/16/11 07:44:16
05/16/11 07:44:18
05/16/11 07:44:20
05/16/11 07:44:22
05/16/11 07:44:24
05/16/11 07:44:26
05/16/11 07:44:28
05/16/11 07:44:30
05/16/11 07:44:32
05/16/11 07:44:34
05/16/11 07:44:36
05/16/11 07:44:38
05/16/11 07:44:40
05/16/11 07:44:42
05/16/11 07:44:44
05/16/11 07:44:46
05/16/11 07:44:48
05/16/11 07:44:50
05/16/11 07:44:52
05/16/11 07:44:54
05/16/11 07:44:56
05/16/11 07:44:58
05/16/11 07:45:00
05/16/11 07:45:02
Hz
59.98642
59.98676
59.98676
59.98642
59.98611
59.98611
59.98514
59.98416
59.98352
59.98224
59.98029
59.979
59.97769
59.97675
59.97641
59.97739
59.97998
59.98318
59.98611
59.98837
59.9903
59.99191
59.99353
59.99579
60
60.00354
60.00647
60.00839
60.00903
60.00873
60.00873
60.00937
60.01099
60.01453
60.0181
60.02002
60.02036
60.02002
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29785.63
29785.63
29785.63
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29787.12
29780.67
29780.67
29780.67
29780.67
29780.67
29780.76
29780.76
29780.76
29780.76
29780.76
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29777.7
29788.63
29788.63
29788.63
29788.63
29788.63
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.003
0.003
0.003
0.002
0.002
0.002
0.002
0.002
0.004
0.004
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.004
0.004
0.002
0.000
0.000
004606
Time (T)
05/16/11 07:45:04
05/16/11 07:45:06
05/16/11 07:45:08
05/16/11 07:45:10
05/16/11 07:45:12
05/16/11 07:45:14
05/16/11 07:45:16
05/16/11 07:45:18
05/16/11 07:45:20
05/16/11 07:45:22
05/16/11 07:45:24
05/16/11 07:45:26
05/16/11 07:45:28
05/16/11 07:45:30
05/16/11 07:45:32
05/16/11 07:45:34
05/16/11 07:45:36
05/16/11 07:45:38
05/16/11 07:45:40
05/16/11 07:45:42
05/16/11 07:45:44
05/16/11 07:45:46
05/16/11 07:45:48
05/16/11 07:45:50
05/16/11 07:45:52
05/16/11 07:45:54
05/16/11 07:45:56
05/16/11 07:45:58
05/16/11 07:46:00
05/16/11 07:46:02
05/16/11 07:46:04
05/16/11 07:46:06
05/16/11 07:46:08
05/16/11 07:46:10
05/16/11 07:46:12
05/16/11 07:46:14
05/16/11 07:46:16
05/16/11 07:46:18
Hz
60.02002
60.01907
60.0181
60.01712
60.01712
60.01712
60.01453
60.01358
60.01227
60.01163
60.01065
60.0097
60.00839
60.00745
60.00775
60.00839
60.00839
60.00809
60.00745
60.00711
60.00839
60.00937
60.0097
60.01001
60.01065
60.01196
60.01324
60.01453
60.01614
60.01712
60.01712
60.01614
60.01584
60.01614
60.01584
60.01486
60.01422
60.01227
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29788.63
29788.63
29788.63
29788.63
29788.63
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29788.51
29780.62
29780.62
29780.62
29780.62
29780.62
29780.56
29780.56
29780.56
29780.56
29780.56
29784.96
29784.96
29784.96
29784.96
29784.96
29784.93
29784.93
29784.93
29784.93
29784.93
29760.42
29760.42
29760.42
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
-0.001
-0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.002
004607
Time (T)
05/16/11 07:46:20
05/16/11 07:46:22
05/16/11 07:46:24
05/16/11 07:46:26
05/16/11 07:46:28
05/16/11 07:46:30
05/16/11 07:46:32
05/16/11 07:46:34
05/16/11 07:46:36
05/16/11 07:46:38
05/16/11 07:46:40
05/16/11 07:46:42
05/16/11 07:46:44
05/16/11 07:46:46
05/16/11 07:46:48
05/16/11 07:46:50
05/16/11 07:46:52
05/16/11 07:46:54
05/16/11 07:46:56
05/16/11 07:46:58
05/16/11 07:47:00
05/16/11 07:47:02
05/16/11 07:47:04
05/16/11 07:47:06
05/16/11 07:47:08
05/16/11 07:47:10
05/16/11 07:47:12
05/16/11 07:47:14
05/16/11 07:47:16
05/16/11 07:47:18
05/16/11 07:47:20
05/16/11 07:47:22
05/16/11 07:47:24
05/16/11 07:47:26
05/16/11 07:47:28
05/16/11 07:47:30
05/16/11 07:47:32
05/16/11 07:47:34
Hz
60.0097
60.00711
60.00583
60.00516
60.00516
60.00485
60.00388
60.00259
59.99902
59.9971
59.99646
59.99579
59.99417
59.99225
59.9903
59.98804
59.98709
59.98676
59.98578
59.9845
59.98288
59.98224
59.98224
59.98224
59.98254
59.98386
59.9848
59.98578
59.98642
59.98999
59.99225
59.99323
59.99646
59.99902
60.00064
60.00647
60.00903
60.01099
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29760.42
29782.35
29782.35
29782.35
29782.35
29782.35
29782.44
29782.44
29782.44
29782.44
29782.44
29785.52
29785.52
29785.52
29785.52
29785.52
29785.55
29785.55
29785.55
29785.55
29785.55
29788.21
29788.21
29788.21
29788.21
29788.21
29788.06
29788.06
29788.06
29788.06
29788.06
29776.11
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.003
-0.003
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.004
-0.002
-0.001
-0.001
-0.002
-0.002
-0.002
-0.002
-0.001
0.000
-0.001
-0.001
-0.002
-0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.003
0.003
0.001
0.001
0.000
0.000
0.001
0.001
0.004
0.002
0.001
0.001
0.002
0.002
0.002
0.002
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.004
0.002
0.001
0.003
0.003
0.002
0.006
0.003
0.002
004608
Time (T)
05/16/11 07:47:36
05/16/11 07:47:38
05/16/11 07:47:40
05/16/11 07:47:42
05/16/11 07:47:44
05/16/11 07:47:46
05/16/11 07:47:48
05/16/11 07:47:50
05/16/11 07:47:52
05/16/11 07:47:54
05/16/11 07:47:56
05/16/11 07:47:58
05/16/11 07:48:00
05/16/11 07:48:02
05/16/11 07:48:04
05/16/11 07:48:06
05/16/11 07:48:08
05/16/11 07:48:10
05/16/11 07:48:12
05/16/11 07:48:14
05/16/11 07:48:16
05/16/11 07:48:18
05/16/11 07:48:20
05/16/11 07:48:22
05/16/11 07:48:24
05/16/11 07:48:26
05/16/11 07:48:28
05/16/11 07:48:30
05/16/11 07:48:32
05/16/11 07:48:34
05/16/11 07:48:36
05/16/11 07:48:38
05/16/11 07:48:40
05/16/11 07:48:42
05/16/11 07:48:44
05/16/11 07:48:46
05/16/11 07:48:48
05/16/11 07:48:50
Hz
60.01132
60.01291
60.01324
60.01324
60.01422
60.0181
60.01907
60.02133
60.02197
60.02164
60.01971
60.01907
60.01746
60.01776
60.0184
60.01776
60.0152
60.01389
60.01422
60.0152
60.01614
60.01614
60.01422
60.01196
60.01035
60.00809
60.00613
60.00516
60.00452
60.00354
60.00128
60
59.99936
59.99838
59.99741
59.99579
59.99515
59.99646
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29776.11
29776.11
29776.11
29776.11
29776.17
29776.17
29776.17
29776.17
29776.17
29794.69
29794.69
29794.69
29794.69
29794.69
29794.66
29794.66
29794.66
29794.66
29794.66
29804.78
29804.78
29804.78
29804.78
29804.78
29804.86
29804.86
29804.86
29804.86
29804.86
29800.12
29800.12
29800.12
29800.12
29800.12
29800.18
29800.18
29800.18
29800.18
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
-0.002
-0.001
-0.002
0.000
0.001
-0.001
-0.003
-0.001
0.000
0.001
0.001
0.000
-0.002
-0.002
-0.002
-0.002
-0.002
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.002
0.000
0.000
0.001
0.004
0.001
0.002
0.001
0.000
0.002
0.001
0.002
0.000
0.001
0.001
0.003
0.001
0.000
0.001
0.001
0.000
0.002
0.002
0.002
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.002
0.001
0.001
004609
Time (T)
05/16/11 07:48:52
05/16/11 07:48:54
05/16/11 07:48:56
05/16/11 07:48:58
05/16/11 07:49:00
05/16/11 07:49:02
05/16/11 07:49:04
05/16/11 07:49:06
05/16/11 07:49:08
05/16/11 07:49:10
05/16/11 07:49:12
05/16/11 07:49:14
05/16/11 07:49:16
05/16/11 07:49:18
05/16/11 07:49:20
05/16/11 07:49:22
05/16/11 07:49:24
05/16/11 07:49:26
05/16/11 07:49:28
05/16/11 07:49:30
05/16/11 07:49:32
05/16/11 07:49:34
05/16/11 07:49:36
05/16/11 07:49:38
05/16/11 07:49:40
05/16/11 07:49:42
05/16/11 07:49:44
05/16/11 07:49:46
05/16/11 07:49:48
05/16/11 07:49:50
05/16/11 07:49:52
05/16/11 07:49:54
05/16/11 07:49:56
05/16/11 07:49:58
05/16/11 07:50:00
05/16/11 07:50:02
05/16/11 07:50:04
05/16/11 07:50:06
Hz
59.99872
60.00128
60.00323
60.00421
60.00485
60.00549
60.00583
60.00583
60.00549
60.00388
60.00226
60.00226
60
60
60
60
60.00452
60.00583
60.00613
60.00583
60.00516
60.00388
60.00195
60.00128
60.00098
60.00034
60
59.99902
59.99872
59.99838
59.99612
59.99579
59.99515
59.99387
59.99225
59.99225
59.99484
59.99646
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29800.18
29799.82
29799.82
29799.82
29799.82
29799.82
29799.79
29799.79
29799.79
29799.79
29799.79
29795.67
29795.67
29795.67
29795.67
29795.67
29795.55
29795.55
29795.55
29795.55
29795.55
29783.53
29783.53
29783.53
29783.53
29783.53
29783.47
29783.47
29783.47
29783.47
29783.47
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
29788.38
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
-0.002
-0.002
0.000
-0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.001
0.000
-0.001
0.000
-0.001
0.000
0.000
-0.002
0.000
-0.001
-0.001
-0.002
0.000
0.003
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.001
0.001
0.001
0.000
0.000
0.000
0.002
0.002
0.000
0.002
0.000
0.000
0.000
0.005
0.001
0.000
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.002
0.000
0.001
0.001
0.002
0.000
0.003
0.002
004610
Time (T)
05/16/11 07:50:08
05/16/11 07:50:10
05/16/11 07:50:12
05/16/11 07:50:14
05/16/11 07:50:16
05/16/11 07:50:18
05/16/11 07:50:20
05/16/11 07:50:22
05/16/11 07:50:24
05/16/11 07:50:26
05/16/11 07:50:28
05/16/11 07:50:30
05/16/11 07:50:32
05/16/11 07:50:34
05/16/11 07:50:36
05/16/11 07:50:38
05/16/11 07:50:40
05/16/11 07:50:42
05/16/11 07:50:44
05/16/11 07:50:46
05/16/11 07:50:48
05/16/11 07:50:50
05/16/11 07:50:52
05/16/11 07:50:54
05/16/11 07:50:56
05/16/11 07:50:58
05/16/11 07:51:00
05/16/11 07:51:02
05/16/11 07:51:04
05/16/11 07:51:06
05/16/11 07:51:08
05/16/11 07:51:10
05/16/11 07:51:12
05/16/11 07:51:14
05/16/11 07:51:16
05/16/11 07:51:18
05/16/11 07:51:20
05/16/11 07:51:22
Hz
59.9971
59.99548
59.99289
59.98999
59.98773
59.98642
59.98547
59.98547
59.98611
59.98611
59.98676
59.98709
59.9874
59.98676
59.98611
59.98642
59.9874
59.98804
59.9874
59.98676
59.9848
59.98288
59.98062
59.97998
59.97931
59.979
59.97931
59.98093
59.98126
59.98126
59.9819
59.98126
59.97964
59.97705
59.97479
59.97351
59.97287
59.97223
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29788.38
29788.38
29788.38
29790.16
29790.16
29790.16
29790.16
29790.16
29790.07
29790.07
29790.07
29790.07
29790.07
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29777.49
29782.49
29782.49
29782.49
29782.49
29782.49
29782.46
29782.46
29782.46
29782.46
29782.46
29756.13
29756.13
29756.13
29756.13
29756.13
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.001
0.000
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
-0.001
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.000
0.000
0.002
0.000
0.000
0.001
-0.001
-0.002
-0.003
-0.002
-0.001
-0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.002
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.002
0.001
0.001
0.000
0.000
0.002
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.001
0.001
004611
Time (T)
05/16/11 07:51:24
05/16/11 07:51:26
05/16/11 07:51:28
05/16/11 07:51:30
05/16/11 07:51:32
05/16/11 07:51:34
05/16/11 07:51:36
05/16/11 07:51:38
05/16/11 07:51:40
05/16/11 07:51:42
05/16/11 07:51:44
05/16/11 07:51:46
05/16/11 07:51:48
05/16/11 07:51:50
05/16/11 07:51:52
05/16/11 07:51:54
05/16/11 07:51:56
05/16/11 07:51:58
05/16/11 07:52:00
05/16/11 07:52:02
05/16/11 07:52:04
05/16/11 07:52:06
05/16/11 07:52:08
05/16/11 07:52:10
05/16/11 07:52:12
05/16/11 07:52:14
05/16/11 07:52:16
05/16/11 07:52:18
05/16/11 07:52:20
05/16/11 07:52:22
05/16/11 07:52:24
05/16/11 07:52:26
05/16/11 07:52:28
05/16/11 07:52:30
05/16/11 07:52:32
05/16/11 07:52:34
05/16/11 07:52:36
05/16/11 07:52:38
Hz
59.97189
59.97125
59.97156
59.97318
59.97415
59.97479
59.97382
59.97287
59.97318
59.97449
59.97675
59.97803
59.97998
59.98093
59.98093
59.97964
59.97803
59.97705
59.97739
59.97836
59.97931
59.98126
59.98416
59.98611
59.98709
59.9874
59.98804
59.98804
59.98773
59.9874
59.9874
59.9874
59.9874
59.98773
59.98901
59.98965
59.98935
59.98837
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29756.18
29756.18
29756.18
29756.18
29756.18
29777.58
29777.58
29777.58
29777.58
29777.58
29777.4
29777.4
29777.4
29777.4
29777.4
29802.24
29802.24
29802.24
29802.24
29802.24
29802.18
29802.18
29802.18
29802.18
29802.18
29802.29
29802.29
29802.29
29802.29
29802.29
29802.32
29802.32
29802.32
29802.32
29802.32
29795.02
29795.02
29795.02
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.001
0.000
0.002
0.001
0.001
-0.001
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.000
0.001
0.002
0.001
0.000
0.001
0.001
0.002
0.003
0.002
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.000
0.001
004612
Time (T)
05/16/11 07:52:40
05/16/11 07:52:42
05/16/11 07:52:44
05/16/11 07:52:46
05/16/11 07:52:48
05/16/11 07:52:50
05/16/11 07:52:52
05/16/11 07:52:54
05/16/11 07:52:56
05/16/11 07:52:58
05/16/11 07:53:00
05/16/11 07:53:02
05/16/11 07:53:04
05/16/11 07:53:06
05/16/11 07:53:08
05/16/11 07:53:10
05/16/11 07:53:12
05/16/11 07:53:14
05/16/11 07:53:16
05/16/11 07:53:18
05/16/11 07:53:20
05/16/11 07:53:22
05/16/11 07:53:24
05/16/11 07:53:26
05/16/11 07:53:28
05/16/11 07:53:30
05/16/11 07:53:32
05/16/11 07:53:34
05/16/11 07:53:36
05/16/11 07:53:38
05/16/11 07:53:40
05/16/11 07:53:42
05/16/11 07:53:44
05/16/11 07:53:46
05/16/11 07:53:48
05/16/11 07:53:50
05/16/11 07:53:52
05/16/11 07:53:54
Hz
59.98868
59.98868
59.9874
59.98611
59.98611
59.98709
59.98837
59.98935
59.98999
59.99127
59.99255
59.99387
59.99387
59.99289
59.99097
59.98868
59.98642
59.98386
59.9816
59.97931
59.97675
59.97415
59.97287
59.97223
59.97318
59.97449
59.97351
59.97253
59.97253
59.97223
59.97156
59.97189
59.97318
59.97479
59.9761
59.97803
59.98062
59.98254
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29795.02
29795.02
29795.05
29795.05
29795.05
29795.05
29795.05
29781.42
29781.42
29781.42
29781.42
29781.42
29781.45
29781.45
29781.45
29781.45
29781.45
29802.43
29802.43
29802.43
29802.43
29802.43
29802.4
29802.4
29802.4
29802.4
29802.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29804.4
29797.32
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.003
-0.002
-0.002
-0.003
-0.003
-0.001
-0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.002
0.002
0.003
0.002
0.002
0.003
0.003
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.003
0.002
004613
Time (T)
05/16/11 07:53:56
05/16/11 07:53:58
05/16/11 07:54:00
05/16/11 07:54:02
05/16/11 07:54:04
05/16/11 07:54:06
05/16/11 07:54:08
05/16/11 07:54:10
05/16/11 07:54:12
05/16/11 07:54:14
05/16/11 07:54:16
05/16/11 07:54:18
05/16/11 07:54:20
05/16/11 07:54:22
05/16/11 07:54:24
05/16/11 07:54:26
05/16/11 07:54:28
05/16/11 07:54:30
05/16/11 07:54:32
05/16/11 07:54:34
05/16/11 07:54:36
05/16/11 07:54:38
05/16/11 07:54:40
05/16/11 07:54:42
05/16/11 07:54:44
05/16/11 07:54:46
05/16/11 07:54:48
05/16/11 07:54:50
05/16/11 07:54:52
05/16/11 07:54:54
05/16/11 07:54:56
05/16/11 07:54:58
05/16/11 07:55:00
05/16/11 07:55:02
05/16/11 07:55:04
05/16/11 07:55:06
05/16/11 07:55:08
05/16/11 07:55:10
Hz
59.98416
59.98611
59.98804
59.9903
59.99161
59.99323
59.99484
59.99579
59.99515
59.99612
59.99805
59.99936
60.00064
60.00098
60.00064
60
59.99902
59.99872
59.99936
60.00034
60.00162
60.00354
60.00485
60.00421
60.00195
59.99902
59.99646
59.99417
59.99323
59.99127
59.98935
59.98709
59.98578
59.98547
59.98547
59.98514
59.9845
59.9845
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29797.32
29797.32
29797.32
29797.32
29797.29
29797.29
29797.29
29797.29
29797.29
29823.76
29823.76
29823.76
29823.76
29823.76
29818.41
29818.41
29818.41
29818.41
29818.41
29808.89
29808.89
29808.89
29808.89
29808.89
29814.89
29814.89
29814.89
29814.89
29814.89
29826.47
29826.47
29826.47
29826.47
29826.47
29826.41
29826.41
29826.41
29826.41
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
-0.001
0.001
0.002
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
-0.001
-0.002
-0.003
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.000
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.002
0.002
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.002
0.003
0.003
0.002
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.000
0.001
0.000
004614
Time (T)
05/16/11 07:55:12
05/16/11 07:55:14
05/16/11 07:55:16
05/16/11 07:55:18
05/16/11 07:55:20
05/16/11 07:55:22
05/16/11 07:55:24
05/16/11 07:55:26
05/16/11 07:55:28
05/16/11 07:55:30
05/16/11 07:55:32
05/16/11 07:55:34
05/16/11 07:55:36
05/16/11 07:55:38
05/16/11 07:55:40
05/16/11 07:55:42
05/16/11 07:55:44
05/16/11 07:55:46
05/16/11 07:55:48
05/16/11 07:55:50
05/16/11 07:55:52
05/16/11 07:55:54
05/16/11 07:55:56
05/16/11 07:55:58
05/16/11 07:56:00
05/16/11 07:56:02
05/16/11 07:56:04
05/16/11 07:56:06
05/16/11 07:56:08
05/16/11 07:56:10
05/16/11 07:56:12
05/16/11 07:56:14
05/16/11 07:56:16
05/16/11 07:56:18
05/16/11 07:56:20
05/16/11 07:56:22
05/16/11 07:56:24
05/16/11 07:56:26
Hz
59.9848
59.9848
59.98611
59.9874
59.98868
59.98837
59.98837
59.98578
59.9845
59.9848
59.98547
59.98642
59.98773
59.98965
59.99063
59.99063
59.99063
59.99063
59.98642
59.9845
59.98224
59.98062
59.97739
59.97641
59.97641
59.9761
59.97543
59.97577
59.97675
59.97705
59.97705
59.97705
59.97675
59.97705
59.97739
59.97803
59.97803
59.97867
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29826.41
29834.18
29834.18
29834.18
29834.18
29834.18
29836.13
29836.13
29836.13
29836.13
29836.13
29821.84
29821.84
29821.84
29821.84
29821.84
29821.87
29821.87
29821.87
29821.87
29821.87
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29831.33
29835.51
29835.51
29835.51
29835.51
29835.51
29856.55
29856.55
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.000
0.001
0.001
0.001
0.000
0.000
-0.003
-0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
-0.004
-0.002
-0.002
-0.002
-0.003
-0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.004
0.002
0.002
0.002
0.003
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
004615
Time (T)
05/16/11 07:56:28
05/16/11 07:56:30
05/16/11 07:56:32
05/16/11 07:56:34
05/16/11 07:56:36
05/16/11 07:56:38
05/16/11 07:56:40
05/16/11 07:56:42
05/16/11 07:56:44
05/16/11 07:56:46
05/16/11 07:56:48
05/16/11 07:56:50
05/16/11 07:56:52
05/16/11 07:56:54
05/16/11 07:56:56
05/16/11 07:56:58
05/16/11 07:57:00
05/16/11 07:57:02
05/16/11 07:57:04
05/16/11 07:57:06
05/16/11 07:57:08
05/16/11 07:57:10
05/16/11 07:57:12
05/16/11 07:57:14
05/16/11 07:57:16
05/16/11 07:57:18
05/16/11 07:57:20
05/16/11 07:57:22
05/16/11 07:57:24
05/16/11 07:57:26
05/16/11 07:57:28
05/16/11 07:57:30
05/16/11 07:57:32
05/16/11 07:57:34
05/16/11 07:57:36
05/16/11 07:57:38
05/16/11 07:57:40
05/16/11 07:57:42
Hz
59.97964
59.9816
59.98352
59.98642
59.9903
59.99451
59.99741
59.99838
59.99805
59.99677
59.99612
59.99548
59.99612
59.99936
60.00323
60.00745
60.01163
60.01453
60.01746
60.01907
60.01938
60.01938
60.01938
60.02036
60.02197
60.02423
60.02682
60.02811
60.02939
60.03036
60.02875
60.02682
60.02457
60.02261
60.02231
60.02295
60.02359
60.02261
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29856.55
29856.55
29856.55
29846.76
29846.76
29846.76
29846.76
29846.76
29860.05
29860.05
29860.05
29860.05
29860.05
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29873.15
29889.67
29889.67
29889.67
29889.67
29889.67
29886.6
29886.6
29886.6
29886.6
29886.6
29891.67
29891.67
29891.67
29891.67
29891.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
-0.001
-0.001
-0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
-0.002
-0.002
-0.002
-0.002
0.000
0.001
0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.002
0.002
0.003
0.004
0.004
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.002
0.000
0.000
0.000
0.001
0.002
0.002
0.003
0.001
0.001
0.001
0.002
0.002
0.002
0.002
0.000
0.001
0.001
0.001
004616
Time (T)
05/16/11 07:57:44
05/16/11 07:57:46
05/16/11 07:57:48
05/16/11 07:57:50
05/16/11 07:57:52
05/16/11 07:57:54
05/16/11 07:57:56
05/16/11 07:57:58
05/16/11 07:58:00
05/16/11 07:58:02
05/16/11 07:58:04
05/16/11 07:58:06
05/16/11 07:58:08
05/16/11 07:58:10
05/16/11 07:58:12
05/16/11 07:58:14
05/16/11 07:58:16
05/16/11 07:58:18
05/16/11 07:58:20
05/16/11 07:58:22
05/16/11 07:58:24
05/16/11 07:58:26
05/16/11 07:58:28
05/16/11 07:58:30
05/16/11 07:58:32
05/16/11 07:58:34
05/16/11 07:58:36
05/16/11 07:58:38
05/16/11 07:58:40
05/16/11 07:58:42
05/16/11 07:58:44
05/16/11 07:58:46
05/16/11 07:58:48
05/16/11 07:58:50
05/16/11 07:58:52
05/16/11 07:58:54
05/16/11 07:58:56
05/16/11 07:58:58
Hz
60.02164
60.01971
60.01776
60.01746
60.01682
60.01712
60.0184
60.01874
60.0181
60.01682
60.0152
60.0152
60.0155
60.0155
60.01453
60.01453
60.0152
60.01584
60.01614
60.01584
60.0152
60.0155
60.01614
60.01776
60.01907
60.02069
60.02133
60.02069
60.01907
60.01746
60.01614
60.0152
60.01453
60.01389
60.01358
60.01099
60.00549
59.99966
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29891.64
29891.64
29891.64
29891.64
29891.64
29891.51
29891.51
29891.51
29891.51
29891.51
29891.6
29891.6
29891.6
29891.6
29891.6
29884.5
29884.5
29884.5
29884.5
29884.5
29881.79
29881.79
29881.79
29881.79
29881.79
29887.14
29887.14
29887.14
29887.14
29887.14
29873.08
29873.08
29873.08
29873.08
29873.08
29862.1
29862.1
29862.1
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
-0.002
-0.002
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.001
-0.002
0.000
0.000
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.002
0.001
0.002
0.001
-0.001
-0.002
-0.002
-0.001
-0.001
-0.001
-0.001
0.000
-0.003
-0.005
-0.006
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.002
0.002
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.002
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.002
0.001
0.002
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.003
0.005
0.006
004617
Time (T)
05/16/11 07:59:00
05/16/11 07:59:02
05/16/11 07:59:04
05/16/11 07:59:06
05/16/11 07:59:08
05/16/11 07:59:10
05/16/11 07:59:12
05/16/11 07:59:14
05/16/11 07:59:16
05/16/11 07:59:18
05/16/11 07:59:20
05/16/11 07:59:22
05/16/11 07:59:24
05/16/11 07:59:26
05/16/11 07:59:28
05/16/11 07:59:30
05/16/11 07:59:32
05/16/11 07:59:34
05/16/11 07:59:36
05/16/11 07:59:38
05/16/11 07:59:40
05/16/11 07:59:42
05/16/11 07:59:44
05/16/11 07:59:46
05/16/11 07:59:48
05/16/11 07:59:50
05/16/11 07:59:52
05/16/11 07:59:54
05/16/11 07:59:56
05/16/11 07:59:58
05/16/11 08:00:00
05/16/11 08:00:02
05/16/11 08:00:04
05/16/11 08:00:06
05/16/11 08:00:08
05/16/11 08:00:10
05/16/11 08:00:12
05/16/11 08:00:14
Hz
59.99451
59.99127
59.98965
59.98868
59.98676
59.9848
59.98288
59.98062
59.97803
59.9761
59.97577
59.9761
59.9761
59.97641
59.97543
59.97479
59.97382
59.97253
59.97223
59.97253
59.97351
59.97351
59.97318
59.97189
59.97092
59.97028
59.97028
59.97028
59.97028
59.97061
59.97287
59.97287
59.97479
59.97479
59.97382
59.96832
59.96802
59.96899
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29862.1
29862.1
29861.95
29861.95
29861.95
29861.95
29861.95
29906.21
29906.21
29906.21
29906.21
29906.21
29878.69
29878.69
29878.69
29878.69
29878.69
29900.56
29900.56
29900.56
29900.56
29900.56
29896.99
29896.99
29896.99
29896.99
29896.99
29905.8
29905.8
29905.8
29905.8
29905.8
29905.77
29905.77
29905.77
29905.77
29905.77
29914.9
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.005
-0.003
-0.002
-0.001
-0.002
-0.002
-0.002
-0.002
-0.003
-0.002
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
-0.001
-0.005
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.005
0.003
0.002
0.001
0.002
0.002
0.002
0.002
0.003
0.002
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.002
0.000
0.002
0.000
0.001
0.005
0.000
0.001
004618
Time (T)
05/16/11 08:00:16
05/16/11 08:00:18
05/16/11 08:00:20
05/16/11 08:00:22
05/16/11 08:00:24
05/16/11 08:00:26
05/16/11 08:00:28
05/16/11 08:00:30
05/16/11 08:00:32
05/16/11 08:00:34
05/16/11 08:00:36
05/16/11 08:00:38
05/16/11 08:00:40
05/16/11 08:00:42
05/16/11 08:00:44
05/16/11 08:00:46
05/16/11 08:00:48
05/16/11 08:00:50
05/16/11 08:00:52
05/16/11 08:00:54
05/16/11 08:00:56
05/16/11 08:00:58
05/16/11 08:01:00
05/16/11 08:01:02
05/16/11 08:01:04
05/16/11 08:01:06
05/16/11 08:01:08
05/16/11 08:01:10
05/16/11 08:01:12
05/16/11 08:01:14
05/16/11 08:01:16
05/16/11 08:01:18
05/16/11 08:01:20
05/16/11 08:01:22
05/16/11 08:01:24
05/16/11 08:01:26
05/16/11 08:01:28
05/16/11 08:01:30
Hz
59.96994
59.97382
59.97382
59.97382
59.97769
59.97739
59.9761
59.9761
59.97705
59.97769
59.97803
59.97803
59.97739
59.97675
59.97641
59.97479
59.97449
59.97543
59.97705
59.97931
59.97964
59.979
59.97803
59.97803
59.979
59.98029
59.9819
59.98318
59.9845
59.98578
59.98642
59.98642
59.98709
59.98773
59.98965
59.99161
59.99255
59.99323
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29914.9
29914.9
29914.9
29914.9
29925.58
29925.58
29925.58
29925.58
29925.58
29938.87
29938.87
29938.87
29938.87
29938.87
29952.51
29952.51
29952.51
29952.51
29952.51
29952.51
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29948.95
29951.05
29951.05
29951.05
29951.05
29951.05
29955.09
29955.09
29955.09
29955.09
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.001
0.004
0.000
0.000
0.004
0.000
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
-0.001
0.000
-0.002
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.004
0.000
0.000
0.004
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.002
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
004619
Time (T)
05/16/11 08:01:32
05/16/11 08:01:34
05/16/11 08:01:36
05/16/11 08:01:38
05/16/11 08:01:40
05/16/11 08:01:42
05/16/11 08:01:44
05/16/11 08:01:46
05/16/11 08:01:48
05/16/11 08:01:50
05/16/11 08:01:52
05/16/11 08:01:54
05/16/11 08:01:56
05/16/11 08:01:58
05/16/11 08:02:00
05/16/11 08:02:02
05/16/11 08:02:04
05/16/11 08:02:06
05/16/11 08:02:08
05/16/11 08:02:10
05/16/11 08:02:12
05/16/11 08:02:14
05/16/11 08:02:16
05/16/11 08:02:18
05/16/11 08:02:20
05/16/11 08:02:22
05/16/11 08:02:24
05/16/11 08:02:26
05/16/11 08:02:28
05/16/11 08:02:30
05/16/11 08:02:32
05/16/11 08:02:34
05/16/11 08:02:36
05/16/11 08:02:38
05/16/11 08:02:40
05/16/11 08:02:42
05/16/11 08:02:44
05/16/11 08:02:46
Hz
59.99289
59.99097
59.98804
59.98578
59.98386
59.98318
59.98318
59.98288
59.98126
59.97998
59.97964
59.98029
59.98126
59.98352
59.98386
59.98126
59.97543
59.96832
59.9635
59.96155
59.96091
59.96155
59.96057
59.95801
59.95575
59.95575
59.95703
59.95895
59.96057
59.96155
59.96252
59.96414
59.96512
59.96512
59.96576
59.96704
59.96994
59.97253
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
29955.09
29967.69
29967.69
29967.69
29967.69
29967.69
29983.13
29983.13
29983.13
29983.13
29983.13
29976.75
29976.75
29976.75
29976.75
29976.75
29976.78
29976.78
29976.78
29976.78
29976.78
30008.51
30008.51
30008.51
30008.51
30008.51
30037.25
30037.25
30037.25
30037.25
30037.25
30055.73
30055.73
30055.73
30055.73
30055.73
30068.76
30068.76
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
-0.002
-0.003
-0.002
-0.002
-0.001
0.000
0.000
-0.002
-0.001
0.000
0.001
0.001
0.002
0.000
-0.003
-0.006
-0.007
-0.005
-0.002
-0.001
0.001
-0.001
-0.003
-0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.002
0.003
0.002
0.002
0.001
0.000
0.000
0.002
0.001
0.000
0.001
0.001
0.002
0.000
0.003
0.006
0.007
0.005
0.002
0.001
0.001
0.001
0.003
0.002
0.000
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.003
0.003
004620
Time (T)
05/16/11 08:02:48
05/16/11 08:02:50
05/16/11 08:02:52
05/16/11 08:02:54
05/16/11 08:02:56
05/16/11 08:02:58
05/16/11 08:03:00
05/16/11 08:03:02
05/16/11 08:03:04
05/16/11 08:03:06
05/16/11 08:03:08
05/16/11 08:03:10
05/16/11 08:03:12
05/16/11 08:03:14
05/16/11 08:03:16
05/16/11 08:03:18
05/16/11 08:03:20
05/16/11 08:03:22
05/16/11 08:03:24
05/16/11 08:03:26
05/16/11 08:03:28
05/16/11 08:03:30
05/16/11 08:03:32
05/16/11 08:03:34
05/16/11 08:03:36
05/16/11 08:03:38
05/16/11 08:03:40
05/16/11 08:03:42
05/16/11 08:03:44
05/16/11 08:03:46
05/16/11 08:03:48
05/16/11 08:03:50
05/16/11 08:03:52
05/16/11 08:03:54
05/16/11 08:03:56
05/16/11 08:03:58
05/16/11 08:04:00
05/16/11 08:04:02
Hz
59.97415
59.9761
59.97739
59.97931
59.98029
59.98062
59.98029
59.98029
59.97836
59.97836
59.979
59.97998
59.98029
59.98093
59.98093
59.97998
59.98062
59.98029
59.97998
59.979
59.97931
59.97998
59.98029
59.98029
59.98029
59.97964
59.979
59.97803
59.97803
59.97867
59.97964
59.98224
59.9848
59.98514
59.98416
59.98224
59.98029
59.979
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30068.76
30068.76
30068.76
30068.21
30068.21
30068.21
30068.21
30068.21
30068.24
30068.24
30068.24
30068.24
30068.24
30076.2
30076.2
30076.2
30076.2
30076.2
30093.95
30093.95
30093.95
30093.95
30093.95
30100.97
30100.97
30100.97
30100.97
30100.97
30118.87
30118.87
30118.87
30118.87
30118.87
30118.77
30118.77
30118.77
30118.77
30118.77
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
-0.002
0.000
0.001
0.001
0.000
0.001
0.000
-0.001
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.002
0.001
0.002
0.001
0.000
0.000
0.000
0.002
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.003
0.003
0.000
0.001
0.002
0.002
0.001
004621
Time (T)
05/16/11 08:04:04
05/16/11 08:04:06
05/16/11 08:04:08
05/16/11 08:04:10
05/16/11 08:04:12
05/16/11 08:04:14
05/16/11 08:04:16
05/16/11 08:04:18
05/16/11 08:04:20
05/16/11 08:04:22
05/16/11 08:04:24
05/16/11 08:04:26
05/16/11 08:04:28
05/16/11 08:04:30
05/16/11 08:04:32
05/16/11 08:04:34
05/16/11 08:04:36
05/16/11 08:04:38
05/16/11 08:04:40
05/16/11 08:04:42
05/16/11 08:04:44
05/16/11 08:04:46
05/16/11 08:04:48
05/16/11 08:04:50
05/16/11 08:04:52
05/16/11 08:04:54
05/16/11 08:04:56
05/16/11 08:04:58
05/16/11 08:05:00
05/16/11 08:05:02
05/16/11 08:05:04
05/16/11 08:05:06
05/16/11 08:05:08
05/16/11 08:05:10
05/16/11 08:05:12
05/16/11 08:05:14
05/16/11 08:05:16
05/16/11 08:05:18
Hz
59.97867
59.97931
59.97998
59.97931
59.979
59.97803
59.97675
59.97739
59.979
59.97964
59.98093
59.98224
59.98318
59.98318
59.98224
59.9819
59.9819
59.9819
59.9816
59.9819
59.9816
59.98126
59.9816
59.98254
59.98352
59.98416
59.98416
59.98416
59.98514
59.9874
59.98901
59.98804
59.98642
59.98288
59.98254
59.98318
59.9819
59.98062
Contingent
Resource
Lost
MW
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30118.74
30118.74
30118.74
30118.74
30118.74
30106.93
30106.93
30106.93
30106.93
30106.93
30106.61
30106.61
30106.61
30106.61
30106.61
30116.02
30116.02
30116.02
30116.02
30116.02
30141.59
30141.59
30141.59
30141.59
30141.59
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30144.23
30148.67
30148.67
30148.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0.000
0.001
0.001
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
-0.001
-0.002
-0.004
0.000
0.001
-0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.002
0.002
0.001
0.002
0.004
0.000
0.001
0.001
0.001
004622
Time (T)
05/16/11 08:05:20
05/16/11 08:05:22
05/16/11 08:05:24
05/16/11 08:05:26
05/16/11 08:05:28
05/16/11 08:05:30
05/16/11 08:05:32
05/16/11 08:05:34
05/16/11 08:05:36
05/16/11 08:05:38
05/16/11 08:05:40
05/16/11 08:05:42
05/16/11 08:05:44
05/16/11 08:05:46
05/16/11 08:05:48
05/16/11 08:05:50
05/16/11 08:05:52
05/16/11 08:05:54
05/16/11 08:05:56
05/16/11 08:05:58
05/16/11 08:06:00
05/16/11 08:06:02
05/16/11 08:06:04
05/16/11 08:06:06
05/16/11 08:06:08
05/16/11 08:06:10
05/16/11 08:06:12
05/16/11 08:06:14
05/16/11 08:06:16
05/16/11 08:06:18
05/16/11 08:06:20
05/16/11 08:06:22
05/16/11 08:06:24
05/16/11 08:06:26
05/16/11 08:06:28
05/16/11 08:06:30
05/16/11 08:06:32
05/16/11 08:06:34
Hz
Contingent
Resource
Lost
MW
59.97964
59.97964
59.97964
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471
471.3000183
471.3000183
471.3000183
471.3000183
471.8999939
471.8999939
471.8999939
471.8999939
471.8999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
471.3999939
470.8999939
470.8999939
470.8999939
470.8999939
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30148.67
30148.67
30155.67
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
0.001
0.003
0.003
0.003
0.001
-0.001
0.000
0.002
0.003
0.002
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.000
0.000
0.001
0.002
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.003
0.003
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.000
004623
Time (T)
05/16/11 08:06:36
05/16/11 08:06:38
05/16/11 08:06:40
05/16/11 08:06:42
05/16/11 08:06:44
05/16/11 08:06:46
05/16/11 08:06:48
05/16/11 08:06:50
05/16/11 08:06:52
05/16/11 08:06:54
05/16/11 08:06:56
05/16/11 08:06:58
05/16/11 08:07:00
05/16/11 08:07:02
05/16/11 08:07:04
05/16/11 08:07:06
05/16/11 08:07:08
05/16/11 08:07:10
05/16/11 08:07:12
05/16/11 08:07:14
05/16/11 08:07:16
05/16/11 08:07:18
05/16/11 08:07:20
05/16/11 08:07:22
05/16/11 08:07:24
05/16/11 08:07:26
05/16/11 08:07:28
05/16/11 08:07:30
05/16/11 08:07:32
05/16/11 08:07:34
05/16/11 08:07:36
05/16/11 08:07:38
05/16/11 08:07:40
05/16/11 08:07:42
05/16/11 08:07:44
05/16/11 08:07:46
05/16/11 08:07:48
05/16/11 08:07:50
Hz
Contingent
Resource
Lost
MW
60.00195 470.8999939
59.95963
0
59.88144
0
59.87237
0
59.87011
0
59.87432
0
59.88076
0
59.88531
0
59.88787
0
59.88949
0
59.8908
0
59.89175
0
59.89242
0
59.89306
0
59.89306
0
59.89306
0
59.89532
0
59.89788
0
59.8995
0
59.90081
0
59.9021
0
59.90179
0
59.90081
0
59.90081
0
59.90048
0
59.8992
0
59.89886
0
59.89856
0
59.90017
0
59.90243
0
59.90469
0
59.90695
0
59.90887
0
59.90921
0
59.90857
0
59.90887
0
59.91018
0
59.91244
0
Load
Resources
Tripped
MW
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30199.61
30199.61
30199.61
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.042
-0.078
-0.009
-0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
-0.001
0.000
0.000
-0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
-0.001
0.000
0.001
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.042
0.078
0.009
0.002
0.004
0.006
0.005
0.003
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.002
0.003
0.002
0.001
0.001
0.000
0.001
0.000
0.000
0.001
0.000
0.000
0.002
0.002
0.002
0.002
0.002
0.000
0.001
0.000
0.001
0.002
004624
Time (T)
05/16/11 08:07:52
05/16/11 08:07:54
05/16/11 08:07:56
05/16/11 08:07:58
05/16/11 08:08:00
05/16/11 08:08:02
05/16/11 08:08:04
05/16/11 08:08:06
05/16/11 08:08:08
05/16/11 08:08:10
05/16/11 08:08:12
05/16/11 08:08:14
05/16/11 08:08:16
05/16/11 08:08:18
05/16/11 08:08:20
05/16/11 08:08:22
05/16/11 08:08:24
05/16/11 08:08:26
05/16/11 08:08:28
05/16/11 08:08:30
05/16/11 08:08:32
05/16/11 08:08:34
05/16/11 08:08:36
05/16/11 08:08:38
05/16/11 08:08:40
05/16/11 08:08:42
05/16/11 08:08:44
05/16/11 08:08:46
05/16/11 08:08:48
05/16/11 08:08:50
05/16/11 08:08:52
05/16/11 08:08:54
05/16/11 08:08:56
05/16/11 08:08:58
05/16/11 08:09:00
05/16/11 08:09:02
05/16/11 08:09:04
05/16/11 08:09:06
Hz
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.6
30223.6
30223.73
30223.73
30223.73
30223.73
30224.39
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
-0.002
-0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.001
0.001
0.002
0.000
0.002
0.005
0.003
0.002
0.001
0.002
0.003
0.002
0.002
0.002
0.000
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.002
0.002
0.001
0.001
0.002
0.003
004625
Time (T)
05/16/11 08:09:08
05/16/11 08:09:10
05/16/11 08:09:12
05/16/11 08:09:14
05/16/11 08:09:16
05/16/11 08:09:18
05/16/11 08:09:20
05/16/11 08:09:22
05/16/11 08:09:24
05/16/11 08:09:26
05/16/11 08:09:28
05/16/11 08:09:30
05/16/11 08:09:32
05/16/11 08:09:34
05/16/11 08:09:36
05/16/11 08:09:38
05/16/11 08:09:40
05/16/11 08:09:42
05/16/11 08:09:44
05/16/11 08:09:46
05/16/11 08:09:48
05/16/11 08:09:50
05/16/11 08:09:52
05/16/11 08:09:54
05/16/11 08:09:56
05/16/11 08:09:58
05/16/11 08:10:00
05/16/11 08:10:02
05/16/11 08:10:04
05/16/11 08:10:06
05/16/11 08:10:08
05/16/11 08:10:10
05/16/11 08:10:12
05/16/11 08:10:14
05/16/11 08:10:16
05/16/11 08:10:18
05/16/11 08:10:20
05/16/11 08:10:22
Hz
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
-0.001
-0.001
-0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
-0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
-0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
-0.001
0.000
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.000
0.002
0.003
0.002
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.001
0.003
0.003
0.003
0.003
0.001
0.001
0.000
0.000
004626
Time (T)
05/16/11 08:10:24
05/16/11 08:10:26
05/16/11 08:10:28
05/16/11 08:10:30
05/16/11 08:10:32
05/16/11 08:10:34
05/16/11 08:10:36
05/16/11 08:10:38
05/16/11 08:10:40
05/16/11 08:10:42
05/16/11 08:10:44
05/16/11 08:10:46
05/16/11 08:10:48
05/16/11 08:10:50
05/16/11 08:10:52
05/16/11 08:10:54
05/16/11 08:10:56
05/16/11 08:10:58
05/16/11 08:11:00
05/16/11 08:11:02
05/16/11 08:11:04
05/16/11 08:11:06
05/16/11 08:11:08
05/16/11 08:11:10
05/16/11 08:11:12
05/16/11 08:11:14
05/16/11 08:11:16
05/16/11 08:11:18
05/16/11 08:11:20
05/16/11 08:11:22
05/16/11 08:11:24
05/16/11 08:11:26
05/16/11 08:11:28
05/16/11 08:11:30
05/16/11 08:11:32
05/16/11 08:11:34
05/16/11 08:11:36
05/16/11 08:11:38
Hz
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30297.68
30297.65
30297.65
30297.65
30297.65
30300.1
30300.1
30300.1
30300.1
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.5
30319.5
30319.5
30319.5
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
-0.001
-0.004
-0.005
-0.003
-0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
-0.001
-0.001
0.002
0.003
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.000
0.003
0.001
0.002
0.002
0.001
0.000
0.000
0.001
0.004
0.005
0.003
0.001
0.001
0.004
0.003
0.003
0.003
0.003
0.003
0.004
0.003
0.001
0.000
0.000
0.001
0.002
0.004
0.003
0.004
0.003
0.002
0.001
0.001
0.001
0.002
0.003
004627
Time (T)
05/16/11 08:11:40
05/16/11 08:11:42
05/16/11 08:11:44
05/16/11 08:11:46
05/16/11 08:11:48
05/16/11 08:11:50
05/16/11 08:11:52
05/16/11 08:11:54
05/16/11 08:11:56
05/16/11 08:11:58
05/16/11 08:12:00
05/16/11 08:12:02
05/16/11 08:12:04
05/16/11 08:12:06
05/16/11 08:12:08
05/16/11 08:12:10
05/16/11 08:12:12
05/16/11 08:12:14
05/16/11 08:12:16
05/16/11 08:12:18
05/16/11 08:12:20
05/16/11 08:12:22
05/16/11 08:12:24
05/16/11 08:12:26
05/16/11 08:12:28
05/16/11 08:12:30
05/16/11 08:12:32
05/16/11 08:12:34
05/16/11 08:12:36
05/16/11 08:12:38
05/16/11 08:12:40
05/16/11 08:12:42
05/16/11 08:12:44
05/16/11 08:12:46
05/16/11 08:12:48
05/16/11 08:12:50
05/16/11 08:12:52
05/16/11 08:12:54
Hz
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.2
30350.2
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.1
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
-0.001
0.000
0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.002
0.002
0.001
-0.001
-0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.002
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
004628
Time (T)
05/16/11 08:12:56
05/16/11 08:12:58
05/16/11 08:13:00
05/16/11 08:13:02
05/16/11 08:13:04
05/16/11 08:13:06
05/16/11 08:13:08
05/16/11 08:13:10
05/16/11 08:13:12
05/16/11 08:13:14
05/16/11 08:13:16
05/16/11 08:13:18
05/16/11 08:13:20
05/16/11 08:13:22
05/16/11 08:13:24
05/16/11 08:13:26
05/16/11 08:13:28
05/16/11 08:13:30
05/16/11 08:13:32
05/16/11 08:13:34
05/16/11 08:13:36
05/16/11 08:13:38
05/16/11 08:13:40
05/16/11 08:13:42
05/16/11 08:13:44
05/16/11 08:13:46
05/16/11 08:13:48
05/16/11 08:13:50
05/16/11 08:13:52
05/16/11 08:13:54
05/16/11 08:13:56
05/16/11 08:13:58
05/16/11 08:14:00
05/16/11 08:14:02
05/16/11 08:14:04
05/16/11 08:14:06
05/16/11 08:14:08
05/16/11 08:14:10
Hz
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30349.1
30349.1
30349.1
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.002
-0.002
-0.001
-0.002
-0.003
-0.002
0.000
-0.001
-0.003
-0.003
-0.001
-0.001
-0.002
-0.002
0.000
0.001
-0.001
0.000
-0.001
-0.002
-0.002
-0.003
-0.002
-0.001
-0.001
-0.002
-0.003
-0.001
0.002
0.000
-0.001
0.000
-0.001
-0.001
-0.001
0.000
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.002
0.001
0.002
0.003
0.002
0.000
0.001
0.003
0.003
0.001
0.001
0.002
0.002
0.000
0.001
0.001
0.000
0.001
0.002
0.002
0.003
0.002
0.001
0.001
0.002
0.003
0.001
0.002
0.000
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
004629
Time (T)
05/16/11 08:14:12
05/16/11 08:14:14
05/16/11 08:14:16
05/16/11 08:14:18
05/16/11 08:14:20
05/16/11 08:14:22
05/16/11 08:14:24
05/16/11 08:14:26
05/16/11 08:14:28
05/16/11 08:14:30
05/16/11 08:14:32
05/16/11 08:14:34
05/16/11 08:14:36
05/16/11 08:14:38
05/16/11 08:14:40
05/16/11 08:14:42
05/16/11 08:14:44
05/16/11 08:14:46
05/16/11 08:14:48
05/16/11 08:14:50
05/16/11 08:14:52
05/16/11 08:14:54
05/16/11 08:14:56
05/16/11 08:14:58
05/16/11 08:15:00
05/16/11 08:15:02
05/16/11 08:15:04
05/16/11 08:15:06
05/16/11 08:15:08
05/16/11 08:15:10
05/16/11 08:15:12
05/16/11 08:15:14
05/16/11 08:15:16
05/16/11 08:15:18
05/16/11 08:15:20
05/16/11 08:15:22
05/16/11 08:15:24
05/16/11 08:15:26
Hz
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
-0.001
-0.001
0.001
-0.001
-0.002
-0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
-0.001
-0.002
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.002
0.003
0.002
0.004
0.002
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.000
0.000
0.000
0.000
0.002
0.002
0.003
0.000
0.001
0.000
0.001
0.002
0.000
004630
Time (T)
05/16/11 08:15:28
05/16/11 08:15:30
05/16/11 08:15:32
05/16/11 08:15:34
05/16/11 08:15:36
05/16/11 08:15:38
05/16/11 08:15:40
05/16/11 08:15:42
05/16/11 08:15:44
05/16/11 08:15:46
05/16/11 08:15:48
05/16/11 08:15:50
05/16/11 08:15:52
05/16/11 08:15:54
05/16/11 08:15:56
05/16/11 08:15:58
05/16/11 08:16:00
05/16/11 08:16:02
05/16/11 08:16:04
05/16/11 08:16:06
05/16/11 08:16:08
05/16/11 08:16:10
05/16/11 08:16:12
05/16/11 08:16:14
05/16/11 08:16:16
05/16/11 08:16:18
05/16/11 08:16:20
05/16/11 08:16:22
05/16/11 08:16:24
05/16/11 08:16:26
05/16/11 08:16:28
05/16/11 08:16:30
05/16/11 08:16:32
05/16/11 08:16:34
05/16/11 08:16:36
05/16/11 08:16:38
05/16/11 08:16:40
05/16/11 08:16:42
Hz
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.004
0.002
0.000
0.001
-0.002
0.000
0.001
0.000
0.000
-0.001
-0.004
-0.001
0.000
-0.002
-0.002
-0.004
-0.004
0.000
-0.004
-0.005
-0.001
0.000
-0.002
-0.002
-0.004
-0.003
-0.001
-0.001
0.000
-0.002
-0.003
-0.002
-0.001
0.000
0.002
0.003
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.004
0.002
0.000
0.001
0.002
0.000
0.001
0.000
0.000
0.001
0.004
0.001
0.000
0.002
0.002
0.004
0.004
0.000
0.004
0.005
0.001
0.000
0.002
0.002
0.004
0.003
0.001
0.001
0.000
0.002
0.003
0.002
0.001
0.000
0.002
0.003
0.002
004631
Time (T)
05/16/11 08:16:44
05/16/11 08:16:46
05/16/11 08:16:48
05/16/11 08:16:50
05/16/11 08:16:52
05/16/11 08:16:54
05/16/11 08:16:56
05/16/11 08:16:58
05/16/11 08:17:00
05/16/11 08:17:02
05/16/11 08:17:04
05/16/11 08:17:06
05/16/11 08:17:08
05/16/11 08:17:10
05/16/11 08:17:12
05/16/11 08:17:14
05/16/11 08:17:16
05/16/11 08:17:18
05/16/11 08:17:20
05/16/11 08:17:22
05/16/11 08:17:24
05/16/11 08:17:26
05/16/11 08:17:28
05/16/11 08:17:30
05/16/11 08:17:32
05/16/11 08:17:34
05/16/11 08:17:36
05/16/11 08:17:38
05/16/11 08:17:40
05/16/11 08:17:42
05/16/11 08:17:44
05/16/11 08:17:46
05/16/11 08:17:48
05/16/11 08:17:50
05/16/11 08:17:52
05/16/11 08:17:54
05/16/11 08:17:56
05/16/11 08:17:58
Hz
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.4
30367.4
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.3
30406.3
30406.3
30406.3
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.3
30451.3
30451.3
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.003
-0.003
0.000
0.002
0.002
-0.001
-0.001
0.001
0.002
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.002
-0.001
-0.001
0.000
-0.001
-0.001
-0.002
-0.002
-0.001
0.001
0.003
0.003
0.001
0.000
-0.001
0.000
0.000
-0.005
0.004
0.005
0.000
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.003
0.003
0.000
0.002
0.002
0.001
0.001
0.001
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.002
0.002
0.001
0.001
0.003
0.003
0.001
0.000
0.001
0.000
0.000
0.005
0.004
0.005
0.000
0.000
004632
Time (T)
05/16/11 08:18:00
05/16/11 08:18:02
05/16/11 08:18:04
05/16/11 08:18:06
05/16/11 08:18:08
05/16/11 08:18:10
05/16/11 08:18:12
05/16/11 08:18:14
05/16/11 08:18:16
05/16/11 08:18:18
05/16/11 08:18:20
05/16/11 08:18:22
05/16/11 08:18:24
05/16/11 08:18:26
05/16/11 08:18:28
05/16/11 08:18:30
05/16/11 08:18:32
05/16/11 08:18:34
05/16/11 08:18:36
05/16/11 08:18:38
05/16/11 08:18:40
05/16/11 08:18:42
05/16/11 08:18:44
05/16/11 08:18:46
05/16/11 08:18:48
05/16/11 08:18:50
05/16/11 08:18:52
05/16/11 08:18:54
05/16/11 08:18:56
05/16/11 08:18:58
05/16/11 08:19:00
05/16/11 08:19:02
05/16/11 08:19:04
05/16/11 08:19:06
05/16/11 08:19:08
05/16/11 08:19:10
05/16/11 08:19:12
05/16/11 08:19:14
Hz
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30451.3
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.3
30465.3
30465.3
30465.3
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
0
0
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.008
-0.002
-0.003
-0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
-0.001
-0.001
0.000
0.000
0.000
0.003
0.003
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.008
0.002
0.003
0.001
0.000
0.004
0.004
0.004
0.003
0.002
0.002
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.003
0.003
0.000
0.001
0.002
0.002
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.000
004633
Time (T)
05/16/11 08:19:16
05/16/11 08:19:18
05/16/11 08:19:20
05/16/11 08:19:22
05/16/11 08:19:24
05/16/11 08:19:26
05/16/11 08:19:28
05/16/11 08:19:30
05/16/11 08:19:32
05/16/11 08:19:34
05/16/11 08:19:36
05/16/11 08:19:38
05/16/11 08:19:40
05/16/11 08:19:42
05/16/11 08:19:44
05/16/11 08:19:46
05/16/11 08:19:48
05/16/11 08:19:50
05/16/11 08:19:52
05/16/11 08:19:54
05/16/11 08:19:56
05/16/11 08:19:58
05/16/11 08:20:00
05/16/11 08:20:02
05/16/11 08:20:04
05/16/11 08:20:06
05/16/11 08:20:08
05/16/11 08:20:10
05/16/11 08:20:12
05/16/11 08:20:14
05/16/11 08:20:16
05/16/11 08:20:18
05/16/11 08:20:20
05/16/11 08:20:22
05/16/11 08:20:24
05/16/11 08:20:26
05/16/11 08:20:28
05/16/11 08:20:30
Hz
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
-0.001
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.003
0.000
-0.001
-0.003
-0.002
-0.002
-0.001
-0.001
-0.001
0.000
0.000
-0.003
-0.005
-0.003
-0.004
-0.002
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.001
0.000
0.000
0.001
0.001
0.001
0.000
0.003
0.000
0.001
0.003
0.002
0.002
0.001
0.001
0.001
0.000
0.000
0.003
0.005
0.003
0.004
0.002
0.001
004634
Time (T)
05/16/11 08:20:32
05/16/11 08:20:34
05/16/11 08:20:36
05/16/11 08:20:38
05/16/11 08:20:40
05/16/11 08:20:42
05/16/11 08:20:44
05/16/11 08:20:46
05/16/11 08:20:48
05/16/11 08:20:50
05/16/11 08:20:52
05/16/11 08:20:54
05/16/11 08:20:56
05/16/11 08:20:58
05/16/11 08:21:00
05/16/11 08:21:02
05/16/11 08:21:04
05/16/11 08:21:06
05/16/11 08:21:08
05/16/11 08:21:10
05/16/11 08:21:12
05/16/11 08:21:14
05/16/11 08:21:16
05/16/11 08:21:18
05/16/11 08:21:20
05/16/11 08:21:22
05/16/11 08:21:24
05/16/11 08:21:26
05/16/11 08:21:28
05/16/11 08:21:30
05/16/11 08:21:32
05/16/11 08:21:34
05/16/11 08:21:36
05/16/11 08:21:38
05/16/11 08:21:40
05/16/11 08:21:42
05/16/11 08:21:44
05/16/11 08:21:46
Hz
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
60.02682
60.02844
60.02972
60.03101
60.03198
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.6
30470.6
30470.6
30470.6
30461.28
30461.28
30461.28
30461.28
30450.44
30450.44
30451.91
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.000
0.001
0.002
0.002
0.000
-0.002
-0.003
-0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.000
0.001
0.002
0.002
0.000
0.002
0.003
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.003
0.008
0.008
0.009
0.006
0.004
0.001
0.000
0.000
0.002
0.002
0.001
0.002
0.001
0.001
0.001
004635
Time (T)
05/16/11 08:21:48
05/16/11 08:21:50
05/16/11 08:21:52
05/16/11 08:21:54
05/16/11 08:21:56
05/16/11 08:21:58
05/16/11 08:22:00
05/16/11 08:22:02
05/16/11 08:22:04
05/16/11 08:22:06
05/16/11 08:22:08
05/16/11 08:22:10
05/16/11 08:22:12
05/16/11 08:22:14
05/16/11 08:22:16
05/16/11 08:22:18
05/16/11 08:22:20
05/16/11 08:22:22
05/16/11 08:22:24
05/16/11 08:22:26
05/16/11 08:22:28
05/16/11 08:22:30
05/16/11 08:22:32
05/16/11 08:22:34
05/16/11 08:22:36
05/16/11 08:22:38
05/16/11 08:22:40
05/16/11 08:22:42
05/16/11 08:22:44
05/16/11 08:22:46
05/16/11 08:22:48
05/16/11 08:22:50
05/16/11 08:22:52
05/16/11 08:22:54
05/16/11 08:22:56
05/16/11 08:22:58
05/16/11 08:23:00
05/16/11 08:23:02
Hz
60.03296
60.03458
60.03488
60.03488
60.03424
60.03458
60.03458
60.03555
60.03586
60.03683
60.03748
60.03748
60.03717
60.03781
60.03781
60.03748
60.0365
60.03683
60.03748
60.03748
60.03812
60.03876
60.04007
60.04169
60.04361
60.04523
60.04492
60.04459
60.04395
60.04199
60.03717
60.03296
60.03101
60.03134
60.03168
60.03101
60.03101
60.03232
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30451.91
30451.91
30451.91
30446.52
30446.52
30446.52
30446.52
30452.43
30452.43
30452.43
30452.43
30452.43
30452.43
30473.21
30473.21
30473.21
30473.21
30476.61
30476.61
30476.55
30476.55
30476.55
30476.55
30473.8
30473.8
30473.8
30473.8
30471
30471
30471.97
30471.97
30471.97
30471.97
30485.47
30485.47
30485.47
30485.47
30505.49
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.002
0.000
0.000
-0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
-0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
-0.001
-0.002
-0.005
-0.004
-0.002
0.000
0.000
-0.001
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.002
0.002
0.000
0.000
0.001
0.002
0.005
0.004
0.002
0.000
0.000
0.001
0.000
0.001
004636
Time (T)
05/16/11 08:23:04
05/16/11 08:23:06
05/16/11 08:23:08
05/16/11 08:23:10
05/16/11 08:23:12
05/16/11 08:23:14
05/16/11 08:23:16
05/16/11 08:23:18
05/16/11 08:23:20
05/16/11 08:23:22
05/16/11 08:23:24
05/16/11 08:23:26
05/16/11 08:23:28
05/16/11 08:23:30
05/16/11 08:23:32
05/16/11 08:23:34
05/16/11 08:23:36
05/16/11 08:23:38
05/16/11 08:23:40
05/16/11 08:23:42
05/16/11 08:23:44
05/16/11 08:23:46
05/16/11 08:23:48
05/16/11 08:23:50
05/16/11 08:23:52
05/16/11 08:23:54
05/16/11 08:23:56
05/16/11 08:23:58
05/16/11 08:24:00
05/16/11 08:24:02
05/16/11 08:24:04
05/16/11 08:24:06
05/16/11 08:24:08
05/16/11 08:24:10
05/16/11 08:24:12
05/16/11 08:24:14
05/16/11 08:24:16
05/16/11 08:24:18
Hz
60.03326
60.03326
60.03394
60.03296
60.03232
60.03168
60.03168
60.03232
60.03232
60.03168
60.03168
60.03134
60.03101
60.03036
60.03036
60.02972
60.02875
60.03006
60.03198
60.03326
60.03458
60.03488
60.0336
60.03326
60.03232
60.03134
60.03168
60.03326
60.03458
60.03586
60.0365
60.03748
60.03683
60.03619
60.03522
60.03424
60.03296
60.03198
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30505.49
30505.26
30505.26
30505.26
30505.26
30515.6
30515.6
30515.6
30515.6
30505.28
30505.28
30506.12
30506.12
30506.12
30506.12
30493.68
30493.68
30493.68
30493.68
30529.28
30529.28
30529.08
30529.08
30529.08
30529.08
30529.52
30529.52
30529.52
30529.52
30535.57
30535.57
30533.89
30533.89
30533.89
30533.89
30521.82
30521.82
30521.82
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.000
0.001
-0.001
-0.001
-0.001
0.000
0.001
0.000
-0.001
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
0.001
0.002
0.001
0.001
0.000
-0.001
0.000
-0.001
-0.001
0.000
0.002
0.001
0.001
0.001
0.001
-0.001
-0.001
-0.001
-0.001
-0.001
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.002
0.001
0.001
0.000
0.001
0.000
0.001
0.001
0.000
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
0.001
004637
Time (T)
05/16/11 08:24:20
05/16/11 08:24:22
05/16/11 08:24:24
05/16/11 08:24:26
05/16/11 08:24:28
05/16/11 08:24:30
05/16/11 08:24:32
05/16/11 08:24:34
05/16/11 08:24:36
05/16/11 08:24:38
05/16/11 08:24:40
05/16/11 08:24:42
05/16/11 08:24:44
05/16/11 08:24:46
05/16/11 08:24:48
05/16/11 08:24:50
05/16/11 08:24:52
05/16/11 08:24:54
05/16/11 08:24:56
05/16/11 08:24:58
05/16/11 08:25:00
05/16/11 08:25:02
05/16/11 08:25:04
05/16/11 08:25:06
05/16/11 08:25:08
05/16/11 08:25:10
05/16/11 08:25:12
05/16/11 08:25:14
05/16/11 08:25:16
05/16/11 08:25:18
05/16/11 08:25:20
05/16/11 08:25:22
05/16/11 08:25:24
05/16/11 08:25:26
05/16/11 08:25:28
05/16/11 08:25:30
05/16/11 08:25:32
05/16/11 08:25:34
Hz
60.03134
60.03168
60.03134
60.03101
60.03036
60.02972
60.03006
60.0307
60.03168
60.0336
60.03488
60.03522
60.03586
60.03717
60.03812
60.03717
60.03748
60.03845
60.03876
60.03781
60.03619
60.03488
60.03394
60.0336
60.0336
60.03458
60.0365
60.03748
60.03781
60.03748
60.0365
60.03488
60.0336
60.03232
60.03134
60.03101
60.03101
60.0307
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30521.82
30533.64
30533.64
30532.32
30532.32
30532.32
30532.32
30551.2
30551.2
30551.2
30551.2
30548.06
30548.06
30543.69
30543.69
30543.69
30543.69
30546.32
30546.32
30546.32
30546.32
30546.28
30546.28
30546.38
30546.38
30546.38
30546.38
30556.84
30556.84
30556.84
30556.84
30557.42
30557.42
30557.43
30557.43
30557.43
30557.43
30566.39
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.000
0.000
-0.001
-0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
-0.001
-0.002
-0.001
-0.001
-0.001
0.000
0.000
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.000
0.000
0.000
0.001
0.001
0.000
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.001
0.000
0.000
0.000
004638
Time (T)
05/16/11 08:25:36
05/16/11 08:25:38
05/16/11 08:25:40
05/16/11 08:25:42
05/16/11 08:25:44
05/16/11 08:25:46
05/16/11 08:25:48
05/16/11 08:25:50
05/16/11 08:25:52
05/16/11 08:25:54
05/16/11 08:25:56
05/16/11 08:25:58
05/16/11 08:26:00
05/16/11 08:26:02
05/16/11 08:26:04
05/16/11 08:26:06
05/16/11 08:26:08
05/16/11 08:26:10
05/16/11 08:26:12
05/16/11 08:26:14
05/16/11 08:26:16
05/16/11 08:26:18
05/16/11 08:26:20
05/16/11 08:26:22
05/16/11 08:26:24
05/16/11 08:26:26
05/16/11 08:26:28
05/16/11 08:26:30
05/16/11 08:26:32
05/16/11 08:26:34
05/16/11 08:26:36
05/16/11 08:26:38
05/16/11 08:26:40
05/16/11 08:26:42
05/16/11 08:26:44
05/16/11 08:26:46
05/16/11 08:26:48
05/16/11 08:26:50
Hz
60.02972
60.02908
60.02811
60.02649
60.02521
60.02359
60.02133
60.02002
60.02002
60.02069
60.02133
60.021
60.02036
60.01938
60.01938
60.01938
60.01971
60.01971
60.01907
60.01938
60.02036
60.02036
60.01907
60.01712
60.01584
60.0152
60.0155
60.01614
60.01746
60.0181
60.01746
60.01712
60.01648
60.01486
60.01227
60.01035
60.00937
60.00903
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30566.39
30566.39
30566.39
30567.26
30567.26
30562.43
30562.43
30562.43
30562.43
30573.32
30573.32
30573.32
30573.32
30567
30567
30567.04
30567.04
30567.04
30567.04
30556.49
30556.49
30556.49
30556.49
30530.19
30530.19
30530.04
30530.04
30530.04
30530.04
30542.27
30542.27
30542.27
30542.27
30559.64
30559.64
30559.67
30559.67
30559.67
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
-0.001
-0.002
-0.001
-0.002
-0.002
-0.001
0.000
0.001
0.001
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
-0.001
0.000
0.001
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.001
0.001
0.001
-0.001
0.000
-0.001
-0.002
-0.003
-0.002
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.001
0.001
0.002
0.001
0.002
0.002
0.001
0.000
0.001
0.001
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.002
0.003
0.002
0.001
0.000
004639
Time (T)
05/16/11 08:26:52
05/16/11 08:26:54
05/16/11 08:26:56
05/16/11 08:26:58
05/16/11 08:27:00
05/16/11 08:27:02
05/16/11 08:27:04
05/16/11 08:27:06
05/16/11 08:27:08
05/16/11 08:27:10
05/16/11 08:27:12
05/16/11 08:27:14
05/16/11 08:27:16
05/16/11 08:27:18
05/16/11 08:27:20
05/16/11 08:27:22
05/16/11 08:27:24
05/16/11 08:27:26
05/16/11 08:27:28
05/16/11 08:27:30
05/16/11 08:27:32
05/16/11 08:27:34
05/16/11 08:27:36
05/16/11 08:27:38
05/16/11 08:27:40
05/16/11 08:27:42
05/16/11 08:27:44
05/16/11 08:27:46
05/16/11 08:27:48
05/16/11 08:27:50
05/16/11 08:27:52
05/16/11 08:27:54
05/16/11 08:27:56
05/16/11 08:27:58
05/16/11 08:28:00
05/16/11 08:28:02
05/16/11 08:28:04
05/16/11 08:28:06
Hz
60.00937
60.01065
60.01163
60.01227
60.01163
60.00873
60.00647
60.00583
60.00613
60.00613
60.00711
60.00903
60.01099
60.01099
60.01035
60.0097
60.00873
60.00711
60.00613
60.00583
60.00711
60.00809
60.00839
60.00809
60.00711
60.00677
60.00775
60.00711
60.00647
60.00388
60.00128
59.99936
59.99805
59.99741
59.9971
59.99677
59.9971
59.99646
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30559.67
30552.02
30552.02
30552.02
30552.02
30556.78
30556.78
30550.7
30550.7
30550.7
30550.7
30559.76
30559.76
30559.76
30559.76
30563.61
30563.61
30556.57
30556.57
30556.57
30556.57
30556.7
30556.7
30556.7
30556.7
30544.52
30544.52
30543.34
30543.34
30543.34
30543.34
30554.42
30554.42
30554.42
30554.42
30534.33
30534.33
30533.84
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.001
0.001
0.001
-0.001
-0.003
-0.002
-0.001
0.000
0.000
0.001
0.002
0.002
0.000
-0.001
-0.001
-0.001
-0.002
-0.001
0.000
0.001
0.001
0.000
0.000
-0.001
0.000
0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
0.000
0.000
0.000
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.001
0.001
0.001
0.003
0.002
0.001
0.000
0.000
0.001
0.002
0.002
0.000
0.001
0.001
0.001
0.002
0.001
0.000
0.001
0.001
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.000
0.000
0.000
0.001
004640
Time (T)
05/16/11 08:28:08
05/16/11 08:28:10
05/16/11 08:28:12
05/16/11 08:28:14
05/16/11 08:28:16
05/16/11 08:28:18
05/16/11 08:28:20
05/16/11 08:28:22
05/16/11 08:28:24
05/16/11 08:28:26
05/16/11 08:28:28
05/16/11 08:28:30
05/16/11 08:28:32
05/16/11 08:28:34
05/16/11 08:28:36
05/16/11 08:28:38
05/16/11 08:28:40
05/16/11 08:28:42
05/16/11 08:28:44
05/16/11 08:28:46
05/16/11 08:28:48
05/16/11 08:28:50
05/16/11 08:28:52
05/16/11 08:28:54
05/16/11 08:28:56
05/16/11 08:28:58
05/16/11 08:29:00
05/16/11 08:29:02
05/16/11 08:29:04
05/16/11 08:29:06
05/16/11 08:29:08
05/16/11 08:29:10
05/16/11 08:29:12
05/16/11 08:29:14
05/16/11 08:29:16
05/16/11 08:29:18
05/16/11 08:29:20
05/16/11 08:29:22
Hz
59.99579
59.99451
59.99353
59.99289
59.99191
59.98901
59.98611
59.9845
59.98318
59.9819
59.98093
59.97964
59.97867
59.97964
59.97998
59.98062
59.98029
59.979
59.97739
59.97513
59.97351
59.97253
59.97189
59.97318
59.97415
59.97449
59.97513
59.97577
59.97641
59.97705
59.97675
59.97675
59.97675
59.9761
59.9761
59.97641
59.97705
59.97803
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30533.84
30533.84
30533.84
30557.2
30557.2
30557.2
30557.2
30560.91
30560.91
30560.56
30560.56
30560.56
30560.56
30560.08
30560.08
30560.08
30560.08
30558.72
30558.72
30553.46
30553.46
30553.46
30553.46
30562.63
30562.63
30562.63
30562.63
30578.05
30578.05
30570.97
30570.97
30570.97
30570.97
30593.17
30593.17
30593.17
30593.17
30575.07
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
-0.001
-0.001
-0.001
-0.001
-0.003
-0.003
-0.002
-0.001
-0.001
-0.001
-0.001
-0.001
0.001
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
0.000
0.000
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.001
0.001
0.001
0.001
0.003
0.003
0.002
0.001
0.001
0.001
0.001
0.001
0.001
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.000
0.000
0.001
0.001
004641
Time (T)
05/16/11 08:29:24
05/16/11 08:29:26
05/16/11 08:29:28
05/16/11 08:29:30
05/16/11 08:29:32
05/16/11 08:29:34
05/16/11 08:29:36
05/16/11 08:29:38
05/16/11 08:29:40
05/16/11 08:29:42
05/16/11 08:29:44
05/16/11 08:29:46
05/16/11 08:29:48
05/16/11 08:29:50
05/16/11 08:29:52
05/16/11 08:29:54
05/16/11 08:29:56
05/16/11 08:29:58
05/16/11 08:30:00
05/16/11 08:30:02
05/16/11 08:30:04
05/16/11 08:30:06
05/16/11 08:30:08
05/16/11 08:30:10
05/16/11 08:30:12
05/16/11 08:30:14
05/16/11 08:30:16
05/16/11 08:30:18
05/16/11 08:30:20
05/16/11 08:30:22
05/16/11 08:30:24
05/16/11 08:30:26
05/16/11 08:30:28
05/16/11 08:30:30
05/16/11 08:30:32
05/16/11 08:30:34
05/16/11 08:30:36
05/16/11 08:30:38
Hz
59.98029
59.98318
59.98547
59.98709
59.98965
59.99225
59.99484
59.99646
59.99774
59.99966
60.00034
60.00128
60.00195
60.00226
60.0029
60.00354
60.00421
60.00452
60.00388
60.00388
60.00421
60.00421
60.00388
60.00195
59.99966
59.99387
59.99387
59.98999
59.98868
59.98709
59.98578
59.98578
59.98288
59.97964
59.97675
59.97479
59.97479
59.97641
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30575.07
30575.07
30575.07
30575.07
30575.07
30575.72
30575.72
30575.72
30575.72
30583.84
30583.84
30586.4
30586.4
30586.4
30586.4
30589.72
30589.72
30589.72
30589.72
30590.3
30590.3
30590.22
30590.22
30590.22
30590.22
30600.12
30600.12
30600.12
30600.12
30603.38
30603.38
30597.09
30597.09
30597.09
30597.09
30603.96
30603.96
30603.96
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
-0.001
0.000
0.000
0.000
0.000
-0.002
-0.002
-0.006
0.000
-0.004
-0.001
-0.002
-0.001
0.000
-0.003
-0.003
-0.003
-0.002
0.000
0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.002
0.003
0.002
0.002
0.003
0.003
0.003
0.002
0.001
0.002
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.001
0.000
0.000
0.000
0.000
0.002
0.002
0.006
0.000
0.004
0.001
0.002
0.001
0.000
0.003
0.003
0.003
0.002
0.000
0.002
004642
Time (T)
05/16/11 08:30:40
05/16/11 08:30:42
05/16/11 08:30:44
05/16/11 08:30:46
05/16/11 08:30:48
05/16/11 08:30:50
05/16/11 08:30:52
05/16/11 08:30:54
05/16/11 08:30:56
05/16/11 08:30:58
05/16/11 08:31:00
05/16/11 08:31:02
05/16/11 08:31:04
05/16/11 08:31:06
05/16/11 08:31:08
05/16/11 08:31:10
05/16/11 08:31:12
05/16/11 08:31:14
05/16/11 08:31:16
05/16/11 08:31:18
05/16/11 08:31:20
05/16/11 08:31:22
05/16/11 08:31:24
05/16/11 08:31:26
05/16/11 08:31:28
05/16/11 08:31:30
05/16/11 08:31:32
05/16/11 08:31:34
05/16/11 08:31:36
05/16/11 08:31:38
05/16/11 08:31:40
05/16/11 08:31:42
05/16/11 08:31:44
05/16/11 08:31:46
05/16/11 08:31:48
05/16/11 08:31:50
05/16/11 08:31:52
05/16/11 08:31:54
Hz
59.97641
59.97543
59.97351
59.97318
59.97513
59.97641
59.97705
59.97867
59.97836
59.97803
59.97543
59.97415
59.97415
59.97479
59.97415
59.97351
59.97351
59.97543
59.97769
59.98062
59.98514
59.98773
59.98965
59.99097
59.99225
59.99323
59.99612
60.00034
60.00452
60.00809
60.01099
60.01389
60.01776
60.02069
60.02164
60.021
60.01907
60.0181
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30603.96
30607.96
30607.96
30601.98
30601.98
30597.09
30597.09
30607.96
30607.96
30607.96
30607.96
30607.96
30601.98
30601.98
30601.98
30601.98
30601.98
30632.79
30632.79
30632.79
30632.79
30632.79
30633.18
30633.18
30633.18
30633.18
30633.18
30620.6
30620.6
30620.6
30620.6
30620.6
30620.91
30620.91
30620.91
30620.91
30620.91
30661.87
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
-0.003
-0.001
0.000
0.001
-0.001
-0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
-0.001
-0.002
-0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.002
0.000
0.000
0.003
0.001
0.000
0.001
0.001
0.001
0.000
0.002
0.002
0.003
0.005
0.003
0.002
0.001
0.001
0.001
0.003
0.004
0.004
0.004
0.003
0.003
0.004
0.003
0.001
0.001
0.002
0.001
004643
Time (T)
05/16/11 08:31:56
05/16/11 08:31:58
05/16/11 08:32:00
05/16/11 08:32:02
05/16/11 08:32:04
05/16/11 08:32:06
05/16/11 08:32:08
05/16/11 08:32:10
05/16/11 08:32:12
05/16/11 08:32:14
05/16/11 08:32:16
05/16/11 08:32:18
05/16/11 08:32:20
05/16/11 08:32:22
05/16/11 08:32:24
05/16/11 08:32:26
05/16/11 08:32:28
05/16/11 08:32:30
05/16/11 08:32:32
05/16/11 08:32:34
05/16/11 08:32:36
05/16/11 08:32:38
05/16/11 08:32:40
05/16/11 08:32:42
05/16/11 08:32:44
05/16/11 08:32:46
05/16/11 08:32:48
05/16/11 08:32:50
05/16/11 08:32:52
05/16/11 08:32:54
05/16/11 08:32:56
05/16/11 08:32:58
05/16/11 08:33:00
05/16/11 08:33:02
05/16/11 08:33:04
05/16/11 08:33:06
05/16/11 08:33:08
05/16/11 08:33:10
Hz
60.0184
60.02069
60.0239
60.02618
60.02682
60.02649
60.02585
60.02359
60.02359
60.02164
60.02231
60.02325
60.02359
60.02295
60.02133
60.021
60.021
60.02133
60.021
60.02036
60.02002
60.01938
60.0184
60.01712
60.01584
60.01486
60.01453
60.01486
60.01453
60.01486
60.0152
60.01486
60.0152
60.0152
60.01648
60.01614
60.0152
60.01486
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30661.87
30661.87
30661.87
30661.87
30663.73
30663.73
30663.73
30663.73
30663.73
30659.84
30659.84
30659.84
30659.84
30659.84
30653.46
30653.46
30653.46
30653.46
30653.46
30661.6
30661.6
30661.6
30661.6
30661.6
30655.51
30655.51
30655.51
30655.51
30655.51
30648.14
30648.14
30648.14
30648.14
30648.14
30648.29
30648.29
30648.29
30648.29
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
0.002
0.003
0.002
0.001
0.000
-0.001
-0.002
0.000
-0.002
0.001
0.001
0.000
-0.001
-0.002
0.000
0.000
0.000
0.000
-0.001
0.000
-0.001
-0.001
-0.001
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.002
0.003
0.002
0.001
0.000
0.001
0.002
0.000
0.002
0.001
0.001
0.000
0.001
0.002
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.000
0.001
0.000
004644
Time (T)
05/16/11 08:33:12
05/16/11 08:33:14
05/16/11 08:33:16
05/16/11 08:33:18
05/16/11 08:33:20
05/16/11 08:33:22
05/16/11 08:33:24
05/16/11 08:33:26
05/16/11 08:33:28
05/16/11 08:33:30
05/16/11 08:33:32
05/16/11 08:33:34
05/16/11 08:33:36
05/16/11 08:33:38
05/16/11 08:33:40
05/16/11 08:33:42
05/16/11 08:33:44
05/16/11 08:33:46
05/16/11 08:33:48
05/16/11 08:33:50
05/16/11 08:33:52
05/16/11 08:33:54
05/16/11 08:33:56
05/16/11 08:33:58
05/16/11 08:34:00
05/16/11 08:34:02
05/16/11 08:34:04
05/16/11 08:34:06
05/16/11 08:34:08
05/16/11 08:34:10
05/16/11 08:34:12
05/16/11 08:34:14
05/16/11 08:34:16
05/16/11 08:34:18
05/16/11 08:34:20
05/16/11 08:34:22
05/16/11 08:34:24
05/16/11 08:34:26
Hz
60.01453
60.01291
60.01099
60.00775
60.00421
60.00162
60
59.99774
59.99515
59.99255
59.9903
59.98676
59.98352
59.98062
59.97964
59.97867
59.97705
59.97641
59.97675
59.97641
59.97577
59.97479
59.97415
59.97287
59.97125
59.97092
59.97125
59.97061
59.97092
59.97125
59.97156
59.97253
59.97449
59.97577
59.97641
59.97641
59.97513
59.9761
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30648.29
30652.04
30652.04
30652.04
30652.04
30652.04
30651.84
30651.84
30651.84
30651.84
30651.84
30633.8
30633.8
30633.8
30633.8
30633.8
30627.71
30627.71
30627.71
30627.71
30627.71
30634.13
30634.13
30634.13
30634.13
30634.13
30627.05
30627.05
30627.05
30627.05
30627.05
30662.72
30662.72
30662.72
30662.72
30662.72
30656.52
30656.52
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.002
-0.002
-0.003
-0.004
-0.003
-0.002
-0.002
-0.003
-0.003
-0.002
-0.004
-0.003
-0.003
-0.001
-0.001
-0.002
-0.001
0.000
0.000
-0.001
-0.001
-0.001
-0.001
-0.002
0.000
0.000
-0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.002
0.002
0.003
0.004
0.003
0.002
0.002
0.003
0.003
0.002
0.004
0.003
0.003
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.002
0.000
0.000
0.001
0.000
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.001
004645
Time (T)
05/16/11 08:34:28
05/16/11 08:34:30
05/16/11 08:34:32
05/16/11 08:34:34
05/16/11 08:34:36
05/16/11 08:34:38
05/16/11 08:34:40
05/16/11 08:34:42
05/16/11 08:34:44
05/16/11 08:34:46
05/16/11 08:34:48
05/16/11 08:34:50
05/16/11 08:34:52
05/16/11 08:34:54
05/16/11 08:34:56
05/16/11 08:34:58
05/16/11 08:35:00
05/16/11 08:35:02
05/16/11 08:35:04
05/16/11 08:35:06
05/16/11 08:35:08
05/16/11 08:35:10
05/16/11 08:35:12
05/16/11 08:35:14
05/16/11 08:35:16
05/16/11 08:35:18
05/16/11 08:35:20
05/16/11 08:35:22
05/16/11 08:35:24
05/16/11 08:35:26
05/16/11 08:35:28
05/16/11 08:35:30
05/16/11 08:35:32
05/16/11 08:35:34
05/16/11 08:35:36
05/16/11 08:35:38
05/16/11 08:35:40
05/16/11 08:35:42
Hz
59.979
59.98126
59.98224
59.98254
59.98254
59.9816
59.98029
59.97964
59.98062
59.98093
59.98029
59.97931
59.97836
59.97803
59.97803
59.97867
59.97964
59.98062
59.98126
59.98224
59.98416
59.98547
59.98578
59.98578
59.98676
59.99063
59.99417
59.99805
59.99966
60.00226
60.00195
60.00098
59.99936
59.99872
59.99774
59.99741
59.99741
59.99838
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30656.52
30656.52
30656.52
30642.25
30642.25
30642.25
30642.25
30642.25
30642.49
30642.49
30642.49
30642.49
30642.49
30645.72
30645.72
30645.72
30645.72
30645.72
30648.55
30648.55
30648.55
30648.55
30648.55
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30661.06
30684.31
30684.31
30684.31
30684.31
30684.31
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
0
0
0
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.003
0.002
0.001
0.000
0.000
-0.001
-0.001
-0.001
0.001
0.000
-0.001
-0.001
-0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
-0.001
-0.002
-0.001
-0.001
0.000
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.003
0.002
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.000
0.001
0.001
0.001
0.000
0.000
0.001
0.001
0.001
0.001
0.001
0.002
0.001
0.000
0.000
0.001
0.004
0.004
0.004
0.002
0.003
0.000
0.001
0.002
0.001
0.001
0.000
0.000
0.001
004646
Time (T)
05/16/11 08:35:44
05/16/11 08:35:46
05/16/11 08:35:48
05/16/11 08:35:50
05/16/11 08:35:52
05/16/11 08:35:54
05/16/11 08:35:56
05/16/11 08:35:58
05/16/11 08:36:00
05/16/11 08:36:02
05/16/11 08:36:04
05/16/11 08:36:06
05/16/11 08:36:08
05/16/11 08:36:10
05/16/11 08:36:12
05/16/11 08:36:14
05/16/11 08:36:16
05/16/11 08:36:18
05/16/11 08:36:20
05/16/11 08:36:22
05/16/11 08:36:24
05/16/11 08:36:26
05/16/11 08:36:28
05/16/11 08:36:30
05/16/11 08:36:32
05/16/11 08:36:34
05/16/11 08:36:36
05/16/11 08:36:38
05/16/11 08:36:40
05/16/11 08:36:42
05/16/11 08:36:44
05/16/11 08:36:46
05/16/11 08:36:48
05/16/11 08:36:50
05/16/11 08:36:52
05/16/11 08:36:54
05/16/11 08:36:56
05/16/11 08:36:58
Hz
59.99966
60.00064
60.00098
60.00064
60
59.99936
59.99741
59.99484
59.99289
59.99097
59.98965
59.98804
59.98773
59.98804
59.98901
59.99063
59.99255
59.99484
59.99677
59.99838
59.99872
59.99872
59.99936
60.00195
60.00485
60.00809
60.01099
60.01324
60.01422
60.01486
60.01453
60.01227
60.01099
60.01099
60.01227
60.01227
60.01163
60.01132
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
-653
-653
-653
-653
-653
-653
-653
BA
Load
MW
30686.83
30686.83
30686.83
30686.83
30686.83
30678.05
30678.05
30678.05
30678.05
30678.05
30679.19
30679.19
30679.19
30679.19
30679.19
30684.85
30684.85
30684.85
30684.85
30684.85
30684.99
30684.99
30684.99
30684.99
30684.99
30687.29
30687.29
30687.29
30687.29
30687.29
30687.59
30687.59
30687.59
30687.59
30687.59
30726.76
30726.76
30726.76
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.001
0.001
0.000
0.000
-0.001
-0.001
-0.002
-0.003
-0.002
-0.002
-0.001
-0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
-0.002
-0.001
0.000
0.001
0.000
-0.001
0.000
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.001
0.000
0.000
0.001
0.001
0.002
0.003
0.002
0.002
0.001
0.002
0.000
0.000
0.001
0.002
0.002
0.002
0.002
0.002
0.000
0.000
0.001
0.003
0.003
0.003
0.003
0.002
0.001
0.001
0.000
0.002
0.001
0.000
0.001
0.000
0.001
0.000
004647
Time (T)
05/16/11 08:37:00
05/16/11 08:37:02
05/16/11 08:37:04
05/16/11 08:37:06
05/16/11 08:37:08
05/16/11 08:37:10
05/16/11 08:37:12
05/16/11 08:37:14
05/16/11 08:37:16
05/16/11 08:37:18
05/16/11 08:37:20
05/16/11 08:37:22
05/16/11 08:37:24
05/16/11 08:37:26
05/16/11 08:37:28
05/16/11 08:37:30
05/16/11 08:37:32
05/16/11 08:37:34
05/16/11 08:37:36
05/16/11 08:37:38
05/16/11 08:37:40
05/16/11 08:37:42
05/16/11 08:37:44
05/16/11 08:37:46
05/16/11 08:37:48
05/16/11 08:37:50
05/16/11 08:37:52
05/16/11 08:37:54
05/16/11 08:37:56
05/16/11 08:37:58
05/16/11 08:38:00
05/16/11 08:38:02
05/16/11 08:38:04
05/16/11 08:38:06
05/16/11 08:38:08
05/16/11 08:38:10
05/16/11 08:38:12
05/16/11 08:38:14
Hz
60.01132
60.01065
60.00903
60.00839
60.00809
60.00809
60.00937
60.01099
60.01227
60.01291
60.0126
60.01132
60.0097
60.00613
60.00259
59.99936
59.99902
60.00034
60.00064
59.99936
59.99741
59.99579
59.99387
59.99255
59.99191
59.99255
59.99548
60
60.00323
60.00516
60.00485
60.00354
60.00226
60.00098
60
59.99966
59.99966
59.99774
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30726.76
30726.76
30726.82
30726.82
30726.82
30726.82
30726.82
30720.93
30720.93
30720.93
30720.93
30720.93
30720.53
30720.53
30720.53
30720.53
30720.53
30720.62
30720.62
30720.62
30720.62
30720.62
30721.15
30721.15
30721.15
30721.15
30721.15
30726.87
30726.87
30726.87
30726.87
30726.87
30734.84
30734.84
30734.84
30734.84
30734.84
30757.45
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.002
-0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
-0.001
-0.002
-0.004
-0.004
-0.003
0.000
0.001
0.000
-0.001
-0.002
-0.002
-0.002
-0.001
-0.001
0.001
0.003
0.005
0.003
0.002
0.000
-0.001
-0.001
-0.001
-0.001
0.000
0.000
-0.002
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.002
0.001
0.000
0.000
0.001
0.002
0.001
0.001
0.000
0.001
0.002
0.004
0.004
0.003
0.000
0.001
0.000
0.001
0.002
0.002
0.002
0.001
0.001
0.001
0.003
0.005
0.003
0.002
0.000
0.001
0.001
0.001
0.001
0.000
0.000
0.002
004648
Time (T)
05/16/11 08:38:16
05/16/11 08:38:18
05/16/11 08:38:20
05/16/11 08:38:22
05/16/11 08:38:24
05/16/11 08:38:26
05/16/11 08:38:28
05/16/11 08:38:30
05/16/11 08:38:32
05/16/11 08:38:34
05/16/11 08:38:36
05/16/11 08:38:38
05/16/11 08:38:40
05/16/11 08:38:42
05/16/11 08:38:44
05/16/11 08:38:46
05/16/11 08:38:48
05/16/11 08:38:50
05/16/11 08:38:52
05/16/11 08:38:54
05/16/11 08:38:56
05/16/11 08:38:58
05/16/11 08:39:00
05/16/11 08:39:02
05/16/11 08:39:04
05/16/11 08:39:06
05/16/11 08:39:08
05/16/11 08:39:10
05/16/11 08:39:12
05/16/11 08:39:14
05/16/11 08:39:16
05/16/11 08:39:18
05/16/11 08:39:20
05/16/11 08:39:22
05/16/11 08:39:24
05/16/11 08:39:26
05/16/11 08:39:28
05/16/11 08:39:30
Hz
59.9971
59.99741
59.99805
59.99872
59.99936
60
60.00162
60.00323
60.00388
60.00485
60.00549
60.00613
60.00647
60.00677
60.00677
60.00613
60.00549
60.00485
60.00485
60.00613
60.01001
60.01324
60.01614
60.0184
60.01971
60.021
60.02133
60.02197
60.02359
60.02682
60.0307
60.0336
60.03424
60.03326
60.0307
60.02875
60.02875
60.02939
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30757.45
30757.45
30757.45
30757.45
30757.92
30757.92
30757.92
30757.92
30757.92
30752.27
30752.27
30752.27
30752.27
30752.27
30752.33
30752.33
30752.33
30752.33
30752.33
30755.63
30755.63
30755.63
30755.63
30755.63
30755.66
30755.66
30755.66
30755.66
30755.66
30784.89
30784.89
30784.89
30784.89
30784.89
30786.98
30786.98
30786.98
30786.98
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
-0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
-0.001
-0.003
-0.002
0.000
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.001
0.000
0.001
0.001
0.001
0.001
0.002
0.002
0.001
0.001
0.001
0.001
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.004
0.003
0.003
0.002
0.001
0.001
0.000
0.001
0.002
0.003
0.004
0.003
0.001
0.001
0.003
0.002
0.000
0.001
004649
Time (T)
05/16/11 08:39:32
05/16/11 08:39:34
05/16/11 08:39:36
05/16/11 08:39:38
05/16/11 08:39:40
05/16/11 08:39:42
05/16/11 08:39:44
05/16/11 08:39:46
05/16/11 08:39:48
05/16/11 08:39:50
05/16/11 08:39:52
05/16/11 08:39:54
05/16/11 08:39:56
05/16/11 08:39:58
05/16/11 08:40:00
Hz
60.02908
60.02844
60.02777
60.02811
60.02777
60.02777
60.02777
60.02747
60.02713
60.02618
60.02521
60.02457
60.02487
60.02551
60.02618
Contingent
Resource
Lost
MW
Load
Resources
Tripped
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NonConforming
Load
Load (-)
MW
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Not
Used
Not
Used
BA
Bias
Setting
MW/0.1 Hz
BA
Load
MW
30786.98
30796.28
30796.28
30796.28
30796.28
30796.28
30792.94
30792.94
30792.94
30792.94
30792.94
30803.58
30803.58
30803.58
30803.58
Event
Recovery
Detection Target Freq:
Row
59.999
805
8:06:38
921
8:10:30
806
03:52
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Max Absolute Delta
Hz
0.078
t(0)
t(Recovery)
Event Length mm:ss
Lowest
Delta Hz
-0.078
Delta
Hz
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
0.000
-0.001
-0.001
0.000
0.000
0.000
0.000
0.000
0.000
-0.001
-0.001
-0.001
0.000
0.001
0.001
Rows of
data to
Highest Delta shift to
Hz
align T(0)
0.009
1
Absolute
Delta Hz
0.000
0.001
0.001
0.000
0.000
0.000
0.000
0.000
0.000
0.001
0.001
0.001
0.000
0.001
0.001
Balancing Authority Name: MyBA
Interconnection Prevailing UFLS First Step Relay trip point
Interconnection High Relay trip point
Note: See "Instruction" tab for more detailed instructions.
Step 1. Copy and Paste Event Data into the appropriate cells of the "Data" worksheet.
Maintain date and time format of mm/dd/yy hh:mm:ss.
Step 2. Data must start at least 2 full minutes before the beginning of the event.
Collect the same amount of data for each event. Suggest 2 to 3 minutes before to 15 minutes after (up
to 60 minutes total). Delete unused rows of data in the Data worksheet below your data, columns A
through R. You must also delete any un-used event detection formulas in columns N through R as well.
Step 3. Enter your BA name in cell B1 of this worksheet.
Step 4. Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz
by comparing time of event and delta Hz on graph to the right to that on Form 1 for this event. If the
wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the
beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Step 5. Verify that the "Auto" selection of T(0) is correct by observing "Graph 20 to 52s".
The very first frequency data point of the event on the graph
must not be included in the "A Value" average. This is accomplished when the
first frequency data point of the event is dead center of the graph on the center
vertical grid line. The Auto event detection will select the single largest event in the
data provided. An adjustment for T(0) alignment is provided in Cell Q3 on the Graph 20 to 52s.
Step 6. When T(0) is properly aligned. Hit the big blue button to copy your data for pasting into FRS Form 1
"BA Event Data" worksheet.
MyBA_110516_0806_FRS_Form2.9.xlsm
004650
58.500 Hz
61.500 Hz
Auto Event Detection
8:06:38
1245 Manually selected row number of the Event Starting Time.
8:10:30
1442 Manually selected row number of the Event Ending Time.
Event Frequency Data
8:06:38
60.1
8:06:38
-0.101
Delta Hz Event Detecte
60.05
60
8:10:30
59.95
59.9
59.85
Copy Form 2 data for
Pasting into Form 1
59.8
59.75
7:40:00
7:45:00
Step 7. Paste data into "FRS Form 1" in the appropriate row on the "BA Event Data" worksheet.
Be sure to use the latest version of Form 1. This is Form 2.9 so use Form 1.9.
Step 8. Save this workbook using the following file name in bold below:
11/05/16 Date yymmdd
8:06 Time hh:ss of T(0)
Where "MyBA" = your BA mnemonic
MyBA_110516_0806_FRS_Form2.9.xlsm
7:50:00
7:55:00
8:00:00
8:05:00
8:10:00
Hz
8:15:00
8:20:00
8:25:00
8:30:0
004651
2 seconds
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Average Contingent MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingent MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingent Delta MW Actual
Initial Performance Ramp Magnitude Adjustment
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Delta
EPFR = Expected Primary Frequency Response
EPFR(Final)
MW Response in right direction for frequency delta
Initial Response P.U. Performance
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
Frequency
Hz
59.98029
59.98224
59.98352
59.98578
59.9874
59.98804
59.9874
59.98611
59.9848
59.98352
59.98318
59.98352
59.98416
59.98514
59.98547
59.98642
59.98676
59.9874
59.98773
59.98901
59.98901
59.98804
59.98642
59.98547
59.98642
59.98935
59.99225
59.99515
59.99579
59.99515
59.99548
59.99741
60
60.00162
60.00162
60.00195
59.95963
59.88144
59.87237
59.87011
59.87011
59.87432
59.88076
59.88531
59.88787
59.88949
59.8908
59.89175
59.89242
59.89306
59.89306
59.89306
59.89532
59.89788
59.8995
59.90081
59.9021
59.90179
59.90081
59.90081
59.90048
59.8992
59.89886
59.89856
59.90017
59.90243
59.90469
59.90695
59.90887
59.90921
59.90857
59.90887
59.91018
59.91244
59.9147
59.9176
59.91922
59.92083
59.92215
59.92309
59.92505
59.92505
59.9273
59.93246
59.93505
59.93701
59.93765
59.93927
59.94183
59.94409
59.94571
59.94797
59.94766
59.9454
59.94443
59.94409
59.94507
59.94604
59.94638
59.94733
59.9483
59.94894
59.94992
59.9509
59.95154
59.95187
Contingent
Resource
Lost
MW
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.000
471.300
471.300
471.300
471.300
471.900
471.900
471.900
471.900
471.900
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
471.400
470.900
470.900
470.900
470.900
470.900
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Value B
20 to 52 sec
Average
Frequency
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
-471.09
-0.06
8.97
671.54
662.57
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Hz
Hz
Hz
MW
MW
MW
MW
MW
MW
MW
Droop Setting
Deadband Setting
Hz Span
TC (frequency response filter constant)
Low Hz
0.00
617.52
226.52
470.90
-494.59
0:03:52
No
641.21
23.69
Yes
No
Yes
146.62
-470.90
Down
662.51 MW
Yes
0.711 P.U.
Bias
(EPFR)
Expected
Primary
Frequency
Response
Average
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
Balancing Authority MyBA
Grid Nominal Frequency
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
A Point
FPointA
A Value
C Value
Delta FC
60.000 Hz
5.00% 3.00000 Hz
0.000 Hz
3.00000 Hz
8:06:36
60.0019531
59.9986267
59.8701134
Non-Conforming Load sign convention
+
(Data is positive for Load then enter "+" else "-"
8:06:36
Monday, May 16, 2011
8:06:38
8:10:30
59.999
59.897
-0.101
471.09
0.00
471.09
Hz
Hz
Hz
MW
MW
MW
EPFR Pre-Perturbation Average
EPFR Post-Perturbation Average
EPFR Unadjusted
EPFR Adjusted
Pre Load Resources MW
Pre Non-Conforming Load MW
Spare
8.97
671.54
662.57
662.57
0.00
0.00
0.00
MW
MW
MW
MW
MW
MW
MW
0.350 Time Constant for delayed delivery of PFR during Sustained Measure
Delta Hz Event
Actual Interchange MW Average during frequency recovery period
Target Interchange MW Average during frequency recovery period
Interchange Average Ramp MW during frequency recovery period
Actual MW @ T(-4)
Starting and Ending Difference in Interchange MW during frequency recovery period (indicates ramp direction during recovery period)
Event Duration (h:mm:ss)
Target MW Average minus MW @ T(-4) less than zero
Interchange Target Relative Average Change - MW (Low Frequency Event)
Interchange Actual Relative Average Change - MW (Low Frequency Event)
Interchange Actual Average minus MW @ T(-4) less than zero
Interchange Average MW minus MW @ T(-4) greater than zero
Interchange Target MW Average minus MW @ T(-4) greater than zero
Interchange Target Relative Average Change - MW (High Frequency Event)
Interchange Actual Relative Average Change - MW (High Frequency Event)
Ramp Direction during frequency recovery period
45.057
69.880
83.086
86.509
85.036
82.615
82.506
85.364
90.221
96.308
101.031
103.334
103.366
101.155
98.951
95.356
92.252
88.770
85.739
80.840
77.655
77.817
81.619
86.252
87.102
80.958
70.339
56.810
46.552
41.349
37.199
30.108
19.570
9.024
2.169
-3.054
90.291
329.669
505.979
625.742
703.588
744.563
756.480
753.833
746.254
737.631
729.027
721.272
714.697
708.959
705.229
702.804
696.067
685.829
675.477
665.750
656.497
651.181
649.957
649.162
649.412
652.504
655.281
657.783
655.713
649.207
639.816
628.550
616.834
608.451
604.466
601.179
596.043
587.544
576.858
563.286
550.767
538.933
528.242
519.131
508.745
501.994
492.444
474.450
456.825
440.904
429.083
417.702
404.446
390.668
378.016
364.630
356.628
356.587
358.792
360.993
360.192
357.439
354.883
351.059
346.341
341.810
336.633
331.036
325.933
321.849
Initial
Measure
Final
Expected
Primary
Frequency
Response
Frequency, Actual Interchange, Adjustment Data, Bias and Load used in the evaluation
Average
Ramp
MW/scan
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
2.947
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
0.000
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
Recovery
Period
Target
MW
471.000
476.805
484.609
493.643
501.313
506.563
509.542
510.278
511.020
510.372
510.215
509.680
509.596
507.643
507.406
510.515
517.263
524.844
528.640
525.443
517.771
507.189
499.878
497.621
496.419
492.275
484.684
477.084
473.176
470.900
564.245
799.359
971.406
1086.905
1160.488
1197.199
1204.852
1197.942
1186.099
1173.212
1160.344
1148.326
1137.487
1127.485
1119.491
1112.803
1101.802
1087.300
1072.685
1058.694
1045.178
1035.598
1030.110
1025.051
1021.037
1019.866
1018.379
1016.618
1010.284
999.514
985.859
970.330
954.350
941.703
933.456
925.905
916.505
903.742
888.792
870.956
854.174
838.077
823.122
809.747
795.097
784.082
770.269
748.011
726.122
705.938
689.853
674.209
656.689
638.647
621.731
604.082
591.816
587.511
585.453
583.390
578.325
571.309
564.489
556.401
547.420
538.625
529.184
519.323
509.957
501.609
Average
Output
During
Recovery
Period
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Average
Target
During
Recovery
Period
MW
681.802
778.337
855.479
916.481
963.267
997.779
1022.800
1040.944
1054.171
1063.823
1070.865
1075.990
1079.668
1082.323
1084.228
1085.261
1085.375
1084.707
1083.406
1081.586
1079.495
1077.348
1075.169
1073.004
1070.960
1069.013
1067.141
1065.181
1062.992
1060.504
1057.686
1054.555
1051.235
1047.870
1044.482
1041.023
1037.411
1033.600
1029.534
1025.257
1020.800
1016.203
1011.511
1006.702
1001.862
996.935
991.749
986.328
980.720
975.017
969.232
963.335
957.322
951.220
945.022
938.825
932.768
926.881
921.156
915.536
909.984
904.500
899.061
893.651
888.272
882.912
877.566
872.238
866.943
Recovery
Period
Ramp
MW
471.678
467.414
463.151
458.887
454.623
450.360
446.096
441.832
437.568
433.305
429.041
424.777
420.514
416.250
411.986
407.723
403.459
399.195
394.932
390.668
386.404
382.141
377.877
373.613
369.350
365.086
360.822
356.559
352.295
348.031
343.768
339.504
335.240
330.977
326.713
322.449
318.186
313.922
309.658
305.395
301.131
296.867
292.603
288.340
284.076
279.812
275.549
271.285
267.021
262.758
258.494
254.230
249.967
245.703
241.439
237.176
232.912
228.648
224.385
220.121
215.857
211.594
207.330
203.066
198.803
194.539
190.275
186.012
181.748
Average
Ramp
During
Recovery
Period
MW
471.678
469.546
467.414
465.282
463.151
461.019
458.887
456.755
454.623
452.491
450.360
448.228
446.096
443.964
441.832
439.700
437.568
435.437
433.305
431.173
429.041
426.909
424.777
422.646
420.514
418.382
416.250
414.118
411.986
409.855
407.723
405.591
403.459
401.327
399.195
397.064
394.932
392.800
390.668
388.536
386.404
384.273
382.141
380.009
377.877
375.745
373.613
371.481
369.350
367.218
365.086
362.954
360.822
358.690
356.559
354.427
352.295
350.163
348.031
345.899
343.768
341.636
339.504
337.372
335.240
333.108
330.977
328.845
326.713
T
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
Spare
Spare
Sum of Pre Perturbation Adjustments
0.00 MW
0.00 MW
0.00 MW
Post Load Resources MW
Post Non-Conforming Load MW
Spare
0.00 MW
0.00 MW
0.00 MW
Spare
Spare
Sum of Post Perturbation Adjustments
Net Total Adjustments MW
Frequency
Hz
Contingent
Resource
Lost
MW
59.980
59.982
59.984
59.986
59.987
59.988
59.987
59.986
59.985
59.984
59.983
59.984
59.984
59.985
59.985
59.986
59.987
59.987
59.988
59.989
59.989
59.988
59.986
59.985
59.986
59.989
59.992
59.995
59.996
59.995
59.995
59.997
60.000
60.002
60.002
60.002
59.960
59.881
59.872
59.870
59.870
59.874
59.881
59.885
59.888
59.889
59.891
59.892
59.892
59.893
59.893
59.893
59.895
59.898
59.900
59.901
59.902
59.902
59.901
59.901
59.900
59.899
59.899
59.899
59.900
59.902
59.905
59.907
59.909
59.909
59.909
59.909
59.910
59.912
59.915
59.918
59.919
59.921
59.922
59.923
59.925
59.925
59.927
59.932
59.935
59.937
59.938
59.939
59.942
59.944
59.946
59.948
59.948
59.945
59.944
59.944
59.945
59.946
59.946
59.947
59.948
59.949
59.950
59.951
59.952
59.952
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.00
471.30
471.30
471.30
471.30
471.90
471.90
471.90
471.90
471.90
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
471.40
470.90
470.90
470.90
470.90
470.90
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Load
Resources
Tripped
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Load (-)
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Not
Used
Not
Used
MW/0.1 Hz
MW
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
MW
MW
MW
MW
Frequency @ T(+46)
Frequency @ T(+76)
Frequency @ T(+106)
Frequency @ T(+136)
Frequency @ T(+166)
EPFR @ T(+46)
EPFR @ T(+76)
EPFR @ T(+106)
EPFR @ T(+136)
EPFR @ T(+166)
59.901
59.915
59.944
59.952
59.967
-653.00
-653.00
-653.00
-653.00
-653.00
Hz
Hz
Hz
Hz
Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
MW/0.1 Hz
T(20) to T(52) Evaluation
Pre-Perturbation Bias Setting
-653.00
Post-Perturbation Bias Setting
-653.00
EPFR for Bias Setting Pre-Perturbation Average
8.97
EPFR for Bias Setting Post-Perturbation Average
671.54
EPFR for Bias Setting Delta
662.57
Primary Frequency Response Delivery % of Bias
71.10%
MW/0.1 Hz
MW/0.1 Hz
MW
MW
MW
Pre-Perturbation BA Load
Post-Perturbation BA Load
Pre to Post Perturbation BA Load Change
Load Dampening Frequency Response
Load Dampening % of Total BA Frequency Response
30202.7 MW
30136.8 MW
-65.973 MW
-65.020 MW/0.1 Hz
14.00%
Average Bias Setting when Hz is greater than +/-0.036 Hz
-653.00 MW/0.1 Hz
Actual
Primary
Freq Response
MW/0.1 Hz
-481.62
-561.31
-863.83
-1000.43
-1507.48
Un-adjusted
P.U.
Performance
0.738
0.860
1.323
1.532
2.309
Expected
MW/0.1 Hz
Response
MW/0.1 Hz
Actual
Average
Primary
Freq Response
MW/0.1 Hz
Load
Resources
Tripped
Adjustment
0.00
0.00
0.00
0.00
0.00
NonConforming
Load
Adjustment
0.00
0.00
0.00
0.00
0.00
Spare
Adjustment
0.00
0.00
0.00
0.00
0.00
0.0197
0.0178
0.0165
0.0142
0.0126
0.0120
0.0126
0.0139
0.0152
0.0165
0.0168
0.0165
0.0158
0.0149
0.0145
0.0136
0.0132
0.0126
0.0123
0.0110
0.0110
0.0120
0.0136
0.0145
0.0136
0.0107
0.0078
0.0049
0.0042
0.0049
0.0045
0.0026
0.0000
0.0016
0.0016
0.0020
0.0404
0.1186
0.1276
0.1299
0.1299
0.1257
0.1192
0.1147
0.1121
0.1105
0.1092
0.1082
0.1076
0.1069
0.1069
0.1069
0.1047
0.1021
0.1005
0.0992
0.0979
0.0982
0.0992
0.0992
0.0995
0.1008
0.1011
0.1014
0.0998
0.0976
0.0953
0.0931
0.0911
0.0908
0.0914
0.0911
0.0898
0.0876
0.0853
0.0824
0.0808
0.0792
0.0779
0.0769
0.0750
0.0750
0.0727
0.0675
0.0649
0.0630
0.0623
0.0607
0.0582
0.0559
0.0543
0.0520
0.0523
0.0546
0.0556
0.0559
0.0549
0.0540
0.0536
0.0527
0.0517
0.0511
0.0501
0.0491
0.0485
0.0481
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
20 to 52 second Average Period Evaluation
0.738 P.U. Sustianed Response P.U. Performance
(TC)
Delayed
Delivery
Frequency
Response
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Date:
Time of T(0)
Time of Frequency Recovery to 60 Hz or Pre-Perturbation Hz
Value A Pre-Perturbation Average Frequency [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Frequency [T(+20 to T(+52)]
Pre to Post Perturbation Delta Frequency Actual
Value A Pre-Perturbation Contingency MW [T(-2 ) to T(-16)]
Value B Post-Perturbation Average Contingency MW [T(+20 to T(+52)]
Pre to Post Perturbation Contingency Delta MW Actual
BA
Bias
Setting
MW/0.1 Hz
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30155.67
30155.67
30155.67
30155.67
30142.79
30142.79
30142.79
30142.79
30142.79
30154.67
30154.67
30154.67
30150.35
30150.35
30159.63
30159.63
30159.63
30159.63
30151.42
30151.42
30156.16
30156.16
30156.16
30156.16
30164.15
30164.15
30164.15
30164.15
30203.91
30203.91
30203.73
30203.73
30203.73
30203.73
30199.61
30199.61
30199.61
30199.61
30086.11
30086.11
30086.11
30086.14
30086.14
30086.14
30086.14
30094.43
30094.43
30094.43
30094.43
30139.49
30139.49
30133.38
30133.38
30133.38
30133.38
30137.26
30137.26
30137.26
30137.26
30171.38
30171.38
30168.76
30168.76
30168.76
30168.76
30208.99
30208.99
30208.99
30208.99
30205.66
30205.66
30205.66
30205.66
30205.66
30205.66
30211.75
30211.75
30211.75
30211.75
30217.55
30217.55
30217.57
30217.57
30217.57
30217.57
30217.59
30217.59
30217.59
30217.59
30210.49
30210.49
30210.26
30210.26
30210.26
30210.26
30234.59
30234.59
30234.59
30234.59
30223.60
30223.60
30223.73
30223.73
30223.73
30223.73
30224.39
Expected Primary
Freq Response
Based on Bias Setting
MW
T
128.735
115.981
107.611
92.864
82.303
78.118
82.303
90.672
99.241
107.611
109.803
107.611
103.426
97.049
94.857
88.680
86.487
82.303
80.110
71.741
71.741
78.118
88.680
94.857
88.680
69.549
50.617
31.685
27.501
31.685
29.493
16.939
0.000
-10.562
-10.562
-12.754
263.647
774.227
833.413
848.160
848.160
820.659
778.611
748.918
732.179
721.617
713.048
706.870
702.486
698.301
698.301
698.301
683.555
666.815
656.253
647.684
639.314
641.307
647.684
647.684
649.876
658.246
660.438
662.431
651.869
637.122
622.376
607.629
595.074
592.882
597.067
595.074
586.505
571.759
557.012
538.080
527.519
T-72 sec
T-70 sec
T-68 sec
T-66 sec
T-64 sec
T-62 sec
T-60 sec
T-58 sec
T-56 sec
T-54 sec
T-52 sec
T-50 sec
T-48 sec
T-46 sec
T-44 sec
T-42 sec
T-40 sec
T-38 sec
T-36 sec
T-34 sec
T-32 sec
T-30 sec
T-28 sec
T-26 sec
T-24 sec
T-22 sec
T-20 sec
T-18 sec
T-16 sec
T-14 sec
T-12 sec
T-10 sec
T-08 sec
T-06 sec
T-04 sec
T-02 sec
T+0 sec
T+02 sec
T+04 sec
T+06 sec
T+08 sec
T+10 sec
T+12 sec
T+14 sec
T+16 sec
T+18 sec
T+20 sec
T+22 sec
T+24 sec
T+26 sec
T+28 sec
T+30 sec
T+32 sec
T+34 sec
T+36 sec
T+38 sec
T+40 sec
T+42 sec
T+44 sec
T+46 sec
T+48 sec
T+50 sec
T+52 sec
T+54 sec
T+56 sec
T+58 sec
T+60 sec
T+62 sec
T+64 sec
T+66 sec
T+68 sec
T+70 sec
T+72 sec
T+74 sec
T+76 sec
T+78 sec
T+80 sec
516.957
508.388
502.210
489.456
489.456
474.709
441.031
424.092
411.338
407.129
396.567
379.827
365.081
354.519
339.772
341.765
356.512
362.888
365.081
358.704
352.327
350.135
343.957
337.580
333.395
327.018
320.641
316.456
314.264
T+82 sec
T+84 sec
T+86 sec
T+88 sec
T+90 sec
T+92 sec
T+94 sec
T+96 sec
T+98 sec
T+100 sec
T+102 sec
T+104 sec
T+106 sec
T+108 sec
T+110 sec
T+112 sec
T+114 sec
T+116 sec
T+118 sec
T+120 sec
T+122 sec
T+124 sec
T+126 sec
T+128 sec
T+130 sec
T+132 sec
T+134 sec
T+136 sec
T+138 sec
8:05:26
8:05:28
8:05:30
8:05:32
8:05:34
8:05:36
8:05:38
8:05:40
8:05:42
8:05:44
8:05:46
8:05:48
8:05:50
8:05:52
8:05:54
8:05:56
8:05:58
8:06:00
8:06:02
8:06:04
8:06:06
8:06:08
8:06:10
8:06:12
8:06:14
8:06:16
8:06:18
8:06:20
8:06:22
8:06:24
8:06:26
8:06:28
8:06:30
8:06:32
8:06:34
8:06:36
8:06:38
8:06:40
8:06:42
8:06:44
8:06:46
8:06:48
8:06:50
8:06:52
8:06:54
8:06:56
8:06:58
8:07:00
8:07:02
8:07:04
8:07:06
8:07:08
8:07:10
8:07:12
8:07:14
8:07:16
8:07:18
8:07:20
8:07:22
8:07:24
8:07:26
8:07:28
8:07:30
8:07:32
8:07:34
8:07:36
8:07:38
8:07:40
8:07:42
8:07:44
8:07:46
8:07:48
8:07:50
8:07:52
8:07:54
8:07:56
8:07:58
8:08:00
8:08:02
8:08:04
8:08:06
8:08:08
8:08:10
8:08:12
8:08:14
8:08:16
8:08:18
8:08:20
8:08:22
8:08:24
8:08:26
8:08:28
8:08:30
8:08:32
8:08:34
8:08:36
8:08:38
8:08:40
8:08:42
8:08:44
8:08:46
8:08:48
8:08:50
8:08:52
8:08:54
8:08:56
Frequency
Hz
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.999
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
59.897
Initial P.U. Performance for FRO
Initial P.U. Performance Adjusted for FRO
NonContingent
Load
Conforming
Resource
Resources
Load
Lost
Tripped
Load (-)
MW
MW
MW
471.09
471.09
471.09
471.09
471.09
471.09
471.09
471.09
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.711 P.U.
0.711 P.U.
Not
Used
Not
Used
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
Not
Used
Not
Used
MW/0.1 Hz
MW
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
BA
Bias
Setting
MW/0.1 Hz
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
BA
Load
MW
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30202.74
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
30136.77
EPFR
MW
Actual
Primary
Freq Response
Beta
MW/0.1 Hz
8.968
8.968
8.968
8.968
8.968
8.968
8.968
8.968
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
671.539
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
653.00
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
464.954
401.98
373.12
366.57
366.57
378.99
399.69
415.73
425.35
431.66
436.91
440.78
443.56
446.26
446.26
446.26
456.01
467.62
475.25
481.62
488.02
486.48
481.62
481.62
479.97
473.79
472.19
470.75
478.49
489.72
501.49
513.85
524.85
526.82
523.07
524.85
532.64
546.60
561.31
581.39
593.23
605.56
615.95
623.67
640.22
640.22
660.50
711.98
741.03
764.52
772.60
793.66
829.48
863.83
890.23
929.92
924.35
885.13
869.18
863.83
879.58
895.91
901.67
918.30
936.12
948.19
967.21
986.99
1000.43
1007.61
Spare
Adjustment
0.00
0.00
0.00
0.00
0.00
Adjusted
Spare
P.U.
Adjustment
Performance
0.00
0.738
0.00
0.860
0.00
1.323
0.00
1.532
0.00
2.309
004652
T+140
T+142
T+144
T+146
T+148
T+150
T+152
T+154
T+156
T+158
T+160
T+162
T+164
T+166
T+168
T+170
T+172
T+174
T+176
T+178
T+180
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
59.95346
59.95508
59.95575
59.95639
59.95801
59.96124
59.96252
59.96188
59.96124
59.96027
59.96057
59.96219
59.96512
59.96738
59.96899
59.97061
59.97318
59.97351
59.97287
59.97253
59.97318
59.97415
59.97543
59.97577
59.9761
59.97675
59.97803
59.97931
59.97998
59.97964
59.979
59.97964
59.98093
59.98224
59.98386
59.98514
59.98773
59.9903
59.99289
59.99579
59.99646
59.99579
59.99612
59.99579
59.99484
59.99484
59.99805
59.99872
60.00034
60.00195
60.00259
60.00226
60.00195
60.00064
59.99646
59.99191
59.98901
59.98773
59.98901
59.99255
59.99579
59.99902
60.00195
60.00485
60.00809
60.01163
60.01422
60.0152
60.0155
60.0155
60.01682
60.01907
60.02295
60.02618
60.02972
60.03262
60.03458
60.03522
60.03424
60.0336
60.03522
60.03812
60.04037
60.04105
60.04199
60.04233
60.0433
60.04425
60.04492
60.04556
60.04587
60.04654
60.0488
60.04974
60.0491
60.0491
60.05042
60.04974
60.04846
60.04718
60.04587
60.04587
60.04556
60.04425
60.04297
60.04169
60.04233
60.04459
60.04654
60.04718
60.0462
60.04425
60.04492
60.04523
60.04523
60.04556
60.0462
60.04654
60.04654
60.04523
60.04361
60.04199
60.04071
60.03876
60.03586
60.03394
60.0336
60.03262
60.03006
60.02747
60.02682
60.02585
60.02359
60.02197
60.02164
60.02231
60.02133
60.02133
60.02002
60.01776
60.01584
60.01291
60.01132
60.01001
60.00937
60.00775
60.00516
60.00452
60.00613
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
315.567
307.788
301.197
295.448
288.014
275.789
264.913
259.309
257.131
257.947
257.780
253.974
244.805
233.684
222.758
211.960
199.083
189.945
185.470
183.329
180.472
176.383
170.796
166.397
162.771
158.949
153.535
147.087
141.361
138.407
137.951
136.190
132.116
126.469
119.101
111.383
100.438
87.464
73.103
57.142
45.233
39.027
34.225
31.872
32.504
32.915
25.859
19.738
12.062
3.377
-3.734
-7.588
-9.396
-7.572
3.169
20.543
38.462
53.039
59.585
55.749
45.862
32.042
16.363
-0.454
-18.778
-38.780
-57.709
-72.246
-82.392
-88.986
-96.272
-106.169
-121.461
-138.793
-158.150
-177.358
-194.307
-206.789
-212.670
-215.028
-220.257
-230.282
-241.960
-251.085
-259.178
-265.206
-271.356
-277.516
-283.054
-288.119
-292.109
-296.236
-304.080
-311.341
-314.596
-316.712
-321.086
-322.395
-320.317
-316.036
-310.255
-306.497
-303.356
-298.316
-292.111
-285.148
-282.086
-285.258
-291.783
-297.489
-298.966
-295.463
-294.720
-294.934
-295.074
-295.932
-297.954
-300.036
-301.389
-299.269
-294.195
-287.200
-279.724
-270.400
-257.714
-245.074
-236.090
-228.019
-216.914
-203.767
-193.757
-185.019
-174.177
-163.434
-155.683
-152.180
-147.671
-144.740
-139.835
-131.486
-121.665
-108.586
-96.457
-85.575
-77.036
-67.789
-55.851
-46.626
-44.326
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
-4.264
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
491.064
479.021
468.166
458.153
446.456
429.967
414.828
404.960
398.518
395.070
390.640
382.571
369.138
353.753
338.564
323.502
306.360
292.959
284.221
277.815
270.695
262.343
252.492
243.830
235.939
227.854
218.176
207.464
197.475
190.257
185.537
179.513
171.175
161.264
149.633
137.651
122.442
105.205
86.580
66.355
50.183
39.713
30.648
24.030
20.399
16.546
5.226
-0.895
-8.570
-17.256
-24.366
-28.221
-30.029
-28.205
-17.464
-0.090
17.830
32.407
38.952
35.116
25.229
11.410
-4.269
-21.086
-39.411
-59.412
-78.342
-92.878
-103.024
-109.619
-116.905
-126.802
-142.093
-159.426
-178.782
-197.990
-214.940
-227.421
-233.302
-235.660
-240.890
-250.915
-262.592
-271.717
-279.811
-285.839
-291.989
-298.149
-303.687
-308.751
-312.741
-316.869
-324.713
-331.974
-335.229
-337.344
-341.719
-343.028
-340.949
-336.669
-330.887
-327.129
-323.989
-318.949
-312.743
-305.780
-302.719
-305.890
-312.416
-318.122
-319.599
-316.095
-315.352
-315.567
-315.706
-316.564
-318.586
-320.668
-322.021
-319.902
-314.827
-307.832
-300.356
-291.033
-278.346
-265.706
-256.723
-248.652
-237.547
-224.400
-214.390
-205.651
-194.810
-184.066
-176.316
-172.812
-168.303
-165.372
-160.468
-152.119
-142.298
-129.218
-117.090
-106.207
-97.669
-88.422
-76.483
-67.258
-64.958
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
861.649
856.335
851.017
845.708
840.385
834.985
829.528
824.085
818.698
813.403
808.184
802.993
797.766
792.480
787.140
781.749
776.284
770.792
765.325
759.908
754.532
749.182
743.842
738.522
733.232
727.968
722.712
717.454
712.202
706.983
701.820
696.699
691.597
686.498
681.385
676.255
671.079
665.840
660.525
655.124
649.674
644.228
638.798
633.405
628.075
622.803
617.525
612.284
607.066
601.864
596.688
591.566
586.512
581.555
576.763
572.185
567.820
563.637
559.570
555.535
551.487
547.396
543.248
539.036
534.752
530.383
525.939
521.455
516.963
512.487
508.023
503.553
499.038
494.465
489.822
485.111
480.349
475.566
470.809
466.099
461.417
456.731
452.029
447.330
442.638
437.969
433.319
428.690
424.083
419.503
414.955
410.438
405.928
401.428
396.964
392.540
388.143
383.791
379.503
375.290
371.160
367.100
363.106
359.186
355.346
351.590
347.893
344.220
340.552
336.893
333.266
329.698
326.173
322.685
319.234
315.816
312.423
309.056
305.717
302.424
299.193
296.031
292.941
289.931
287.016
284.196
281.451
278.773
276.179
273.676
271.248
268.887
266.603
264.393
262.244
260.132
258.062
256.026
254.033
252.099
250.230
248.440
246.724
245.075
243.481
241.944
240.477
239.065
237.677
177.484
173.221
168.957
164.693
160.430
156.166
151.902
147.638
143.375
139.111
134.847
130.584
126.320
122.056
117.793
113.529
109.265
105.002
100.738
96.474
92.211
87.947
83.683
79.420
75.156
70.892
66.629
62.365
58.101
53.838
49.574
45.310
41.047
36.783
32.519
28.256
23.992
19.728
15.465
11.201
6.937
2.673
-1.590
-5.854
-10.118
-14.381
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
324.581
322.449
320.317
318.186
316.054
313.922
311.790
309.658
307.526
305.395
303.263
301.131
298.999
296.867
294.735
292.603
290.472
288.340
286.208
284.076
281.944
279.812
277.681
275.549
273.417
271.285
269.153
267.021
264.890
262.758
260.626
258.494
256.362
254.230
252.099
249.967
247.835
245.703
243.571
241.439
239.308
237.176
235.044
232.912
230.780
228.648
226.516
224.421
222.361
220.336
218.344
216.386
214.459
212.564
210.700
208.865
207.059
205.282
203.533
201.810
200.114
198.445
196.800
195.180
193.584
192.012
190.463
188.937
187.433
185.950
184.489
183.048
181.628
180.227
178.846
177.484
176.141
174.816
173.509
172.219
170.947
169.691
168.452
167.229
166.022
164.831
163.655
162.493
161.347
160.215
159.097
157.993
156.903
155.826
154.762
153.711
152.673
151.647
150.633
149.632
148.642
147.663
146.697
145.741
144.796
143.862
142.939
142.026
141.123
140.231
139.348
138.475
137.612
136.758
135.913
135.078
134.251
133.434
132.625
131.825
131.033
130.249
129.473
128.706
127.946
127.195
126.451
125.714
124.985
124.263
123.549
122.841
122.141
121.447
120.761
120.081
119.407
118.740
118.080
117.426
116.778
116.136
115.500
114.870
114.246
113.628
113.016
112.409
111.808
T+140
T+142
T+144
T+146
T+148
T+150
T+152
T+154
T+156
T+158
T+160
T+162
T+164
T+166
T+168
T+170
T+172
T+174
T+176
T+178
T+180
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
8:09:40
8:09:42
8:09:44
8:09:46
8:09:48
8:09:50
8:09:52
8:09:54
8:09:56
8:09:58
8:10:00
8:10:02
8:10:04
8:10:06
8:10:08
8:10:10
8:10:12
8:10:14
8:10:16
8:10:18
8:10:20
8:10:22
8:10:24
8:10:26
8:10:28
8:10:30
8:10:32
8:10:34
8:10:36
8:10:38
8:10:40
8:10:42
8:10:44
8:10:46
8:10:48
8:10:50
8:10:52
8:10:54
8:10:56
8:10:58
8:11:00
8:11:02
8:11:04
8:11:06
8:11:08
8:11:10
8:11:12
8:11:14
8:11:16
8:11:18
8:11:20
8:11:22
8:11:24
8:11:26
8:11:28
8:11:30
8:11:32
8:11:34
8:11:36
8:11:38
8:11:40
8:11:42
8:11:44
8:11:46
8:11:48
8:11:50
8:11:52
8:11:54
8:11:56
8:11:58
8:12:00
8:12:02
8:12:04
8:12:06
8:12:08
8:12:10
8:12:12
8:12:14
8:12:16
8:12:18
8:12:20
8:12:22
8:12:24
8:12:26
8:12:28
8:12:30
8:12:32
8:12:34
8:12:36
8:12:38
8:12:40
8:12:42
8:12:44
8:12:46
8:12:48
8:12:50
8:12:52
8:12:54
8:12:56
8:12:58
8:13:00
8:13:02
8:13:04
8:13:06
8:13:08
8:13:10
8:13:12
8:13:14
8:13:16
8:13:18
8:13:20
8:13:22
8:13:24
8:13:26
8:13:28
8:13:30
8:13:32
8:13:34
8:13:36
8:13:38
8:13:40
8:13:42
8:13:44
8:13:46
8:13:48
8:13:50
8:13:52
8:13:54
59.953
59.955
59.956
59.956
59.958
59.961
59.963
59.962
59.961
59.960
59.961
59.962
59.965
59.967
59.969
59.971
59.973
59.974
59.973
59.973
59.973
59.974
59.975
59.976
59.976
59.977
59.978
59.979
59.980
59.980
59.979
59.980
59.981
59.982
59.984
59.985
59.988
59.990
59.993
59.996
59.996
59.996
59.996
59.996
59.995
59.995
59.998
59.999
60.000
60.002
60.003
60.002
60.002
60.001
59.996
59.992
59.989
59.988
59.989
59.993
59.996
59.999
60.002
60.005
60.008
60.012
60.014
60.015
60.016
60.016
60.017
60.019
60.023
60.026
60.030
60.033
60.035
60.035
60.034
60.034
60.035
60.038
60.040
60.041
60.042
60.042
60.043
60.044
60.045
60.046
60.046
60.047
60.049
60.050
60.049
60.049
60.050
60.050
60.048
60.047
60.046
60.046
60.046
60.044
60.043
60.042
60.042
60.045
60.047
60.047
60.046
60.044
60.045
60.045
60.045
60.046
60.046
60.047
60.047
60.045
60.044
60.042
60.041
60.039
60.036
60.034
60.034
60.033
60.030
60.027
60.027
60.026
60.024
60.022
60.022
60.022
60.021
60.021
60.020
60.018
60.016
60.013
60.011
60.010
60.009
60.008
60.005
60.005
60.006
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30224.39
30224.39
30224.39
30255.53
30255.53
30252.87
30252.87
30252.87
30252.87
30232.45
30232.45
30232.45
30232.45
30263.99
30263.99
30263.68
30263.68
30263.68
30263.68
30264.96
30264.96
30264.96
30264.96
30263.63
30263.63
30279.39
30279.39
30279.39
30279.39
30255.32
30255.32
30255.32
30255.32
30260.67
30260.67
30259.99
30259.99
30259.99
30259.99
30274.08
30274.08
30274.08
30274.08
30297.68
30297.68
30297.65
30297.65
30297.65
30297.65
30300.10
30300.10
30300.10
30300.10
30314.84
30314.84
30309.71
30309.71
30309.71
30309.71
30319.50
30319.50
30319.50
30319.50
30357.21
30357.21
30357.18
30357.18
30357.18
30357.18
30354.26
30354.26
30354.26
30354.26
30354.48
30354.48
30353.83
30353.83
30353.83
30353.83
30370.41
30370.41
30370.41
30370.41
30374.79
30374.79
30366.14
30366.14
30366.14
30366.14
30373.53
30373.53
30373.53
30373.53
30343.46
30343.46
30335.12
30335.12
30335.12
30335.12
30337.29
30337.29
30337.29
30337.29
30350.20
30350.20
30350.07
30350.07
30350.07
30350.07
30354.77
30354.77
30354.77
30354.77
30372.38
30372.38
30372.38
30372.38
30372.38
30372.38
30349.10
30349.10
30349.10
30349.10
30363.65
30363.65
30363.88
30363.88
30363.88
30363.88
30364.77
30364.77
30364.77
30364.77
30374.33
30374.33
30364.67
30364.67
30364.67
30364.67
30361.56
30361.56
30361.56
30361.56
30350.69
30350.69
30344.52
30344.52
30344.52
30344.52
303.902
293.340
288.956
284.771
274.209
253.085
244.716
248.900
253.085
259.462
257.469
246.908
227.777
213.030
202.468
191.906
175.167
172.975
177.160
179.352
175.167
168.790
160.420
158.228
156.036
151.851
143.481
135.112
130.728
132.920
137.104
132.920
124.550
115.981
105.419
97.049
80.110
63.371
46.432
27.501
23.116
27.501
25.309
27.501
33.678
33.678
12.754
8.370
-2.192
-12.754
-16.939
-14.747
-12.754
-4.185
23.116
52.809
71.741
80.110
71.741
48.624
27.501
6.377
-12.754
-31.685
-52.809
-75.926
-92.864
-99.241
-101.234
-101.234
-109.803
-124.550
-149.858
-170.982
-194.099
-213.030
-225.784
-229.969
-223.592
-219.407
-229.969
-248.900
-263.647
-268.031
-274.209
-276.401
-282.778
-288.956
-293.340
-297.525
-299.518
-303.902
-318.648
-324.826
-320.641
-320.641
-329.210
-324.826
-316.456
-308.087
-299.518
-299.518
-297.525
-288.956
-280.586
-272.216
-276.401
-291.148
-303.902
-308.087
-301.710
-288.956
-293.340
-295.333
-295.333
-297.525
-301.710
-303.902
-303.902
-295.333
-284.771
-274.209
-265.839
-253.085
-234.154
-221.599
-219.407
-213.030
-196.291
-179.352
-175.167
-168.790
-154.043
-143.481
-141.289
-145.674
-139.297
-139.297
-130.728
-115.981
-103.426
-84.295
-73.933
-65.364
-61.179
-50.617
-33.678
-29.493
-40.055
T+140
T+142
T+144
T+146
T+148
T+150
T+152
T+154
T+156
T+158
T+160
T+162
T+164
T+166
T+168
T+170
T+172
T+174
T+176
T+178
T+180
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
sec
8:08:58
8:09:00
8:09:02
8:09:04
8:09:06
8:09:08
8:09:10
8:09:12
8:09:14
8:09:16
8:09:18
8:09:20
8:09:22
8:09:24
8:09:26
8:09:28
8:09:30
8:09:32
8:09:34
8:09:36
8:09:38
1043.01
1081.75
1098.69
1115.36
1159.77
1260.13
1304.87
1282.11
1260.13
1228.05
1237.90
1292.85
1405.88
1507.48
1589.76
1681.55
1850.91
1875.65
1828.98
1805.45
1850.91
1924.76
2031.13
2060.96
2091.68
2152.94
2286.90
2438.64
2526.45
2481.77
2400.71
2481.77
2661.48
2874.60
3189.38
3492.44
4323.98
5654.43
8210.95
16598.49
21741.68
16598.49
18825.12
16598.49
12448.87
12448.87
81245.24
21741.68
7016.63
4900.51
4323.98
4900.51
7757.08
16598.49
0.0465
0.0449
0.0443
0.0436
0.0420
0.0388
0.0375
0.0381
0.0388
0.0397
0.0394
0.0378
0.0349
0.0326
0.0310
0.0294
0.0268
0.0265
0.0271
0.0275
0.0268
0.0258
0.0246
0.0242
0.0239
0.0233
0.0220
0.0207
0.0200
0.0204
0.0210
0.0204
0.0191
0.0178
0.0161
0.0149
0.0123
0.0097
0.0071
0.0042
0.0035
0.0042
0.0039
0.0042
0.0052
0.0052
0.0020
0.0013
0.0003
0.0020
0.0026
0.0023
0.0020
0.0006
0.0035
0.0081
0.0110
0.0123
0.0110
0.0074
0.0042
0.0010
0.0020
0.0049
0.0081
0.0116
0.0142
0.0152
0.0155
0.0155
0.0168
0.0191
0.0229
0.0262
0.0297
0.0326
0.0346
0.0352
0.0342
0.0336
0.0352
0.0381
0.0404
0.0410
0.0420
0.0423
0.0433
0.0443
0.0449
0.0456
0.0459
0.0465
0.0488
0.0497
0.0491
0.0491
0.0504
0.0497
0.0485
0.0472
0.0459
0.0459
0.0456
0.0443
0.0430
0.0417
0.0423
0.0446
0.0465
0.0472
0.0462
0.0443
0.0449
0.0452
0.0452
0.0456
0.0462
0.0465
0.0465
0.0452
0.0436
0.0420
0.0407
0.0388
0.0359
0.0339
0.0336
0.0326
0.0301
0.0275
0.0268
0.0258
0.0236
0.0220
0.0216
0.0223
0.0213
0.0213
0.0200
0.0178
0.0158
0.0129
0.0113
0.0100
0.0094
0.0078
0.0052
0.0045
0.0061
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
-653
004653
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
60.00613
60.00549
60.00516
60.00388
60.00259
60.00128
60.00128
60.00064
60.00034
60.00226
60.00421
60.00677
60.00903
60.01291
60.01486
60.01453
60.01422
60.0152
60.01614
60.01682
60.01746
60.01712
60.01682
60.01648
60.01614
60.01746
60.01776
60.01776
60.01648
60.01584
60.01648
60.01584
60.01358
60.01163
60.01132
60.01132
60.01099
60.01099
60.01291
60.01486
60.01776
60.01776
60.0184
60.0181
60.01746
60.0152
60.0152
60.01389
60.01746
60.01907
60.01907
60.02036
60.01874
60.01874
60.01971
60.01971
60.01971
60.0184
60.01486
60.01358
60.01389
60.01227
60.01001
60.00583
60.00162
60.00162
59.99805
59.99353
59.99255
59.99225
59.98999
59.98837
59.98416
59.9816
59.98093
59.98029
59.97998
59.97836
59.97513
59.97287
59.97189
59.97156
59.97382
59.97641
59.97836
59.97705
59.97449
59.97125
59.97092
59.97287
59.97449
59.97382
59.97318
59.97449
59.9761
59.97739
59.97836
59.97769
59.97705
59.97641
59.97543
59.97382
59.97318
59.97223
59.97189
59.97092
59.96994
59.96832
59.96606
59.96542
59.96606
59.9693
59.97253
59.97351
59.97382
59.97253
59.97253
59.97253
59.96768
59.97125
59.97577
59.97577
59.97577
59.98416
59.9819
59.979
59.97769
59.97769
59.98126
59.9848
59.98868
59.99161
59.99353
59.99579
59.99677
59.99774
59.99838
59.99774
59.9971
59.99741
59.99741
59.99741
60.00064
60.00323
60.00354
60.00259
60.00098
59.99936
59.99741
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
-42.831
-40.395
-38.044
-33.587
-27.760
-20.973
-16.562
-12.230
-8.717
-10.827
-16.663
-26.315
-37.750
-54.041
-69.094
-78.111
-83.275
-88.863
-94.658
-99.959
-104.869
-107.293
-108.172
-107.976
-107.081
-109.498
-111.767
-113.242
-111.271
-108.525
-108.205
-106.533
-100.284
-91.759
-85.520
-81.464
-78.061
-75.849
-78.805
-85.191
-95.967
-102.972
-108.990
-112.204
-112.828
-108.073
-104.982
-99.974
-104.879
-111.764
-116.239
-122.077
-122.175
-122.239
-124.513
-125.990
-126.951
-124.576
-114.942
-105.750
-100.473
-93.346
-83.552
-67.631
-47.657
-34.673
-18.074
3.039
18.994
30.062
42.417
54.145
71.394
88.464
101.094
110.768
117.754
125.991
138.739
152.186
163.159
171.058
171.032
165.086
156.757
154.342
158.632
168.813
176.198
176.535
173.057
172.331
173.323
170.969
165.743
159.416
153.072
150.482
150.264
151.587
154.678
160.385
165.558
171.084
175.442
180.507
186.031
193.319
203.217
211.115
214.785
209.776
199.128
189.974
183.327
181.936
181.031
180.443
191.151
189.951
178.848
171.631
166.940
144.710
135.422
136.011
139.393
141.591
134.859
122.393
105.432
87.711
71.799
56.295
43.985
33.751
25.635
21.824
20.812
19.456
18.575
18.002
10.237
-0.739
-8.571
-11.500
-9.707
-4.845
2.779
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-63.464
-61.027
-58.677
-54.219
-48.392
-41.606
-37.195
-32.863
-29.349
-31.460
-37.295
-46.947
-58.383
-74.673
-89.726
-98.743
-103.907
-109.495
-115.290
-120.591
-125.501
-127.926
-128.804
-128.608
-127.713
-130.131
-132.400
-133.874
-131.904
-129.158
-128.838
-127.165
-120.917
-112.391
-106.152
-102.097
-98.693
-96.481
-99.438
-105.823
-116.600
-123.604
-129.622
-132.836
-133.461
-128.705
-125.614
-120.606
-125.511
-132.396
-136.871
-142.710
-142.808
-142.872
-145.145
-146.623
-147.583
-145.209
-135.574
-126.382
-121.105
-113.978
-104.185
-88.263
-68.289
-55.306
-38.706
-17.594
-1.639
9.429
21.785
33.513
50.761
67.831
80.462
90.136
97.122
105.359
118.107
131.554
142.526
150.426
150.399
144.453
136.125
133.710
137.999
148.181
155.566
155.902
152.424
151.698
152.691
150.337
145.110
138.784
132.439
129.850
129.632
130.954
134.046
139.752
144.926
150.451
154.810
159.875
165.399
172.686
182.584
190.483
194.152
189.144
178.495
169.342
162.695
161.303
160.399
159.811
170.519
169.318
158.215
150.999
146.308
124.078
114.790
115.379
118.760
120.959
114.227
101.761
84.800
67.079
51.167
35.662
23.352
13.119
5.003
1.192
0.179
-1.176
-2.057
-2.630
-10.396
-21.372
-29.204
-32.132
-30.339
-25.477
-17.853
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
236.308
234.963
233.640
232.349
231.096
229.884
228.702
227.550
226.423
225.297
224.155
222.982
221.769
220.497
219.171
217.818
216.455
215.080
213.691
212.293
210.885
209.479
208.082
206.696
205.325
203.956
202.589
201.227
199.883
198.562
197.252
195.960
194.703
193.489
192.309
191.154
190.022
188.907
187.790
186.656
185.490
184.306
183.107
181.906
180.711
179.544
178.397
177.277
176.147
175.000
173.845
172.677
171.517
170.365
169.214
168.065
166.922
165.795
164.711
163.667
162.650
161.666
160.723
159.843
159.040
158.288
157.599
156.989
156.438
155.929
155.467
155.048
154.691
154.394
154.143
153.926
153.734
153.571
153.452
153.379
153.342
153.333
153.323
153.294
153.237
153.173
153.124
153.108
153.116
153.125
153.122
153.118
153.116
153.108
153.082
153.037
152.971
152.899
152.825
152.757
152.698
152.658
152.634
152.627
152.634
152.656
152.695
152.756
152.847
152.962
153.087
153.196
153.272
153.320
153.348
153.372
153.393
153.412
153.462
153.509
153.523
153.516
153.495
153.409
153.297
153.187
153.087
152.995
152.883
152.737
152.543
152.299
152.012
151.682
151.320
150.930
150.520
150.102
149.683
149.263
148.843
148.423
147.984
147.518
147.032
146.542
146.058
145.591
145.147
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
111.212
110.622
110.037
109.457
108.883
108.314
107.749
107.190
106.636
106.086
105.542
105.002
104.466
103.936
103.410
102.888
102.371
101.858
101.350
100.846
100.346
99.850
99.358
98.870
98.387
97.907
97.432
96.960
96.492
96.027
95.567
95.110
94.657
94.207
93.761
93.319
92.879
92.444
92.012
91.583
91.157
90.735
90.316
89.900
89.487
89.078
88.671
88.268
87.867
87.470
87.075
86.684
86.295
85.909
85.526
85.146
84.769
84.394
84.022
83.653
83.286
82.922
82.561
82.202
81.845
81.491
81.140
80.791
80.445
80.101
79.759
79.420
79.083
78.748
78.416
78.085
77.758
77.432
77.108
76.787
76.468
76.151
75.836
75.523
75.212
74.904
74.597
74.292
73.989
73.689
73.390
73.093
72.798
72.505
72.214
71.924
71.637
71.351
71.067
70.785
70.505
70.226
69.949
69.674
69.401
69.129
68.859
68.590
68.324
68.059
67.795
67.533
67.273
67.014
66.757
66.501
66.247
65.994
65.743
65.493
65.245
64.998
64.753
64.509
64.267
64.026
63.786
63.548
63.311
63.076
62.841
62.609
62.377
62.147
61.918
61.690
61.464
61.239
61.015
60.793
60.572
60.352
60.133
59.915
59.699
59.483
59.269
59.057
58.845
8:13:56
8:13:58
8:14:00
8:14:02
8:14:04
8:14:06
8:14:08
8:14:10
8:14:12
8:14:14
8:14:16
8:14:18
8:14:20
8:14:22
8:14:24
8:14:26
8:14:28
8:14:30
8:14:32
8:14:34
8:14:36
8:14:38
8:14:40
8:14:42
8:14:44
8:14:46
8:14:48
8:14:50
8:14:52
8:14:54
8:14:56
8:14:58
8:15:00
8:15:02
8:15:04
8:15:06
8:15:08
8:15:10
8:15:12
8:15:14
8:15:16
8:15:18
8:15:20
8:15:22
8:15:24
8:15:26
8:15:28
8:15:30
8:15:32
8:15:34
8:15:36
8:15:38
8:15:40
8:15:42
8:15:44
8:15:46
8:15:48
8:15:50
8:15:52
8:15:54
8:15:56
8:15:58
8:16:00
8:16:02
8:16:04
8:16:06
8:16:08
8:16:10
8:16:12
8:16:14
8:16:16
8:16:18
8:16:20
8:16:22
8:16:24
8:16:26
8:16:28
8:16:30
8:16:32
8:16:34
8:16:36
8:16:38
8:16:40
8:16:42
8:16:44
8:16:46
8:16:48
8:16:50
8:16:52
8:16:54
8:16:56
8:16:58
8:17:00
8:17:02
8:17:04
8:17:06
8:17:08
8:17:10
8:17:12
8:17:14
8:17:16
8:17:18
8:17:20
8:17:22
8:17:24
8:17:26
8:17:28
8:17:30
8:17:32
8:17:34
8:17:36
8:17:38
8:17:40
8:17:42
8:17:44
8:17:46
8:17:48
8:17:50
8:17:52
8:17:54
8:17:56
8:17:58
8:18:00
8:18:02
8:18:04
8:18:06
8:18:08
8:18:10
8:18:12
8:18:14
8:18:16
8:18:18
8:18:20
8:18:22
8:18:24
8:18:26
8:18:28
8:18:30
8:18:32
8:18:34
8:18:36
8:18:38
8:18:40
8:18:42
8:18:44
8:18:46
8:18:48
8:18:50
8:18:52
60.006
60.005
60.005
60.004
60.003
60.001
60.001
60.001
60.000
60.002
60.004
60.007
60.009
60.013
60.015
60.015
60.014
60.015
60.016
60.017
60.017
60.017
60.017
60.016
60.016
60.017
60.018
60.018
60.016
60.016
60.016
60.016
60.014
60.012
60.011
60.011
60.011
60.011
60.013
60.015
60.018
60.018
60.018
60.018
60.017
60.015
60.015
60.014
60.017
60.019
60.019
60.020
60.019
60.019
60.020
60.020
60.020
60.018
60.015
60.014
60.014
60.012
60.010
60.006
60.002
60.002
59.998
59.994
59.993
59.992
59.990
59.988
59.984
59.982
59.981
59.980
59.980
59.978
59.975
59.973
59.972
59.972
59.974
59.976
59.978
59.977
59.974
59.971
59.971
59.973
59.974
59.974
59.973
59.974
59.976
59.977
59.978
59.978
59.977
59.976
59.975
59.974
59.973
59.972
59.972
59.971
59.970
59.968
59.966
59.965
59.966
59.969
59.973
59.974
59.974
59.973
59.973
59.973
59.968
59.971
59.976
59.976
59.976
59.984
59.982
59.979
59.978
59.978
59.981
59.985
59.989
59.992
59.994
59.996
59.997
59.998
59.998
59.998
59.997
59.997
59.997
59.997
60.001
60.003
60.004
60.003
60.001
59.999
59.997
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30354.37
30354.37
30354.37
30354.37
30373.31
30373.31
30373.78
30373.78
30373.78
30373.78
30366.33
30366.33
30366.33
30366.33
30373.85
30373.85
30373.05
30373.05
30373.05
30373.05
30369.77
30369.77
30369.77
30369.77
30388.99
30388.99
30388.16
30388.16
30388.16
30388.16
30376.94
30376.94
30376.94
30376.94
30371.85
30371.85
30362.65
30362.65
30362.65
30362.65
30395.46
30395.46
30395.46
30395.46
30397.03
30397.03
30396.67
30396.67
30396.67
30396.67
30388.62
30388.62
30388.62
30388.62
30381.78
30381.78
30382.96
30382.96
30382.96
30382.96
30381.48
30381.48
30381.48
30381.48
30394.03
30394.03
30394.07
30394.07
30394.07
30394.07
30376.91
30376.91
30376.91
30376.91
30367.96
30367.96
30367.46
30367.46
30367.46
30367.46
30361.18
30361.18
30361.18
30361.18
30365.59
30365.59
30365.19
30365.19
30365.19
30365.19
30375.91
30375.91
30375.91
30375.91
30367.40
30367.40
30367.72
30367.72
30367.72
30367.72
30416.87
30416.87
30416.87
30416.87
30413.65
30413.65
30406.30
30406.30
30406.30
30406.30
30418.59
30418.59
30418.59
30418.59
30433.31
30433.31
30433.31
30433.31
30433.31
30433.31
30451.30
30451.30
30451.30
30451.30
30425.74
30425.74
30419.18
30419.18
30419.18
30419.18
30424.29
30424.29
30424.29
30424.29
30440.82
30440.82
30431.58
30431.58
30431.58
30431.58
30444.25
30444.25
30444.25
30444.25
30465.11
30465.11
30465.30
30465.30
30465.30
-40.055
-35.870
-33.678
-25.309
-16.939
-8.370
-8.370
-4.185
-2.192
-14.747
-27.501
-44.240
-58.987
-84.295
-97.049
-94.857
-92.864
-99.241
-105.419
-109.803
-113.988
-111.796
-109.803
-107.611
-105.419
-113.988
-115.981
-115.981
-107.611
-103.426
-107.611
-103.426
-88.680
-75.926
-73.933
-73.933
-71.741
-71.741
-84.295
-97.049
-115.981
-115.981
-120.166
-118.173
-113.988
-99.241
-99.241
-90.672
-113.988
-124.550
-124.550
-132.920
-122.358
-122.358
-128.735
-128.735
-128.735
-120.166
-97.049
-88.680
-90.672
-80.110
-65.364
-38.062
-10.562
-10.562
12.754
42.247
48.624
50.617
65.364
75.926
103.426
120.166
124.550
128.735
130.728
141.289
162.413
177.160
183.537
185.729
170.982
154.043
141.289
149.858
166.598
187.722
189.914
177.160
166.598
170.982
175.167
166.598
156.036
147.666
141.289
145.674
149.858
154.043
160.420
170.982
175.167
181.345
183.537
189.914
196.291
206.852
221.599
225.784
221.599
200.475
179.352
172.975
170.982
179.352
179.352
179.352
211.037
187.722
158.228
158.228
158.228
103.426
118.173
137.104
145.674
145.674
122.358
99.241
73.933
54.802
42.247
27.501
21.124
14.747
10.562
14.747
18.932
16.939
16.939
16.939
-4.185
-21.124
-23.116
-16.939
-6.377
4.185
16.939
81245.24
9243.47
7757.08
7385.93
5454.63
4594.22
3256.67
2766.41
2661.48
2568.49
2526.45
2324.79
2004.75
1828.98
1762.17
1740.32
1898.72
2120.41
2324.79
2183.39
1951.53
1720.91
1700.07
1828.98
1951.53
1898.72
1850.91
1951.53
2091.68
2217.90
2324.79
2250.23
2183.39
2120.41
2031.13
1898.72
1850.91
1784.58
1762.17
1700.07
1642.19
1554.54
1446.73
1418.80
1446.73
1606.31
1805.45
1875.65
1898.72
1805.45
1805.45
1805.45
1522.35
1720.91
2060.96
2060.96
2060.96
3256.67
2816.90
2400.71
2250.23
2250.23
2712.93
3407.64
4735.15
6711.56
9243.47
16598.49
25305.89
53229.64
192957.44
53229.64
30873.19
38591.49
38591.49
38591.49
38591.49
0.0061
0.0055
0.0052
0.0039
0.0026
0.0013
0.0013
0.0006
0.0003
0.0023
0.0042
0.0068
0.0090
0.0129
0.0149
0.0145
0.0142
0.0152
0.0161
0.0168
0.0175
0.0171
0.0168
0.0165
0.0161
0.0175
0.0178
0.0178
0.0165
0.0158
0.0165
0.0158
0.0136
0.0116
0.0113
0.0113
0.0110
0.0110
0.0129
0.0149
0.0178
0.0178
0.0184
0.0181
0.0175
0.0152
0.0152
0.0139
0.0175
0.0191
0.0191
0.0204
0.0187
0.0187
0.0197
0.0197
0.0197
0.0184
0.0149
0.0136
0.0139
0.0123
0.0100
0.0058
0.0016
0.0016
0.0020
0.0065
0.0074
0.0078
0.0100
0.0116
0.0158
0.0184
0.0191
0.0197
0.0200
0.0216
0.0249
0.0271
0.0281
0.0284
0.0262
0.0236
0.0216
0.0229
0.0255
0.0287
0.0291
0.0271
0.0255
0.0262
0.0268
0.0255
0.0239
0.0226
0.0216
0.0223
0.0229
0.0236
0.0246
0.0262
0.0268
0.0278
0.0281
0.0291
0.0301
0.0317
0.0339
0.0346
0.0339
0.0307
0.0275
0.0265
0.0262
0.0275
0.0275
0.0275
0.0323
0.0287
0.0242
0.0242
0.0242
0.0158
0.0181
0.0210
0.0223
0.0223
0.0187
0.0152
0.0113
0.0084
0.0065
0.0042
0.0032
0.0023
0.0016
0.0023
0.0029
0.0026
0.0026
0.0026
0.0006
0.0032
0.0035
0.0026
0.0010
0.0006
0.0026
004654
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.99677
59.99677
59.9971
59.99774
59.99872
59.99966
60
60.00034
60.00098
60.00226
60.0029
60.00259
60.00226
60.00226
60.00323
60.00421
60.00485
60.00452
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00354
60.00613
60.00485
60.00452
60.00452
60.00354
60.0029
60.00162
60.00162
60.00421
60.00421
60.0029
60.00034
59.99805
59.99646
59.99515
59.99387
59.99289
59.99255
59.99225
59.98965
59.98514
59.98254
59.97836
59.97641
59.97705
59.97705
59.97705
59.97803
59.97964
59.9816
59.98126
59.97931
59.9761
59.97543
59.97577
59.97675
59.97803
59.979
59.97964
59.98062
59.9819
59.98224
59.98254
59.98288
59.98254
59.98254
59.98288
59.98611
59.99387
60.00226
60.01099
60.01712
60.02069
60.02133
60.02133
60.02133
60.02325
60.02551
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
19590
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
9.200
13.373
15.319
15.118
12.756
9.059
5.888
3.060
-0.243
-5.319
-10.084
-12.483
-13.275
-13.790
-16.357
-20.257
-24.257
-26.090
-25.049
-24.373
-23.933
-23.647
-23.461
-23.341
-23.262
-29.140
-30.031
-29.843
-29.720
-27.409
-24.442
-19.584
-16.426
-20.302
-22.822
-21.460
-14.716
-5.102
4.775
14.193
23.245
31.361
37.403
42.028
50.963
67.093
83.506
103.730
121.340
131.321
137.809
142.026
142.536
139.170
132.519
128.962
131.115
139.837
147.041
150.957
151.270
148.544
144.540
140.473
135.597
129.499
124.767
120.995
117.775
116.450
115.588
114.261
106.005
82.922
48.738
6.571
-34.858
-69.947
-94.219
-109.996
-120.251
-131.311
-143.662
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
-11.433
-7.259
-5.314
-5.514
-7.876
-11.574
-14.744
-17.572
-20.875
-25.952
-30.716
-33.115
-33.908
-34.423
-36.989
-40.890
-44.890
-46.722
-45.682
-45.005
-44.565
-44.280
-44.094
-43.973
-43.895
-49.772
-50.663
-50.475
-50.353
-48.041
-45.074
-40.216
-37.059
-40.935
-43.454
-42.093
-35.349
-25.734
-15.858
-6.439
2.613
10.728
16.770
21.395
30.330
46.461
62.874
83.098
100.707
110.689
117.177
121.394
121.903
118.538
111.886
108.330
110.482
119.205
126.409
130.324
130.637
127.911
123.908
119.840
114.965
108.866
104.135
100.362
97.143
95.817
94.956
93.628
85.372
62.290
28.106
-14.062
-55.490
-90.579
-114.852
-130.629
-140.884
-151.944
-164.294
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
144.722
144.312
143.908
143.507
143.101
142.687
142.267
141.842
141.411
140.968
140.515
140.058
139.601
139.146
138.686
138.218
137.743
137.265
136.792
136.324
135.859
135.397
134.938
134.481
134.027
133.561
133.094
132.631
132.170
131.717
131.274
130.845
130.427
130.000
129.570
129.145
128.739
128.358
128.004
127.675
127.369
127.084
126.816
126.560
126.327
126.134
125.982
125.879
125.818
125.782
125.762
125.751
125.742
125.725
125.692
125.651
125.616
125.600
125.602
125.613
125.625
125.630
125.626
125.613
125.588
125.550
125.501
125.443
125.378
125.311
125.242
125.170
125.080
124.937
124.719
124.406
124.002
123.521
122.988
122.422
121.835
121.227
120.594
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
-18.645
58.634
58.425
58.217
58.009
57.803
57.598
57.394
57.192
56.990
56.789
56.590
56.391
56.194
55.997
55.802
55.608
55.414
55.222
55.031
54.840
54.651
54.462
54.275
54.088
53.903
53.718
53.535
53.352
53.170
52.989
52.809
52.630
52.452
52.275
52.098
51.923
51.748
51.574
51.401
51.229
51.058
50.887
50.718
50.549
50.381
50.214
50.048
49.882
49.717
49.553
49.390
49.228
49.066
48.906
48.745
48.586
48.428
48.270
48.113
47.956
47.801
47.646
47.492
47.338
47.185
47.033
46.882
46.731
46.582
46.432
46.284
46.136
45.989
45.842
45.696
45.551
45.406
45.262
45.119
44.976
44.834
44.693
44.552
8:18:54
8:18:56
8:18:58
8:19:00
8:19:02
8:19:04
8:19:06
8:19:08
8:19:10
8:19:12
8:19:14
8:19:16
8:19:18
8:19:20
8:19:22
8:19:24
8:19:26
8:19:28
8:19:30
8:19:32
8:19:34
8:19:36
8:19:38
8:19:40
8:19:42
8:19:44
8:19:46
8:19:48
8:19:50
8:19:52
8:19:54
8:19:56
8:19:58
8:20:00
8:20:02
8:20:04
8:20:06
8:20:08
8:20:10
8:20:12
8:20:14
8:20:16
8:20:18
8:20:20
8:20:22
8:20:24
8:20:26
8:20:28
8:20:30
8:20:32
8:20:34
8:20:36
8:20:38
8:20:40
8:20:42
8:20:44
8:20:46
8:20:48
8:20:50
8:20:52
8:20:54
8:20:56
8:20:58
8:21:00
8:21:02
8:21:04
8:21:06
8:21:08
8:21:10
8:21:12
8:21:14
8:21:16
8:21:18
8:21:20
8:21:22
8:21:24
8:21:26
8:21:28
8:21:30
8:21:32
8:21:34
8:21:36
8:21:38
59.997
59.997
59.997
59.998
59.999
60.000
60.000
60.000
60.001
60.002
60.003
60.003
60.002
60.002
60.003
60.004
60.005
60.005
60.004
60.004
60.004
60.004
60.004
60.004
60.004
60.006
60.005
60.005
60.005
60.004
60.003
60.002
60.002
60.004
60.004
60.003
60.000
59.998
59.996
59.995
59.994
59.993
59.993
59.992
59.990
59.985
59.983
59.978
59.976
59.977
59.977
59.977
59.978
59.980
59.982
59.981
59.979
59.976
59.975
59.976
59.977
59.978
59.979
59.980
59.981
59.982
59.982
59.983
59.983
59.983
59.983
59.983
59.986
59.994
60.002
60.011
60.017
60.021
60.021
60.021
60.021
60.023
60.026
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
-653.00
30465.30
30478.25
30478.25
30478.25
30478.25
30473.86
30473.86
30468.84
30468.84
30468.84
30468.84
30469.63
30469.63
30469.63
30469.63
30488.41
30488.41
30480.29
30480.29
30480.29
30480.29
30477.13
30477.13
30477.13
30477.13
30487.82
30487.82
30489.73
30489.73
30489.73
30489.73
30480.09
30480.09
30480.09
30480.09
30480.91
30480.91
30480.84
30480.84
30480.84
30480.84
30476.09
30476.09
30476.09
30476.09
30456.76
30456.76
30457.12
30457.12
30457.12
30457.12
30446.98
30446.98
30446.98
30446.98
30461.02
30461.02
30460.94
30460.94
30460.94
30460.94
30469.23
30469.23
30469.23
30469.23
30481.49
30481.49
30480.29
30480.29
30480.29
30480.29
30473.15
30473.15
30473.15
30473.15
30470.66
30470.66
30470.60
30470.60
30470.60
30470.60
30461.28
30461.28
21.124
21.124
18.932
14.747
8.370
2.192
0.000
-2.192
-6.377
-14.747
-18.932
-16.939
-14.747
-14.747
-21.124
-27.501
-31.685
-29.493
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-23.116
-40.055
-31.685
-29.493
-29.493
-23.116
-18.932
-10.562
-10.562
-27.501
-27.501
-18.932
-2.192
12.754
23.116
31.685
40.055
46.432
48.624
50.617
67.556
97.049
113.988
141.289
154.043
149.858
149.858
149.858
143.481
132.920
120.166
122.358
135.112
156.036
160.420
158.228
151.851
143.481
137.104
132.920
126.543
118.173
115.981
113.988
111.796
113.988
113.988
111.796
90.672
40.055
-14.747
-71.741
-111.796
-135.112
-139.297
-139.297
-139.297
-151.851
-166.598
25305.89
25305.89
30873.19
53229.64
81245.24
21741.68
13540.87
9895.25
8210.95
7757.08
7385.93
5250.54
3492.44
2929.15
2324.79
2120.41
2183.39
2183.39
2183.39
2286.90
2481.77
2766.41
2712.93
2438.64
2091.68
2031.13
2060.96
2152.94
2286.90
2400.71
2481.77
2616.37
2816.90
2874.60
2929.15
2991.59
2929.15
2929.15
2991.59
3765.02
9895.25
0.0032
0.0032
0.0029
0.0023
0.0013
0.0003
0.0000
0.0003
0.0010
0.0023
0.0029
0.0026
0.0023
0.0023
0.0032
0.0042
0.0049
0.0045
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0035
0.0061
0.0049
0.0045
0.0045
0.0035
0.0029
0.0016
0.0016
0.0042
0.0042
0.0029
0.0003
0.0020
0.0035
0.0049
0.0061
0.0071
0.0074
0.0078
0.0103
0.0149
0.0175
0.0216
0.0236
0.0229
0.0229
0.0229
0.0220
0.0204
0.0184
0.0187
0.0207
0.0239
0.0246
0.0242
0.0233
0.0220
0.0210
0.0204
0.0194
0.0181
0.0178
0.0175
0.0171
0.0175
0.0175
0.0171
0.0139
0.0061
0.0023
0.0110
0.0171
0.0207
0.0213
0.0213
0.0213
0.0233
0.0255
004655
Monday, May 16, 2011
Balancing Authority
MyBA
60.02
0.711
0.711
"Auto" Event Detection adjustment of T(0).
# of rows to shift T(0)
1
A zero value aligns the data to the hightest Frequency change value.
Usually the event begins one or two data scans earlier than this scan.
Initial P.U. Performance
Initial P.U. Performance Adjusted
700.0
20 to 52 second Average Period
59.999
60
653.00
653.00
600.0
Increasing this value shifts graph data to the right.
Decreasing this value shifts graph data to the left.
59.98
59.96
500.0
0.00
464.954
59.92
59.9
400.0
300.0
59.897
59.88
MW/0.1 Hz
Frequency - Hz
59.94
Note: The P.U. Performance values indicate performance as a P.U. value of BA Bias setting.
For BAs that utilize a variable Bias, the Bias average during T(+20) to T(+52) is used.
P.U. values above 1.0 indicate that the Bias setting was below measured Frequency Response.
P.U. values below 1.0 indicate that the Bias setting was above measured Frequency Response.
200.0
59.86
59.84
100.0
59.82
59.8
8:05:38
8:05:48
8:05:58
8:06:08
8:06:18
8:06:28
8:06:38
8:06:48
8:06:58
8:07:08
8:07:18
8:07:28
Hz
Average Frequency
Actual Primary Freq Response Beta
Actual Average Primary Freq Response
EPFR Adjusted
EPFR Unadjusted
0.0
8:07:38
T(0)
First change in frequency of the event should occur here on the vertical grid line.
It is important that the pre-event frequency average to NOT contain frequency data of the event, "Average Frequency" trend to the left of center of the graph.
To shift the data on the graph left or right, adjust the value in cell Q3 highlighted in yellow above.
004656
Monday, May 16, 2011
-653.00
MyBA
Avg Bias While Hz >+/-0.036 Hz
60.08
60.06
1400.0
60.04
60.02
1200.0
60
59.98
1000.0
59.94
800.0
59.92
59.9
600.0
59.88
59.86
400.0
59.84
59.82
200.0
59.8
59.78
59.76
8:05:38
0.0
8:06:38
8:07:38
8:08:38
8:09:38
Hz
8:10:38
8:11:38
8:12:38
BA Bias Setting
8:13:38
8:14:38
8:15:38
8:16:38
8:17:38
Actual Primary Freq Response Beta
8:18:38
8:19:38
8:20:38
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
004657
Value A Data
Date
Monday, May 16, 2011
A Value
Time
8:06:38
FPointA
Hz
60.002
A Value
Hz
59.999
t(0) Time
8:06:38
C Value
Hz
Frequency
Hz
59.870
59.999
Contingent
Resource
Lost
MW
471.09
BA Performance
NonLoad
Conforming
Resources
Load
Tripped
Load (-)
MW
MW
0.00
0.00
Value B
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
0.00
Spare
MW
BA
BA
Bias
Load
Setting
MW/0.1 Hz
MW
0.00
-653.00 30202.74
Bias
Setting
EPFR
Frequency
MW
Hz
8.97
59.897
20 to 52 second Average Period Evaluation
Contingent
Resource
Lost
MW
0.00
Load
Resources
Tripped
MW
0.00
NonConforming
Load
Load (-)
MW
0.00
Spare
MW
0.00
Frequency Response Initiative - Additional Primary Frequency Response Evaluation Points
Spare
MW
0.00
Spare
MW
Spare
MW
0.00
0.00
Initial
Performance
Adjusted
P.U.
0.711
Initial
Performance
Unadjusted
P.U.
0.711
Sustained
Performance
BA
BA
Bias
Load
Setting
P.U.
MW/0.1 Hz
MW
0.738
-653.00 30136.77
Average
Bias
Bias While
Setting Hz > +/-0.036
EPFR
Hz
MW
MW/0.1 Hz
671.54
-653.00
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Unadjusted
Adjusted
Adjusted
Adjusted
Adjusted
Adjusted
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
PFR
Performance Performance Performance Performance Performance Performance Performance Performance Performance Performance
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
@ T(+46)
@ T(+76)
@ T(+106)
@ T(+136)
@ T(+166)
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
P.U.
0.738
0.860
1.323
1.532
2.309
0.738
0.860
1.323
1.532
2.309
Maximum
Minimum
Bias Setting Bias Setting
MW/0.1 Hz MW/0.1 Hz
-653.00
-653.00
004658
Steps
1
2
3
4
5
6
To be completed for each event evaluated.
Set-up Data collection in exact same order as the "Data" sheet of this work book. Data should be in this order:
Column A: Date and Time in this format, mm/dd/yy HH:MM:SS
Column B: Frequency Hz
Column C: Contingent Resouce Lost MW or Lost Load
Column D: Load Resources tripped during the event.
Column E: Non Conforming Load
Column F: Spare
Column G: Not Used
Column H: Spare
Column I: Spare
Column J: BA Bias Setting
Column K: BA Load
Note: Columns D & E are optional data. If you choose not to use these, leave the columns blank. Do not delete the columns. Use the sign (+/-) convention defined in FRS Form 1.
Data compression must be turned off for each data point. Quality data will give you quality results in the evaluation.
Data must start a minimum of two (2) minutes before the event begins and includes a minimum of 15 minutes after the beginning of the event with up to 60 minutes of data.
Be sure the "Data" worksheet is clear of any old data. Collect the same total minutes of data for each event evaluated to minimize your effort and time.
If using PI historian as your data source, use "PasteSpecial/Values" to enter data into the spreadsheet. Do not include historian data collection formulas in the data.
Verify that the "Auto" Event Detection selected the correct event. Verify time and delta Hz by comparing time of event and delta Hz on the graph on the "Copy Results" worksheet.
If the wrong event was selected, in cell "E4" of this worksheet select "Manual" and manually select the beginning and ending row numbers of the desired event and enter these in cells "E5" and "E6". Only
rarely should you have to use the "Manual" process.
Once data is in place in the "Data" worksheet, confirm the Auto selection of the beginning of the event by observing the "Graph 20 to 52s" worksheet. Adjust the selection if necessary.
To make an adjustment, change the value in cell "Q3" on the "Graph 20 to 52s" worksheet. Usually a 0, 1 or 2 will achive the correct alignment of T(0).
7
If the correct row is selected, the "Graph 20 to 52s" worksheet will indicate the first change in frequency (red trend) of the event on the center vertical grid line of the graph.
8
The end of the event will be Auto selected based on the frequency value in cell "N2" on the Data worksheet. This will be the frequency at the beginning of the event or 60 Hz, whichever is lower. (for low Hz events)
This value controls the end of the "Sustained Frequency Response" evaluation period.
Primary Frequency Response should be sustained during the event recovery period. This evaluation determines how well you achieved this goal.
Use the "Copy Form 2 data for Pasting into Form 1" button provided on the "Copy Results" worksheet (Cells B21 through B28) to copy the evaluation and event specific data for the "FRS Form 1" of this field trial. This data is summarized
in the correct order on worksheet "Form 1 Summary Data".
Use PasteSpecial/Values and paste the copied data into FRS Form 1 on the appropriate event row. Be sure to use the latest version of Form 1, currently Form 1.9.
Save this Form 2 using the file name convention on the "Copy Results" worksheet. The complete file name is in bold in cell B38. Return all completed Form 2s with your Form 1 to NERC.
9
10
11
Steps
A
To be completed the first time you use Form 2 for your BA.
Enter the Balancing Authority name as you want it to appear on the graphs in cell "B1" of the "Copy Results" worksheet. For example: "ERCOT".
004659
Monday, May 16, 2011
MyBA
Load
Resources
Tripped
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
59.92
0.5
A Value
59.9
0.00
B Value
Average Period
20 to 52 second
0.00
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
8:13:38
8:14:38
8:15:38
Hz
Initial Load Resources
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
004660
Monday, May 16, 2011
MyBA
NonConforming
60.08
1.0
Load
60.06
Load (-)
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
8:15:38
Non- Conforming Load
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
004661
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
59.9
A Value
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
004662
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.2
60.06
60.04
1.0
60.02
60
59.98
0.8
59.94
0.6
59.92
A Value
59.9
0.00
B Value
0.00
Average Period
20 to 52 second
59.88
0.4
59.86
59.84
59.82
0.2
59.8
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW
Frequency - Hz
59.96
004663
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
0.5
59.92
A Value
59.9
B Value
0.00
0.00
Average Period
20 to 52 second
59.88
59.86
0.4
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
MW/0.1 Hz
Frequency - Hz
59.96
004664
Monday, May 16, 2011
MyBA
Not
Used
60.08
1.0
60.06
0.9
60.04
60.02
0.8
60
0.7
59.98
0.6
59.94
MW
Frequency - Hz
59.96
59.92
A Value
59.9
B Value
0.00
15.00
0.5
Average Period
20 to 52 second
0.4
59.88
59.86
0.3
59.84
0.2
59.82
59.8
0.1
59.78
59.76
8:05:38
8:06:38
8:07:38
8:08:38
8:09:38
8:10:38
8:11:38
8:12:38
Hz
8:13:38
8:14:38
Not Used
8:15:38
8:16:38
8:17:38
8:18:38
8:19:38
8:20:38
0.0
8:21:38
004665
Monday, May 16, 2011
BA
Load
MyBA
30600.0
60.08
60.06
30500.0
60.04
60.02
30400.0
60
59.98
30300.0
59.94
30200.0
59.92
A Value
59.9
7651.305
B Value
30136.8
Average Period
20 to 52 second
30100.0
59.88
59.86
30000.0
59.84
59.82
29900.0
59.8
59.78
29800.0
59.76
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
BA Load
MW
Frequency - Hz
59.96
004666
Monday, May 16, 2011
MyBA
Expected Primary
Freq Response
Based on Bias Setting
60.08
1000.0
60.06
60.04
800.0
60.02
60
600.0
59.98
400.0
59.94
MW
Frequency - Hz
59.96
59.92
59.9
200.0
59.88
59.86
0.0
59.84
59.82
-200.0
59.8
A Value
59.78
8.97
B Value
671.54
Average Period
20 to 52 second
59.76
-400.0
8:05:38 8:06:38 8:07:38 8:08:38 8:09:38 8:10:38 8:11:38 8:12:38 8:13:38 8:14:38 8:15:38 8:16:38 8:17:38 8:18:38 8:19:38 8:20:38 8:21:38
Hz
Expected Primary Freq Response Based on Bias Setting
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004667
Standards Announcement
Project 2007-12 Frequency Response
Recirculation Ballot is now open through 8 p.m. Friday, December 21, 2012
Now Available
A recirculation ballot window for BAL-003-1 – Frequency Response and Frequency Bias Setting is now
open through 8 p.m. Eastern on Friday, December 21, 2012.
The Frequency Response Standard Drafting Team did not make any substantive changes to the
documents, but did make the following minor changes based on stakeholder comments:
Made clarifying changes to the proposed standard including replacing the term “…subject to…” with
“…in accordance with…” in Requirement R2.
Clarified the description of the calculation for the Interconnection IFRO in Attachment A.
Modified Attachment A and the Procedure to provide consistency with the use of the term
“resource contingency criteria.”
Corrected typographical errors in all documents.
Instructions
In the recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast
a ballot; all ballot pool members may change their previously cast votes. A ballot pool member who
failed to cast a ballot during the last ballot window may cast a ballot in the recirculation ballot
window. If a ballot pool member does not participate in the recirculation ballot, that member’s vote
cast in the previous ballot will be carried over as that member’s vote in the recirculation ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps
Voting results will be posted and announced after the ballot window closes. If approved, the standard
will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. There is evidence of continuing
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004668
decline in Frequency Response over the past 10 years, but no confirmed reason for the apparent
decline. The proposed standard would set a minimum Frequency Response obligation, provide a
uniform calculation of Frequency Bias Settings that transition to values closer to Frequency Response,
and encourage coordinated AGC operation.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-12
2
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004669
Standards Announcement
Project 2007-12 Frequency Response
Recirculation Ballot Results
Now Available
A recirculation ballot for BAL-003-1 – Frequency Response and Frequency Bias Setting concluded at 8
p.m. Eastern on Friday, December 21, 2012.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results.
Approval
Quorum: 86.19%
Approval: 76.53%
Next Steps
The standard will be presented to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Background
Frequency Response, a measure of an Interconnection’s ability to stabilize frequency immediately
following the sudden loss of generation or load, is a critical component to the reliable operation of the
bulk power system, particularly during disturbances and restoration. There is evidence of continuing
decline in Frequency Response over the past 10 years, but no confirmed reason for the apparent
decline. The proposed standard would set a minimum Frequency Response obligation, provide a
uniform calculation of Frequency Bias Settings that transition to values closer to Frequency Response,
and encourage coordinated AGC operation.
Additional information is available on the project page.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004670
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-12 Frequency Response
2
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004671
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Project 2007-12 Frequency Response Recirculation Ballot December
Ballot Name:
2012_in
Password
Ballot Period: 12/12/2012 - 12/21/2012
Log in
Ballot Type: Recirculation
Register
Total # Votes: 312
Total Ballot Pool: 362
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Quorum: 86.19 % The Quorum has been reached
Weighted Segment
76.53 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
92
11
79
28
80
48
0
9
6
9
362
1
1
1
1
1
1
0
0.7
0.3
0.7
7.7
#
Votes
41
5
40
16
42
28
0
7
1
7
187
Fraction
Negative
#
Votes
0.661
0.5
0.769
0.889
0.75
0.824
0
0.7
0.1
0.7
5.893
Abstain
Fraction
21
5
12
2
14
6
0
0
2
0
62
No
# Votes Vote
0.339
0.5
0.231
0.111
0.25
0.176
0
0
0.2
0
1.807
20
1
16
5
10
6
0
2
1
2
63
10
0
11
5
14
8
0
0
2
0
50
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Member
Ballot
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
James Armke
Scott J Kinney
Kevin Smith
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Affirmative
Negative
Affirmative
Negative
Affirmative
Comments
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Raj Rana
Rochester Gas and Electric Corp.
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Joseph Turano Jr.
Negative
Negative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Gordon Pietsch
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Cole C Brodine
Randy MacDonald
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brad Chase
Ryan Millard
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A. Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
Rajendrasinh D Rana
John C. Allen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Negative 004672
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Abstain
Negative
Abstain
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Tim Kelley
Kathryn Spence
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Angela L Summer
Noman Lee Williams
Beth Young
Larry G Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Patrick Woods
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Brian Glover
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Affirmative004673
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Ocala Electric Utility
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
LaGen
Madison Gas and Electric Co.
Northern California Power Agency
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
David Anderson
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Richard Comeaux
Joseph DePoorter
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Affirmative004674
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Edison Mission Energy
Electric Power Supply Association
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Douglas Hohlbaugh
Henry E. LuBean
Abstain 004675
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Mike D Kukla
Negative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Jeanie Doty
Paul A. Cummings
Negative
Affirmative
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Ellen Oswald
John R Cashin
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
S N Fernando
David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Allen D Schriver
Hari Modi
William O. Thompson
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Gary L Tingley
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
Joseph O'Brien
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Negative 004676
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
NERC
Standards
20130329-5116
FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Energy Mark, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative004677
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F Lemmons
Roger C Zaklukiewicz
James A Maenner
Robert Blohm
Edward C Stein
Howard F. Illian
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Donald Nelson
Affirmative
Diane J. Barney
Negative
Thomas G. Dvorsky
Jerome Murray
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Negative
Abstain
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ffd00534-2954-427b-8a42-1299bd9493c7[12/26/2012 12:10:10 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004678
Exhibit L
Standard Drafting Team Roster for NERC Standards Development
Project 2007-12
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004679
Project 2007-12 Frequency Response
Name and Title
Company
David Lemmons – Xcel Energy, Inc
Chair
Senior Manager,
Market Operations
Contact Info
303.571.6520
david.f.lemmo
ns@xcelenergy
.com
Terry Bilke – Vice‐ Midwest Independent 317‐249‐5463
chair
System Operator
TBilke@misoe
Consulting Advisor
nergy.org
Bio
David Lemmons began his career in the
electric industry with Southwestern Public
Service Company (SPS) in Amarillo, Texas in
1989. He spent 8 years in the Rates and
Regulation Department where he performed
rate of return analyses, designed rates and
worked with other regulatory issues. In
1997, David moved to the Energy Trading
Department during the merger between SPS
and Public Service Company of Colorado
(PSCo). In this capacity, with Xcel Energy
and its predecessor, New Century Energies,
he analyzed the electric system loads and
resources for day‐ahead and real‐time
operations and trading, working with
generation and fuel procurement to ensure
resources were ready and available to serve
loads. Since 2001, in the positions of
Manager and Senior Manager of Market
Operations, he has represented Xcel Energy
at electric reliability, RTO development and
system operation meetings throughout the
United States as well as providing support
for state and Federal regulatory
proceedings. He has a Master of Science in
Finance and Economics from West Texas
A&M University.
Terry Bilke is a Consulting Advisor in the
Compliance Services department at MISO.
He has over thirty years of power system
operations and maintenance experience, 16
years of this as a transmission and balancing
authority operator. He is a former chair of
the NERC Resources Subcommittee and is
presently chair of the NERC Compliance and
Certification Committee. Terry received his
PhD in Quality Systems from Indiana State
University, MSME from Colorado State
University, and MBA from the University of
Wisconsin‐Whitewater.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004680
Don Badley
Northwest Power Pool 503‐445‐1076
don.badley@n
wpp.org
Don Badley has been a member of the
Northwest Power Pool (NWPP) Staff since
1975. Don manages the NWPP Operating
Committee. He is currently Chairman of the
North American Electric Reliability
Corporation (NERC) Resources
Subcommittee, a member of Western
Electricity Coordinating Council’s (WECC)
Performance Work Group and has chaired
numerous NERC and WECC groups.
In the past Don has served as Chairman of
the North American Power Systems
Interconnection Committee’s Performance
Subcommittee, a member of the WECC
Technical Operations Subcommittee, and a
member of the WECC Control Work Group.
Regarding his association the Institute of
Electrical and Electronics Engineers (IEEE),
Don is a member of the IEEE Power
Engineering Society and has co‐authored
three IEEE papers on system control. Don
has served as Chairman of the Oregon
Section and Area Chairman for the States of
Alaska, Oregon, and Washington.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004681
Howard Illian
President
Energy Mark, Inc.
847‐913‐5491
howard.illian@ Howard F. Illian graduated from Carnegie
energymark.co Institute of Technology (Carnegie‐Mellon
University) in 1970 with a B.S. in Electrical
m
Engineering. From 1970 until 1982 he
worked for ComEd in the field of Operations
Research, and was Supervisor, Economic
Research and Load Forecasting from 1976
until he was reassigned to Bulk Power
Operations in 1982 where he was Technical
Services Director when he retired in 1998.
He is now President of Energy Mark, Inc., a
consulting firm specializing in the
commercial relationships required by
restructuring. He has authored numerous
papers, and has testified as an expert
witness before the Illinois EPA, the Federal
EPA, the Illinois Commerce Commission and
the Public Utility Commission of Texas. He
has developed and applied several new
mathematical techniques for use in
simulation and decision making. He has
served on the NERC Performance
Subcommittee, the Interconnected
Operations Services Implementation Task
Force, the Joint Inadvertent Interchange
Task Force, and the NAESB Inadvertent
Interchange Payback Task Force. Recent
work includes significant contributions to
the development of new NERC Control
Performance Standards including the
Balancing Authority Ace Limit and a
suggested mathematical foundation for
control based on classical statistics. His
current research concentrates on the
development of technical definitions for
Ancillary or Reliability Services including
frequency response and their market
implementation.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004682
Clyde Loutan
Senior Advisor
California ISO
916‐608‐5917
cloutan@caiso
.com
Clyde Loutan is presently a Senior Advisor at
the California Independent System Operator
Corporation (ISO) focusing on power system
operation performance, and is the lead
investigator for the ISO’s renewable
resource integration technical studies. He is
a technical subject matter expert on power
grid planning, system operations, and
renewable energy integration. Mr. Loutan
previously worked at the Pacific Gas and
Electric Company for 14 years in various
capacities such as Real Time System
Operations, Transmission Planning and High
Voltage Protection.
Mr. Loutan is a licensed professional
engineer in the State of California. He holds
B.S. and M.S. degrees in Electrical
Engineering from Howard University in
Washington D.C., and is a senior member of
the IEEE.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004683
Carlos Martinez
CERTS
cmartinez@asr Carlos Martinez is presently leading for the
esearchers.co
Consortium for Electric Reliability
m
Technology Solutions (CERTS) and Advanced
Systems Researchers, Inc., (ASR) a group of
researchers and analysts investigating,
deploying and field testing advanced real
time reliability monitoring applications for
identifying interconnections load‐generation
and grid controls adequacy, reliability
performance, and trends. He participates in
North American Electric Reliability
Corporation (NERC) Standard Drafting
Teams researching, recommending and field
testing load‐generation and grid control
performance standards.
Carlos holds a MS in Electrical Engineering
from the University of Miami, Florida, and
brings 30 years of experience in the
electricity power industry first deploying and
supporting advanced monitoring
applications at Florida Power and light,
second as Manager of Southern California
Edison Energy Management System (EMS)
and 4 SCADA systems, and during the last 10
years working on advanced, applied
research for processes optimization, risk
analysis, control, monitoring and geo‐
graphic visualizations for Lawrence Berkeley
National Laboratory (LBNL), Department of
Energy (DOE) and Federal Energy Regulatory
Commission (FERC). After the Eastern
blackout of August 14, 2003 Carlos chaired
the NERC Frequency‐ACE Investigation Team
(FAIT).
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004684
Sydney Niemeyer
Control System
Specialist
NRG Texas LP
713‐795‐6108
sydney.niemey
er@nrgenergy.
com
Mike Potishnak
Principal Engineer
ISO New England, Inc.
413‐535‐4308
mpotishnak@i
so‐ne.com
Sydney L. Niemeyer started with Houston
Lighting and Power Co. in June of 1969 as a
Cooperative Education student. He earned
a B.S. in Electrical Technology in 1975 from
the University of Houston. Between 1972
and 1988 he worked as an Instrument
control technician, Master Instrument &
Control Technician and Crew Leader at
various plants including the startup of 7 of
the 59 units at 11 sites. In 1988 he
coordinated the installation and placed in
service RTU’s at each site and interfaced
new AGC for each unit. He developed and
implemented a computer program to
monitor the startup processes of large
steam turbines. In 1997 he transferred to
the generation dispatch division and
managed the AGC of all units for what is
now NRG Texas. Since then he has been
involved with numerous ERCOT and NERC
task forces, working groups and committees
including: Performance, Disturbance and
Compliance Working Group (PDCWG) of
ERCOT; Resources Subcommittee of NERC
and its Frequency Control and Reserves
Working
Groups;
NERC
Eastern
Interconnection August 4, 2007 frequency
event investigation team; NERC Frequency
Response Standard Drafting Team and the
ERCOT BAL‐001‐TRE‐1 Regional Standard
Drafting Team.
Mike Potishnak is a Principal Engineer for
ISO New England since 1989. He has been a
member of the NERC Resources
Subcommittee for the past 15 years, and has
participated in the Balancing Authority
Reliability‐based Control Standard Drafting
Team in addition to the Frequency Response
Standard Drafting Team. He has been the
engineer with primary responsibility for
Automatic Generation Control for more than
20 years, and has played a major role in ISO
New England’s regulation markets prior to
their inception in 1999. He also has
substantial experience in monitoring and
enhancing generator governor response.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004685
Tom Washburn
Executive Director
Florida Municipal
Power Pool
407‐434‐4228
TWashburn@o
uc.com
With over 40 years of experience, Tom
Washburn has provided a diverse set of
services to Orlando Utilities Commission and
the Florida Municipal Power Pool. As Vice
President of the Transmission Unit at
Orlando Utilities Commission, he was
responsible for the planning, regulatory
permitting, construction and operation of
over 300 miles high voltage transmission
lines, over 30 high voltage substations, and
the 24‐by‐7 system operations of the
transmission and generation system. As the
Chief Information Officer at Orlando Utilities
Commission, Washburn was responsible for
all of the Information Technology including
microcomputer
support,
computer
applications,
computer
hardware,
telecommunication and the fiber optics data
communications. In other management
roles at Orlando Utilities Commission, he
was responsible for financial planning, load
forecasting, rate design, wholesale
marketing, and generation planning. Tom
Washburn helped form the Florida
Municipal Power Pool, which started
operation in July 1988. As the first Executive
Director of the Florida Municipal Power
Pool, since May. 2006, Washburn is
responsible for the reliable, economic
operation of more than 4,500 megawatts of
generation serving 20 municipal utilities in
Florida, compliance with the North America
Reliability Corporation Reliability Standards,
and overseeing the clearinghouse price
process for the Pool.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004686
Sandip Sharma
Senior Operations
Engineer
ERCOT
512‐248‐4298 Sandip Sharma received his M.S.E.E in
ssharma@erco Electrical Engineering from the University of
t.com
Texas at Arlington in 2006 specializing in
Power Systems. He joined the Electric
Reliability Council of Texas Inc., (ERCOT)
after graduation, and has been working
since then in the Operations Planning group.
While working at ERCOT, he was
responsible for monitoring overall
Frequency Control and Primary Frequency
Response performance of the ERCOT
Interconnection. He was the primary
subject matter expert in governor response
analysis post frequency disturbance and
Automatic Generation Control/Load
Frequency Control tuning. He has authored
several IEEE papers and represented ERCOT
at various technical conferences on primary
frequency response and integration of
intermittent resources. He is also a member
of the regional standard drafting team (BAL‐
TRE‐001) for the ERCOT region; working on
individual generator governor setting and
performance requirements.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004687
Robert Cummings NERC
Director, Reliability
Initiatives and
System Analysis
404‐446‐9717
bob.cummings
@nerc.net
Mr. Cummings joined NERC in 1996 and has
extensive experience in the industry in
system planning, operations engineering,
and wide area planning. He holds a
Bachelor of Science Degree in Power System
Engineering from Worcester Polytechnic
Institute and is an IEEE Senior Member.
His geographically diverse experience
includes Central Vermont Public Service
Corporation in System Planning (generation
and transmission), Public Service Company
of New Mexico, and the East Central
Reliability Coordination Agreement (ECAR).
Mr. Cummings was the “father” of power
interchange transaction “tagging” and the
Interchange Distribution Calculator, which
shows loading contributions on key system
transmission interfaces, or “flowgates,” for
the Eastern Interconnection.
The Reliability Initiatives and System
Analysis group acts provides a consulting
engineering function within NERC,
performing deep‐dive forensic engineering
analysis of major system disturbances and
providing subject matter expertise to
standards drafting teams and various other
areas of NERC staff.
Cummings was intimately involved in the
investigation team of the 2003 blackout as a
team leader and the more recent September
8, 2011 Arizona‐Southern California Outage
analysis. In both instances he led multiple
teams with responsibilities in the sequence
of events development, modeling and
studies (powerflow and dynamics analysis),
and transmission/generation performance
areas. From 2005 through 2009, he directed
the NERC Event Analysis and Information
Exchange program, directing or working on
12 major disturbance analyses.
Mr. Cummings was instrumental in the
founding of the NERC System Protection and
Controls Task Force, now the System
Protection and Control Subcommittee,
acting as the staff coordinator from 2004
through 2009.
Mr. Cummings is the staff coordinator for
the NERC System Analysis and Modeling
Subcommittee and is the technical advocate
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
004688
Darrel Richardson
Standards
Developer
NERC
609‐613‐1848
Darrel.richards
[email protected]
Darrel Richardson joined the NERC staff as a
Standards Developer. In this role he
facilitates and provides guidance to drafting
teams in the development of technically
excellent and timely reliability standards for
the reliable operation and planning of the
bulk power system. Darrel began his career
with NERC in November 2007.
Darrel has extensive experience in the utility
industry having spent over 37 years with
Illinois Power Company. In his tenure at
Illinois Power he held several different
positions in the Engineering, Planning and
Operations groups. Among the position he
has held are Transmission Coordinator,
Generation Coordinator, Manager
Wholesale Marketing, Manager Wholesale
Marketing and Trading, Director Generation
Control and Manager Compliance.
20130329-5116 FERC PDF (Unofficial) 3/29/2013 1:17:15 PM
Document Content(s)
Petition and Exhibits A-J_FINAL.PDF...................................1-986
EXHIBIT K_pt 1.PDF....................................................987-2485
EXHIBIT K_pt
PDF....................................................2486-4703
EXHIBIT L_Drafting Team Roster_Project
07-121.PDF...................4704-4714
| File Type | application/pdf |
| File Title | Microsoft Word - Petition for Approval of BAL-003_FINAL |
| File Modified | 2013-04-01 |
| File Created | 2013-04-01 |